September 19, 2020

Volume X, Number 263

September 18, 2020

Subscribe to Latest Legal News and Analysis

September 17, 2020

Subscribe to Latest Legal News and Analysis

September 16, 2020

Subscribe to Latest Legal News and Analysis

FERC Finalizes Reforms to PURPA Regulations

On July 16, 2020, the Federal Energy Regulatory Commission (“FERC” or “Commission”) issued Order No. 872, a final rule that the Commission explains is intended to implement its statutory mandate to update rules promulgated pursuant to the Public Utility Regulatory Policies Act of 1978 (“PURPA”).[1]  The rule will become effective in late November.[2]  The changes  generally restrict the ability of the owners of Qualifying Facilities (“QFs”) to access some of the more favorable commercial terms mandated by Commission policy previously in place for several decades.  As background, PURPA generally imposes a mandatory obligation on any “electric utility” to purchase the energy and capacity from an interconnected QF.  See 18 C.F.R. § 292.303(a).  QFs also enjoy relief from certain Federal Power Act and Public Utility Holding Company Act of 2005 requirements and from state regulation of utility rates and finances.  Order 872 also adopts a new version of FERC Form No. 556, the form related to the FERC QF certification process. 

On most major issues, the Final Rule generally tracks the NOPR that the Commission issued last fall. There are some noteworthy differences, however.  For example, in the NOPR, the Commission proposed to lower the rebuttable presumption of small QFs’ nondiscriminatory access to 1 MW or larger as opposed to the currently-effective 20 MW threshold.  The rebuttable presumption is applied when considering whether the interconnected utility should be relieved of its PURPA purchase obligation.  After receiving significant pushback on this point from commenters, the Commission raised the threshold in the final rule to 5 MW.  Further, in the NOPR, the Commission proposed a requirement that a QF actually obtain all necessary permits for construction prior to establishing a legally enforceable obligation (“LEO”); in Final Rule, however, the Commission loosened its proposed restriction by holding that a QF need only to have applied for all required permits prior to establishing a LEO.  Also, FERC did not adopt its proposal that utilities in states with retail competition could use the state’s retail competition regime as support for obtaining relief from the PURPA purchase obligation.  FERC emphasized, however, that its existing PURPA regulations already require that states, to the extent practicable, account for reduced loads in setting QF capacity rates.

A brief overview of each major change implemented by Order No. 872 follows.

Challenging QF Certifications

Interested parties may now protest and intervene in QF self-certification proceedings before the Commission.[3]  Whereas previously parties seeking to challenge a QF self-certification had to file a petition for declaratory order, and pay the associated filing fee, such parties may now file directly, with no filing fee, in the QF certification proceeding within 30 days of the QF’s filing of self-certification.  The Commission clarified that such protests will only be allowed for QF self-certifications filed after the effective date of Order 827.  Thus, potential challengers will have to wait until late November to take advantage of this new procedural right.  FERC also clarified that self-recertifications may similarly be protested but only if there has been a substantive change in facts, such as a change in electrical generating equipment that increases power production capacity by the greater of 1 MW or 5% of the previously certified capacity or a change in ownership of 10% or greater.                

During the pendency of a contested self-certification or self-recertification process, QF status is effective. The Commission will act in the proceeding within 90 days of a protest.  If the Commission requires additional information, the time period would be extended to 60 days from the date the requested information is filed with FERC.  The Commission also held that it could toll the 90 day period to provide itself with one extension of an additional 60 days.  If FERC does not act within that tolling period extension, the self-certification or recertification would remain effective.

FERC updated the form used to self-certify – FERC Form No. 556 – and will also provide an opportunity for QF owners to provide additional support for its self-certification to preemptively defend against anticipated arguments opposing the QF self-certification or self-recertification.

Rates

FERC’s current PURPA regulations provide QFs with two options for selling their output to a utility:  (1) a QF may sell as much of its energy as it chooses when it becomes available in accordance with the rate calculated at the time of delivery; (2) a QF may sell its output pursuant to contract over a specified term at either (a) a fixed rate based on the utility’s avoided cost at the LEO is incurred, or (b) the utility’s avoided cost calculated at the time of delivery.  State regulatory proceedings to determine avoided cost rates are typically heavily litigated. 

The Final Rule changed requirements for state avoided cost determinations, expressly recognizing that states may now choose to use variable as opposed to fixed energy rates for QF sales.  We note that this change only applies to energy sales and leaves capacity contracts untouched.[4]  Order 872 is clear that states may choose to implement variable energy rates for QF sales but are not required to do so.[5]  Those states wishing to continue to offer fixed energy rates may do so.  If a state adopts variable energy rates for QF sales, a QF may no longer have the opportunity to sell at fixed energy rates but would continue to be eligible for a fixed capacity rate for the term of the LEO (or contract).  Among other things, FERC emphasized that using transparent market prices to establish an as-available avoided cost rate provides cost savings by obviating the need for state cases to set avoided costs.  Also, this approach is more transparent, simpler and allows rates to automatically adjust up and down as avoided costs change.

In RTO/ISO markets, there is a rebuttable presumption that the locational marginal price (“LMP”) should reflect the “purchasing electric utility’s avoided as-available energy costs” whereas in non-RTO/ISO areas states will be able to set as-available avoided cost rates at a “competitive price.”  FERC recognized that some states have already set avoided costs at LMP.  FERC emphasized that payments based on LMP do not relieve the interconnected utility of the obligation to compensate the QF owner for values in addition to its output such as RECs.   

FERC further concluded that Western Energy Imbalance Market (“EIM”) prices could also be presumptively relied upon as a measure of as-available energy avoided costs for utilities able to participate in the Western EIM market. 

For states in non-RTO/ISO areas, a competitive price can be established in one of two ways: “(1) energy rates established at liquid market hubs; or (2) energy rates determined pursuant to formulas based on natural gas price indices and a proxy heat rate for an efficient natural gas combined-cycle generating facility.”[6]  As examples of liquid market hubs, FERC referenced the Mid-Columbia hub in the Pacific Northwest and Palo Verde hub in the Southwest.  If a state chose to rely on avoided cost rates for as-available energy established at liquid market hubs, the relevant electric utility purchaser requires reasonable access to the liquid market hub.  Accordingly, a state could adjust a market hub price for a utility to account for transmission costs it may incur.  For example, a state could consider the cost of delivery from the QF node to the load node and also specifically consider resulting redispatch costs if transmission constraints exist between those nodes.  FERC also found that states could rely on natural gas indices coupled with the heat rate of an efficient natural gas combined-cycle generating facility to measure avoided costs in non-RTO/ISO markets where natural gas is the marginal fuel. 

Additionally, FERC concluded that states could set avoided cost energy and capacity rates through a competitive solicitation process such as a Request for Proposal process that included both QF and non-QF resources.  FERC noted that a competitive solicitation process may result in a zero rate for capacity if no capacity is needed. 

FERC anticipates that providing states with the ability to implement variable avoided cost determinations will not create an obstacle to financing.  FERC pointed to non-QFs that have negotiated contractual arrangements for financing that rely on a variety of hedging and risk management tools.  In the QF context, FERC concluded that financial hedges could be a contractual approach for QF developers to guarantee a steady fixed-price revenue stream even when a QF’s PURPA contract included variable pricing.  Others took a different view in the comment process, noting that developers of solar facilities, for example, have less access to hedging due to their smaller size and the relatively high transaction costs.  In the discussion on variable avoided cost determinations, FERC also noted that QFs receive benefits outside of their PURPA contracts, including federal and state incentives designed to encourage the construction of renewable resources.  

Mandatory Purchase Obligations

The Final Rule established a rebuttable presumption that QFs located in competitive markets (i.e., in RTO/ISO areas) that have more than 5 MW of capacity have non-discriminatory access to competitive markets, thereby providing the interconnected utility with the opportunity to make a filing with FERC seeking to eliminate its obligation to purchase from such facilities.  This lowered threshold (from 20 MW) reflects a Commission determination, “in light of the maturation of organized electric markets,” that smaller power production facilities face far fewer market access barriers than they did 15-20 years ago when FERC implemented the former threshold of 20 MW.[7]  The lowered threshold applies to small power production facilities but does not include cogeneration facilities.[8]

Comments emphasized that smaller generation facilities are participating in RTO/ISO markets and RTOs/ISOs have adjusted their market rules to accommodate variable resources, referencing RTO/ISO implementation of adjusted bidding rules, forecasts and operations.  Comments submitted by the renewable industry, however, claimed that capacity markets in RTO/ISO regions, in particular, have not evolved to provide a real opportunity for any QF to sell capacity on a long-term basis. 

Notably, utilities that were previously granted termination of the mandatory purchase obligation for new contracts and obligations for QFs above 20 MW are now able to return to FERC to seek authorization for termination of mandatory purchase obligation for new contracts and obligations for small power production facilities between 5-20 MW using the existing FERC procedures.  FERC will consider such requests on a case-by-case basis.  FERC also mentioned that it would consider such requests for utilities outside of RTO/ISO markets based on other indicia of competitive markets such as the existence of liquid market hubs. 

One-Mile Rule

The Final Rule largely implemented its new one-mile rule as proposed.[9]  A small power production facility seeking QF status located within one mile of an affiliated QF that uses the same energy resource will be irrebuttably presumed to be at the same site as one another and the Commission’s 80 MW “cap” will apply to both small power production facilities on a combined basis.  Any such facilities located more than 10 miles apart from an affiliated QF will be irrebuttably presumed to be located at different sites.  For a small power production facility located between one and 10 miles of an affiliated QF, the new rules create a rebuttable presumption that the facility constitutes a separate site from the affiliated QF.  Essentially this changes the pre-existing irrebuttable presumption for facilities located more than one mile but less than 10 miles apart as being separate facilities to a rebuttable presumption.  However, the presumption that the facilities are at separate sites remains unchanged.  Facilities located 10 miles or more apart would continue to have an irrebuttable presumption that these facilities are separate.  There has been significant litigation before FERC where interconnected utilities have alleged that developers of small power production facilities developed single sites strategically with the one-mile rule in mind.  

Distance

Evaluation of Whether QFs are at Separate Sites

<1 mile

Irrebuttable presumption that facilities are at the same site

1 – 10 miles

Rebuttable presumption that facilities constitute separate sites

>10 miles

Irrebuttable presumption that facilities constitute separate sites

 

As background, a small power production facility must be 80 MW or less to qualify as a QF.  16 U.S.C. § 796(17)(A).  FERC’s one-mile rule provides that, for purposes of determining whether facilities seeking QF status are considered to be located “at the same site,” FERC will aggregate the capacity of generating facilities that: (1) are located within one mile of each other, (2) use the same energy resource, e.g., solar or wind, and (3) are owned by the same persons or their affiliates.  18 C.F.R. § 292.204(a).  Developers that intend to rely on a project’s QF status and the mandatory purchase provisions of PURPA to sell the output of a project have an incentive to configure each project as a “facility” that does not to exceed the 80 MW threshold.  Thus, some developers have sited generation projects slightly more than one mile apart to qualify as separate small power production facilities.    

Under FERC’s regulations, the distance between generating facilities for the one-mile rule is measured from the electrical generating equipment of each facility.  18 C.F.R. § 292.204(a)(2)(ii).  For an entity seeking to be irrebuttably presumed to be at a separate site from an affiliated small power production QF, all equipment of the affiliated small power production QF must be at least 10 miles away from the generation seeking QF status.  FERC explained that each wind turbine at a wind facility and each solar panel at a solar facility would constitute “electrical generating equipment” for this purpose.  So the one mile would be measured from the edge of the solar power or inverter closest to the edge of the nearest “electrical generating equipment” of an affiliate.  For wind facilities, the measurement will be from the edge turbine or inverter closest to the edge of the nearest “electric generating equipment” of an affiliated small power production QF. 

Some argued that in areas where the geographic footprint was expansive and rural, such as in some areas in the Pacific Northwest, the measurements should be different.  FERC responded that the focus was not on the utility’s service territory but on the question posed by the statute – whether or not a number of small power production QFs are located at the same site. 

FERC also identified specific factors it would consider in deciding whether small power production facilities that are under common control are located “at the same site” that should provide helpful guidance for developers and utilities.  Among other things, FERC identified  common infrastructure, property leases, interconnection agreements or off-take agreements, the facility owner using common debt or equity financing, or the facilities being constructed by the same entity within 12 months as possible indicia of facilities being “at the same site”. 

Commenters and the Commission itself realized that FERC’s new approach to applying the “one-mile rule” will result in additional up front work for some facilities seeking QF status.  FERC is allowing filings to provide additional information “up front” to preemptively defend against challenges.  FERC understood that small rooftop solar PV developers will be particularly challenged by the new requirements and is implementing a quarterly self-recertification process for rooftop solar PV developers in quarters that a developer accumulates changes greater than 1 MW.   As noted above, FERC is committing to resolve contested QF self-certifications and self-recertifications within a set period of time. 

Legally Enforceable Obligation

In Order 872, FERC emphasized that states may not impose requirements for a LEO other than a showing of commercial viability and financial commitment to construct the facility.  Order 872 intends to raise the bar to prevent speculative QFs from obtaining LEOs but also to ensure that states do not establish a barrier to financially committed developers seeking to develop commercially viable QFs.  FERC recognized that requiring developers to invest additional capital prior to obtaining a LEO could prevent smaller companies from developing facilities.  The Commission directed states to determine “objective” and “reasonable” criteria by which it may determine that a proposed QF project is commercially viable.[10]  This is in contrast to existing rules which allow states to set LEO criteria without meaningful Commission oversight.  The Commission noted some factors which states could use to determine commercial viability: taking meaningful steps to obtain site control and the proposed location and filing an interconnection request.  FERC emphasized that the criteria states adopted must be “factors that are within the control of the QF.”

The relevant section of FERC’s PURPA regulations is Section 292.304(d)(2)(ii) where FERC’s rules provide that a QF may choose to sell to the interconnected utility pursuant to a LEO (such as a contract) at the avoided costs of the utility calculated at the time the obligation is incurred.  FERC has explained that the term “legally enforceable obligation” contained in its regulations was “intended to prevent a utility from circumventing the requirement that provides capacity credit for an eligible facility merely by refusing to enter into a contract with a qualifying facility.”  Order No. 69, FERC Stats. & Regs. ¶ 30,128, at 30,880 (1980). 

FERC contrasted requiring a QF to have secured local permitting and zoning with a state requiring a developer to have applied for all necessary permits and zoning variances as a factor to demonstrate the QF’s commercial viability.  FERC also noted that demonstrating the required financial commitment does not require a demonstration of having obtained financing. 

States are left to determine what demonstrates commercial viability and financial commitment in the context of unique conditions or circumstances in each state but also recognizing that FERC precedent creates boundaries of what is reasonable and not discriminatory when establishing a LEO.  


[1] Qualifying Facility Rates and Requirements Implementation Issues Under the Public Utility Regulatory Policies Act of 1978, Order No. 872, 172 FERC ¶ 61,041 (2020) (“Order 872”).  The rule has not yet been published in the Federal Register.

[2] 120 days from publication in Federal Register, so the precise date is not yet known. 

[3] Id. at P 547.

[4] Id. at P 36.

[5] Id.

[6] Id. at P 106.

[7] Id. at PP 598-99.

[8] Id. at PP 64, 601 (“unlike small power production facilities, which are constructed solely to produce and sell electricity, cogeneration facilities seeking QF certification after February 2, 2006 are statutorily required to show that they are intended primarily to provide heat for an industrial, commercial, residential or institutional process rather than fundamentally for sale to an electric utility.”).

[9] Id. at P 466.

[10] Id. at P 684.

© 2020 Bracewell LLPNational Law Review, Volume X, Number 204

TRENDING LEGAL ANALYSIS


About this Author

Catherine McCarthy, Energy Regulation Attorney, Bracewell law firm
Partner

Catherine McCarthy has represented clients on energy regulation and policy matters for over two decades. She has experience with obtaining Federal Energy Regulatory Commission (FERC) and state authorizations for major projects and transactions; FERC compliance and enforcement matters; FERC transmission and centralized markets issues; and rate, tariff and refund matters. She also represents energy clients before the Department of Energy, the Federal Communications Commission and the Nuclear Regulatory Commission. Cathy joined the firm from Dewey & LeBoeuf where she...

202-828-5839
Stephen Hug, Environmental Attorney, Bracewell Law Firm
Associate

Stephen Hug represents clients in matters related to federal regulatory policies, regulations and rules applicable to the electric industry. His experience includes assisting clients with compliance with the rules and regulations of the Federal Energy Regulatory Commission (FERC) and the Federal Power Act (FPA).  Stephen also represents clients in litigated proceedings before FERC.

202-828-5866
Boris Shkuta Environmental Energy utilities Attorney Bracewell law Firm
Associate

Boris Shkuta’s practice focuses on electric power and transmission regulatory work and energy storage technologies. He also advises clients on matters related to lending, project finance, mergers and acquisitions, and infrastructure and development, primarily in the energy industry.

202.845.5164