United States: FERC Updates Market-Based Rate Program And Clarifies Gen-Tie Policy

Last Updated: October 27 2015
Article by Adam Wenner and A. Cory Lankford

At its October 2015 meeting, the Federal Energy Regulatory Commission ("FERC") issued Order No. 816, a final rule adopting proposals to update its market-based rate program.  In addition, FERC denied rehearing and granted clarification of its Order No. 807, a ruling that waived open access requirements for owners of "gen-tie" interconnection facilities and established a rebuttable presumption that for the first five years following commercial operation, the gen-tie owner and its affiliates will have priority rights to unused capacity on the gen-tie.  (See Orrick's client alert on Order No. 807, below.)

Both policy reforms have been addressed in prior Orrick client alerts available here and here.

Order No. 816

Under FERC's market-based rate policies, FERC-regulated generation owners and power marketers that sell wholesale energy, capacity, or ancillary services must obtain authorization from FERC to sell at "market-based rates," which are rates, terms and conditions established by mutual agreement, as opposed to rates based on the seller's cost-of-service or other traditional ratemaking policies.  FERC grants requests for market-based rate authority to sellers that demonstrate that they and their affiliates lack or have adequately mitigated horizontal and vertical market power in the relevant geographic market.  A seller that obtains market-based rate authority is subject to ongoing compliance obligations to demonstrate that it continues to lack or has adequately mitigated market power in its relevant market.

FERC uses two indicative screens to assess an applicant's horizontal market power: the "pivotal supplier analysis" and the "wholesale market share analysis."  Under each screen, FERC considers all of the generation owned or controlled by an applicant and its affiliates in the relevant market as compared to the supply of generation within that market.  FERC uses a seller's balancing authority area ("BAA") or the relevant regional transmission organization or independent system operator market, as applicable, as the default geographic market.  FERC also reviews a seller's "vertical" market power, which is based on its control of "inputs" to power generation, including fuel supplies and transportation and electric transmission. 

In Order No. 816, FERC revised its policies for obtaining and maintaining market-based rate authority.  The reforms and clarifications adopted by FERC include the following:

  • FERC clarified that a seller is not required to submit indicative market power screens if it demonstrates that the generation it and its affiliates control within the relevant geographic market is fully-committed.  FERC further clarified that in order to qualify as "fully-committed," none of the capacity can be available to the seller or its affiliates for one year or longer.  As defined by FERC, the relevant market includes the seller's BAA and adjacent BAAs ("first-tier" markets).
  • FERC required market-based rate sellers to report long-term firm purchases of power in their indicative market power screens and in their asset appendices, regardless of whether the seller has operational control of the generation capacity supplying the purchased power.
  • In recent years, FERC has advised market-based rate sellers to include "behind-the-meter" generation in their indicative market screens and asset appendices – although FERC permitted sellers to aggregate behind-the-meter capacity by BAA.  In Order No. 816, FERC ruled that market-based rate sellers are not required to report behind-the-meter generation either in their indicative market power screens or in their asset appendices.  
  • Similarly, FERC determined that market-based rate sellers are no longer required to include qualifying small power production facilities ("QFs") with a capacity of 20 MW or smaller in their market screens or asset appendices, because such facilities are exempt from Section 205 of the Federal Power Act, including FERC's market-based rate rules thereunder.  FERC required that any affiliated QF with market-based rate authority must be included in the seller's indicative market power screens and asset appendices.
  • FERC historically has permitted sellers submitting indicative screens and asset appendices to use either nameplate or seasonal ratings in reporting their and their affiliates' generating capacities.  FERC also has permitted sellers with "energy-limited" generation facilities – generation whose production is constrained by available wind, water or other resources – to use generation capacity ratings based on a five-year production average.  However, FERC has required sellers to use nameplate ratings for solar projects.  In its notice of proposed rulemaking, FERC considered requiring sellers to identify solar technologies as energy-limited generation resources and allowing sellers of solar resources to use either nameplate or five-year historical average capacity ratings.  In response to comments, FERC allowed sellers to report solar thermal generation using either nameplate or a five-year historical average capacity rating, but required sellers to use nameplate capacity for solar photovoltaic units.  (Solar developers may seek rehearing of this holding, since the "net" capacity of their projects is often lower than the nameplate rating, due to power losses incurred in converting power from direct current, as it is produced, to alternating current.)
  • FERC adopted its proposal to require market-based rate sellers to submit appendices to market-based rate filings that set forth the indicative market power screens and list sellers' energy affiliates in an electronic spreadsheet format that can be searched, sorted, and otherwise accessed using electronic tools (i.e., in Excel).  FERC will post to its website a pre-programmed website that sellers can use as a template.  FERC explained that the revised submission requirements will aid sellers in developing their appendices and minimize the need for follow-up inquiries from FERC staff.
  • FERC has previously required market-based rate sellers to submit quarterly reports of acquisitions of sites for potential generation development.  However, for purposes of evaluating the potential market power of a seller, FERC established a rebuttable presumption that ownership or control of, or affiliation with entities that own or control, sites for generation development does not create barriers to entry into the relevant electric market.  In Order No. 816, FERC adopted its proposal to eliminate the land acquisition reporting requirements.  However, FERC will retain the right to request additional information at any time if it has reason to believe that a seller's acquisition of land has created a barrier to entry or otherwise been used to exercise vertical market power.
  • FERC has previously required market-based rate sellers to file a notice of change in status demonstrating that they continue to satisfy the requirements for market-based rate authority if the sellers become affiliated with any new entity or with 100 MW or more of generating capacity in any relevant market.  In Order No. 816, FERC established a 100 MW threshold for reporting affiliations with new entities that own or control generation within the seller's relevant market.  For example, a seller is not required to report a new affiliation with an entity that owns a 45 MW generating facility within the seller's relevant market unless and until the seller becomes affiliated with an additional 55 MW of generation in that market.  Consistent with the requirement described above, market-based rate sellers must include long-term firm purchases of capacity and/or energy in calculating their newly affiliated capacity for purposes of determining whether they meet the 100 MW threshold for the requirement to file a notice of change in status.

The final rule will become effective 90 days after publication in the Federal Register, which means that the rule will take effect in the first quarter of 2016.  A copy of Order No. 816 can be found here.

Order No. 807-A

In Order No. 807, FERC revised its regulations to establish a presumption that developers of power projects and related transmission assets ("gen-ties") necessary to interconnect projects with a local utility's distribution or transmission system (collectively referred to as interconnection customer interconnection facilities or "ICIF") are entitled to priority rights over the unused capacity of the ICIF for a period of five years from their commercial operation date. FERC also adopted procedures to grant automatic waivers of FERC's open access requirements to ICIF owners. The National Rural Electric Cooperative Association ("NRECA") and the American Public Power Association and the Transmission Access Policy Study Group ("APPA and TAPS") subsequently requested FERC to revise its ruling, as described below.

NRECA requested FERC to establish an exception to the presumption that the ICIF owner is entitled to priority rights for five years on unused ICIF capacity if the entity seeking to use the ICIF is a traditional utility, or "load serving entity," that needs access on the ICIF to "serve native load efficiently."  FERC rejected NRECA's request, pointing out that the presumption granting priority to the ICIF owner is rebuttable, and noted that even during the five-year priority period, an ICIF owner is required to expand the gen-tie facility to accommodate an additional user if the potential user is willing to "carry the burden associated with that expansion."

In their request for rehearing, APPA and TAPS asserted that by waiving open access transmission tariff ("OATT") requirements for ICIF owners, Order No. 807 unreasonably departs from FERC's and the Federal Power Act's open access transmission policies.  APPA and TAPS further stated that the reforms adopted by FERC in Order No. 807 (1) promote inefficient use and development of the transmission grid that is increasingly being expanded to accommodate renewable resources, (2) allow ICIF owners to monopolize the transmission grid, and (3) are inconsistent with Order No. 1000's objectives of efficient and cost-effective grid expansion.  In denying the APPA and TAPS requests, FERC reiterated its conclusion that Order No. 807 appropriately balanced the need for open access on gen-tie facilities with the concern that, absent the grant of priority for future use, "there would be little incentive for a developer to shoulder the extra expense of ICIF sized larger than the initial phase of the project."  FERC also found that many requirements set forth in FERC's OATT, such as provisions relating to network service, ancillary services and planning requirements, do not apply to the transmission services provided over an interconnection customer's gen-tie facilities.

Finally, FERC granted a requested clarification that "non-public utility ICIF owners" – namely cooperative utilities with funding from the Rural Utilities Service, municipal utilities, and federal entities not regulated by FERC under the Federal Power Act – that provide open access transmission under Order No. 888 "reciprocity" provisions are entitled to the OATT waiver and five-year priority safe harbor period.

A copy of Order No. 807-A can be found here.

The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.

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