Summary of FERC Order Nos. 860 and 861: Reforms to FERC’s Market-Based Rate Program
If you have any questions regarding this advisory, please contact Amie V. Colby or Christopher R. Jones.
On July 18, 2019, the Federal Energy Regulatory Commission (“FERC” or “Commission”) issued Order Nos. 860 and 861, in which FERC revised the requirements for sellers authorized or seeking authorization to make sales of energy, capacity, or ancillary services at market-based rates (“Sellers”). Order No. 860 rolled out longer-term changes to the way the Commission tracks affiliate relationships, and Order No. 861 eliminated the screen analyses for certain Sellers in regional transmission organization (“RTO”)/independent system operator (“ISO”) markets.
In Order No. 860, FERC revised its requirements to require Sellers to provide certain information about corporate relationships and affiliations through a “relational database” the Commission will be rolling out. Among other things, FERC (1) reduced and clarified the scope of information provided in market-based rate filings; (2) changed the information to be included in an asset appendix; (3) required market-based rate Sellers to update the relational database on a monthly basis; (4) changed the notice of change in status filing requirement to a quarterly basis; and (5) eliminated the requirement that Sellers submit corporate organizational charts adopted in Order No. 816. FERC declined to require Sellers and entities trading virtual or holding financial transmission rights to submit Connected Entity information and instead transferred the record on this proposal to Docket No. AD19-17-000 for possible future consideration. Order No. 860 will become effective October 1, 2020.
In Order No. 861, FERC relieved Sellers of the requirement to submit indicative screens to obtain or retain authority to sell energy, ancillary services, and capacity at market-based rates in markets with RTO/ISO administered energy, ancillary services, and capacity markets that are subject to FERC-approved RTO/ISO monitoring and mitigation. FERC also eliminated the rebuttable presumption that FERC-approved RTO/ISO market monitoring and mitigation is sufficient to address any horizontal market power concerns regarding the sales of capacity in RTOs/ISOs that do not have an RTO/ISO-administered capacity market. Order No. 861 will become effective 60 days after publication in the Federal Register.
II. Summary of Order No. 860
A. Overview
FERC revised its regulations to require market-based rate Sellers to provide certain information in a consolidated and streamlined manner through a relational database that FERC will establish over the next year and half. According to the Commission, the new “relational database construct modernizes the Commission’s data collection processes, eliminates duplications, and renders information collected through its market-based rate program usable and accessible for the Commission.”
Amongst the changes, FERC adopted rules to reduce and clarify the scope of ownership information provided by Sellers in their market-based rate filings, change the information to be included in a Seller’s asset appendix, and require market-based rate Sellers to update the relational database on a monthly basis to reflect any changes that have occurred. In addition, FERC changed the notice of change in status filing requirement from a rolling 30-days basis to a quarterly basis and eliminated the requirement that Sellers submit corporate organizational charts. FERC declined to adopt its proposal to collect Connected Entity data from market-based rate Sellers and entities trading virtual or holding financial transmission rights. Because these reforms will require significant changes to the systems used to report corporate affiliations, the regulatory changes in Order No. 860 will not become effective until October 1, 2020.
B. Submission of Information Through a Relational Database
FERC adopted its proposal to create a relational database that would collect market-based rate information, [1] where a relational database is a database model that contains multiple data tables which relate to one another via unique identifiers. [2] FERC clarified that there will be a two-step process for the data submission process. [3] Sellers will first submit information in XML into the relational database, which will produce a retrievable asset appendix and indicative screens that will be accessible via serial numbers. [4] Sellers can then submit market-based rate filings through eFiling, identifying its asset appendices and indicatives screens in its transmittal letter through the usage of the generated serial numbers. [5]
C. Obtaining a Legal Entity Identifier (“LEI”)
In order to track each unique public utility and each discrete affiliate, FERC will require that each entity have a unique identifier. FERC had proposed to have each entity register using an LEI. [6] FERC declined to require Sellers to obtain and maintain LEIs and adopted instead the proposal put forth by commenters to allow Sellers to use their Company Identifiers (“CID”) in the relational database. [7] FERC stated that because Sellers are already required to obtain and maintain CIDs, requiring Sellers to obtain and maintain LEIs was unnecessarily burdensome and duplicative. [8] However, FERC did maintain that Sellers may identify their affiliates through LEIs, as some affiliates may not have CIDs. [9] For affiliates without a CID or an LEI, the Commission created a new “FERC generated ID” to serve as their form of identification. The system will allow Sellers to obtain unique FERC generated IDs for their affiliates.
D. Substantive Changes to Market-Based Rate Requirements
1. Asset Appendix
a. New Format
FERC adopted the Data Collection NOPR’s proposal to require that Sellers submit asset appendix information in XML format instead of the excel format used currently. [10] FERC also adopted the proposals that while Sellers would no longer be required to report assets owned by its affiliates with market-based rate authority, Sellers would be required to include in their relational databases any assets owned by their affiliates that do not have market-based rate authority. [11] FERC noted that it was not changing existing policy regarding exempt Qualifying Facilities and behind-the-meter generation. [12]
b. Reporting of Generation Assets
FERC adopted the Data Collection NOPR’s proposal to require that Sellers report each generator separately into the relational database, with Sellers being required to report each generator’s Plant Code, Generator ID, and Unit Code (if applicable) (collectively, “EIA Code”), as gathered from the EIA-860 database. [13] For generators that do not appear in the EIA-860 database, FERC is creating a new “Asset Identification” number that can be obtained by Sellers prior to their relational database submissions to FERC. [14]
FERC also adopted the Data Collection NOPR’s proposal to require Sellers to report the telemetered market/balancing authority area of their generation in the relational database. [15] However, Sellers will not be required to report the telemetered region of their generation. [16]
c. Power Purchase Agreements
FERC adopted the Data Collection NOPR’s proposal to require Sellers to include information on long-term firm sales in the relational database, [17] with long-term firm sales being defined as sales for one year or longer that are not interruptible for economic reasons. [18]
d. Providing EIA Codes for Unit-Specific Power Purchase Agreements
FERC adopted the Data Collection NOPR’s proposal that, for unit-specific power purchase agreements, Sellers must provide the unit’s associated EIA Codes or Asset ID in the relational database, [19] with such requirement applying to both unit-specific sales and unit-specific purchases. [20]
e. Vertical Assets
FERC adopted the Data Collection NOPR’s proposal to require Sellers to signify in the relational database whether they have transmission facilities covered by a tariff in a specific balancing authority area. [21] For natural gas pipelines and/or storage facilities, Sellers need only indicate if they own such facilities and in which balancing authority area the facilities are located. [22] FERC also eliminated the requirement for Sellers to file specific details about their transmission facilities. [23]
2. Ownership Information
FERC adopted its proposal to require Sellers to identify their ultimate upstream affiliates when submitting their market-based rate applications or baseline submissions. [24] Sellers must also inform FERC of new “ultimate upstream affiliates” as part of their change in status reporting obligations. [25] FERC will also remove the requirement for Sellers to file corporate organizational charts, as the requirement to identify ultimate upstream affiliates will allow FERC to create such charts. [26] FERC will continue to require narrative descriptions of Sellers’ ownership structures that should capture any ownership or affiliate relationship information that has a bearing on Sellers’ horizontal and vertical market power analyses. [27]
FERC chose to not adopt the Data Collection NOPR proposal under which the first time an entity is identified as an ultimate upstream affiliate by Seller in an XML Submission, a unique identifier would be created for such entity. [28] However, a list of unique identifiers for Sellers’ ultimate upstream affiliates will be published on FERC’s website. [29]
3. Passive Owners
FERC adopted its proposal to require Sellers to affirm in their market-based rate narratives their owners who have a passive ownership interest. [30] Sellers must identify the owners and affirm that such ownership interests consist of passive rights that do not confer control over the Seller. [31]
4. Foreign Governments
FERC opted to not adopt the Data Collection NOPR’s proposal requiring Sellers to identify relationships with specific foreign governments. [32] However, Sellers must still identify all ultimate upstream affiliates, regardless of whether such affiliates are owned or controlled by a foreign government. [33]
5. Indicative Screens
FERC adopted its proposal to require Sellers to submit indicative screen information in XML format, thereby enabling the indicative screens to be included in the relational database. [34] However, because the relational database will not have the capability to populate indicative screens into the eLibrary record, Sellers must instead include the serial number of the indicative screens in their associated market-based rate filings. [35] Such serial numbers will be assigned to each indicative screen after a Seller submits its indicative screen-related XML data into the relational database. [36]
6. Other Market-Based Rate Information
FERC adopted its proposal to require each Seller to submit the following information into the relational database as set forth in the MBR Data Dictionary:
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Information about its operation reserves;
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Category status for each region in which it has market-based rate authority; and
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Mitigation, if any.
E. Change-in-Status Filings and Ongoing Reporting Requirements
FERC adopted new rules requiring Sellers to submit monthly relational database updates on the 15th day of each month following the occurrence of any reportable change to relational database information. [37] FERC also changed the required timing for filing notices of change in status so that Sellers will only need to file notices of change in status on a quarterly basis, instead of 30 days after the change in status occurs. [38]
F. Connected Entity Information
FERC declined to adopt the Data Collection NOPR’s proposal requiring Sellers and Virtual/FTR Participants to submit Connected Entity Information. [39] FERC instead transferred the record on this proposal to Docket No. AD19-17-000 for possible future consideration by FERC. [40] This decision drew a dissenting opinion from Commissioner Glick.
G. Initial Submissions/Implementation and Timing
The effective date of the final rule will be October 1, 2020, but submitters will have until close of business on February 1, 2021 to make their initial baseline submissions into the relational database. As of February 1, 2021, prior to filing an initial market-based rate application, a new Seller will be required to make a submission into the relational database. According to the Commission, this will allow the relational database to create the asset appendices and indicative screens and provide the Seller with the serial numbers that it needs to reference in its transmittal letter as discussed above. FERC stated, “We affirm that after January 31, 2021, no asset appendices or indicative screens are to be submitted as attachments to filings through the eFiling system.” [41]
H. Data Dictionary
FERC adopted the Data Collection NOPR’s proposal to post on FERC’s website a dictionary that would define the framework for Sellers to follow when submitting information (the “MBR Data Dictionary”) and made numerous changes to MBR Data Dictionary entries. [42]
I. Confidentiality
FERC provided clarity that certain aspects of Sellers’ market-based rate filings will appear in eLibrary as either public or non-public, with Sellers being able to request privileged treatment of their filings they believe to be exempt. [43] However, FERC noted that much of the information submitted into the relational database will likely not qualify for privileged treatment, including the relationship between the Seller and its ultimate upstream affiliates. [44]
J. Due Diligence
FERC provided clarity that it will not seek to impose sanctions for inadvertent errors, misstatements, or omissions in the data submission process. [45] FERC added that any necessary corrections to a submission under the final rule should be submitted on a timely basis, as soon as practicable after the discovery of the inadvertent error or omission. [46] However, FERC also stated that certain circumstances could result in a violation and the imposition of sanctions, including if there are systemic or repeated failures to provide accurate information and a consistent failure to ensure the accuracy of the information submitted through due diligence. [47]
FERC declined to adopt a “safe harbor,” a “presumption of good faith,” a “good faith reliance on others defense,” or a standard where FERC would limit bringing enforcement actions only when there is evidence of an entity intentionally submitting inaccurate or misleading information to FERC. [48] Instead, FERC will rely on looking at extraneous circumstances and whether the entity submitting the information exercised due diligence. [49]
III. Summary of Order No. 861
A. Overview
In Order No. 861, FERC modified its regulations regarding the horizontal market power analysis required to obtain authorization to sell energy, capacity, or ancillary services at market-based rates. In order to sell energy, capacity, or ancillary services at market-based rates, FERC requires the Seller and its affiliates to demonstrate that they do not have, or have adequately mitigated, both horizontal and vertical market power. [50] FERC previously adopted two indicative screens—the pivotal supplier screen and the wholesale market share screen—for assessing horizontal market power within a geographic area, often the RTO/ISO that the Seller is a member of and located in. [51] Order No. 861 relieves market-based rate Sellers that study RTO/ISO markets of the obligation to submit indicative screens as part of the horizontal market power analysis in any organized wholesale power market that administers energy, ancillary services, and capacity markets subject to Commission-approved monitoring and mitigation. [52]
The rule contains two caveats: First, Sellers will continue to be required to submit indicative screens for authorization to make capacity sales at market-based rates in markets that lack an RTO/ISO administered capacity market subject to FERC-approved monitoring and mitigation—at present, California Independent System Operator Corp. (“CAISO”) and Southwest Power Pool, Inc. (“SPP”). However, Sellers in these markets would still be relieved of the requirement to submit indicative screens if they sought market-based rate authority limited to sales of energy and/or ancillary services. Second, while FERC previously adopted a rebuttable presumption that existing, FERC-approved market power mitigation measures by RTOs/ISOs are sufficient to address market power concerns when a Seller fails the indicative screens, Order No. 861 holds that such mitigation mechanisms are no longer presumed 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. [53]
B. Arguments Regarding Assurance of Just and Reasonable Rates
FERC rejected concerns that relieving Sellers in RTO/ISO markets of the obligation to submit indicative screens would deprive FERC and other parties of the data necessary to assess market power and to meet the evidentiary burdens required to challenge market-based rate filings. [54] FERC explained that Sellers continue to be required to submit ownership information, vertical market power analysis, asset appendix, market monitor reports, and Electronic Quarterly Reports (“EQR”). [55] A successful challenge to a Seller’s market-based rate requires demonstrating that: (1) the Seller has market power, and (2) such market power is not addressed by existing FERC-approved RTO/ISO market monitoring and mitigation. To the extent that a complainant successfully rebuts the presumption of sufficiency of market monitoring and mitigation, FERC clarified that it retains its authority to require the Seller to submit indicative screens or other evidence to determine whether the Seller has market power. [56]
C. Capacity Sellers in CAISO and SPP
Order No. 861 requires Sellers to continue to submit indicative screens for capacity sales in CAISO and SPP, and eliminates the rebuttable presumption that FERC-approved RTO/ISO market monitoring and mitigation is sufficient to address any horizontal market power concerns regarding capacity sales in these markets. [57] FERC rejected objections that capacity sales in CAISO and SPP are subject to ISO- and state-level regulation that effectively mitigates market power. [58] FERC observed that neither CAISO nor SPP review, approve, or monitor capacity sales, [59] and found that there is no transparent market price for capacity sales in either market-determined under Commission-approved rules comparable to the price established by RTOs/ISOs with centralized capacity markets. [60] FERC also clarified that:
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In the event of indicative screen failures, the CAISO or SPP Seller’s evidentiary burden is limited to demonstrating that it lacks market power in capacity markets, or to proposing a satisfactory mitigation plan that is specific to capacity sales. [61]
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A CAISO or SPP Seller may still rely on the rebuttable presumption that it lacks market power in energy and ancillary services markets as a result of FERC-approved monitoring and mitigation. [62]
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An RTO/ISO Seller that would normally study CAISO or SPP as a relevant market and that seeks to offer capacity at market-based rates in those markets must submit indicative screens to demonstrate that it will not have market power in capacity sales. [63]
D. EIM
Some parties proposed that indicative screens should not be required to obtain or retain market-based rate authority in the Western Energy Imbalance Market (“EIM”) because the EIM is part of CAISO’s real-time energy market and is subject to FERC-approved market monitoring and mitigation. [64] FERC rejected this proposal, finding that such market monitoring and mitigation is not sufficient to address market power concerns. [65]
E. Bilateral Sales
FERC rejected arguments that ISO/RTO monitoring and mitigation measures would not ensure just and reasonable rates for bilateral sales of electricity in ISO/RTO markets [66] and affirmed that FERC-approved RTO/ISO monitoring and mitigation would enable it to retain sufficient oversight of bilateral sales in RTO/ISO markets. [67] FERC acknowledged that centralized markets may be imperfect substitutes for long-term bilateral contracts, but found that prices set in centralized auctions provide a benchmark against which to compare prices in long-term bilateral contracts, and that buyers with access to centralized markets can always purchase from the short-term market if the Seller of a long-term contract tries to charge an excessive price. [68] FERC also pointed out that RTO/ISO Sellers engaged in bilateral sales remain subject to EQR reporting requirements. [69]
F. Current Status and Effectiveness of RTO/ISO Monitoring and Mitigation
FERC rejected requests to initiate a formal review of RTO/ISO monitoring and mitigation provisions, explaining that it has accepted these provisions as just and reasonable, and that removing the indicative screens would not affect an RTO/ISO’s application of market power monitoring and mitigation provisions its market. [70] FERC also noted that nothing in its final rule precludes an RTOs/ISO from filing to amend its existing market power mitigation provisions if improvement is needed. [71]
G. Other Issues
FERC also rejected requests to:
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eliminate requirement for change in status reporting; [72]
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reconsider the continued need for triennial market power updates; [73]
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remove the current stay of the requirement in 18 CFR 35.37(a)(2) that Sellers submit an organizational chart; [74]
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state that independent market monitors have the right to file FPA section 206 complaints; [75]
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establish corporate character reporting requirements for market-based rate applications; [76]
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defer action on the rulemaking until FERC acts on the related, pending Data Collection Notice of Proposed Rulemaking (Docket No. RM16-17-000) and Market Power Notice of Inquiry (RM16-21-000). [77]
H. Effective Date
The changes in Order No. 861 will become effective 60 days after the rule is published in the Federal Register.
[1] Data Collection for Analytics and Surveillance and Market-Based Rate Purposes, Order No. 860, 168 FERC ¶ 61,039, at P 15 (2019) (“Order No. 860”).
[2] Data Collection for Analytics and Surveillance and Market-Based Rate Purposes, Notice of Proposed Rulemaking, 156 FERC ¶ 61,045, at n.7 (2016) (“Data Collection NOPR”).
[3] Order No. 860 at P 15.
[4] Id. at P 16.
[5] Id.
[6] According to FERC, “An LEI is a unique 20-digit alpha-numeric code assigned to a single entity. They are issued by the Local Operating Units of the Global LEI System.”
[7] Id. at P 23.
[8] Id.
[9] Id. at P 24.
[10] Id. at P 39.
[11] Id.
[12] Id. at P 47.
[13] Id. at P 64.
[14] Id.
[15] Id. at P 67.
[16] Id.
[17] Id. at P 85.
[18] Id. at P 86.
[19] Id. at P 104.
[20] Id.
[21] Id. at 110.
[22] Id.
[23] Id.
[24] Id. at 121.
[25] Id.
[26] Id. at 124
[27] Id. at 127.
[28] Id. at 128
[29] Id.
[30] Id. at P 137.
[31] Id. at P 138.
[32] Id. at P 146.
[33] Id.
[34] Id. at P 150.
[35] Id. at P 151.
[36] Id.
[37] Id. at 171
[38] Id.
[39] Id. at 184.
[40] Id.
[41] Id. at 308.
[42] Id. at 209.
[43] Id. at 284.
[44] Id.
[45] Id. at 291.
[46] Id. at 293
[47] Id.
[48] Id. at 294.
[49] Id.
[50] Refinements to Horizontal Market Power Analysis for Sellers in Certain Regional Transmission Organization and Independent System operator Markets, Order No. 861, 168 FERC ¶ 61,040, at P 5 (2019) (“Order No. 861”) (citing Market-Based Rates for Wholesale Sales of Electric Energy, Capacity, and Ancillary Services by Public Utilities, Order No. 697, 119 FERC ¶ 61,295, PP 62, 399, 408, 440 (2006) (“Order No. 697”), clarified 121 FERC ¶ 61,260 (2007), on reh’g, Order No. 697-A, 123 FERC ¶ 61,055, clarified, 124 FERC ¶ 61,055 (“Order No. 697-A”) , on reh’g, Order No. 697-B, 125 FERC ¶ 61,326 (2008), on reh’g, Order No. 697-C, 127 FERC ¶ 61,284 (2009), on reh’g, Order No. 697-D, 130 FERC ¶ 61,206 (2010), aff’d sub nom. Pub. Citizen, Inc. v. FERC, 567 U.S. 934 (2012)).
[51] Id. at P 6 (citing Order No. 697 at P 62). Passing both screens establishes a rebuttable presumption that the Seller does not possess horizontal market power, while failing either screen creates a rebuttable presumption that the Seller has horizontal market power. Id. (citing Order No. 697 at PP 33, 62–63).
[52] Id. at PP 1–4.
[53] Id. at P 6.
[54] Id. at PP 10, 16.
[55] Id. at PP 19, 22. EQRs show the volumes and prices at which Sellers are transacting and can be used to determine a Seller’s market share of sales and relative prices. Id. at P 19.
[56] Id. at PP 25–27.
[57] Id. at PP 32, 46.
[58] Id. at PP 33–35, 47. While CAISO does not have a centralized capacity market, CAISO and the California Public Utilities Commission have established a Capacity Procurement Mechanism and a Reliability-Must-Run process to set a ceiling on resources’ bilateral capacity contract compensation. Id. at PP 35–36. In SPP, capacity costs are recovered in the rate bases of franchised public utilities and are therefore subject to state regulatory review. Id. at P 47.
[59] Id. at PP 39, 48.
[60] Id. at PP 39, 47.
[61] Id. at P 51.
[62] Id.
[63] Id. at P 52.
[64] Id. at P 53.
[65] Id. at P 56.
[66] Id. at PP 57–58.
[67] Id. at P 59.
[68] Id. (citing Order No. 697-A at P 285).
[69] Id. at P 62.
[70] Id. at P 65.
[71] Id. at P 66.
[72] Id. at P 71.
[73] Id.
[74] Id. at P 72.
[75] Id. at P 71.
[76] Id. at P 78.
[77] Id. at PP 79–80. FERC explained that any action taken in those proceedings will not impact the implementation of the removal of the screen requirement. Id. at PP 79–80. After noting its concurrent issuance of Order No. 860 in Docket No. RM16-17-000, FERC stated that it would continue to monitor RTO/ISO mitigation provisions on an ongoing basis and take necessary action, as appropriate. Id. at P 80.