Commissioner Richard Glick Statement
November 19, 2020
Docket No. RM19-15-001
Order: Order No 872-A
Item No: E-2

I dissent in part from today’s order on rehearing (Rehearing Order[1]) because it upholds the overwhelming majority of Order No. 872,[2] which effectively gutted the Commission’s implementation of the Public Utility Regulatory Policies Act (PURPA).[3]  The Commission’s basic responsibilities under PURPA are three-fold:  (1) to encourage the development of qualifying facilities (QFs); (2) to prevent discrimination against QFs by incumbent utilities; and (3) to ensure that the resulting rates paid by electricity customers remain just and reasonable, in the public interest, and do not exceed the incremental costs to the utility of alternative energy.[4]  I do not believe that Order No. 872 satisfies those responsibilities.   

Although I have concerns about many of the individual changes imposed by the Order No. 872,[5] I remain, on a broader level, dismayed that the Commission is attempting to accomplish via administrative fiat what Congress has repeatedly declined to do via legislation.  I am especially disappointed because Congress expressly provided the Commission with a different avenue for “modernizing” our administration of PURPA.  The Energy Policy Act of 2005 gave the Commission the authority to excuse utilities from their obligations under PURPA where QFs have non-discriminatory access to competitive wholesale markets.[6]  Had we pursued reforms based on those provisions, rather than gutting our longstanding regulations, I believe we could have reached a durable, consensus solution that would ultimately have done more for all interested parties.

PURPA’s Continuing Relevance Is an Issue for Congress to Decide

This proceeding began with a bang.  The Commission championed its NOPR as a “truly significant” action that would fundamentally overhaul the Commission’s implementation of PURPA.[7]  And so it was.  The NOPR suggested altering almost every significant aspect of the Commission’s PURPA regulations, thereby transforming the foundation on which the Commission had carried out its statutory responsibility to “encourage” the development of QFs for over four decades.  Although Order No. 872 walked back some of the NOPR’s most extreme proposals, it adopted the overwhelming majority of the NOPR, including all of its tenets.  In so doing, the Commission upended the regulatory regime that has formed the basis of its implementation of PURPA almost since the day the statute was enacted.

I partially dissented from both the NOPR and Order No. 872 in large part because I believe that it is not the Commission’s role to sit in judgment of a duly enacted statute and determine whether it has outlived its usefulness.  As I explained, “almost from the moment PURPA was passed, Congress began to hear many of the arguments being used today to justify scaling the law back.”[8]  Congress, however, has seen fit to significantly amend PURPA only once in its more-than-forty-year lifespan.  As part of the Energy Policy Act of 2005, Congress amended PURPA, leaving in place the law’s basic framework, while adding a series of provisions that allowed the Commission to excuse utilities from its requirements in regions of the country with sufficiently competitive wholesale energy markets.[9]  And while Congress considered numerous proposals to further reform the law, it never saw fit to act on them.[10]  Against that background, I could not support my colleagues’ willingness to “remove[] an important debate from the halls of Congress and isolate[] it within the Commission.”[11]  Whatever your position on PURPA—and I recognize views vary widely—“what should concern all of us is that resolving these sorts of questions by regulatory edict rather than congressional legislation is neither a durable nor desirable approach for developing energy policy.”[12] 

Order No. 872 and today’s order on rehearing retreat from much of the original rationale used to support the NOPR, but the effect is the same:  The Commission is administratively gutting PURPA.  Make no mistake, although the Commission has dropped much of the NOPR preamble’s opening screed against PURPA’s continuing relevance, Order No. 872 is a full-throated endorsement of the conclusion that PURPA has outlived its usefulness.  And while walking back the argument that PURPA is antiquated may reduce the risk that Order No. 872 is overturned on appeal, that does not change the fact that the rule usurps what should be Congress’s proper role.

Throughout this proceeding, the Commission has been quick to point to Congress’s directive to from time to time amend our regulations implementing PURPA.[13]  Order No. 872, however, is a wholesale overhaul of the Commission’s PURPA regulations that reflects a deep skepticism of the need for the law we are charged with implementing.  I continue to doubt that is what Congress had in mind when it gave us responsibility for periodically updating our implementing regulations.

The Commission’s Proposed Reforms Are Inconsistent with Our Statutory Mandate

PURPA directs the Commission to adopt such regulations as are “necessary to encourage” QFs,[14] including by establishing rates for sales by QFs that are just and reasonable and by ensuring that such rates “shall not discriminate” against QFs.[15]  The changes adopted by the Commission in Order No. 872 fail to meet that standard.  In addition, many of the reforms are unsupported—and, in many cases, contradicted—by the evidence in the record.[16]  Accordingly, I believe Order No. 872 is not just poor public policy, but also arbitrary and capricious agency action. 

Avoided Cost

The Final Rule adopted two fundamental changes to how QF rates are determined.  First, and most importantly, it eliminated the requirement that a utility must afford a QF the option to enter a contract at a rate for energy that is either fixed for the duration of the contract or determined at the outset—e.g., based on a forward curve reflecting estimated prices over the term of the contract.[17]  Second, it presumptively allows states to set the rate for as-available energy at the relevant locational marginal price (LMP).[18]  The record in this proceeding does not support either of those changes. 

Elimination of Fixed Energy Rate

Prior to Order No. 872, a QF generally had two options for selling its output to a utility.  Under the first option, the QF could sell its energy on an as-available basis and receive an avoided cost rate calculated at the time of delivery.  This is generally known as the as-available option.  Under the second option, a QF could enter into a fixed-duration contract at an avoided cost rate that was fixed either at the time the QF established a legally enforceable obligation (LEO) or at the time of delivery.  This is generally known as the contract option.  The ability to choose between the two options played an important role in fostering the development of a variety of QFs.  For example, the as-available option provided a way for QFs whose principal business was not generating electricity, such as industrial cogeneration facilities, to monetize their excess electricity generation.  The contract option, by contrast, provided QFs who were principally in the business of generating electricity, such as small renewable electricity generators, a stable option that would allow them to secure financing.  Together, the presence of these two options allowed the Commission to satisfy its statutory mandate to encourage the development of QFs and ensured that the rates they received were non-discriminatory.

Order No. 872 eliminated the requirement that states provide a contract option that includes a fixed energy rate.[19]  Prior to this proceeding, the Commission recognized time and again that fixed-price contracts play an essential role in financing QF facilities, making them a necessary element of any effort to encourage QF development, at least in certain regions of the country.[20]  In addition, fixed-price contracts have helped prevent discrimination against QFs by ensuring that they are not structurally disadvantaged relative to vertically integrated utilities that are guaranteed to recover the costs of their prudently incurred investments through retail rates.[21] 

The record before us confirms the continuing importance of the fixed-price contract option for QFs.  Numerous entities with experience in financing and developing QFs explain that a fixed revenue stream of some sort is necessary to obtain the financing needed to develop a new QF.[22]  In both Order No. 872 and today’s order on rehearing, the Commission responds to that evidence with a reference to the general track record of independent power producers, and renewables developers in particular, that develop new resources without a regulatory guarantee of a fixed revenue stream.[23]  But the overwhelming majority of the Commission’s statistics reflect development in RTO/ISO markets, where developers generally can rely on financing arrangements, such as commodity hedges, to lock-in the revenue needed to secure financing.[24] 

Those products are far less ubiquitous—if they are available at all—outside of RTO/ISO markets. [25]  Accordingly, the success of relatively large independent power producers in the organized markets does not constitute substantial evidence suggesting that QFs will be able to finance new development outside RTO/ISO markets where PURPA plays a larger role.[26]  Indeed, the Commission’s deliberate blurring of the lines between RTO/ISO markets and the rest of the country is the equivalent of arguing that Tommie and Hank Aaron ought to both be hall-of-famers because, together, they hit 768 home runs, while ignoring the fact that Hank was responsible for 755 of the brothers’ 768 home runs.[27]

The Commission next responds that PURPA does not require that QFs be financeable.[28]  That is true in a literal sense; nothing in PURPA directs the Commission to ensure that at least some QFs be financeable.  But it does require the Commission to encourage their development, which we have previously equated with financeability.[29]  If the Commission is going to abandon that standard, it must then explain why what is left of its regulations provides the requisite encouragement—an explanation that is lacking from this order, notwithstanding the Commission’s repeated assertions to the contrary.[30] 

In addition, much of the Commission’s justification for eliminating the fixed-price contract option for energy rests on the availability of a fixed-price contract option for capacity.[31]  Commission precedent, however, permits utilities to offer a capacity rate of zero to QFs when the utility does not need incremental capacity.[32]  That means that, after Order No. 872, QF developers now face the very real prospect of not receiving any fixed revenue stream, whether for energy or capacity, on top the fact at they also may not be able to secure hedging products or other mechanisms needed to finance a new QF.[33]  It is hard for me to understand how the Commission can, with a straight face, claim to be encouraging QF development while at the same time eliminating the conditions necessary to develop QFs in the regions where they are being built.[34] 

The Commission also does not sufficiently explain how eliminating the fixed-price contract requirement is consistent with PURPA’s requirement that rates “shall not discriminate against” QFs.[35]  Vertically integrated utilities effectively receive guaranteed fixed-price contracts through their rights to recover prudently incurred investments.[36]  QFs’ equivalent right to receive fixed-price contracts for energy has to date proved an integral element of the Commission’s ability to prevent discrimination against QFs.[37]  Neither Order No. 872 nor today’s order on rehearing adequately explain how eliminating the fixed-price option is consistent with that prohibition or, moreover, how permitting QFs to receive variable rates for energy while any vertically integrated utility to which they sell electricity receives fixed rates is consistent with the Commission’s obligation to encourage QF development.[38] 

On rehearing, the Commission argues that both Congress and the Supreme Court “recognize that PURPA treats QFs differently from purchasing utilities, rendering QFs not similarly situated to non-QF resources.”[39]  As an initial matter, the question of whether entities are similarly situated is one that is relevant to evaluating whether any discrimination is undue.[40]  PURPA, however, prohibits any discrimination against QFs, not just undue discrimination.[41]  In any case, the congressional language cited by the Commission,[42] which the Court reiterated, stands only for the proposition that Congress did not intend to apply traditional utility ratemaking concepts, such as guaranteed cost recovery, to QFs.  But while Congress clearly envisioned different cost-recovery regimes for incumbent utilities and QFs, PURPA’s prohibition on discrimination against QFs indicates that the ratemaking regime applicable to QFs can be no less favorable than that applied to incumbent purchasing utilities.  Permitting QFs to receive only variable-rate contracts while incumbent utilities simultaneously receive what are functionally decades-long fixed price contracts through their retail rates plainly falls short of the standard.  

Finally, the Commission fails to explain why certain allegations of QF rates exceeding a utility’s actual avoided cost require us to abandon fixed-price contracts.[43]  The Commission has long recognized that QF rates may exceed actual avoided costs, but, at the same time, that avoided cost rates might also turn out to be lower than the electric utility’s avoided costs over the course of the contract.  The Commission has reasoned that, “in the long run, ‘overestimations’ and ‘underestimations’ of avoided costs will balance out.”[44]  Today’s order on rehearing takes the position that variable-price contracts are necessary to ensure that QF rates do not exceed utility avoided costs.[45]  The Commission, however, both fails to adequately explain that new interpretation of PURPA[46] and justify the avulsive change of course that it represents.[47]  

Setting Avoided Cost at LMP

I also do not support the Commission’s decision to treat LMP as a presumptively reasonable measure of a utility’s as-available avoided cost for energy.[48]  The short-term marginal cost of production represented by LMP can be a useful and transparent input and ought to be considered in calculating an appropriate avoided-cost for as-available energy.  But considering LMP in setting avoided cost is not the same thing as presuming that LMP is a sufficient measure to establish the avoided cost rate for energy.  And, as the Public Interest Organizations explain, the record is replete with evidence indicating that vertically integrated utilities’ costs are often well above LMP.[49]  Where there is good reason to believe that LMP may not actually reflect the avoided cost of the purchasing utility, it makes no sense to put the burden on QFs to prove the point.

On rehearing, the Commission responds that its rebuttable presumption has not changed the burden of proof, only the burden of production.[50]  That’s an argument that only a lawyer’s mother could love.  It discounts the very real concerns about whether LMP is an accurate reflection of a purchasing utility’s avoided energy costs.  In any case, as the precedent cited by the Commission makes clear, an administrative agency cannot defend an irrational presumption simply by labeling it a shift in the burden of production.[51]  Because the presumption does not makes sense in its own right, the Commission cannot rehabilitate that presumption by labeling it merely a shift in the burden of production rather than persuasion.[52]

Finally, the presumption that LMP is an adequate measure of a utility’s full avoided energy cost is even more problematic when combined with the decision to eliminate the fixed-price contract option.  Because the Commission has removed the requirement that utilities offer a fixed-price contract option for energy, it is entirely possible that a QF will be eligible to receive only LMP both on a short-term basis and a long-term basis as a result of the variable cost structure now permitted under the long-term contract.[53]  Given this reality, QFs may be reduced to relying solely on some highly variable measure of the spot market price for energy, all while the utilities whose costs the QF is avoiding potentially recover an effectively guaranteed rate well above that spot market price, particularly in RTO/ISO markets that remain vertically integrated.[54]  I am not persuaded that this approach will satisfy our obligation to encourage QFs and do so using rates that are non-discriminatory across all regions of the country.

Rebuttable Presumption 20 MW to 5 MW

Following the Energy Policy Act of 2005, the Commission established a rebuttable presumption that QFs with a capacity greater than 20 MW operating in RTOs and ISOs have non-discriminatory access to competitive markets, eliminating utilities’ must-purchase obligation from those resources.[55]  Order No. 872 reduced the threshold for that presumption from 20 MW to 5 MW. [56]  That was an improvement over the NOPR, which—without any support whatsoever—proposed to lower that threshold to 1 MW.[57]  But, even so, the reduced 5-MW threshold is unsupported by the record and inadequately justified on rehearing.

When it originally established the 20-MW threshold, the Commission pointed to an array of barriers that prevented resources below that level from having truly non-discriminatory access to RTO/ISO markets.  Those barriers included complications associated with accessing the transmission system through the distribution system (a common occurrence for such small resources), challenges with reaching distant off-takers, as well as “jurisdictional differences, pancaked delivery rates, and additional administrative procedures” that complicate those resources’ ability to participate in those markets on a level playing field.[58]  In just the last few years, the Commission has recognized the persistence of those barriers “that gave rise to the rebuttable presumption that smaller QFs lack nondiscriminatory access to markets.”[59]

Nevertheless, Order No. 872 abandoned the 20 MW threshold based on the conclusory assertion that “it is reasonable to presume that access to RTO/ISO markets has improved,” making it “appropriate to update the presumption.”[60]  No doubt markets have improved.  But a borderline-truism about maturing markets does not explain how the barriers arrayed against small resources have dissipated, why it is reasonable to “presume” that the remaining barriers do not still significantly inhibit non-discriminatory access, or why 5 MW is an appropriate new threshold for that presumption.[61]

Instead of any such evidence, Order No. 872 noted that the Commission uses the 5-MW level as a demarcating line for other rules applying to small resources.  It points in particular to the fact that resources below 5 MW can use a “fast-track” interconnection process, whereas larger ones must use the large generator interconnection procedures.[62]  But the fact that the Commission used 5 MW as the cut off in another context hardly shows that it is the right cut off to use in this context.  Specifically, the 5 MW cut off in the Commission’s interconnection rule is based on the impacts that projects below 5 MW are likely to have on system safety and reliability, not on whether they have non-discriminatory market access.[63]  In addition, the Commission points to the fact that “‘all of the RTOs/ISOs have at least one participation model that allows resources as small as 100 kW to participate in their markets.’”[64]  Be that as it may, that fact that all RTOs do not prohibit certain small resources from accessing their markets does not support the proposition that QFs below 5 MW now have non-discriminatory access to those markets.

Lacking substantial evidence to support the 5 MW threshold, Order No. 872 made a great deal out the deferential standard of review applied to the Commission’s rulemakings.[65]  But while judicial review of agency policymaking is deferential, it is not toothless.  The cases on which the Commission relied still require that, when an agency’s policy reversal “rests upon factual findings that contradict those which underlay its prior policy,” the agency must “provide a more detailed justification than what would suffice for a new policy created on a blank slate.”[66]  That is because reasoned decisionmaking requires that, when an agency changes course, it must provide “a reasoned explanation . . . for disregarding facts and circumstances that underlay or were engendered by the prior policy.”[67]  For the foregoing reasons, the Commission has failed to produce any such explanation, making its change of course arbitrary and capricious.  

Environmental Review under the National Environmental Policy Act

Today’s order also doubles down on the Commission’s refusal to conduct any environmental review whatsoever of the likely consequences of Order No. 872’s reforms.  Whatever one may think of the questionable merits of those reforms, no one can seriously argue that they are anything short of a significant and sweeping overhaul of the Commission’s forty-year-old framework for implementing PURPA.  And yet, at the same time that the Commission has championed the scope of its sweeping reforms, it simultaneously insists that no environmental review is necessary both because it cannot venture any guess as to the effects of those reforms and because they somehow fit into a categorical exception from NEPA review.  Neither justification holds water.

As an initial matter, the Commission’s assertion that Order No. 872’s effects are overly speculative is tough to square with the fact that it has not undertaken any effort whatsoever to assess those effects.  For example, instead of performing any modeling exercises, as the Commission did in the environmental assessment it issued along with its PURPA regulations in 1980,[68] the Commission peremptorily rejects the possibility that it could glean anything useful from such an exercise.  I have a hard time believing that our modeling capabilities have not improved dramatically over the course of the last four decades or that we cannot use those capabilities to perform an analysis that is quite a bit more detailed and reliable than that which was previously good enough for the Commission.  In any case, NEPA does not require complete certainty or exacting precision.  Instead, it recognizes that administrative agencies will often have to rely “‘reasonable forecasting”’ aided by “‘educated assumptions.”’[69]  Nothing in Order No. 872 or today’s order on rehearing adequately explains why those techniques could not have formed the basis for a useful environmental review of the likely consequences of this proceeding. 

In addition, in a head-spinning contrast to the Commission’s crowing over the significance of its PURPA overhaul, the Commission describes the changes adopted as merely corrective and clarifying in nature for the purposes of avoiding its environmental review.[70]  In particular, the Commission contends that “the changes adopted in this final rule are required to ensure continued future compliance of the PURPA Regulations with PURPA, based on the changed circumstances found by the Commission in this final rule.”[71]  In other words, because the Commission believes that the changes adopted are necessary to conform with the statute, they are mere corrective changes, which, in turn, qualifies them for the categorical exemption from any environmental review under NEPA, or so the argument goes. 

But by that logic, any Commission action needed to comply with our various statutory mandates—whether “just and reasonable” or the “public interest”—would be deemed corrective in nature and, therefore, excluded from environmental review.  That would seem to exempt any future Commission action under PUPRA or Title II of the FPA from NEPA, at least absent a major congressional revision of those statutes.  The Commission, however, fails to point to any evidence suggesting that is what the Council on Environmental Quality contemplated when it allowed for categorical exemptions.  Accordingly, I do not believe that the Commission has demonstrated that the significant changes made in Order No. 872 qualify for any of the existing categorical exclusions, meaning that this significant revision of our PURPA regulations requires an environmental review under NEPA.

The Way to Revise PURPA Is to Create More Competition, Not Less

It didn’t have to be this way.  When Congress reformed PURPA in the 2005 Energy Policy Act amendments, it indicated an unmistakable preference for using market competition as the off-ramp for utilities seeking relief from their PURPA obligations.[72]  Those reforms directed the Commission to excuse utilities from those obligations where QFs had non-discriminatory access to RTO/ISO markets or other sufficiently competitive constructs.[73] 

This record contains numerous comments explaining how the Commission could use those amendments as a way to “modernize” PURPA in a manner that both promotes actual competition and reflects Congress’s unambiguous intent.[74]  For example, in a white paper released prior to the NOPR, the National Association of Regulatory Utility Commissioners (NARUC) urged the Commission to give meaning to the 2005 amendments by establishing criteria by which a vertically integrated utility outside of an RTO or ISO could apply to terminate the must-purchase obligation if it conducts sufficiently competitive solicitations for energy and capacity.[75]  Other groups, including representatives of QF interests, submitted additional comments on how an approach along those lines might work.[76]  Several parties commented on those proposals.[77]

It is a shame that the Commission has elected to administratively gut its long-standing PURPA implementation regime, rather than pursuing reform rooted in PURPA section 210(m), such as the NARUC proposal.  Although the Commission can still consider proposals along the lines of the NARUC approach,[78] making that approach the center of our reforms could have produced a durable, consensus solution to the issues before us.  I continue to believe that the way to modernize PURPA is to promote real competition, not to simply dismantle the provisions that the Commission has relied on for decades out of frustration that Congress has repeatedly failed to repeal the statute itself.

For these reasons, I respectfully dissent in part.


[1] Qualifying Facility Rates and Requirements Implementation Issues Under the Public Utility Regulatory Policies Act of 1978, Order No. 872-A, 173 FERC ¶ 61,158 (2020).

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

[3] Pub. L. No. 95-617, 92 Stat. 3117 (1978).

[4] See 16 U.S.C. § 824a-3(a)-(b) (2018).

[5] Those concerns notwithstanding, I supported certain aspects of Order No. 872, including the revisions to the “one-mile” rule, requiring that QFs demonstrate commercial viability before securing a legally enforceable obligation, and allowing stakeholders to protest a QF’s self-certification.  See Order No. 872, 172 FERC ¶ 61,041 (Glick, Comm’r, dissenting in part at n.4).

[6] Pub. L. No. 109-58, § 1253, 119 Stat. 594 (2005).

[7] Sept. 2019 Commission Meeting Tr. at 8. 

[8] 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) (Glick, Comm’r, dissenting in part at P 3).

[9] Supra note 6. 

[10] See Solar Energy Industries Association (SEIA) Comments at 11.

[11] NOPR, 168 FERC ¶ 61,184 (Glick, Comm’r, dissenting in part at P 4).

[12] Id.

[13] Order No. 872-A, 173 FERC ¶ 61,158 at P 115; Order No. 872, 172 FERC ¶ 61,041 at PP 24, 48, 54, 67, 296, 628; NOPR, 168 FERC ¶ 61,184 at PP 4, 16, 29, 155.

[14] A QF is a cogeneration facility or a small power production facility.  See 18 C.F.R. § 292.101(b)(1) (2019).

[15] 16 U.S.C. § 824a–3(a)-(b).

[16] Genuine Parts Co. v. EPA, 890 F.3d 304, 312 (D.C. Cir. 2018) (“[A]n agency cannot ignore evidence that undercuts its judgment; and it may not minimize such evidence without adequate explanation.”) (citations omitted); id. (“Conclusory explanations for matters involving a central factual dispute where there is considerable evidence in conflict do not suffice to meet the deferential standards of our review.” (quoting Int’l Union, United Mine Workers v. Mine Safety & Health Admin., 626 F.3d 84, 94 (D.C. Cir. 2010)).

[17] Order No. 872, 172 FERC ¶ 61,041 at P 253.

[18] Id. P 151.

[19] Id. P 253.

[20] See, e.g., Small Power Production and Cogeneration Facilities; Regulations

Implementing Section 210 of the Public Utility Regulatory Policies Act of 1978, Order

No. 69, FERC Stats. & Regs. ¶ 30,128, at 30,880, order on reh’g sub nom. Order

No. 69-A, FERC Stats. & Regs. ¶ 30,160 (1980), aff’d in part vacated in part, Am. Elec.

Power Serv. Corp. v. FERC, 675 F.2d 1226 (D.C. Cir. 1982), rev’d in part sub nom. Am.

Paper Inst. v. Am. Elec. Power Serv. Corp., 461 U.S. 402 (1983) (justifying the rule on the basis of “the need for certainty with regard to return on investment in new technologies”); NOPR, 168 FERC ¶ 61,184 at P 63 (“The Commission’s justification for allowing QFs to fix their rate at the time of the LEO for the entire term of a contract was that fixing the rate provides certainty necessary for the QF to obtain financing.”); Windham Solar LLC, 157 FERC ¶ 61,134, at P 8 (2016).

[21] See, e.g., ELCON Comments at 21-22 (“More variable avoided cost rates will result in unintended consequences that result in less competitive conditions and may leave consumers worse off, as utility self-builds do not face the same market risk exposure. Pushing more market risk to QFs while utility assets remain insulated from markets creates an investment risk asymmetry. This puts QFs at a competitive disadvantage.”); South Carolina Solar Business Association Comments at 8 (“[A]s-available rates for QFs in vertically-integrated states therefore discriminate against QFs by requiring QFs to enter into contracts at substantially and unjustifiably different terms than incumbent utilities.”); Southern Environmental Law Center Supplement Comments, Docket No. AD16-16-000, at 6-8 (Oct. 17, 2018) (explaining that vertically integrated utilities in Indiana, Alabama, Virginia and Tennessee only offer short-term rates to QFs); sPower Comments at 13; see also Statement of Travis Kavulla, Docket No. AD16-16-000, at 2 (June 29, 2016).

[22] See, e.g., Public Interest Organizations Rehearing Request at 73-76; SEIA Comments at 29; North Carolina Attorney General’s Office Comments at 5; ConEd Development Comments at 3; South Carolina Solar Business Association Comments at 6; sPower Comments at 11; Resources for the Future Comments at 6-7; Southeast Public Interest Organizations Comments at 9.

[23] Order No. 872-A, 173 FERC ¶ 61,158 at PP 150-151 (citing Order No. 872, 172 FERC ¶ 61,041 at P 340).

[24] See, e.g., EEI Comments at 36; sPower Comments at 12; Public Interest Organization Comments at n. 87 (fixed price contracts for non-QF generation); SEIA Rehearing Request at 14-15.

[25] See, e.g., SEIA Comments at 29-30 (“As both Mr. Shem and Mr. McConnell explain, financial hedge products are not available outside of ISO/RTO markets.”); Resources for the Future Comments at 6-7 (“[W]hile hedge products do support wind and solar project financing, they would not be suited for most QF projects.  To hedge energy prices, wind projects have used three products: bank hedges, synthetic power purchase agreements (synthetic PPAs), and proxy revenue swaps. . . .  From US project data for 2017 and 2018, the smallest wind project securing such a hedge was 78 MW, and most projects were well over 100 MW.  Additionally, as hedges rely on wholesale market access and liquid electricity trading, all of the projects were in ISO regions.”); SEIA Rehearing Request at 18.

[26] See, e.g., Public Interest Organizations Rehearing Request at 74-78; Northwest Coalition Rehearing Request at 28.

[27] Compare with  The Commission also points to the rate structure discussed in Town of Norwood v. FERC, 962 F.2d 20, 21, 24 (D.C. Cir. 1992), “variable energy rate/fixed capacity rate construct is the standard rate structure used throughout the electric industry.”  Order No. 872, 172 FERC ¶ 61,041 at P 38; see also Order No. 872-A, 173 FERC ¶ 61,158 at P 143.  I do not believe that the discussion of a single contract in a single case, decided roughly thirty years ago, is substantial evidence regarding the typical financing and contractual requirements of a QF in the contemporary electricity sector. 

[28] See, e.g., Order No. 872-A, 173 FERC ¶ 61,158 at PP 145-146, 172.

[29]  See, e.g., Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,880 (finding that “legally enforceable obligations are intended to reconcile the requirement that the rates for purchases equal to the utilities avoided cost with the need for qualifying facilities to be able to enter into contractual commitments, by necessity, on estimates of future avoided costs” and “the need for certainty with regard to return on investment in new technologies”); NOPR, 168 FERC ¶ 61,184 at P 63 (“The Commission’s justification for allowing QFs to fix their rate at the time of the LEO for the entire term of a contract was that fixing the rate provides certainty necessary for the QF to obtain financing.”).  The Commission responds that “[i]t is not necessary to prove that all potential QFs would be able to raise useful financing.”  Order No. 872-A, 173 FERC ¶ 61,158 at P 175.  Talk about moving the goal posts.  No one has argued that this is the Commission’s burden.  Rather, the argument is that the Commission’s reforms may render it impossible, or nearly so, for QFs outside the organized markets to obtain the necessary financing.  Order No. 872, 172 FERC ¶ 61,041 (Comm’r, Glick, dissenting in part at PP 11-12); Public Interest Organizations at 79-84.  The Commission cannot skirt that point by knocking down a strawman, especially given the weight it is has historically given to the importance of financeability for QFs.

[30] See, e.g., Order No. 872-A, 173 FERC ¶ 61,158 at P 43.

[31] See id. P 174; Order No. 872, 172 FERC ¶ 61,041 at P 36 (“This assertion that the Commission has eliminated fixed rates for QFs is not correct. . . . The NOPR thus made clear:  under the proposed revisions to § 292.304(d), a QF would continue to be entitled to a contract with avoided capacity costs calculated and fixed at the time the LEO is incurred.”) (internal quotation marks omitted); id. P 237 (“The Commission stated that these fixed capacity and variable energy payments have been sufficient to permit the financing of significant amounts of new capacity in the RTOs and ISOs.”).

[32] See, e.g., Order No. 872, 172 FERC ¶ 61,041 at P 422 (citing to City of Ketchikan, Alaska, 94 FERC ¶ 61,293, at 62,061 (2001)).

[33] See, e.g., Electric Power Supply Association (EPSA) Rehearing Request at 13-14; Resources for the Future Comments at 6; SEIA Comments at 30; Southeast Public Interest Organizations Comments at 12.

[34] See Public Interest Organizations Comments at 10-11 (“Obviously, rules that have an effect of discouraging QFs cannot be ‘necessary to’ encouraging them.”); see also Massachusetts Attorney General Maura Healey Comments at 6 (“This action may reduce investor confidence and discourage future development.  That outcome is a negative one for the Commonwealth and its ratepayers.”).


[35] 16 U.S. Code § 824a–3(b)(2).  Unlike provisions of the Federal Power Act, PURPA prohibits any discrimination against QFs, not just undue discrimination.  See Order No. 872, 172 FERC ¶ 61,041 at P 82; see also EPSA Rehearing Request at 6; ELCON Comments at 21-22; South Carolina Solar Business Alliance Comments at 7-8; sPower Comments at 13.

[36] Order No. 872, 172 FERC ¶ 61,041 at P 40.

[37] See supra note 20; Commissioner Slaughter Comments at 4.

[38] EPSA Rehearing Request at 8-9; Public Interest Organizations Comments at 51 (“[L]imiting QFs to contracts providing no price certainty for energy values, while non-QF generation regularly obtains fixed price contracts and utility-owned generation receives guaranteed cost recovery from captive ratepayers, constitutes discrimination.”).

[39] Order No. 872-A, 173 FERC ¶ 61,158 at P 142.

[40] See Public Interest Organizations Rehearing Request at 94-95; Northwest Coalition Rehearing Request at 11-12.

[41] See supra note 35.

[42] Order No. 872-A, 173 FERC ¶ 61,158 at P 142 n.275.

[43] Id. PP 76-78.

[44] Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,880.  

[45] Order No. 872-A, 173 FERC ¶ 61,158 at PP 84, 175.

[46] EPSA Rehearing Request at 15-16 (citing Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,880).

[47] Order No. 872 was quick to point to “the precipitous decline in natural gas prices” starting in 2008 that may have caused QF contracts fixed prior to that period to underestimate the actual cost of energy.  See, e.g., Order No. 872, 172 FERC ¶ 61,041 at P 287.  However, PURPA has been in place for forty years, and the Commission does not wrestle with the magnitude of potential savings conveyed to consumers from the fixed-price energy contracts that locked-in low rates for consumers during the decades prior when natural gas prices were several times higher.  See Energy Information Administration Total Energy, tbl. 9.10, (last viewed November 18, 2020).

[48] Order No. 872, 172 FERC ¶ 61,041 at PP 151, 189, 211.

[49] See, e.g., Public Interest Organizations Rehearing Request at 69-71.  These points have also been raised throughout this proceeding.   Public Interest Organizations Comments at 47-49 (explaining that numerous power plants incur marginal production costs that exceed the LMP); id at 50-51 (discussing analysis from Bloomberg New Energy Finance that compares marginal production costs with LMP and finds that many vertically integrated utilities regularly incur production costs that exceed LMP); id. at 51-52 (showing that a Springfield Illinois coal-fired power plant’s marginal dispatch costs exceeds LMP); id. at 52-53 (explaining that many utilities’ per-net-kWh costs exceed LMP); id. at 53-54 (contending that the cost associated with long-term fixed-price contracts for nuclear plants exceed LMP even net of capacity value).


[50] Order No. 872-A, 173 FERC ¶ 61,158 at PP 63-64 (citing Cablevision Sys. Corp. v. FCC, 649 F.3d 695, 716 (D.C. Cir. 2011)).

[51] Cablevision, 649 F.3d at 716 (“‘[A]n evidentiary presumption is only permissible if there is a sound and rational connection between the proved and inferred facts, and when proof of one fact renders the existence of another fact so probable that it is sensible and timesaving to assume the truth of the inferred fact.’” (quoting Nat’l Mining Ass’n v. Dep’t of Interior, 177 F.3d 1, 6 (D.C. Cir. 1999))).

[52] It is also unclear from this record whether that presumption is best characterized as a shift in the burden of production rather than the burden of persuasion.  To the extent that a QF or other entity must show that LMP is not an adequate measure of avoided cost in order to rebut the presumption, then the Commission has, for all intents and purposes, shifted the burden of persuasion to those entities no matter how the Commission describes its presumption.

[53] Public Interest Organizations Rehearing Request at P 61.

[54] EPSA Rehearing Request at 13-14; Public Interest Organizations Rehearing Request at 98-99.

[55]  New PURPA Section 210(m) Regulations Applicable to Small Power Production and Cogeneration Facilities, Order No. 688, 117 FERC ¶ 61,078, at P 72 (2006), order on reh’g, Order No. 688-A, 119 FERC ¶ 61,305 (2007), aff’d sub nom. Am. Forest & Paper Ass’n v. FERC, 550 F.3d 1179 (D.C. Cir. 2008); see 16 U.S.C. § 824a-3(m).

[56] Order No. 872, 172 FERC ¶ 61,041 at P 625.

[57] NOPR, 168 FERC ¶ 61,184 at P 126.

[58] Order No. 688-A, 119 FERC ¶ 61,305 at PP 96, 103.

[59] E.g., N. States Power Co., 151 FERC ¶ 61,110, at P 34 (2015). 

[60] Order No. 872, 172 FERC ¶ 61,041 at P 629 (“Over the last 15 years, the RTO/ISO markets have matured, market participants have gained a better understanding of the mechanics of such markets and, as a result, we find that it is reasonable to presume that access to the RTO/ISO markets has improved and that it is appropriate to update the presumption for smaller production facilities.”); see Order No. 872-A, 173 FERC ¶ 61,158 at P 361.

[61] See Public Interest Organizations Rehearing Request at 135.

[62] Order No. 872, 172 FERC ¶ 61,041 at P 630; Order No. 872-A, 173 FERC ¶ 61,158 at P 361.      

[63] Order No. 792, 145 FERC ¶ 61,159, at P 103 (2013) (“The Commission finds that the modifications . . . are just and reasonable and strike a balance between allowing larger projects to use the Fast Track Process while ensuring safety and reliability.”); see also SEIA Rehearing Request at 39-40.

[64] Order No. 872-A, 173 FERC ¶ 61,158 at P 362 (citing Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators, Order No. 841, 162 FERC ¶ 61,127 (2018), at P 272).

[65] Order No. 872, 172 FERC ¶ 61,041 at P 637 (citing FCC v. Fox Television, 556 U.S. 502, 515 (2009), for the proposition that an agency “need not demonstrate to a court’s satisfaction that the reasons for the new policy are better than the reasons for the old one; it suffices that the new policy is permissible under the statute, that there are good reasons for it, and that the agency believes it to be better, which the conscious change of course adequately indicates.”); see Order No. 872-A, 173 FERC ¶ 61,158 at P 347.

[66] Fox Television, 556 U.S. at 515; Advanced Energy Economy Comments at 6.

[67] Fox Television, 556 U.S. at 516; Advanced Energy Economy Comments at 6-7.

[68] Small Power Production and Cogeneration Facilities--Environmental Findings; No Significant Impact and Notice of Intent To Prepare Environmental Impact Statement, 45 FR 23,661 (Apr. 8, 1980).

[69] Sierra Club v. FERC, 867 F.3d 1357, 1374 (D.C. Cir. 2018) (quoting Del. Riverkeeper Network v. FERC, 753 F.3d 1304, 1310 (D.C. Cir. 2014)).

[70] Order No. 872-A, 173 FERC ¶ 61,158 at P 449.

[71] Order No. 872, 172 FERC ¶ 61,041 at P 722; Order No. 872-A, 173 FERC ¶ 61,158 at P 438.

[72] 16 U.S.C. § 824a-3(m).

[73] See Order No. 688, 117 FERC ¶ 61,078 at P 8.

[74] See Advanced Energy Economy Comments at 13; Industrial Energy Consumers Comments at 13-14; EPSA Comments at 16.

[75] National Association of Regulatory Utility Commissioners Supplemental Comments, Docket No. AD16-16-00, Attach. A, at 8 (Oct. 17, 2018); id. (proposing the Commission’s Edgar-Allegheny criteria as a basis for evaluating whether a proposal was adequately competitive).

[76] See, e.g., SEIA Supplemental Comments, Docket No. AD16-16-000 (Aug. 28, 2019).

[77] See, e.g., Advanced Energy Economy Comments at 12; APPA Comments at 29; Colorado Independent Energy Comments at 7; ELCON Comments at 19; Public Interest Organizations Comments at 90; SEIA Comments at 24; Xcel Comments at 11.

[78] Order No. 872, 172 FERC ¶ 61,041 at P 662.


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