Throughout June 2020, a number of legislative proposals poised to impact hydropower resources have been introduced in Congress.  On Monday, June 22, Democratic members of the House of Representatives released H.R. 2, the Moving Forward Act, which aims to encourage investment in infrastructure and includes several provisions on hydropower and dam safety.  On Monday June 29, Congresswoman Cathy McMorris Rodgers (WA-05) introduced the Hydropower Clean Energy Future Act which includes updates to the licensing process for non-federal hydroelectric projects and promotes innovation of new generation technologies that would protect the environment and natural resources while providing additional reliability services to the nation’s electric grid.  Finally, on June 30, Democratic members of the House Select Committee on the Climate Crisis released a Climate Crisis Action Plan, which includes provisions on hydropower and marine energy facilities. Continue Reading Federal Hydropower Legislative Proposals Introduced on Capitol Hill

On Thursday, July 9, 2020 the Supreme Court, in a 5-4 decision, held that a large swath of northeastern Oklahoma, including most of the city of Tulsa, remains part of the Muscogee (Creek) Reservation and, as a result, that the state lacks jurisdiction to prosecute a major crime involving a tribal member within the reservation. Justice Gorsuch delivered the opinion for the Majority, confirming the durable principle of tribal sovereignty, despite significant efforts throughout history to dismantle tribal reservations and governments.  Chief Justice Roberts filed a dissenting opinion, in which Justices Alito and Kavanaugh joined, and in which Justice Thomas joined, except as to one footnote.  Some analyses have raised the possibility that this decision could have a significant impact on taxation and natural resources management in Indian Country throughout the United States, as discussed more fully below.  However, because the direct holding of the Court is quite narrow, the full impact of this decision remains to be seen.  Continue Reading Supreme Court Determines that Area in Northeastern Oklahoma Constitutes a Reservation

Executive Summary of FERC Order No. 872: Qualifying Facility Rates and Requirements Implementation Issues Under the Public Utility Regulatory Policies Act of 1978 [1]

I. Overview

On July 16, 2020, the Federal Energy Regulatory Commission (FERC or the Commission) issued Order No. 872, the Commission’s final order revising its regulations implementing Sections 201 and 210 of the Public Utility Regulatory Policies Act of 1978 (PURPA) [2]. This order, which follows a 2016 technical conference on PURPA issues and a September 2019 Notice of Proposed Rulemaking (NOPR) [3], is the first major set of revisions to FERC’s regulations implementing PURPA since they were established through Order No. 69 in 1980.

As FERC explained in the NOPR, the energy landscape has evolved in significant ways since the initial PURPA regulations were established, which includes increased supplies of natural gas, a more matured renewables industry, and the growing presence of non-Qualifying Facility (QF) independent power producers. These and other changes prompted FERC to revise its PURPA regulations, many of which are implemented by the states. These new changes provide additional guidance to state commissions regarding PURPA implementation and rests additional authority in state commissions regarding QF rates and contract terms. These regulatory changes fall into five categories, as outlined below:

  1. Rates:
    • In the case of QF power sales contracts and other Legally Enforceable Obligations (LEOs), in addition to continuing to allow states to establish fixed QF rates, FERC granted states the flexibility to set variable rates for QF energy (but not capacity).
    • In the case of QF power sales contracts and LEOs utilizing fixed rates, FERC granted states additional flexibility to establish such fixed rates using projected energy prices during the term of a QF’s contract.
    • In the case of QFs selling on an “as-available” basis within an organized wholesale market, FERC established a rebuttable presumption, rather than a per se rule (as proposed in the NOPR), that locational marginal prices (LMPs) may reflect a purchasing electric utility’s avoided energy costs. Outside of an organized wholesale market, FERC granted states flexibility to set “as available” energy rates at competitive prices from liquid market hubs or calculated from a formula based on natural gas price indices and heat rates.
    • Allows states to utilize transparent and non-discriminatory competitive solicitations to set “avoided costs” for QF energy and capacity sales.
  2. One-Mile Rule:
    • Amends the “one-mile” rule to add a new rebuttable presumption that affiliated facilities more than one mile apart but less than 10 miles apart are separate facilities.
    • Maintains the irrebuttable presumption that facilities located one mile apart or less constitute a single facility and creates an irrebuttable presumption that facilities 10 miles apart or more are separate facilities.
  3. Obligation to Purchase:
    • Reduces the size threshold from 20 MW to 5 MW for the rebuttable presumption that QFs have nondiscriminatory access to markets.
    • However, FERC confirmed that utilities that were previously granted termination of the mandatory purchase obligation for contracts above 20 MW must reapply with FERC requesting relief from the mandatory purchase obligation for small power production facilities between 5 MW and 20 MW.
  4. Legally Enforceable Obligation:
    • Allows states to establish objective and reasonable criteria to determine a QF’s commercial viability and financial commitment to construction before a QF may establish a LEO.
  5. QF Self-Certification:
    • Allows parties to protest QF certifications without filing a petition for declaratory order.
    • Clarifies that protests may be made to new certifications, but only to recertifications that make substantive changes to the existing certification.

FERC declined to adopt the proposed rule permitting states with retail competition to allow relief from the PURPA purchase obligation. Instead, FERC clarified that the Commission’s existing PURPA Regulations already require that states, to the extent practicable, must account for reduced loads in setting QF capacity rates.

FERC also rejected arguments from various parties that an environmental analysis under the National Environmental Policy Act of 1969 (NEPA) was required.

In a partial dissent, Commissioner Glick rejected much of the Commission’s Order No. 872 as an “administrative gutting” of its long-standing PURPA implementation regime, chastising the Commission for failing to pursue a more “durable, consensus solution” rooted in promoting competition. In particular, Commissioner Glick argued that the reduction to the rebuttable 20 MW purchase-obligation threshold in Order No. 872 and changes to its avoided cost rate determination violated PURPA’s mandate to prevent discriminatory rate treatment and encourage QF development.

Order No. 872 will go into effect 120 days from its publication in the Federal Register.

II. Summary of Revisions

A. QF Rates

A core aspect to PURPA is the obligation on utilities to purchase QF power at a rate that does not exceed such utility’s “incremental cost…of alternative electric energy,” i.e., the rate that, but for the QF purchase, the utility would otherwise incur by purchasing from another source. This rate, referred to as the “avoided cost” rate, must be both non-discriminatory for the QFs, while also being just and reasonable to the consumers of the electric utility and in the public interest [4]. FERC’s PURPA regulations provide QFs with two options for selling their power at avoided cost rates: (1) selling as much energy as the QF chooses whenever it becomes available (referred to as an “as-available” sale), and (2) selling its output pursuant to an LEO (such as a contract), over a specified term, with the “avoided cost” rate calculated either at the time of delivery, or calculated and fixed at the time the LEO is incurred [5].

Order No. 872 is notable, therefore, in so far as it fundamentally reforms how states are allowed to set “avoided costs” rates for QFs—both in the “as-available” and LEO contexts. In particular, and as summarized below, FERC revised its PURPA regulations to permit states to incorporate competitive market forces in setting QF rates.

1. Granting States the Flexibility to Require Variable Energy (but not Capacity) QF Rates in QF Power Sales Contracts and Other LEOs

Under long-standing PURPA regulations, if a QF chooses to sell energy and/or capacity pursuant to a contract, the QF would be provided the option of receiving the purchasing electric utility’s avoided cost that was calculated and fixed at the time an LEO is incurred [6]. In the NOPR, FERC proposed to revise its regulations to allow states the flexibility to require QF energy rates to vary during the term of a QF contract [7]. Avoided capacity costs calculated at the time the contract or LEO is incurred would still remain fixed, however. As FERC explained in the NOPR, record evidence at the time suggested that fixed QF energy rates more often led to QFs receiving greater than avoided-cost rates [8].

The proposal drew criticism and support from a variety of parties, with proponents generally arguing that fixed rates, coupled with the overall decline in energy prices, led to improper customer subsidization of QFs, while opponents argued that Congress and court precedent supported long-term fixed energy rates as being necessary to encourage QF development [9].

In Order No. 872, FERC adopted the NOPR proposal without modification. As FERC explained, the primary impetus for the change was “to better comply with Congress’s clear instruction in PURPA that the Commission may not require QF rates in excess of a purchasing utility’s avoided costs.” [10] In support, FERC argued first, that the record evidence demonstrates that long-term fixed avoided cost energy rates are often well above avoided-costs without balancing out over time [11]. Second, although FERC acknowledged the obligation in PURPA for commission regulations to encourage QF development, this obligation, FERC argued, “is bounded” by the general prohibition that QF rates may not exceed avoided costs [12]. Third, FERC generally rejected claims that allowing variable QF energy prices would lead to discrimination against QFs [13], and argued that, even if PURPA guaranteed QF financeability, variable avoided cost energy rates would still allow QFs to obtain financing [14].

In adopting the NOPR proposal, FERC also rejected requests to allow for variable avoided capacity costs, reasoning that the cost for avoided capacity is determined at the time of the capacity purchase obligation, which is different from variable energy prices determined at the time of delivery. FERC also declined requests to specify a minimum required contract length and to adopt additional criteria for establishing avoided capacity costs, leaving such decisions up to existing state processes [15].

FERC cautioned, however, that states may not “toggle” back and forth between requiring fixed and variable QF energy rates. Rather, “QFs are entitled to the certainty that once a state has made its choice with respect to a particular QF’s contract or LEO, that QF’s contract or LEO is not subject to change during the term of that contract or LEO except by mutual consent.” [16]

2. Granting Additional Flexibility to Establish Fixed QF Energy Contract Rates Based on Forecasts

In addition to allowing variable energy rates in QF contracts, for QF contracts utilizing fixed energy rates, FERC proposed to permit a QF to request a fixed energy rate for the entire term of the contract based on a forward price curve—i.e., forecasted energy prices at the times of delivery over the life of the contract. This proposal generally received widespread support.

FERC adopted the proposed reform in Order No. 872 [17]. FERC clarified that a state may use competitive market prices and/or variable energy rates in the context of a more fixed estimated avoided cost energy rate (together with a fixed avoided capacity rate) that is determined at the time an LEO or contract is incurred. This fixed energy rate component, FERC explained, could be a single rate, based on the amortized present value of forecast energy prices, or it could be a series of specified rates that change from year-to-year (or other periods) in future years. According to FERC, states may establish the applicable energy rate(s) for the QF for the entire term, or the rate may change from year-to-year (or some other period) of the contract at the time the LEO is incurred [18].

3. Granting States Inside and Outside RTOs/ISOs Additional Flexibility in Setting “As Available” QF Energy Rates

In the NOPR, FERC also proposed various reforms related to “as available” QF sales—both inside and outside organized wholesale markets operated by Regional Transmission Operators (RTOs) and Independent System Operators (ISOs).

For QFs selling their energy on an as-available basis in an RTO/ISO, FERC proposed in the NOPR, and adopted in Order No. 872, to permit states to set such as-available QF energy rates at the Locational Marginal Price (LMP) calculated at the time of delivery [19]. In contrast to the NOPR, however, FERC declined to adopt a rule that LMP was a “per se” appropriate measure of avoided costs, but instead that there was a presumption of appropriateness, that could be rebutted by an aggrieved party (such as a QF).

For QFs selling their energy on an as-available basis outside of an RTO/ISO, FERC proposed, and adopted in Order No. 872, to allow states to set such as-available QF energy rates at delivery-based competitive prices from liquid market hubs [20], or, in the absence of such a hub, calculated from a formula based on natural gas price indices and heat rates [21]. In either case, FERC noted that states must first find that the chosen option adequately represents the purchasing utility’s avoided cost for as-available energy [22].

In the case of liquid market hubs, FERC also confirmed that (1) states with access to more than one such market may average or develop a formula to derive an as-available avoided energy cost; (2) states must determine that a liquid market hub is sufficiently liquid that its prices are competitive; and (3) the market hub price may need to be subject to adjustments to account for transmission costs the electric utility would incur [23]. In the case of formula-based natural gas price indices, FERC confirmed the formula should include recovery of variable O&M costs [24]. FERC also rejected calls to consider other, non-combined cycle natural gas, technologies, reasoning that states already have that flexibility—and nothing in the rule foreclosed that option—and that focusing on combined cycle technology was appropriate for the proposal, given that such generation makes up a large portion of the country’s generation fleet [25].

4. Granting States Flexibility to Set Energy and Capacity Rates based on Competitive Solicitations

In the NOPR, the Commission also proposed to permit states to set avoided energy and/or capacity rates using competitive solicitations (i.e., RFPs). In Order No. 872, FERC adopted this proposal, with several modifications and clarifications. First, FERC expanded on the NOPR minimum criteria for what constitutes a transparent and non-discriminatory solicitation. Without passing judgment on previously-conducted solicitations, FERC concluded that, going forward, a PURPA-compliant solicitation must be conducted in a process that includes, but is not limited to, the following factors: (i) the solicitation process is an open and transparent process that includes, but is not limited to, providing equally to all potential bidders “substantial and meaningful” information regarding transmission constraints, levels of congestion, and interconnections, subject to appropriate confidentiality safeguards; (ii) solicitations must be open to all sources, to satisfy that purchasing electric utility’s capacity needs, “taking into account the required operating characteristics of the needed capacity”;(iii) solicitations are conducted at “regular intervals”; (iv) solicitations are subject to oversight by an “independent administrator”; and (v) solicitations are “certified” as fulfilling the above criteria by the relevant state regulatory authority or nonregulated electric utility through a post-solicitation report [26].

Second, FERC clarified that competitive solicitations must also be conducted in accordance with the principles in Allegheny Energy Supply Co., LLC, 108 FERC ¶ 61,082, at P 18 (2004) [27]. FERC then made certain other clarifications from the NOPR, including:

    • Participants must be given “substantial and meaningful information regarding transmission constraints, levels of congestion, and interconnections, subject to appropriate confidentiality safeguards.” [28]
    • Utilities must provide state commissions, and make publicly available, a post-solicitation report that summarizes the solicitation results and demonstrates non-preference for the utility and its affiliates [29].
    • The phrase “taking into account the operating characteristics of the needed capacity” necessarily allows utilities to procure the type of capacity that they need, but it should not be used to effectively exclude QF generation [30].
    • FERC declined to be overly prescriptive about what constitutes “regular intervals” or an “independent administrator,” but did clarify that “certification” required a written, formally-issued finding by the relevant state commission that the solicitation was PURPA-compliant [31].

B. The One-Mile Rule

Under FERC’s current PURPA regulations, there is an irrebuttable presumption that facilities owned by the same person(s) that use the same energy resource, but are more than one mile apart from each other, are located on separate sites and are therefore separate facilities [32]. This is often referred to as FERC’s “one-mile rule”.

In the NOPR, FERC proposed to change the one-mile rule by creating a new rebuttable presumption that facilities more than one mile apart and less than 10 miles apart are separate facilities [33]. This new presumption would allow any interested party to intervene and file a protest to argue that two facilities (which would be more than one mile apart and less than 10 miles apart) should be treated as a single facility.

Commenting parties were divided as to whether QF developers are currently circumventing the current one-mile rule by strategically siting small power production facilities that use the same energy resource more than one mile apart. FERC noted that some parties had expressed that concern while others argued there was no evidence of any such “gaming” of the current one-mile rule [34]. Commenters also questioned the potential impact the one-mile rule revisions could have on other Federal Power Act (FPA) and Public Utility Holding Act (PUHCA) exemptions [35].

Order No. 872 adopts the NOPR proposal to change the one-mile rule. Thus, if a small power production facility seeking QF status is located more than one mile but less than 10 miles from any affiliated small power production QFs that use the same energy resource, it will be presumed to be at a separate site [36]. Any such QFs located one mile or less will be irrebuttably presumed to be at the same site, and any such QFs located 10 miles or more will be irrebuttably presumed to be at separate sites [37]. While the rebuttable presumption can be protested by any interested person or entity, FERC also noted that it could act sua sponte [38].

FERC confirmed the one-mile rule would not remove or amend other exemptions that a QF is entitled to, but that the one-mile rule would be used to determine whether affiliated facilities were at the same site and if a QF did not meet the 80 MW size limit “for whatever reason” (including a failure to meet the revised one-mile rule) then it would not be a QF [39].

FERC also explained that a small power production facility seeking QF status may provide additional information in its certification (or recertification) to preemptively defend against a challenge by identifying certain physical and ownership factors that affirmatively show its facility is at a separate site from affiliated small power production QFs that use the same energy resource that are more than one but less than 10 miles from its facility [40]. Finally, FERC defined “electrical generating equipment” and confirmed that any such equipment must be measured from the edge of the equipment closest to the affiliated small production QF’s nearest electrical generating equipment [41].

C. Relief from Purchase Obligation in Competitive Retail Markets—Not Adopted

In the NOPR, FERC proposed to amend Section 292.303(a) of the PURPA regulations, which generally requires utilities to purchase “any energy and capacity which is made available from a qualifying facility,” [42] to provide that a utility’s obligation to purchase power from QFs may be reduced to the extent the purchasing electric utility’s supply obligation has been reduced by a state retail choice program. In Order No. 872, FERC declined to adopt its NOPR proposal, but instead clarified that its existing PURPA regulations already require that states, to extent practicable, account for reduced loads in setting QF rates [43].

FERC received comments both in support and in opposition to its proposal. Commenters in opposition argued, among other things, that FERC lacked statutory authority to implement its proposal, and that FERC’s rationale for the rule was unclear [44]. Other commenters requested additional clarification from FERC, including on states’ authority to exempt traditional or alternative retail suppliers from PURPA’s mandatory purchase obligation [45].

In declining to adopt its proposed amendments to Section 292.303(a), FERC explained that Section 292.304(e)(3) already does, and will continue to allow states, when setting avoided cost rates, to take into account “the ability of the electric utility to avoid costs, including the deferral of capacity additions.” [46] FERC stated that it regards this existing regulation as allowing a state to consider reductions in a purchasing electric utility’s provider of last resort obligations under state law [47]. FERC further clarified that it did not intend for this to be reflected as a MW-for-MW reduction (or increase) based on yearly changes in load, and that Section 292.304(e)(3) “does not and may not serve to terminate a purchasing utility’s mandatory purchase obligation under PURPA section 210(a).” [48]

D. Self-Certification Process

Under the current PURPA regulations, QFs file a FERC Form 556 to certify that they meet the requirements for QF status [49]. If a QF makes any material modification to its facility, it cannot rely upon its certification and must re-certify with the updated information [50]. FERC does not verify any of the information provided, and has declined to make any changes to the self-certify process in past orders to provide any such verification.

In the NOPR, FERC proposed to change section 292.207(a) of its PURPA regulations to allow interested persons to protest QF self-certifications and recertifications without having to file a petition for a declaratory order or paying any associated fees [51]. FERC also proposed to change its Form 556 to allow QFs to proactively provide information that would be considered in any challenge pertaining to the changes to the one-mile rule regulations. These changes include providing all affiliated facilities within 10 miles rather than affiliated QFs within one mile, as required before.

Several commenters raised the issue of grandfathering existing QFs for their future recertifications arguing, among other things, that the application of the new rule to existing QFs would effectively bar the transfer or sale of existing assets that were lawfully qualified under the one-mile rule but would not pass the 80 MW aggregate threshold under the new rule [52]. Other implementation questions were posed focusing on the administrative burden and litigation risk imposed by the new rule.

Order No. 872 largely adopted the NOPR proposal but did provide for limited grandfathering. When the rules become effective, protests may be made to new certifications (both self-certifications and applications for FERC certification) but only to recertifications that make substantive changes to the existing certification [53]. FERC agreed that recertifications that were needed for non-substantive changes should not subject existing QFs to potentially losing their QF status [54]. FERC also adopted its proposal to expand the affiliated facility information collected on Form No. 556 from one to 10 miles [55]. FERC explained that this information was necessary to implement the new rules. As mentioned above, applicants with affiliated small power production QFs greater than one mile and less than 10 miles from the entity seeking QF status may, if they choose, explain why the QFs should be considered to be at separate sites by providing the relevant physical and ownership factors.

Any protest filed under the new rules must be made 30 days from the filing of a QF’s Form No. 556, and the party filing any such protest bears the burden to demonstrate that the facility does not satisfy the requirements for QF status [56]. If this prima facie burden is met, then the burden shifts to the applicant submitting the QF self-certification or recertification to demonstrate that the certification is warranted [57]. FERC will issue an order within 90 days of the filing of a protest and if FERC declines to take action on the protest it will be deemed denied and the certification will remain effective [58].

E. Obligation to Purchase

PURPA is perhaps most known for its mandatory purchase obligation, but FERC’s PURPA regulations permit an electric utility to file an application requesting relief from the mandatory purchase obligation if FERC determines that the QF has nondiscriminatory access to certain markets to sell its power. This provision was added by the Energy Policy Act of 2005, and was intended to reflect the fact that organized electric markets provide alternative markets for sales by QFs. The current PURPA regulations include a rebuttable presumption that QFs with a net power production capacity at or below 20 MW lack nondiscriminatory access to any such markets [59].

In the NOPR, FERC proposed to reduce the size threshold at which the presumption of nondiscriminatory access to a market attaches from 20 MW to 1 MW for small power production facilities (but not cogeneration facilities) [60]. FERC reasoned that in light of the maturation of organized markets, such a reduction was consistent with Congress’s intent to relieve electric utilities of their obligation to purchase when a QF has nondiscriminatory access to competitive markets [61]. FERC proposed to exclude cogeneration facilities from the revisions because the owners of cogeneration facilities might not be as familiar with energy markets and the technical requirements for such sales.

FERC noted numerous comments addressing the proposal. Parties opposed to the reduction argued, among other things, that there was a lack of evidentiary support or sufficient explanation for FERC’s change in policy and a substantial increase in administrative burdens [62]. Comments supporting the revisions pointed to the widespread participation in RTO/ISO markets that has taken place since 2005 [63]. The National Association of Regulatory Utility Commissioners (NARUC) suggested that FERC allow utilities to rely upon RFPs and liquid market hubs to establish eligibility to terminate the mandatory purchase obligation, while other comments suggested that utility-sponsored RFP programs were not robust enough to simulate a competitive market [64].

Recognizing some of the challenges that QFs near 1 MW have in participating in markets, FERC modified its proposal and changed the size threshold to 5 MW instead of 1 MW [65]. Thus, the rebuttable presumption that QFs with a net capacity at or below 20 MW do not have nondiscriminatory access to those markets is reduced to 5 MW for small power production facilities (but remains unchanged for cogeneration facilities). FERC stated it would consider on a case-by-case basis whether a properly run RFP or competitive acquisition process could also justify the termination of the mandatory purchase obligation [66].

FERC also confirmed that utilities that were previously granted termination of the mandatory purchase obligation for contracts above 20 MW must reapply with FERC requesting relief from the mandatory purchase obligation for small power production facilities between 5 MW and 20 MW [67]. FERC noted that QFs over 5 MW and under 20 MW can still attempt to rebut the presumption, and make their case that they do not truly have nondiscriminatory access to a market and therefore should still be entitled to a mandatory purchase obligation [68].

F. Legally Enforceable Obligation

The current PURPA regulations specifically provide that QFs can choose to have their rates based on the avoided cost calculated at the time of delivery, or at the time an LEO is incurred. The regulations do not provide any details, however, about when or how an LEO is established, which has been a frequent area of litigation.

The NOPR proposed to amend Section 292.304(d)(3) of the PURPA regulations to require that QFs demonstrate that a proposed project is commercially viable, and that the QF has a financial commitment to construct the proposed project pursuant to objective, reasonable, state-determined criteria to be eligible for an LEO [69]. FERC intended the revisions to ensure that no electric utility obligation was triggered for a QF project that was not sufficiently advanced in its development and for which it would be unreasonable for a utility to include in its resource planning while at the same time ensuring that the purchasing utility does not unilaterally and unreasonably decide when its obligation arises [70].

Among the arguments opposing the LEO changes, some commenters stated that developers cannot obtain financing without the financial commitment of a power purchase agreement (PPA) or LEO from the utility and that the new requirement would lead to a substantial reduction in the number of QFs. Others argued that the new requirement would not narrow the range of divergent LEO tests currently adopted by states. Commenters supporting the proposal thought the revisions appropriately balanced the interests of utilities and developers and provided states more clarity about the LEO while still preserving their ability to develop criteria specific to local planning needs. Numerous commenters also requested additional modifications to the LEO proposal [71].

Order No. 872 adopted the NOPR proposal requiring states to establish objective and reasonable criteria to determine a QF’s commercial viability and financial commitment to construction before a QF can establish a LEO [72]. FERC confirmed states have flexibility as to what constituted an acceptable showing of commercial viability and financial commitment but noted that the factors must be within the control of the QF [73]. Thus, states could reasonably require QFs to take meaningful steps to obtain site control or file an interconnection application with the appropriate entity but could not require QFs to obtain site control or obtain a PPA [74].

FERC described the LEO revisions as “raising the bar to prevent speculative QFs from obtaining LEOs” without “establishing a barrier for financially committed developers seeking to develop commercially viable QFs.” [75] FERC disagreed with those arguing that the revisions would cause a substantial reduction of QFs, stating that objective criteria will protect QFs against onerous requirements that hinder financing [76]. FERC also confirmed that the LEO changes do not affect the viability of any executed contact or LEO in place as of the effective date of the final rule [77].

G. Environmental Analysis

In the NOPR, FERC explained that it was not possible to determine environmental effects related to the proposed revisions to the PURPA regulations given numerous uncertainties and therefore environmental review under the National Environmental Policy Act of 1969 (NEPA) was not needed [78]. Several commenters argued that FERC erred in failing to conduct such a review, pointing out, for example, that FERC undertook a NEPA analysis when it first implemented PURPA [79].

In Order No. 872, FERC found that no Environmental Assessment (EA) or Environmental Impact Statement (EIS) to evaluate the final rule was required, as the final rule does not propose, authorize, or define the scope and limits of any potential energy infrastructure, and in the alternative, FERC found that this rule was categorically excluded due to the fact that the revisions to PURPA were clarifying, corrective, and procedural in nature and do not substantially change the effect of a regulation being amended [80].

III. Commissioner Glick Partial Dissent

In a lengthy partial dissent, Commissioner Glick explained that, despite supporting certain aspects of Order No. 872, such as the revision allowing stakeholders to protest a QF’s self-certification, he believed that the Order as a whole is “not just poor public policy, but also arbitrary and capricious agency action.” [81] Specifically, he argued that Order No. 872 fails to encourage the development of QF facilities and prevent discrimination against QFs, as statutorily mandated under PURPA. In support of his conclusion, Commissioner Glick pointed to a number of specific aspects of the Order that he viewed as problematic.

    • Avoided Cost Rate: With respect to the Order’s elimination of the fixed energy rate, or contract option, Commissioner Glick highlighted his belief in the “essential role” fixed-price contracts play both in the financing of QF facilities and in helping to ensure QFs are guaranteed full cost recovery on par with the cost recovery guarantees afforded to vertically integrated utilities. As a result, he dismissed as “hogwash” the Commission’s arguments that its removal of the fixed energy rate option will encourage QF development and continue to satisfy PURPA’s prohibition on discriminatory rates. Second, Commissioner Glick disagreed with the Order’s rebuttable presumption for setting the avoided cost rate at the LMP as discriminatory, noting his concern that short-term prices may not reflect the long-term marginal energy costs avoided by purchasing utilities [82].
    • 20 MW Threshold: Commissioner Glick asserted that Order No. 872 reduces the threshold for the rebuttable presumption that QFs operating in RTO/ISOs have non-discriminatory access to competitive markets from 20 MW to 5 MW without explanation as to how the barriers arrayed against small QFs in organized markets have dissipated. As a result, he concluded that the Commission’s policy reversal is “toothless” and “arbitrary and capricious.” [83]
    • NEPA Review: Commissioner Glick also challenged the Commission’s characterization of revisions set forth in Order No. 872 as “mere corrective changes” that would qualify them for categorical exemption from environmental review under NEPA [84].

Finally, on a more macro level, Commissioner Glick expressed dismay over the Commission’s election to, in his words, “administratively gut” its implementation of PURPA, instead of modernizing its PURPA regulations by promoting market competition. In particular, Commissioner Glick pointed to a proposal released by the National Association of Regulatory Utility Commissioners—which urged the Commission to establish criteria for vertically- integrated utilities outside of RTOs/ISOs to terminate its must-purchase obligation based on competitive solicitations—as a more “durable, consensus solution” than the Order [85].

The effective date of Order No. 872 will be 120 days from the date of the Federal Register publication.




[2] Qualifying Facility Rates and Requirements Implementation Issues Under the Public Utility Regulatory Policies Act of 1978, 172 FERC ¶ 61,041 (2020) (Order No. 872).

[3] Qualifying Facility Rates and Requirements Implementation Issues Under the Public Utility Regulatory Policies Act of 1978, Notice of Proposed Rulemaking, 168 FERC ¶ 61,184 (2019) (NOPR).

[4] Order No. 872 at P 96.

[5] Id. at P 97.

[6] Id. at P 232. An LEO gives a QF the enforceable right to require utilities to purchase the QF’s power at avoided cost rates.

[7] Id. at P 234 (explaining NOPR proposal).

[8] Id. at P 235.

[9] Id. at PP 245-252.

[10] Id. at P 256.

[11] Id. at PP 283-293.

[12] Id. at PP 295-296

[13] Id. at P 302.

[14] Id. at PP 335-336.

[15] Id. at PP 357-360.

[16] Id. at P 353

[17] Id. at P 227

[18] Id. at P 227.

[19] Id. at P 151

[20] Id. at P 189.

[21] Id. at P 211.

[22] Id. at P 190 (setting out factors for states to consider in making a determination regarding whether a liquid market hub represents the purchasing utility’s avoided cost for as-available energy); id. at P 212.

[23] Id. at P 201.

[24] Id. at P 211

[25] Id. at P 214.

[26] Id. at P 427.

[27] Id. at P 430.

[28] Id. at P 431.

[29] Id. at P 432.

[30] Id. at P 433.

[31] Id. at P 436.

[32] Id. at P 458.

[33] Id. at P 460.

[34] Id. at P 470.

[35] Id. at P 512.

[36] Id. at P 466. FERC modified the NOPR proposal slightly to shift from focusing on identifying “separate facilities” to identifying whether facilities are at “the same site” to better match its statutory language. Seeid. at P 476.

[37] Id. at P 466.

[38] Id. at P 460.

[39] Id. at P 514.

[40] Id. at P 480. See also id. at P 509 (listing the specific physical and ownership factors adopted by FERC).

[41] Id. at PP 521-23. FERC defines “electrical generating equipment” to include all boilers, heat recovery steam generators, prime movers, electrical generators, photovoltaic solar panels and/or inverters, fuel cell equipment and/or other primary power generation equipment, but excluding equipment used for gathering energy to be used in the facility.

[42] 18 C.F.R. § 292.303(a).

[43] Order No. 872 at P 457.

[44] Id. at PP 444-48.

[45] Id. at PP 449-55.

[46] Id. at PP 456-57.

[47] Id.

[48] Id.

[49] Id. at P 525.

[50] Id. at P 552.

[51] Id. at P 525.

[52] Id. at P 531.

[53] Id. at P 547.

[54] Id. at P 550. FERC also determined that its recertification requirement would be unduly burdensome for rooftop solar PV developers, and is therefore requiring any such developers to recertify quarterly. Id. at P 559.

[55] Id. at P 591. FERC modified its proposal slightly by including the expanded information in item 8a rather than adding another line item as 8b.

[56] Id. at P 526.

[57] Id. at P 557.

[58] Id. at P 566.

[59] Id. at PP 118-121.

[60] Id. at P 597.

[61] Id. at P 598.

[62] Id. at PP 602-13.

[63] Id. at PP 614-23.

[64] Id. at P 648.

[65] Id. at P 625.

[66] Id. at P 662.

[67] Id. at P 645.

[68] Id. at PP 636, 641 (listing factors to rebut the presumption to access to market).

[69] Id. at P 663.

[70] Id at P 664.

[71] Id. at PP 676-83.

[72] Id. at P 684.

[73] Id. at PP 684-85.

[74] Id. at P 685.

[75] Id. at P 688.

[76] Id. at P 689 (citing FERC orders pertaining to state LEO standards).

[77] Id. at P 694.

[78] Id. at P 702.

[79] Id. at PP 704-09.

[80] Id. at 710-42.

[81] Partial Dissent, P 7.

[82] Id. at PP 9-16.

[83] Id. at PP 20-24.

[84] Id. at PP 25-26.

[85] Id. at P 29.

On July 8, 2020, the U.S. Department of Energy (“DOE”) issued a request for information (“RFI”) seeking public input on the energy industry’s current risk mitigation practices with regard to the bulk-power system supply chain. The DOE issued the RFI pursuant to Executive Order No. 13920 (“Executive Order”), wherein the Secretary of Energy was directed, among other things, to investigate the bulk power system for equipment presenting a risk from foreign adversaries (see May 5, 2020 edition of the WER). In the RFI, DOE asks stakeholders to identify potential vulnerabilities in the bulk-power system supply chain that could have national security implications and the estimated economic costs of implementing the Executive Order. Continue Reading DOE Requests Information on Bulk Power System Vulnerabilities Pursuant to Executive Order

On July 10, 2020, the United States Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”) issued an opinion resolving jurisdictional challenges under the Federal Power Act (“FPA”) of FERC’s electric storage resource (“ESR”) participation rule, holding that the challenges “fail to show that Order Nos. 841 and 841-A run afoul of the [FPA’s] jurisdictional bifurcation or that they are otherwise arbitrary and capricious” because they do not include a state opt-out provision. Continue Reading D.C. Circuit Upholds FERC Storage Rule’s Lack of a State Opt-Out

On July 6, 2020, FERC moved for a ninety-day stay of the United States Court of Appeals for the District of Columbia Circuit’s (“D.C. Circuit’s”) mandate in Allegheny Defense Project v. FERC. That decision upset FERC’s long-used practice of granting itself more time to consider requests for rehearing of its orders by issuing tolling orders (see July 1, 2020 issue of the WER). Although the decision was issued in the context of a pipeline proceeding under the Natural Gas Act (“NGA”), FERC’s motion noted that the impact of the D.C. Circuit’s decision extends to all requests for rehearing under the NGA, and presumably to those under the Federal Power Act as well. In support of its motion, FERC explained that over the past fifty years, tolling orders have been a critical tool to help manage its large case load and bring its expertise to bear on complex technical matters before they are presented to the courts of appeals. FERC stated that a stay of the court’s mandate would afford it time to consider how to revise its processes and allocate its resources in the absence of tolling orders. FERC also argued that a stay would give it and the Solicitor General additional time to consider whether to petition the Supreme Court for a writ of certiorari, though it noted that the ultimate decision of whether to petition the Supreme Court lies with the Solicitor General and the Department of Justice. Continue Reading FERC Moves to Stay DC Circuit’s Tolling Order Decision

On July 7, 2020, the PJM Interconnection, L.L.C. (“PJM”) Planning Committee held an informational session on its State Agreement Approach, a transmission planning process that allows one or more states to request the studying and funding of new transmission projects within the PJM footprint to address identified public policy needs. The State Agreement Approach could help accommodate the anticipated growth in offshore wind generation by allowing states to submit transmission expansion or extension projects in the Regional Transmission Expansion Plan (“RTEP”) so long as the states agree to assume responsibility for project costs. Continue Reading PJM Planning Committee Holds Stakeholder Meeting About Process for States to Fund New Transmission Projects

On June 18, 2020, FERC denied rehearing, but granted partial clarification, of a 2019 order addressing certain market power mitigation reforms proposed by the California Independent System Operator Corporation (“CAISO”). In particular, FERC again rejected CAISO’s “Net Export Limit” proposal to enhance local market power mitigation in the western energy imbalance market (“EIM”). As FERC reiterated in its order, the Net Export Limit proposal could allow EIM resource owners to limit dispatch during periods of market power mitigation, resulting in unjust and unreasonable market outcomes. Continue Reading FERC Denies CAISO’s Rehearing Request, and Grants Limited Clarification, Regarding CAISO’s EIM Net Export Limit Proposal

On July 1, 2020, FERC’s new rules for physical filings became effective.  The rules require that all physical filings and submissions delivered to FERC other than those sent via the U.S. Postal Service (“USPS”), be sent to an off-site security screening facility (see September 17, 2019 edition of the WER). Continue Reading FERC’s New Rules for Physical Filings Become Effective

On June 30, 2020, the United States Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”), sitting en banc, upset FERC’s long-used practice of granting itself more time to consider requests for rehearing of its orders by issuing “tolling orders.” FERC’s prior use of tolling orders prevented parties from seeking judicial review of a Commission order, but did not stay the effect of that order. The crux of the court’s decision is that the Natural Gas Act (“NGA”) gives FERC four express options to address a request for rehearing, all of which must be taken within thirty days, but deciding only to grant itself more time is not one of those options. The decision marks a sea change in FERC procedure, and raises a host of questions for pending and future proceedings under both the NGA and its companion statute, the Federal Power Act (“FPA”).

On July 2, 2020, FERC Chairman Neil Chatterjee and Commissioner Richard Glick issued a joint statement requesting that Congress pass legislation “providing FERC with a reasonable amount of additional time to act on rehearing requests involving orders under both the Natural Gas Act and the Federal Power Act.”  The statement goes on to say that “any such legislation should make clear that, while rehearing requests are pending, the Commission should be prohibited from issuing a notice to proceed with construction and no entity should be able to begin eminent domain proceedings involving the projects addressed in the orders subject to those rehearing requests.”

Continue Reading In Significant Order on FERC Procedure, <em>En Banc</em> D.C. Circuit Rejects FERC’s Use of Tolling Orders under the Natural Gas Act, Raising Significant Implementation Questions for All Pending and Future Proceedings