A. Horizontal Market Power Analysis Reforms
1. Elimination of Requirement to File Indicative Screens for Sellers with “Fully Committed” Generation Capacity
FERC declined to adopt the Notice of Proposed Rulemaking (NOPR) proposal to relieve sellers in Regional Transmission Organization (RTO) or Independent System Operator (ISO) markets of the obligation to submit indicative horizontal market power screens. However, FERC did eliminate the requirement for sellers to file indicative horizontal market power screens where all generation owned or controlled by the seller and its affiliates in the relevant market(s), including first-tier markets, is “fully committed” as defined in the Final Rule. Such sellers may instead explain that their capacity is fully committed to satisfy FERC’s requirements for MBR authority.
2. Definition of Relevant Geographic Market(s) for Certain Sellers in Generation-Only Balancing Authority Areas
FERC adopted the NOPR proposal to define the default relevant geographic market for certain independent power producers (IPPs) located in a generation-only Balancing Authority Area (BAA) as the BAAs of each transmission provider to which the IPP’s generation-only BAA is directly interconnected, rather than using only the generation-only BAA where the IPP’s generation is located. Thus, if an IPP’s generation-only BAA is directly interconnected to several other BAAs, the IPP will be required to study all of its uncommitted generation capacity from the generation-only BAA in each directly interconnected BAA. FERC will also require an IPP in a generation-only BAA that is directly interconnected to a transmission provider at a trading hub to provide indicative screens that study the IPP in the BAA of each transmission provider directly interconnected to that trading hub and to assume that all of the IPP’s uncommitted capacity may compete in each of those BAAs.
3. New Rows and Revised Format Requirement for Indicative Screens
FERC adopted the NOPR proposal to include new rows in the indicative horizontal market power screens for Simultaneous Transmission Import Limit (SIL) Values, Long-Term Firm Purchases (from outside the study area) and Remote Capacity (from outside the study area). FERC also modified the descriptive text of the rows in the screens to increase clarity and consistency. In addition, FERC will require sellers to file the indicative screens in a “workable electronic spreadsheet” format that includes intact formulas. Static PDF files without working formulas will no longer be acceptable.
4. Clarification Regarding Simplifying Assumptions Regarding Imports
FERC explained that it has allowed sellers to make simplifying assumptions in their horizontal market power analyses, such as “performing the indicative screens assuming no import capacity.” In the Final Rule, FERC clarified that “assuming no import capacity” means that a seller may assume that there is no competing import capacity from relevant first-tier markets. Therefore, a seller must still include in its indicative screens any uncommitted capacity that it or its affiliates can import into the study area.
5. Capacity Ratings in Asset Appendices and Indicative Screens
Sellers submitting asset appendices or indicative screens are generally allowed to rate their generation facilities using either nameplate or seasonal capacity ratings. However, for sellers with “energy-limited generation resources,” such as hydroelectric or wind generation, FERC has allowed the use of a five-year average capacity factor. In the Final Rule, FERC adopted the NOPR proposal to include solar photovoltaic and solar thermal technologies as energy-limited generation resources. In asset appendices and market power screens, sellers will be required to use nameplate ratings for solar photovoltaic facilities, but may use a five-year average capacity factor for solar thermal facilities. Sellers will be required to specify which rating methodology they are using for each technology and to use those rating methodologies consistently. Where a seller chooses to use a capacity factor for an eligible technology, it will be required to use a unit-specific, historical, five-year average for any unit for which it can obtain five or more years of operating history. For other units, the seller may use regional capacity factors derived by the U.S. Energy Information Administration.
6. Reporting Long-Term Firm Purchases
FERC’s current policy is that a seller’s uncommitted capacity should be calculated by (1) adding the nameplate or seasonal capacity of generation owned or controlled through contract and long-term firm capacity purchases; and (2) subtracting operating reserves, native load commitments and long-term firm sales. Therefore, sellers have generally reported long-term firm purchases only if the purchase granted them control over the relevant capacity. In the Final Rule, FERC adopted the NOPR proposal to require sellers to report all of their long-term firm purchases of capacity or energy in their indicative screens and asset appendices, regardless of whether the seller has control over the generation capacity supplying the purchased power.
7. Clarifications Regarding Preparation of SIL Studies
FERC provided detailed guidance regarding preparing SIL studies for use in horizontal market power analyses. Of particular note, FERC clarified that, where there is a conflict between the transmission provider’s tariff or Open Access Same-Time Information System (OASIS) practices and FERC’s instructions for performing SIL studies in its Puget Sound Energy order,2 sellers—except as set forth in the Final Rule—should follow OASIS practices and provide documentation specifically identifying such practices. To the extent that a seller’s SIL study departs from actual OASIS practices, such departures are permitted only where use of actual OASIS practices is incompatible with an analysis of import capability from an aggregated first-tier area.
B. Elimination of Land Acquisition/Site Control Reporting Requirements
In the Final Rule, FERC eliminated the existing requirements that MBR sellers provide information regarding sites for generation capacity development to demonstrate a lack of vertical market power and then report, on a quarterly basis, acquisition of control of a site or sites for new generation capacity development for which site control has been demonstrated. FERC stated that it retains the right to request additional information on potential barriers to entry from a seller at any time and will continue to require MBR sellers to affirmatively state that they and their affiliates have not, and will not, raise barriers to entry in relevant markets, including land acquisitions, in initial applications, triennial market power analyses and notices of changes in status that affect the vertical market power analysis. (See also infra Part H.2.)
C. Reforms to Notice of Change in Status Reporting Requirements
1. Threshold of 100 MW Not Limited to a Single Geographic Market
FERC requires MBR sellers to report any change in status that would reflect a departure from the characteristics upon which FERC relied in granting MBR authority. The change in status reporting requirement is triggered by, among other things, ownership or control of generation capacity that results in net increases of 100 MW or more. In the Final Rule, FERC clarified that the 100 MW increase threshold will apply to a seller’s and/or its affiliates’ net generation capacity additions in each individual relevant market (i.e., each market in which a seller or its affiliates already has generation and acquires an additional 100 MW or new market that the seller has not studied previously), but will exclude markets and BAAs that are first-tier to the seller’s study area. In other words, a seller will not have to consider its or its affiliates’ new generation—including generation from long-term purchase agreements—in first-tier markets in determining whether it has triggered the 100 MW notice of change in status threshold.
2. Long-Term Contracts Count Toward the 100 MW Threshold
In addition to FERC’s new requirement that sellers report all long-term firm purchases of capacity or energy in their indicative screens and asset appendices regardless of whether the seller has control over the generation capacity (see supra Part A.6), sellers also will be required to include long-term firm purchases of capacity or energy when calculating whether their net increases have crossed the 100 MW change in status threshold. Previously, the calculation was limited to whether “[o]wnership or control of generation capacity” resulted in a reportable increase.
3. Threshold of 100 MW Will Apply to New Affiliations
FERC also will apply a 100 MW threshold for reporting new affiliations. Thus, an MBR seller need not file a notice of change in status for a new affiliation resulting in a net increase of less than 100 MW. FERC’s current regulations require a notice change in status for any new affiliation with an entity not disclosed in the seller’s market-based rate application that owns or controls generation facilities or inputs to electric power production, regardless of how small the amount of generation owned or controlled by the new affiliate might be. The 100 MW threshold for affiliations will be calculated in the same way as for other notices of changes in status.
4. Exclusion of Behind-the-Meter Generation and Certain Qualifying Facilities from Asset Appendices, Market Power Screens, and Change in Status and Seller Category Thresholds
FERC declined to adopt the NOPR proposal to count behind-the-meter generation in the 100 MW change in status threshold and 500 MW per region Category 1 Seller status threshold, (see infra Part E) and to require sellers to include such generation in their asset appendices and market power screens. In addition, FERC clarified that Qualifying Facilities (QFs) that are exempt from Section 205 of the Federal Power Act will not need to be reported in sellers’ asset appendices or market power screens. However, QFs with MBR authority must be included in market power screens and asset appendices and will count toward the 100 MW change in status threshold.
D. Asset Appendix Reforms
1. Changes to Existing Column Headings; Prohibition of Footnotes
FERC requires sellers to attach an asset appendix to each MBR application, market power analysis or change in status that lists all of the seller’s affiliates that have MBR authority and identifies assets owned or controlled by the seller and its affiliates. In the Final Rule, FERC revised certain asset appendix column headings to improve clarity and consistency across filings. Sellers will be required to populate every column for all facilities in the asset appendix, even facilities that are not otherwise addressed in a particular filing. FERC also adopted the NOPR proposal to prohibit using footnotes in asset appendices, but added a separate column to the form of asset appendix for explanatory notes and clarifications.
2. Clarifications Regarding Existing Columns
FERC also clarified various asset appendix requirements, including:
- A seller will be required to list a generator’s entire capacity, even if the seller owns only part of the generator; to the extent that a seller is attributing to itself less than the full capacity of the generator, the seller can explain that in the new explanatory notes column.
- A seller will be required to list one of the following specified uses for assets in its electric transmission and intrastate natural gas asset list: (1) transmission, (2) intrastate natural gas storage, (3) intrastate natural gas transportation or (4) intrastate natural gas distribution.
- Sellers should not include assets for which they have claimed and demonstrated to FERC that their only relationship to such facilities is through passive, noncontrolling interests consistent with those FERC addressed in AES Creative Resources.3
3. Changes Regarding Open Access Transmission Tariff Order Citations in Transmission Asset Lists
FERC has stated that, even if a seller has been granted a waiver of the requirement to file an OATT for transmission facilities that otherwise would require an Open Access Transmission Tariff (OATT), those transmission facilities still should be reported in the seller’s asset appendix. In the Final Rule, FERC added a new column to the transmission asset table in the form of asset appendix that will require sellers to provide a citation to the FERC order accepting the seller’s OATT or, if the seller has transferred operational control of its facilities to an RTO or ISO, the FERC order authorizing the transfer. Sellers need not provide a citation to an order granting the seller waiver of the OATT requirements, which FERC explained would not provide useful information in light of FERC’s recent change to its regulations regarding blanket waiver of FERC’s open access and Standards of Conduct requirements for entities subject to such requirements solely because they own, control or operate interconnection customer’s interconnection facilities.4
4. Workable Electronic Spreadsheet Format Requirement
FERC currently accepts asset appendices in several formats, including static PDF. In the Final Rule, FERC adopted the NOPR proposal to require sellers to submit their asset appendices in a “workable electronic spreadsheet” format with intact, working formulas and that can be searched, sorted and accessed using electronic tools.
5. Searchable Public Database of Asset Appendix Information
In the NOPR, FERC sought comment on whether it would be beneficial to develop a comprehensive, searchable, public database of the information contained in sellers’ asset appendices that sellers could update in lieu of filing revised asset appendices. In the Final Rule, FERC declined to direct the creation of such a database, but recognized its potential and indicated that it may reconsider the creation of such a database in the future.
E. Category 1 and Category 2 Sellers
In the Final Rule, FERC revised its regulations to reflect the distinction between power marketers and power producers that FERC has applied in practice when designating MBR sellers as either Category 1 (exempt from the requirement to submit triennial updated market power analyses) or Category 2. FERC clarified that, for purposes of determining a seller’s category status for each region, a power marketer should include all affiliated generation capacity in that region, whereas a power producer only needs to include affiliated generation located in the same region as the power producer’s generation assets. In explaining this change, FERC noted that a power marketer with no “home market” is likely to make sales in any region, whereas a power producer is likely to make most of its sales in the region(s) where it owns generation assets.
FERC also clarified that, for any region where a power marketer’s affiliates are Category 2 Sellers, the power marketer itself will be considered a Category 2 Seller. A power producer, however, even in a region where it has affiliates that are Category 2 Sellers, may qualify as a Category 1 Seller in any region in which the power producer itself owns generation and the power producer and its affiliates own or control, in aggregate, 500 MW of generation capacity or less, as long as the power producer meets FERC’s other Category 1 Seller requirements.
F. Corporate Family Issues
1. New Requirement to Provide an Organizational Chart
FERC previously did not require MBR applicants to submit organizational charts. In the Final Rule, FERC adopted the NOPR proposal to require sellers to provide an organizational chart, including all of the seller’s “affiliates,” as defined in Section 35.36(a)(9) of FERC’s regulations, in MBR applications, updated market power analyses and notices of changes in status reporting new affiliations. To minimize burdens on filers and to simplify the required organizational charts, FERC clarified that, if an entity is owned by multiple individual investors, those investors may be grouped in the organizational chart as long as they are identified elsewhere in the filing. FERC cautioned sellers to examine all upstream ownership information to ensure that all affiliates are captured in the chart, and to not assume that certain upstream owners are not “affiliates” of the seller without “looking further up the ownership chain.” FERC also stated, as it previously clarified in Tonopah Solar Energy, LLC,5 that sellers should not use a “derivative share” or fractional interest multiplication methodology to calculate ownership interests in downstream partially owned entities for purposes of identifying affiliates. FERC will not require an organizational chart where a change in status does not affect a seller’s affiliations.
2. Joint Tariff for Affiliated MBR Sellers in a Corporate Family
FERC’s current policy allows for the use of a single, joint MBR tariff to cover multiple MBR sellers who are affiliated within a corporate family. In the Final Rule, FERC reiterated that, when a corporate family has more than one affiliated seller, it may use a joint master tariff, and FERC provided guidance regarding the instructions for entities that wish to use this approach.
G. Part 101 and Part 141 Waivers
FERC’s current practice is to grant certain MBR entities a waiver of its Uniform System of Accounts requirements, specifically Parts 41, 101 and 141 of FERC’s regulations, except Sections 141.14 and 141.15, which address certain reporting requirements applicable to hydropower licensees. In the NOPR, FERC clarified that any waiver of Part 101 granted to an MBR entity is limited such that the waiver of the provisions of Part 101 that apply to hydropower licensees is not granted with respect to licensed hydropower projects. In the Final Rule, FERC reaffirmed this clarification. FERC also directed MBR sellers that own licensed hydropower projects to ensure that their MBR tariffs reflect appropriate limitations on any previously granted waivers. These MBR tariff compliance filings should be made the next time the hydropower licensee files a change to its MBR tariff, a notice of change in status or an updated market power analysis. FERC also clarified that, going forward, any MBR seller requesting waivers of Part 101 and/or Part 141 should include these limitations in its MBR tariff, regardless of whether it owns any licensed hydropower projects. If an MBR seller becomes a hydropower licensee after receiving MBR authority and full waivers without the referenced hydropower licensee limitations, the seller must file tariff revisions to reflect the limitations in its Parts 101 and 141 waivers within 30 days of the effective date of its license.
H. Other Miscellaneous Reforms
1. Regional Reporting Schedule for Triennial Updated Market Power Analyses
Category 2 Sellers currently are required to submit an updated market power analysis “every three years, according to the schedule contained in Appendix D to Order No. 697.” In the Final Rule, FERC adopted the NOPR proposal to refer instead to an updated reporting schedule posted on FERC’s website. The updated reporting schedule and regions map are available here.
2. Affirmative Statements Regarding Not Erecting Barriers to Entry
FERC currently requires sellers, as part of their vertical market power analysis, to affirmatively state that they have not erected barriers to entry into the relevant market(s) and will not erect barriers to entry into the relevant markets(s). Noting that many sellers have not mentioned their affiliates when making this affirmative statement, FERC, in the Final Rule, clarified that the affirmative statement requirement applies to sellers and their affiliates.
1 Refinements to Policies & Procedures for Mkt.-Based Rates for Wholesale Sales of Elec. Energy, Capacity & Ancillary Servs. by Pub. Utils., Order No. 816, 153 FERC ¶ 61,065 (2015) (Final Rule). See also Refinements to Policies & Procedures for Mkt.-Based Rates for Wholesale Sales of Elec. Energy, Capacity & Ancillary Servs. by Pub. Utils., Notice of Proposed Rulemaking, 147 FERC ¶ 61,232 (2014) (NOPR).
2 135 FERC ¶ 61,254, Appendix B (2011).
3 129 FERC ¶ 61,239 (2009).
4 Open Access & Priority Rights on Interconnection Customer’s Interconnection Facilities, Order No. 807, FERC Stats. & Regs. ¶ 31,367 (amending FERC’s regulations to waive FERC’s open access requirements, under certain conditions, for entities that own interconnection facilities), order on reh’g and clarification, 153 FERC ¶ 61,047 (2015).
5 151 FERC ¶ 61,203 (2015).