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Commissioner Richard Glick Statement
September 19, 2019

Docket Nos. RM19-15-000, AD16-16-000

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Dissent in Part of Commissioner Richard Glick Regarding FERC’s Notice of Proposed Rulemaking to Update PURPA Regulations

I dissent in part from today’s notice of proposed rulemaking (NOPR) because it would effectively gut the Public Utility Regulatory Policies Act (PURPA).1 Our 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 and in the public interest.2 As discussed further below, it is not clear from the record or the discussion in today’s NOPR that many of the proposed changes will satisfy those requirements. Although the record developed in response to this NOPR will give us a basis to address those issues, I am deeply concerned that the Commission has failed so far to show that certain aspects of its proposal satisfy our basic responsibilities under the law.

It appears that the Commission no longer believes that PURPA is necessary. I disagree. I believe that the goals of PURPA—including the need to expand competition and reduce our reliance on fossil fuels3 —remain as relevant now as ever. But our apparent disagreement is beside the point. Whether PURPA’s goals remain relevant is a decision for Congress, not an administrative agency. The Commission should not be seizing the reins from Congress in order to isolate an important debate about national energy policy within an independent regulatory agency.

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

A fundamental reform to a major energy statute, particularly one that Congress has been debated for decades, ought to come from Congress, not an independent regulatory agency. For more than forty years, the Commission has rather consistently interpreted Congress’s directives in PURPA. During that time, Congress has repeatedly considered legislation to amend the statute, in some cases to expand its reach and in others to pare it back. Indeed, almost from the moment PURPA was passed, Congress began to hear many of the arguments being used today to justify scaling the law back. Yet Congress only on one occasion—in 2005—significantly amended the statute. After a lengthy debate, which included proposals to repeal PURPA, Congress adopted the Energy Policy Act of 2005 (EPAct 2005), which left in place PURPA’s basic framework but added a series of provisions that relieved utilities of their requirements in regions of the country with robust wholesale energy markets.4 Over the course of the last fourteen years, Congress has continued to consider a wide range of proposals to reform PURPA, some of which would have enacted into law many of the proposals advanced in this NOPR. But Congress did not enact any of these reforms.

Today’s NOPR flips that dynamic on its head. It removes an important debate from the halls of Congress and isolates it within the Commission. That may help to achieve certain stakeholders’ objectives and, no doubt, some Members of Congress that have unsuccessfully sought to further reform PURPA will applaud this outcome. But 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.

With those concerns in mind, the Commission’s explanation of the purported need for reform rings hollow. The majority recites statistics to show that the energy landscape has changed over the last 40 years. And there is no doubt that it has. Renewables are growing rapidly and, in some parts of the country, are being financed in large numbers without PURPA’s protections.5 Natural gas production has increased in similarly dramatic fashion and recently surpassed coal as the country’s principal source of fuel for generating electricity.6 But reams of statistics do not make a law irrelevant. The majority and I might disagree about PURPA and the importance of its objectives, but that is not a dispute that we, as Commissioners, should resolve. A policy debate about the continuing relevance of PURPA—which, make no mistake, is what this NOPR is really about—is an issue for Congress to resolve.

II. Certain Proposed Revisions are Inconsistent with Our Statutory Obligations

In addition to my general concerns about the direction and intent of today’s NOPR, I have a number of more discrete objections regarding aspects of the Commission’s proposal. I raise these concerns in particular because I believe that neither the record established to date nor the rationale articulated in today’s NOPR suggest that these changes are consistent with our obligations under PURPA. Accordingly, I am especially interested in reviewing the record developed in response to these elements of the proposed rule and I encourage parties to address these issues in detail in their comments.

A. Avoided Cost

No issue has consumed as much attention in the debates over PURPA as how to set avoided cost. Following PURPA’s enactment in 1978, the Commission introduced a framework for setting “avoided cost” that allows each individual state to consider a wide range of factors in identifying the “full” costs that are avoided when a utility purchases energy and capacity from a QF.7 The basic idea is that the avoided cost figure should reflect the full cost that the utility would incur but for the purchase of the QF output of energy or capacity, with each individual state enjoying considerable flexibility in implementing that concept.8 The Commission’s regulations also provide states the flexibility to accommodate Congress’s intent that the rates paid to QFs “look beyond” just “instantaneous cost savings” in order to consider savings over a longer time horizon.9

The NOPR proposes two fundamental changes to how avoided cost is calculated and applied to QFs. First, it proposes to eliminate the requirement that a utility must afford a QF the option to enter a contract at an avoided cost energy rate that is fixed or known for the duration of the contract.10 As things stand now, a QF generally has two options for selling its output to a utility. Under the first option, the QF can 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 can enter into a fixed duration contract at an avoided cost rate that is fixed either at the time the QF establishes a legally enforceable obligation or at the time of delivery. This is generally known as the contract option. The ability to choose between both types sale options has played an important role in fostering the development of a variety of QFs. For example, the as-available option provides a way for QFs whose principal business is not generating electricity, such as industrial cogeneration facilities, to monetize their excess electricity generation. The contract option, by contrast, provides QFs who are principally in the business of generating electricity, such as small renewable electricity generators, a relatively stable option that will allow them to secure financing. Together, the presence of these two options have allowed the Commission to satisfy its statutory mandate to encourage the development of QFs and ensure that the rates they receive are non-discriminatory.

I am concerned that the Commission’s proposal to allow utilities to eliminate the fixed-price contract option will make it more difficult—or in some cases impossible—for QFs to obtain financing. The option to enter a contract with a fixed or known price has played in essential role in encouraging QF development.11 In addition, those contracts have played an important role in ensuring that QFs receive non-discriminatory rates, especially in areas of the country with vertically integrated utilities that are guaranteed to recover the costs of their prudently incurred investments through retail rates.12 Neither the record nor the rationale in this NOPR addresses these concerns in a manner that is even remotely convincing.

Second, I am concerned about the implications of the Commission’s proposal to determine that a locational marginal price (LMP) is a per se reasonable measure of an as-available avoided cost for energy and to preliminarily advance several other “Competitive Prices” that would also be sufficient.13 Current regulations require states to consider factors, including reliability and when the QF is available, when calculating the avoided cost rate. Today’s NOPR proposes to allow states to ignore these factors and, instead, rely entirely on LMP or a price set at a “liquid market hub.” That rule would apply across the country, irrespective of whether the QF has access non-discriminatory access to competitive markets.14 That is notwithstanding the fact that the evidence the Commission relies on to justify this proposal comes overwhelmingly from regions with sophisticated RTO and ISO markets and/or restructured utilities.

As an initial matter, I support introducing more competition into the Commission’s implementation of PURPA. Liquid price signals can be useful and transparent inputs that are worthy of considering as part of the overall calculation of an appropriate avoided cost number that includes both the short-term and long-term costs avoided by the utility’s purchases from QFs. But referencing the words “competitive” and “market” over and over again is not the same thing as proof that there is sufficient market competition. Many regions of the country—often the same regions where the debates about PURPA are most heated—have not established competitive markets, let alone non-discriminatory access to those markets for independent generators, even if there are liquid market hubs for spot energy purchases. When combined with the Commission’s proposal to allow utilities to eliminate the contract option, discussed above, QFs may be reduced to relying solely on some synthetic measure of what spot prices would be in a competitive market based on gas prices and heat rates. I am not persuaded that this will satisfy our obligation to encourage QFs.

Nor am I confident that this proposal will not result in discriminatory rates. In regions of the country with vertically integrated utilities (including some parts of RTO/ISO markets) the relevant utility will almost always receive guaranteed cost-recovery on its generation investments. Indeed, state regulators will often effectively pre-approve certain incumbent utility investments through those utilities’ integrated resource plans, making it highly unlikely that the utility investments will ultimately be disallowed as imprudent. Under those circumstances, it is not clear to me how a rule that conclusively presumes that LMP—let alone some other measure of price—is a non-discriminatory rate in those regions.

I recognize that in some regions of the country—such as the RTOs and ISOs with developed real-time and day-ahead markets and largely restructured utilities—this may be an appropriate approach for calculating the as-available rate for energy, at least for relatively large QFs. But the NOPR’s proposed revisions are not limited to those regions and are not even predicated on utilities themselves actually relying on LMP, liquid market hubs, or other calculations of “Competitive Prices.” In any case, neither the record nor the rationale in this NOPR addresses these concerns in a convincing manner.

B. Reducing the 20 MW Rebuttable Presumption

The Commission is also proposing to reduce the threshold for the rebuttable presumption of non-discriminatory access to competitive wholesale markets within RTOs and ISOs from 20 MW to 1 MW. This proposal would, in essence, relieve most utilities within RTOs and ISOs from the must-purchase obligation for any resource greater than 1 MW based on the theory that those resources have non-discriminatory access to the RTO and ISO markets.15

The Commission created the rebuttable presumption framework in response to Congress’s enactment of section 210(m) in EPAct 2005. The Commission explained that QFs smaller than 20 MW often face more challenges than larger QFs in accessing competitive wholesale markets and therefore presumptively do not have non-discriminatory access.16 The challenges it identified included issues such as interconnection at the distribution level, jurisdictional differences, pancaked delivery rates, and administrative burdens to obtaining access to distant buyers.17

Today’s NOPR contains precious little justification to support that change and does not cite a single piece of record evidence supporting its proposal.18 That may be because it seems a stretch to suggest that a 1 MW resource can generally access and compete in markets as sophisticated and complex as, for example, PJM Interconnection, L.L.C., on a similar footing as the resources in the portfolio of a large vertically integrated utility or merchant power generator.

These are among the most important issues presented in this NOPR. I hope that the parties will assemble a correspondingly robust record that allows to us to dig into them in detail and evaluate whether the Commission’s proposals are consistent with our obligations under the statute.

III. PURPA Should Be Revised to Create More Competition, Not Less

Insofar as I can tell, the Commission interprets the success of PURPA since 1978 as evidence that the law is no longer needed and that the Commission should revise its regulations so that they do less to encourage QFs. I draw a slightly different conclusion from the same evidence. I view PURPA’s success in deploying gigawatts of relatively low-cost electricity as proof of the benefits of introducing competition into the bulk power system.

Several proposals in the record would do just that. For example, the National Association of Regulatory Commissioners (NARUC) submitted a proposal for how the Commission might implement section 210(m)(1), which was added by the Energy Policy Act of 2005. The new provision provided three bases for FERC to terminate a utility’s must-purchase obligation under PURPA, all of which hinged on QFs’ access to competitive wholesale electricity markets.19 The NARUC proposal urged the Commission to give meaning to section 210m(1)(C) of the Federal Power Act 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 auctions or RFPs for energy and capacity.20 In other words, it would use the pathway established by Congress’s amendments to PURPA to create more opportunity and competition in areas where, for non-incumbent utilities, PURPA is often the only game in town.

The NARUC proposal was a whitepaper, not a detailed NOPR. It would surely require more development before we could determine whether it satisfies PURPA’s statutory requirements. Nevertheless it represented a step in the right direction that would have been consistent with PURPA’s pro-competitive purposes. It was also an idea that we could have—and should have—amply explored through a technical conference or other proceeding since the Chairman indicated his intent to go forward with revisions to PURPA.

The Solar Energy Industries Association also put forward a pro-competitive proposal of the type that I would like to have explored in more detail in this NOPR.21 The proposal would address competitive solicitations as a means of procuring energy and capacity from all new generation resources, including QFs. It also discussed the potential for these competitive solicitations to set avoided cost under certain circumstances. As with the NARUC proposal, this proposal would revise PURPA to include more genuine competition rather simply revising the regulations to do less to encourage QFs.

Rather than seeking to expand competition, the majority is instead using the success of competition in certain parts of the country as a reason to scale back PURPA throughout the country. In some areas of the country, particularly those with developed RTO and ISO markets and with few, if any, vertically integrated utilities, competition is the norm and PURPA may not be necessary, at least for generators that are sufficiently large and sophisticated to participate on an equal footing with other market participants. But it does not necessarily follow that the healthy competition we see in those regions means that PURPA does not continue to play a vital role in other parts of the country, including those without RTO and ISO markets or where vertically integrated utilities dominate. To put it bluntly, the success that a QF might have in selling its energy and capacity within ISO New England Inc. tells you very little about the success a similar resource might have in the Southeast or the West, at least without PURPA. I worry that applying lessons learned in the truly competitive regions of the country to the less competitive regions will actually result in less competition and, ultimately, higher prices for consumers.

I support certain aspects of this NOPR that I believe are consistent with the Commission’s proper role in administering PURPA and are supported by the record developed so far. First and foremost, I agree that it is time to address the “one-mile” rule, which currently provides an irrebuttable presumption that resources located more than a mile apart are separate QFs.22 There is evidence compiled as part of the Commission’s 2016 technical conference on PURPA that suggests that this rule is susceptible to gaming and that some developers are splitting what should fairly be considered one project into a series of discrete projects spread separated by a mile each.23 I do not believe that is what Congress had in mind when it set out to promote small power production facilities in PURPA. The NOPR proposes what I believe is a reasonable framework for addressing this issue and I look forward to reviewing the comments we receive.

In addition, I support the proposal to require that QFs demonstrate commercial viability before securing a legally enforceable obligation with the relevant utility. It seems only fair to require that a proposed QF demonstrate that it is not speculative and will likely enter service before a utility incurs an obligation to purchase that QF’s output at any particular price. The proposal in today’s NOPR appears to strike a reasonable balance between allowing QFs to secure a commitment for purchase early enough in their development cycle so that they can use it to facilitate financing while preventing QFs from locking-in avoided-cost rates too far ahead of their actual delivery of any energy or capacity. Nevertheless, in contrast to the one-mile rule, the record on this question is relatively underdeveloped and I hope that parties will address the specifics of this proposal in detail.

Finally, I support the proposal to allow stakeholders to protest self-certification of QFs. If an entity believes a resource does not qualify as a QF, it should have the opportunity to protest the QF’s filing in the same way that stakeholders have the opportunity to protest most other Commission filings. At the very least, it seems unfair to require them to file a declaratory order, and pay tens of thousands of dollars, in order to inform the Commission of their views. * * *

The Commission seems to believe that PURPA’s time has passed. But that is Congress’s decision to make, not the Commission’s. So long as PURPA is on the books, we must faithfully implement the requirements of the law. Although I support certain elements of today’s NOPR, I am concerned that many of the Commission’s proposals will fall short of our statutory obligations. In addition, I am also disappointed that the Commission is not doing more to explore using PURPA to expand opportunities for genuine competition, including through section 210(m)—the avenue for reform that Congress enacted in 2005. I believe that focusing on expanding opportunities for genuine competition would far better serve the public interest than simply rebalancing the scales against QFs, which seems to be the principal goal of today’s NOPR.

For these reasons, I respectfully dissent in part


    1 Pub. L. No. 95-617, 92 Stat. 3117 (1978).
    2 See 16 U.S.C. § 824a-3 (2018).

    See 16 U.S.C. § 824a-3 (2018).
    3 See Am. Paper Inst., Inc. v. Am. Elec. Power Serv. Corp., 461 U.S. 402, 405 (1983) (describing Congress’s intent in enacting PURPA).
    4 Pub. L. No. 109-58, 119 Stat. 594 (2005).
    5 See Qualifying Facility Rates and Requirements; Implementation Issues Under the Public Utility Regulatory Policies Act of 1978, 168 FERC ¶ 61,184, at PP 19-21 (2019) (NOPR).
    6 U.S. Energy Info. Admin., What is U.S. electricity generation by energy source?, (last visited Sept. 19, 2019).
    7 See 18 C.F.R. § 292.304(e) (2019).
    8 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 30,865 (cross-referenced 10 FERC ¶ 61,150), order on reh’g, Order No. 69-A, FERC Stats. & Regs. ¶ 30,160 (1980) (cross-referenced at 11 FERC ¶ 61,166), aff’d in part & vacated in part sub nom. 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) (API).
    9 H.R. Rep. 95-1750, at 98-99 (1978) (Conf. Rep.) (“In interpreting the incremental cost of alternative energy, the Conferees expect that the Commission and the states may look beyond the costs of alternative sources which are instantaneously available to the utility.  Rather the Commission and states should look to the reliability of that power and the cost savings to the utility which may result at some later date by reasons of supply to the utility at that time of power from the cogenerate or small power producers.”).
    10 The NOPR proposes to eliminate the contract option for the energy component, keeping the long-term contract requirement in place for capacity.  That sounds more reasonable than it will often be in practice.  The NOPR later clarifies that the fixed capacity value may be zero if the state determines that the electric utility does not have a need for additional capacity resources.  See NOPR, 168 FERC ¶ 61,184 at P 67.  That would also mean that, in some instances, there would be no fixed element in an avoided cost contract, which would seem inconsistent with the Commission’s rationale justifying variable energy price contracts.  See id. P 70.
    11 See, e.g., June 29, 2016 Technical Conf. Tr. at 26-27 (Solar Energy Industries Association) (“The Power Purchase Agreement is the single most important contract of the development and financing of an energy project that’s not owned by a utility.  Without the long-term commitment to buy the output of that agreement at a fixed price, there is no predictable stream of revenue.  Without a predictable stream of revenues, there is no financing.  Without any financing, there is no project.”).
    12 See Statement of Travis Kavulla, Docket No. AD16-16-000, at 2 (June 29, 2016) (“Whether compensation for a QF is a matter of market clearing prices or of administrative decision-making is largely a reflection of how larger or utility-owned generation is compensated.”).
    13 NOPR, 168 FERC ¶ 61,184 at PP 50, 55-60.
    14 The NOPR proposes to allow states or utilities to use this liquid market price only for the “as-available” energy sales rate, not the capacity rate or for QFs that choose the contract option. But given that the Commission is also proposing to allow utilities to eliminate the fixed-price contract option for energy sales, QFs may have no choice but to rely on the “as-available” option for sales of energy.
    15 This issue, as much as any other, has been subject to vigorous debate in Congress.  See supra at 3.
    16 New PURPA Section 210(m) Regulations Applicable to Small Power Production and Cogeneration Facilities, Order No. 688, 117 FERC ¶ 61,078, at PP 9-12 (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).
    17 NOPR, 168 FERC ¶ 61,184 at P 121.
    18 To the contrary, the Commission has found that QFs less than 20 MW may not have non-discriminatory access, even within RTO/ISO markets.  In just the last few years, the Commission has explained that barriers such as transmission constraints are the very “circumstances explained in Order No. 688 that gave rise to the rebuttable presumption that smaller QFs lack nondiscriminatory access to markets.” N. States Power Co.,151 FERC ¶ 61,110, at P 34 (2015).  Today’s NOPR fails to provide any explanation for the departure from the Commission’s existing policy.
    19 Section 210m(1) provides:
      (A)(i) independently administered, auction-based day ahead and real-time wholesale markets for the sale of electric energy; and (ii) wholesale markets for long-term sales of capacity and electric energy; or

      (B)(i) transmission and interconnection services that are provided by a Commission approved regional transmission entity and administered pursuant to an open access transmission tariff that affords nondiscriminatory treatment to all customers; and (ii) competitive wholesale markets that provide a meaningful opportunity to sell capacity, including long-term and short-term sales, and electric energy, including long-term, short-term, and real-time sales, to buyers other than the utility to which the qualifying facility is interconnected. In determining whether a meaningful opportunity to sell exists, the Commission shall consider, among other factors, evidence of transactions within the relevant market; or

      (C) wholesale markets for the sale of capacity and electric energy that are, at a minimum, of comparable competitive quality as markets described in subparagraphs (A) and (B).

    16 U.S.C. § 824a-3(m)(1) (2018)
    20 National Association of Regulatory Utility Commissioners Supplemental Comments, Docket No. AD16-16-00 (Oct. 17, 2018), Attachment A at 8; id. (proposing the Commission’s Edgar-Allegheny criteria as a basis for evaluating whether a proposal was adequately competitive). 
    21 Solar Energy Industries Association Supplemental Comments, Docket No. AD16-16-000 (Aug. 28, 2019).
    22 18 C.F.R. § 292.204(a) (2019).
    23 See Statement of Paul Kjellander, Docket No. AD16-16-000, at 4-5 (June 29, 2016); Portland General Electric Company Comments, Docket No. AD16-16-000, at 6 (June 29, 2016).
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