Commissioner Richard Glick
July 16, 2020
Docket Nos. RM19-15-000, AD16-16-000
Order No. 872
I dissent in part from today’s final rule (Final Rule) because it effectively guts the Commission’s implementation of the Public Utility Regulatory Policies Act (PURPA). 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. I do not believe that today’s Final Rule satisfies those responsibilities. Instead, the Final Rule raises as many questions as it answers, not least of which is the long-term legal viability of an approach that does so little to encourage QF development.
Although I have concerns about many of the individual changes imposed by the Final Rule, 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. 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, even those that may celebrate the immediate effects of this Final Rule.
PURPA’s Continuing Relevance Is an Issue for Congress to Decide
This proceeding began with a bang. My colleagues championed the proposed rule as a “truly significant” action that would fundamentally overhaul the Commission’s implementation of PURPA. And so it was. The NOPR proposed to alter 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.
I dissented from the NOPR 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.” 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. And while Congress considered numerous proposals to further reform the law, it never saw fit to act on them. 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.” 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.”
Today’s Final Rule retreats 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, this Final Rule 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 this Final Rule is overturned on appeal, that does not change the fact that today’s Final 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. This Final Rule, 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 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, including by establishing rates for sales by QFs that are just and reasonable and by ensuring that such rates “shall not discriminate” against QFs. As explained below, many of the changes adopted by the Commission in the Final Rule fail to meet that standard. In addition, many of the reforms are unsupported—or, in many cases, contradicted—by the evidence in the record. Accordingly, I believe today’s Final Rule is not just poor public policy, but also arbitrary and capricious agency action.
A. Avoided Cost
The Final Rule adopts two fundamental changes to how QF rates are determined. First, and most importantly, it eliminates 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. Second, it presumptively allows states to set the rate for as-available energy at the relevant locational marginal price (LMP) or a similarly “competitive market price.” The record in this proceeding does not support either of those changes.
i. Elimination of Fixed Energy Rate
Prior to today’s Final Rule, 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 both types of sale 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.
The Final Rule eliminates the requirement that states provide a contract option that includes a fixed energy rate. Prior to this proceeding, the Commission recognized time and again that fixed-price contracts play an essential role in the financing of QF facilities, making them a necessary element of any effort to encourage QF development, at least in certain regions of the country. 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.
If anything, the record before us confirms the continuing importance of fixed-price contracts. Numerous entities with experience 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. The fixed revenue stream is particularly important because QFs are overwhelmingly developed outside of the organized markets, meaning that developers cannot necessarily obtain hedging contracts to create the revenue predictability needed to obtain financing. And that is why the Final Rule’s parade of statistics about the growth of renewables misses the point. It is true that, primarily in organized markets, independently developed renewables are able to develop without the entitlement to a fixed-price contract for energy from the relevant utility. But the growth of renewables and their financeability in organized markets tells us almost nothing about what is required to sufficiently encourage QFs outside those markets.
It would be one thing to eliminate the requirement to provide a fixed-price option for energy rates for QFs that are entitled to a fixed price for capacity. Although reasonable minds might disagree about whether a fixed price for capacity alone is sufficient encouragement, combining one with a variable price for energy would provide at least some guaranteed revenue stream with which to finance new development. Indeed, 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. Commission precedent, however, permits utilities to offer a capacity rate of zero to QFs when the utility does not need incremental capacity. That means that, as a result of this Final Rule, QF developers will face the very real prospect of not receiving any fixed revenue stream, whether for energy or capacity, in areas where they also cannot secure hedging products or other mechanisms needed to finance a new QF. 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.
The Commission sidesteps this point in responding that PURPA does not require that QFs be financeable. 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. 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 Final Rule, notwithstanding the Commission’s repeated assertions to the contrary.
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. Vertically integrated utilities effectively receive guaranteed fixed-price contracts through their rights to recover prudently incurred investments. The equivalent right to receive fixed-price contracts has to date proved an integral element of the Commission’s ability to satisfy PURPA’s prohibition on discriminatory rates.
And yet this Final Rule fails to explain how eliminating the fixed-price option is consistent with that prohibition or, moreover, how permitting QFs to receive variable contract rates while vertically integrated utilities receive fixed ones is consistent with the Commission’s obligation to promote QFs. Instead, the Commission notes that, through so-called fuel adjustment clauses, vertically integrated utilities’ rates change as the price of fuel changes. The idea that those clauses, which ensure that utilities recover a specific variable cost (i.e., their cost of fuel), is the same thing as having your entire revenue exposed to variations in prevailing market conditions is hogwash. The presence of fuel adjustment clauses in no way suggests that vertically integrated utilities are subject to anything remotely close to the level of revenue variation contemplated in this Final Rule.
Finally, the Commission fails to explain why allegations of QF rates exceeding a utility’s actual avoided cost requires us to abandon the Commission’s long-held principles regarding certainty and financing. As an initial matter, the Commission has recognized that QF rates may exceed actual avoided costs, but, at the same time, recognized 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.” However, when presented with a couple allegations that avoided costs were overestimated, the Commission now concludes that that possibility suggests it must abandon the fixed-energy rate contract altogether. The Commission, however, makes no effort to validate these allegations, or assess whether the overestimations of avoided cost were, in fact, balanced out. It is arbitrary and capricious to point to only half the picture in abandoning a forty-year-old principle.
ii. Rebuttable Presumption for Setting Avoided Cost at LMP and Similar Measures
I also do not support the Commission’s decision to treat LMP or other “competitive market prices” as a presumptively reasonable measure of an as-available avoided cost for energy. Liquid price signals can be useful and transparent inputs and ought to be considered in calculating an appropriate avoided-cost figure. But considering those price signals in setting avoided cost is not the same thing as presuming that LMP or similar measures are alone sufficient to establish avoided cost. Many regions of the country—often the same regions where the debates about PURPA are most heated—have not established sufficiently competitive markets. In these regions it is not clear from the record that the prices in, for example, a neighboring RTO, are a representative measure of a utility’s avoided cost. In those less competitive markets, it simply does not make sense to presume that LMP or other “competitive market prices” are a representative measure of avoided cost, rather than one of many criteria that should go into that determination.
For similar reasons, I share the concern of many commenters that short-term or spot prices, such as LMP, may not reflect the long-term marginal energy costs avoided by purchasing utilities, especially outside of organized markets. Although the Commission revises the NOPR’s per se rule to be a rebuttable presumption, it nevertheless plows ahead with the conclusion that LMP, and similar measures, reflect a utility’s avoided cost of energy. Where there is good reason to believe that those measures do not actually reflect the long-term value of energy that they are supposed to represent, it makes no sense to put the burden on QFs to prove the point, rather than leaving the burden with the proponents of using such measures.
The Commission’s presumptive approval of LMP and similar measures is even more problematic when combined with the decision to allow utilities to eliminate the fixed-price contract option. Following this Final Rule, QFs may be reduced to relying solely on some synthetic and highly variable measure of what spot prices should be in a competitive market based on gas prices and heat rates, all while the utilities whose costs the QF is avoiding recovers an effectively guaranteed rate potentially in excess of this representative “competitive market price.” I am not persuaded that this approach will satisfy our obligation to encourage QFs and to do so using rates that are non-discriminatory across all regions of the country.
B. 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. The Final Rule reduces the threshold for that presumption from 20 MW to 5 MW.  That is an improvement over the NOPR, which—without any support whatsoever—proposed to lower that threshold to 1 MW. But, even so, the reduced 5 MW threshold is unsupported by the record and inadequately justified in today’s Final Rule.
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. 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.”
Nevertheless, the Final Rule abandons the 20 MW threshold based on the conclusory assertion that “it is reasonable to presume that access to RTO/ISO markets has improved” and it is, therefore, “appropriate to update the presumption.” 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 inhibit non-discriminatory access, or why 5 MW is an appropriate new threshold for that presumption.
Instead of any such evidence, the Final Rule notes that the Commission uses the 5 MW as a demarcating line for other rules applying to small resources. Specifically, it points 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. 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.
Lacking substantial evidence to support the 5 MW threshold, the Commission falls back on a deferential standard of review. But while judicial review of agency policymaking is deferential, it is not toothless. The same cases on which the Commission relies 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.” 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.” 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
In contrast to the Commission’s crowing over the significance of its PURPA overhaul, the Final Rule describes the changes adopted as merely corrective and clarifying in nature when it comes to conducting an environmental review. 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.” 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. 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.
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. 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.
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. 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. Other groups, including representatives of QF interests, submitted additional comments on how an approach along those lines might work. Several parties commented on those proposals.
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. Pursuing an option along those lines 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 gut 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.
 Qualifying Facility Rates and Requirements Implementation Issues Under the Public Utility Regulatory Policies Act of 1978, Order No. 872, 172 FERC ¶ 61,041 (2020) (Final Rule).
 Pub. L. No. 95-617, 92 Stat. 3117 (1978).
 See 16 U.S.C. § 824a-3(a)-(b) (2018).
 Notwithstanding those concerns, I support certain aspects of this Final Rule. First and foremost, I agree with the update to the “one-mile” rule, which prior to today provided an irrebuttable presumption that resources located more than one mile apart are separate QFs. In addition, I support requiring that QFs demonstrate commercial viability before securing a legally enforceable obligation with the relevant utility. Finally, I also support the revision to allow stakeholders to protest a QF’s self-certification.
 Pub. L. No. 109-58, § 1253, 119 Stat. 594 (2005).
 Sept. 2019 Commission Meeting Tr. at 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).
 Pub. L. No. 109-58, § 1253, 119 Stat. 594 (2005).
 See Solar Energy Industries Association (SEIA) Comments at 11.
 NOPR, 168 FERC ¶ 61,184 (Glick, Comm’r, dissenting in part at P 4).
 Final Rule, 172 FERC ¶ 61,041 at PP 24, 48, 54, 67, 296, 628; NOPR, 168 FERC ¶ 61,184 at PP 4, 16, 29, 155.
 A QF is a cogeneration facility or a small power production facility. See 18 C.F.R. § 292.101(b)(1) (2019).
 16 U.S.C. § 824a–3(a)-(b).
 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)).
 Final Rule, 172 FERC ¶ 61,041 at P 253.
 Id. PP 151, 189, 211.
 Id. P 253.
 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).
 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).
 See, e.g., SEIA Comments at 29; North Carolina Attorney General’s Office Comments at 5; Con Ed Development Comments at 3; South Carolina Solar Business Association Comments at 6; sPower Comments at 11; Resources for the Future Comments at 6-7.
 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.”) (emphasis added).
 Harvard Electricity Law Comments at 22 (referring to a similar statistical parade in the NOPR and observing that “[a]ll [the Commission] can actually conclude from this loosely connected array of facts, data, and speculation is that some non-QF generators are developed with variable-rate energy contracts. That unremarkable conclusion has no bearing on whether repeal will discourage QF development by ‘materially affect[ing] the ability of QFs to obtain financing.’” (citing NOPR, 168 FERC ¶ 61,184 at P 69)); SEIA Comments at 30.
 See Final Rule, 172 FERC ¶ 61,041 at P 340 (“EIA data demonstrates that net generation of energy by non-utility owned renewable resources in the United States grew by almost 700% between 2005 and 2018.”). Although independent power producers, renewable or otherwise, within the RTO/ISO markets are not entitled to fixed price contracts for energy as a matter of law, they generally do rely on alternative tools, such as commodity hedges, to lock-in energy revenue streams. See, e.g., EEI Comments at 36; sPower Comments at 12.
 In the logical leap of the year, the Commission notes that in some areas of the country, unspecified resources are developed with a fixed-price contract for capacity and a variable price for energy and, separately, that renewables have grown nationwide more than seven-fold between 2005 and 2018. Final Rule, 172 FERC ¶ 61,041 at P 340. From those disparate observations, the Commission concludes that “renewable resources are able to acquire financing even without the right to require long-term fixed energy rates.” Id. But nothing in the record suggests that that phenomenal growth in renewables was at all the result of that bifurcated contract structure. That, it should be clear, is not reasoned decisionmaking. Cf. Nat’l Ass’n of Recycling Indus., Inc. v. Fed. Mar. Comm’n, 658 F.2d 816, 820 n.10 (D.C. Cir. 1980) (“We do not want, after all, blithely to compare apples and oranges. Likewise, an agency should also avoid unavailing comparisons of nonsubstitutes.”); see also Commissioner Slaughter Comments at 4 (noting the “widespread geographic differentiation” in renewable energy progress and “barriers to independent renewable energy-based power producers”).
 See, e.g., SEIA Comments at 29 (“While securing financing based on an As-Available Energy rate and a fixed capacity rate may be a rare possibility in a few sub-markets across the country, as Mr. Shem explains, it certainly is not the case in any state that does not participate in an ISO/RTO market.”).
 See Final Rule, 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.”).
 See, e.g., id. P 422 (citing to City of Ketchikan, Alaska, 94 FERC ¶ 61,293, at 62,061 (2001)).
 See, e.g., Resources for the Future Comments at 6; SEIA Comments at 30; Southeast Public Interest Organizations Comments at 12.
 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.”).
 See, e.g., Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,880 (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.”).
 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 ELCON Comments at 21-22; South Carolina Solar Business Alliance Comments at 7-8; sPower Comments at 13.
 See supra n.20; Commissioner Slaughter Comments at 4.
 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.”).
 See supra n.19.
 Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,880.
 Final Rule, 172 FERC ¶ 61,041 at PP 265, 268.
 Id. PP 291, 293.
 The Commission is 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., Final Rule, 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 July 15, 2020), https://www.eia.gov/totalenergy/data/browser/.
 Final Rule, 172 FERC ¶ 61,041 at PP 151, 189, 211.
 Congress itself seems to have contemplated that states would not rely solely on spot market prices when establishing avoided cost. H.R. Rep. No. 95-1750, at 7833 (1978) (“In interpreting the term ‘incremental cost of alternative energy,’ the conferees expect that the Commission and the states may look beyond the cost of alternative sources which are instantaneously available to the utility.”).
 Final Rule, 172 FERC ¶ 61,041 at n.163; Hydro Comments at 11; Southeast Public Interest Organizations Comments at 19; NIPPC, CREA, REC, and OSEIA Comments at 52, 55; Union of Concerned Scientists Comments at 6. Take, for example, the Commission’s approval of the Mid-Columbia market hub price as presumptively reflecting a utility’s avoided cost for energy. See Final Rule, 172 FERC ¶ 61,041 at PP 180, 189. Notwithstanding explicit support for this approach from the regulated utility industry, the Washington Utilities and Transportation Commission which, when addressing Puget Sound Energy’s plan to increase wholesale purchases from the Mid-Columbia market “liquid hub” to 1,600 MW, expressed a concern about the regulated utility’s overreliance on such wholesale market pricing and directed them to pursue an alternative plan to eliminate this “excessive risk.” That is the exact type of tension conveyed in the record—i.e, that such competitive market prices may not accurately reflect a utility’s avoided cost, as approved by regulators. See Washington UTC, Acknowledgment Letter Attachment, Puget Sound Energy’s 2017 Electric and Natural Gas Integrated Resource Plan, Wash. UTC Docket Nos. UE-160918, UG-160919 (Revised June 19, 2018); see NIPPC, CREA, REC, and OSEIA Comments at 56.
 Final Rule, 172 FERC ¶ 61,041 at P 152.
 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).
 Final Rule, 172 FERC ¶ 61,041 at P 625.
 NOPR, 168 FERC ¶ 61,184 at P 126.
 Order No. 688-A, 119 FERC ¶ 61,305 at PP 96, 103.
 E.g., N. States Power Co., 151 FERC ¶ 61,110, at P 34 (2015).
 Final Rule, 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.”).
 Id. P 630.
 Id. 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.”).
 Fox Television, 556 U.S. at 515; Advanced Energy Economy Comments at 6.
 Fox Television, 556 U.S. at 516; Advanced Energy Economy Comments at 6-7.
 Under the National Environmental Policy Act (NEPA), the Commission must consider whether its action associated with rulemakings will have a significant impact on the environment. See 42 U.S.C. §§ 4321 et seq.
 Final Rule, 172 FERC ¶ 61,041 at P 722.
 16 U.S.C. § 824a-3(m).
 See Order No. 688, 117 FERC ¶ 61,078 at P 8.
 See Advanced Energy Economy Comments at 13; Industrial Energy Consumers Comments at 13-14; EPSA Comments at 16.
 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).
 See, e.g., SEIA Supplemental Comments, Docket No. AD16-16-000 (Aug. 28, 2019).
 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.