Commissioner Richard Glick Statement
April 16, 2020
Docket Nos. EL16-49-001 and EL16-49-002
Orders: E-4 | E-5
Rehearing Dissent Regarding PJM MOPR
From the beginning, this proceeding has been about two things: Dramatically increasing the price of capacity in PJM Interconnection, L.L.C. (PJM) and slowing the region’s transition to a clean energy future. Today’s orders on rehearing make that even more clear. 1 Accordingly, I dissent as strongly as I can from both orders, which are illegal, illogical, and truly bad public policy.
The Commission started down this road in June 2018, when it is issued a deeply misguided order finding that PJM’s capacity market was unjust and unreasonable because it did not prevent state public policies from influencing the resource mix in PJM’s capacity market. 2 Then-Commissioner LaFleur aptly described that decision, which was based on a tenuous theory and a thin record, as “a troubling act of regulatory hubris.” 3 To address the purported problems with the capacity market, the June 2018 Order proposed a so-called “resource-specific FRR Alternative” 4 that would have bifurcated the market and cordoned off state-sponsored resources.
Then, in December 2019, after a year and a half of indecision, the Commission took a sharp right turn, altogether abandoning the resource-specific FRR Alternative in favor of a radical effort to extirpate state subsidies from the capacity market. 5 That order established a sweeping definition of state subsidy that will subject much, if not most, of the resources in PJM’s capacity market to a minimum offer price rule (MOPR). In so doing, the Commission turned the “market” into a system of bureaucratic pricing so pervasive that it would have made the Kremlin economists in the old Soviet Union blush. In addition, the order created a number of exemptions to the MOPR that will have the principal effect of entrenching the current resource mix by excluding several classes of existing resources from mitigation. Finally, in ditching the resource-specific FRR Alternative, the Commission made clear that it had no concern for the interests of states seeking to exercise their authority over generation resources or for the customers that would be left to pick up the tab.
Today’s orders affirm the conclusions in both the June 2018 and December 2019 Orders with a degree of condescension that is unbecoming of an agency of the federal government. And, as if that were not enough, today’s orders show no interest in the careful, detailed analysis that has long been the Commission’s hallmark. Instead, they turn away the several dozen rehearing requests with little more than generalities and claims that the parties misunderstood the underlying orders or the governing law—a charge that often more accurately describes the Commission’s orders today than it does those rehearing requests. 6 All parties deserve better from this Commission, even the ones that will benefit financially from today’s orders.
Today’s Orders Unlawfully Target a Matter under State Jurisdiction
The FPA is clear. The states, not the Commission, are the entities responsible for shaping the generation mix. Although the FPA vests the Commission with jurisdiction over wholesale sales of electricity as well as practices affecting those wholesale sales, 7 Congress expressly precluded the Commission from regulating “facilities used for the generation of electric energy.” 8 Congress instead gave the states exclusive jurisdiction to regulate generation facilitates. 9
But while those jurisdictional lines are clearly drawn, the spheres of jurisdiction themselves are not “hermetically sealed.” 10 One sovereign’s exercise of its authority will inevitably affect matters subject to the other sovereign’s exclusive jurisdiction. 11 For example, any state regulation that increases or decreases the number of generation facilities will, through the law of supply and demand, inevitably affect wholesale rates. 12 But the existence of such cross-jurisdictional effects is not necessarily a “problem” for the purposes of the FPA. Rather, those cross-jurisdictional effects are the product of the “congressionally designed interplay between state and federal regulation” 13 and the natural result of a system in which regulatory authority over a single industry is divided between federal and state government. 14 Maintaining that interplay and permitting each sovereign to carry out its designated role is essential to the cooperative federalist regime that Congress made the foundation of the FPA.
In recent years, the Supreme Court has repeatedly admonished both the Commission and the states that the FPA prohibits actions that “aim at” or “target” the other sovereign’s exclusive jurisdiction. 15 Beginning with Oneok,the Court underscored that its “precedents emphasize the importance of considering the target at which the state law aims.” 16 The Court has subsequently explained how that general principle plays out in practice when analyzing the limits on both federal and state authority. In EPSA, the Court held that the Commission can regulate a practice affecting wholesale rates, provided that the practice “directly” affects those rates and that the Commission does not regulate or target a matter reserved for exclusive state jurisdiction. 17 And, in Hughes, the Court returned to this theme, explaining that the FPA prohibits one sovereign from exercising its authority in a manner that aims at or targets the other sovereign’s exclusive jurisdiction, which, in that case, meant that a state could not “tether” its regulations to the Commission-jurisdictional wholesale market by requiring the resource to bid and clear in that market in order to secure a subsidy. 18 Together, those cases stand for the unremarkable proposition that the FPA prohibits one sovereign from taking advantage of the law’s cooperative federalist model to aim at or target, and, thus, interfere with, the other sovereign’s exclusive jurisdiction.
But that is exactly what the Commission’s new MOPR does. The record in this proceeding makes unmistakably clear that the purpose and effect of the new MOPR is to interfere with state regulation of generation facilities. Indeed, at every turn, the Commission’s has described the new MOPR as targeting the PJM states’ exercise of their exclusive jurisdiction to regulate generation facilities under FPA section 201(b). For example, the Commission began its determination section in the June 2018 Order with a discussion of purported problems evidenced in “[t]he records [before it, which] demonstrate that states have provided or required meaningful out-of-market support to resources in the current PJM capacity market, and that such support is projected to increase substantially in the future” 19 —i.e., the simple fact that states are exercising their reserved authority. The Commission explained that states’ exercise of their reserved authority created “significant uncertainty” and left other resources unable to “predict whether their capital will be competing against” subsidized or unsubsidized units, 20 again making clear that it is the mere exercise of that authority that is the purported problem. And, ultimately, the Commission found that PJM’s tariff was unjust and unreasonable because it did not prevent the ineluctable effects of state action from making their way to the wholesale market. 21
The December 2019 order made the Commission’s attempt to interfere with state authority even more clear. Its rationale for the new MOPR was that it was needed to combat increasing state policies and ensure that state actions do not shape entry and exit through the capacity market. 22 In addition, the Commission focused only on what it deemed to be states’ regulation of generation facilities, explicitly ignoring other state policies that might equally affect wholesale rates, such as so-called general industrial development policies or local siting support. 23 That concession is plain evidence that the new MOPR is not about the effects of state actions on wholesale rates, but rather all about blocking particular state efforts to shape the generation mix. Indeed, it is irrational in the extreme to profess concern about the effects of state policies on the generation mix, but then completely ignore whole classes of state policies that significantly affect wholesale prices in order to focus exclusively on the particular subsidies that various states have enacted pursuant to their reserved authority under FPA section 201(b). That result, and the Commission’s total failure to provide a reasoned explanation for the arbitrary lines it drew, show this proceeding for what it is: An effort aimed directly at state efforts to shape the generation mix, price suppression pretext notwithstanding. 24
And, lest there be any doubt, the December 2019 Order made clear that the Commission fully understood the effect of the MOPR on those disfavored state policies. As discussed further below, 25 the Commission refused to extend the MOPR to federal policies because doing so would “nullify” those policies. 26 Indeed, the Commission asserted that federal subsidies “distort competitive market outcomes” every bit as much as state subsidies 27 and that the only reason to refrain from applying the new MOPR to federal subsidies is that the Commission lacks the power to “nullify” or “disregard” federal legislation.” 28 That moment of honesty revealed that the Commission knew exactly what its new MOPR did to the state regulation of generation facilities targeted in its order, undercutting its various statements about the MOPR’s supposed limited effect on state resource decisionmaking. The problem for the Commission, is that it is equally impermissible for it to use its authority over wholesale rates in an attempt to nullify state regulation of the generation mix and it cannot, consistent with reasoned decisionmaking, insist that the MOPR has one effect on federal policies and a totally different effect on state policies. If the MOPR would nullify federal policies—an assessment with which I agree—than it must equally nullify state policies.
And, finally, the December 2019 Order admitted that its purpose was to the disfavored state actions with what the Commission described as “price signals on which investors and consumers can rely to guide the orderly entry and exit of economically efficient capacity resources.” 29 That is to say, its goal was to establish a set of price signals to determine resource entry and exit in the capacity market for the explicit purpose of superseding state resource decisionmaking and to better reflect the Commission’s preferences for merchant generators that do not rely on compensation they receive for addressing externalities.
In short, the December 2019 Order conceded that the “problem” was state efforts to shape the generation mix, that the Commission was focused only on those state efforts, that the Commission’s action would “nullify” those state efforts, and that it would override those efforts in order to send price signals that better aligned with the Commission’s preferences. 30 That directly targets states’ reserved authority under section 201(b).
Today’s orders erase any lingering doubt about the purpose and effect of the Commission’s new MOPR. In addition to affirming its earlier statements, the Commission doubles down on its still unexplained “most nearly tethered” standard, this time describing it as some form of administrative grace for which states should thank their lucky stars. 31 Putting aside the dripping arrogance of that worldview, the only issue that phrase elucidates is the extent to which today’s orders are focused on blocking state efforts to shape the resource mix and not on the effects of state policies on wholesale markets. 32 After all, if today’s orders were actually concerned with the wholesale-market effects of state policies, they would not excuse from the new MOPR general industrial development policies and local siting support—categories which have much larger effects on the wholesale market than many of the policies targeted in today’s orders. 33
But that is not even the half of it. A few hundred paragraphs later, the Commission comes right out and admits that its goal is to penalize and, ultimately, discourage states from exercising their exclusive jurisdiction. In patting itself on the back for issuing what it describes as a “decisive order,” the Commission laments the fact that its supposedly decisive order was not enough to deter states from continuing to exercise their section 201(b) jurisdiction. 34 But it is no more our role to deter states from regulating generation facilities than it is the states’ role to prevent us from ensuring that rates are just and reasonable. 35 And, as the Supreme Court has repeatedly made clear, the FPA does not permit FERC or the states to exercise their authority under the FPA to target the other sovereign’s exclusive jurisdiction. 36
All told, this simply is not a proceeding where “the Commission’s justifications for regulating . . . are all about, and only about, improving the wholesale market.” 37 Unlike the rule upheld in EPSA, where the matters subject to state jurisdiction “figure[d] no more in the Rule’s goals than in the mechanism through which the Rule operates,” state actions are front and center in the Commission’s justification for acting. 38 To be sure, the Commission doffs its hat to “price suppression” throughout the orders. But repeating the phrase “price suppression” does not change the fact that the Commission’s stated concern in the June 2018 Order, the December 2109 Order, and today’s orders is the states’ exercise of their authority under section 201(b) or the fact that the goal of the new MOPR is to “nullify” and “disregard” the effects of state resource decisionmaking. Similarly, the Commission’s observation that it is not literally precluding states from building new resources is beside the point. As I explained in my earlier dissent, that is the equivalent of saying that a grounded teenager is not being punished because he can still play in his room—it deliberately mischaracterizes both the intent and the effect of the action in question. 39
The extent to which the Commission is attempting to interfere with state resource decisionmaking is even clearer with a little context. The MOPR was originally used to mitigate buyer-side market power within the wholesale market 40 —a concern at the heart of the Commission’s responsibility to ensure that wholesale rates are just and unreasonable. 41 And for much of the MOPR’s history, that is what it did. Even when the Commission eliminated the categorical exemption for resources developed pursuant to state public policy, the Commission limited the MOPR’s application only to natural gas-fired resources—i.e., those that would most likely be used as part of an effort to decrease capacity market prices. 42
How things have changed. Today, the Commission expressly admits that, for the first time, the MOPR is no longer about buyer-side market power. 43 Instead, as noted, it is all about and only about nullifying the effects of state public policies. That dramatic shift began only in 2018, more than a decade after the MOPR was first employed to mitigate the exercise of market power. 44 The intervening two years have been head-spinning as the Commission has rapidly transformed a narrowly tailored anti-monopsony measure into a regime for blocking state efforts to shape the generation mix.
At no point, however, has the Commission been able to coherently justify the MOPR’s change of target. It first claimed that this transformation of the MOPR was necessary to ensure “investor confidence” and the ability of unsubsidized resources to compete against resources receiving state support. 45 A few months later, at the outset of this proceeding, the Commission abandoned “investor confidence” and asserted that the need to mitigate state policies in order to protect the “integrity” of the capacity market—another concept that it did not bother to explain. 46 And last December, the Commission added yet another new twist: That state subsidies “reject the premise of the capacity market.” 47 But, as with investor confidence and market integrity, it is hard to know exactly what that premise is. Today’s orders provide more of the same, reiterating those buzz words without any further explanation. 48 If there is one thing that those inscrutable terms share, it is their inability to conceal, much less justify, the fundamental shift in the Commission’s focus. 49 The Commission’s effort to recast the MOPR as always having been about price suppression at some level of generality 50 obfuscates that point and badly mischaracterizes the recent shift in the MOPR’s focus.
Neither of the Commission’s responses provide it much cover. First, the Commission asserts that the new MOPR does not intrude on states’ exclusive jurisdiction just because it “affect[s] matters within the states’ jurisdiction.” 51 Of course that is true; EPSA tells as much. 52 But it is also beside the point. My argument—and the arguments made by several parties on rehearing 53 —is that the Commission is exercising its authority over wholesale sales to “aim at” or “target” matters subject to exclusive state jurisdiction. As explained above, the “goals” of the new MOPR and the mechanism “through which [it] operates” demonstrate an unmistakable focus on states’ exercise of their reserved authority. 54 That means that, unlike the rule in EPSA, today’s orders are not “all about, and only about, improving the wholesale market.” 55 Accordingly, the Court’s precedent regarding the incidental effects of a valid exercise of Commission authority are beside the point.
In addition, the Commission appears to suggest that it can overstep its jurisdictional bounds only if it literally requires states to build certain resources or prevents states from doing the same. 56 In other words, the Commission’s theory of the case is that it exceeds its jurisdiction only if it directly regulates the construction of new resources. But that suggestion is inconsistent with the Supreme Court’s recent cases, including EPSA, that make clear that the FPA does not permit federal or state regulators to use their authority in an attempt to interfere with the other’s sphere of exclusive jurisdiction by aiming at or targeting the matters peculiarly within that sphere. 57 Accordingly, the Commission’s reasoning is both a misapplication of the law and arbitrary and capricious insofar as it utterly misses the point of the argument made by several parties on rehearing. 58
Second, the Commission points to a handful of court of appeals decisions upholding various Commission orders addressing capacity markets. None of those cases sanction the Commission’s actions in this proceeding. The December 2019 Rehearing Order contends principally that the U.S. Court of Appeals for the Third Circuit’s (Third Circuit) decision in NJPBU inoculates the Commission against any charge that it has exceeded its jurisdiction by intruding on state authority over resource decisionmaking. 59 That is not how precedent works. Just because a court upheld one order against a particular challenge does not mean that it would uphold all similar orders against other challenges.
In any case, the orders in this proceeding bear only a surface-level similarity to NJBPU. 60 As the Third Circuit explained, the purpose of the MOPR on review in that case was limited to mitigating the exercise of buyer-side market power 61 —a concern that, as noted, lies at the core of the Commission’s authority over wholesale rates and practices. 62 Consistent with that focus, that MOPR applied only to natural gas-fired power plants because they were the resources that a large net buyer of capacity could rationally use to suppress the capacity market clearing price. 63 In that case, the Commission eliminated an “exception” from the MOPR that had previously allowed state-sponsored natural gas-fired units to skirt the MOPR. 64 The Commission justified its decision by pointing to a pair of (ultimately preempted) state laws that subsidized new natural gas plants by effectively guaranteeing them a predetermined wholesale rate. 65 The court concluded that all the MOPR did in that case was ensure a “new resource is economical—i.e., that it is needed by the market—and ensures that its sponsor cannot exercise market power by introducing a new resource into the auction at a price that does not reflect its costs and that has the effect of lowering the auction clearing price.” 66 In addition, in reviewing those facts, the court observed that “FERC’s enumerated reasons for approving the elimination of the state-mandated exception relate directly to the wholesale price for capacity.” 67
Today’s orders are an altogether different animal. As noted above, the December 2019 Rehearing Order explicitly disavows the mitigation of market power as the basis for the new MOPR, 68 instead making it “all about and only about” 69 “nullifying” 70 state efforts to shape the generation mix 71 —or at least those state efforts that the Commission dislikes. 72 As explained above, today’s orders—and, indeed, every order in this proceeding—has made clear that the aim of the new MOPR is to “deter” states from taking actions of which the Commission disapproves. 73 That makes today’s orders a far cry from NJBPU. In addition, the new MOPR mitigates indiscriminately and explicitly does not require that the mitigated state policy actually affect the capacity market clearing price or even be likely to have such an effect. 74 That is distinctly unlike the targeted MOPR in NJBPU that addressed only the resources most likely to be used in an exercise of market power. 75 Simply put, the MOPR addressed in today’s orders is so fundamentally different from that before the court in NJBPU as to render the holding in that case next to meaningless as applied to these orders.
The Commission also suggests that the D.C. Circuit’s decisions in Connecticut Department and Municipalities of Groton support today’s outcome. 76 But those cases have even less in common with the facts before us than NJBPU. In both instances, the court upheld the Commission’s authority to require wholesale buyers to purchase particular quantities of capacity. 77 As the Court explained in Connecticut Department, the Commission’s focus was squarely on market structures that would motivate utilities to develop or acquire the necessary capacity. 78 But the Court went out of its way to explain that nothing in the Commission’s orders in any way limited the states’ ability to influence or, indeed, directly select the resources that would meet those capacity requirements. 79 And that is where any superficial similarity to today’s orders ends. As noted, the new MOPR is expressly about limiting—“nullify[ing]” to use the Commission’s word 80 —state efforts to shape the resources that meet those requirements. 81 What is more, that nullification is the express reason for of the Commission’s action: The orders’ goal is to block the effects of state policies and deter states from exercising their authority over generation facilities. 82
Finally, it is important to be precise about my jurisdictional argument. I do not believe that any MOPR is per se invalid just because it complicates state efforts to regulate generation facilities. 83 After all, NJBPU indicates that the use of a MOPR that addresses matters squarely within the Commission’s authority is permissible, at least in certain circumstances. 84 But that is not what we have here. As explained above, today’s orders confirm that the Commission is deploying its new MOPR to aim at state resource decisionmaking and for the purpose of substituting its own policy preferences for those of the states. That “fatal defect” renders this particular MOPR in excess of the Commission’s jurisdiction. 85
The Commission’s Orders Are Arbitrary and Capricious
Today’s orders are also arbitrary and capricious. The upshot of the majority’s position is that PJM’s capacity market is a just and reasonable construct only if the Commission “nullifies” the effects of state public policies. That interpretation of the FPA is as radical as it is wrong and finds no support in the 80-year history of the Act or in any Commission or court precedent. 86 I suppose it should be no surprise that installing such an unprecedented mitigation regime proves to be a difficult task. But that is no excuse for an order riddled with determinations that are unsupported by the record and deeply arbitrary and capricious. The whole purpose of the Administrative Procedure Act is to prevent an agency from relying on fundamentally flawed reasoning in order to impose its policy preferences. If ever those protections were needed to address an action of the Commission, it is this one, both because of the shoddy reasoning on which the Commission’s actions are based and the tremendous damage they may ultimately do. In the following sections, I detail several of what I view to be the most serious flaws in the Commissions reasoning, any of which should be sufficient to invalidate today’s orders.
The Commission Has Not Shown that the Existing Rate Was Unjust and Unreasonable
Section 206 of the FPA requires the Commission to show that the existing rate is unjust and unreasonable or unduly discriminatory or preferential before it can set a replacement rate. 87 The June 2018 Rehearing Order fails to articulate a reasoned basis for concluding that the pre-existing capacity market rules were unjust and unreasonable or unduly discriminatory or preferential. Instead, the Commission doubles down on a conclusory theory of the case that does not seriously wrestle with the contrary arguments and evidence in the record.
The June 2018 Rehearing Order does not rely on any evidence that state policies are actually distorting prices, much less that they are doing so in a way that imperils resource adequacy in the region. Instead, the Commission’s case rests on two propositions: (1) that certain state subsidies permit resources to lower their capacity market offers, which, if enough resources do it, will lower the clearing price 88 and (2) that the number of potentially subsidized megawatts in PJM appears likely to grow in coming years. 89 That is the entirety of the Commission’s theory. And that is not enough, on this record, to reasonably conclude that PJM’s existing tariff was unjust and unreasonable or unduly discriminatory or preferential.
As numerous parties argued on rehearing, the idea that resource adequacy in PJM is currently imperiled by state subsidies is, frankly, laughable. The Base Residual Auction has consistently procured more resources than required to meet PJM’s reliability requirement and thousands of megawatts of additional resources have elected not to retire, even though they are not receiving any capacity market payment. 90 If state policies are, in fact, a threat to resource adequacy, there is certainly no evidence of that in PJM’s current reserve margins. Instead, as discussed in some detail in another statement I am issuing today, if there is a problem in PJM’s capacity market, it is not that prices are too low, but rather that the market is designed to produce prices that are too high, over-procuring capacity and dulling the price signals in the energy and ancillary service markets. 91 Faced with that fact, the Commission responds with the assertion that state subsidies will surely cause a problem in the future. 92 Maybe, but there is no evidence in this record that suggests that state policies will cause any resource adequacy concerns whatsoever.
Apparently recognizing that point, the Commission pivots to economic theory as the basis for its action. 93 It is true that the Commission need not prove basic economic principles every time that it seeks to act on them. After all, “[a]gencies do not need to conduct experiments in order to rely on the prediction that an unsupported stone will fall.” 94 Instead, agencies can rely on economic theory to make predictive judgments about howthe future will play out. 95 But that does not mean that an agency can turn “economic theory” into a “talismanic phrase that does not advance reasoned decision making” and claim to have satisfied its obligations under the APA. 96 In other words, an agency cannot articulate a principle, label it “economic,” make a prediction, and move on without wrestling with contrary record evidence or reasonable alternative applications of that economic theory.
But that is exactly what the June 2018 Rehearing Order does. It asserts that state subsidies in PJM are increasing, that subsidies reduce the costs of the resource being subsidized and, therefore, subsidies will cause more subsidized resources to clear the capacity market. All true. From that though, the Commission concludes that PJM’s tariff will no longer ensure resource adequacy at rates that are just and reasonable and not unduly discriminatory or preferential, which is where its reasoning gets a little tenuous, as the economic principle articulated does not lead ineluctably to the regulatory conclusion reached. Instead, the record is replete with evidence and reasonable theories that could support an alternative conclusion. For one thing, the evidence in the record of continued high prices and entry of new resources (not to mention, retention of old ones) could just as easily support the conclusion that a more-than-adequate quantity of resources will remain in the market, state subsidies notwithstanding. 97 As numerous parties point out, that has been the experience to date in PJM. 98 Why the Commission is so confident that things will change at some undefined future inflection point is never explained. Nor does the Commission explain why it is confident that those assumed effects justify an increase in customer’s rates.
In addition, it is equally reasonable to suggest that the natural effect of state subsidies (indeed, in many cases, their intended result) will be to bring online large amounts of new resources that will themselves help to ensure resource adequacy. 99 Nothing in today’s orders explains why the Commission is so confident that the deployment of state-sponsored resources will impair PJM’s ability to ensure resource adequacy at just and reasonable rates rather than enhancing it. After all, it is worth remembering that, as discussed above, the FPA expressly reserved the regulation of generation facilities to the states and Congress presumably expected the states to wield that reserved authority. 100 Why the exercise of that authority is inherently unjust and unreasonable or a “problem” in need of “solving” is never clearly explained. Repeated incantations of the phrase “economic theory” does not provide a reasoned answer to the question.
The closest the Commission comes to explaining its confidence in a looming future problem is its series of elliptical statements about investor confidence and the merchant business model. Throughout this proceeding, the Commission has relied on various inscrutable principles, such as “investor confidence” or “market integrity,” to justify its new MOPR. 101 At various points in the June 2018 Order, and again today, the Commission expressed concern about the challenges state policymaking may create for investors in particular resources in the capacity market 102 and the June 2018 Rehearing Order specifically raises the concern that state policies may harm unsubsidized generators. 103 These statements seem to suggest that the problem with the state policies is that they may reduce the profit margins of unsubsidized resources and make it correspondingly less likely investors will pour their money into those resources, which the Commission assumes will impair resource adequacy.
I recognize and appreciate the large influx of capital that investors and the merchant business model, more generally, have brought to PJM over the last two decades. Those investments have enhanced the grid’s reliability while helping to decrease its carbon intensity—both good outcomes. But it is not our responsibility to protect particular businesses, business models, or their investors from state regulation. If states choose to address a market failure by promoting particular resource types or business models over others, it is not for the Commission to give a leg up to business models that might lose out as a result. In any case, PJM’s generation resource mix has long reflected a mix of vertically integrated utilities and merchant generators, both of which have benefited from public policies. The June 2018 Rehearing Order does not adequately explain the Commission’s apparent confidence that that cannot continue in a future in which states continue to exercise their authority under FPA section 201(b).
The Commission also makes the assertion that state policies are a problem because they create “significant uncertainty” and “investors cannot predict whether their capital will be competing” against subsidized resources. 104 As I explained in my dissent from the June 2018 Order, uncertainty about regulation will always be endemic in a regulated industry. 105 And nothing in the June 2018 Order or the June 2018 Rehearing Order explains why the purported uncertainty caused by state policymaking is more problematic than the other forms of uncertainty that pervade the industry.
The bottom line is that neither the June 2018 Order nor today’s order on rehearing has adequately explained why the existing tariff is unjust and unreasonable or unduly discriminatory or preferential. The sum total of the Commission’s analysis is that the PJM states will likely, in the future, subsidize more generating resources and that, all else equal, those subsidies will cause those resources to offer into the capacity market at lower prices than they would otherwise. But that alone does not prove the existing tariff is unjust and unreasonable, especially given the long history of state policies affecting the capacity market and the equally plausible future scenarios in which the capacity market continues to ensure resource adequacy at just and reasonable rates while state-sponsored resources co-exist with other business models. After all, to carry its burden under section 206, the Commission must do more than articulate a theory, label it “economics,” and call it a day.
The Commission Has Not Shown that Its Replacement Rate Is Just and Reasonable
If the Commission meets its burden to show that the existing rate is unjust and unreasonable or unduly discriminatory or preferential, then the burden is again on the Commission to establish a “replacement rate” that is itself just and unreasonable and not unduly discriminatory or preferential. 106 The December 2019 Rehearing Order fails to articulate a reasoned basis for concluding that the new MOPR meets that burden. Instead, like the June 2018 Rehearing Order, it doubles down on a conclusory statements that do not seriously wrestle with the contrary arguments and evidence in the record.
The Commission’s Definition of State Subsidy Is Arbitrary and Capricious
The crux of the December 2019 Order, and today’s order on rehearing, is the Commission’s definition of subsidy. That definition, however, is also the source of many of the Commission’s most arbitrary and capricious determinations. Simply put, it is little more than a series of arbitrary lines that do not comport with the Commission’s explanation for why the existing tariff was unjust and unreasonable or why the new MOPR will produce a just and reasonable rate.
Excluding Federal Subsides Is Arbitrary and Capricious
No single determination is in today’s orders is more arbitrary than the Commission’s exclusion of all federal subsidies from the new MOPR. 107 Federal subsidies have pervaded the energy sector for more than a century, beginning even before Congress, in the FPA, declared that the “business of transmitting and selling electric energy . . . is affected with a public interest.” 108 Since 1916, federal taxpayers have supported domestic exploration, drilling, and production activities for our nation’s fossil fuel industry. 109 And since 1950, the federal government has provided roughly a trillion dollars in energy subsidies, of which 65 percent has gone to fossil fuel technologies. 110 Those federal policies present all the same “problems” that the Commission identifies with state policies. They have “artificially” reduced the price of natural gas, oil, and coal, which in turn has allowed resources that burn these fuels—including many of the so-called “competitive” resources that stand to benefit from today’s orders—to submit “uncompetitive” bids into PJM’s markets. By lowering the marginal cost of fossil fuel-fired units, federal policies have allowed those units to operate more frequently and have encouraged the development of more of those units than would otherwise have been built. Indeed, those subsidies, even ones that have subsequently lapsed, are a major reason why many of the current resources in PJM are able to bid into the capacity market at the levels they do.
Federal subsidies remain pervasive in PJM. The federal tax credit for nonconventional natural gas 111 sparked the shale gas revolution, triggering a steep decline in natural gas prices, which, in turn, drove the spike in new natural gas-fired power plants starting in the early 2000s. Similarly, federal subsidies such as the percentage depletion allowance and the ability to expense intangible drilling costs have shaved billions of dollars off the cost of extracting coal and natural gas—two of the principal sources of electricity in PJM. 112 In addition, the domestic nuclear power industry would not exist without the Price-Anderson Act, which saves nuclear power generators billions of dollars through indemnity limits that enable them to secure financing and insurance at rates far below their true cost. 113 Federal subsidies have also promoted the growth of renewable resources through, for example, the production tax credit (largely used by wind resources) 114 and the investment tax credit (largely used by solar resources). 115 These and other federal government interventions have had a far greater “suppressive” impact on the capacity market than the “state subsidies” targeted by today’s orders, especially when you consider that resources having benefited from them make up the vast majority of the cleared capacity in PJM. 116
Nevertheless, today’s order affirms the December 2019 Order’s decision to exclude all federal subsidies from the new MOPR on the theory that the Commission lacks the authority to “disregard or nullify the effect of federal legislation.” 117 It is true that the FPA does not give the Commission the authority to undo other federal legislation. But the Commission’s defense of applying the new MOPR to state policies is that it neither disregards nor nullifies those policies, but instead addresses only the effects that those policies have on the PJM market. 118
“[T]he Commission cannot have it both ways.” 119 If the MOPR disregards or nullifies federal policy, then it must do the same to state policy. And if it does not nullify or disregard state policy, then the Commission’s justification for exempting federal subsidies collapses. The Commission, however, does not even attempt to explain its conclusion that applying the new MOPR to state policies respects authority, but applying it to federal policies would “disregard” or “nullify” federal authority. The failure to address, much less resolve, that tension is arbitrary and capricious.
Instead of confronting this tension, the December 2019 Order cited to a number of cases for well-established canons of statutory interpretation, such as that the general cannot control the specific and that federal statutes must, when possible, be read harmoniously. 120 Today’s order does the same. 121 But those general canons do not help much. They discuss rules of statutory interpretation that are not disputed here and they certainly do not give the Commission license to pretend that the new MOPR has one type of effect on state policies and another type on federal policies. 122 In any case, if we assume, for the sake of argument, that the Commission’s benign characterization of the effect of the new MOPR on state policies is accurate, 123 then no number of interpretive canons can cure the Commission’s arbitrary refusal to apply the MOPR to federal subsidies.
In addition, the Commission asserts that it may treat state and federal subsidies differently because it “has a reasonable basis to distinguish federal subsidies and State Subsidies, that is, whether the subsidies were established via federal law or state law.” 124 But that tautology is not as helpful as it might at first seem. Just as not all discrimination is undue, irrelevant differences do not make parties dissimilarly situated. 125 Today’s order does not coherently explain why the difference between federal and state subsidies is relevant to its theory of the case.
The Commission’s apparent belief—implicit today, but stated explicitly in the December 2019 order—is that resources that receive federal subsidies are not similarly situated to resources that receive state subsidies because the Commission cannot nullify or disregard federal policies, but can do that to state subsidies. 126 Putting aside whether that is true, 127 that line of reasoning just brings us back to square one as it relies on an unexplained distinction in the differing effects that the MOPR has on state and federal policies.
Treating Any Revenue or Other Funding Tangentially Related to a State Law As a Subsidy Is Arbitrary and Capricious
As discussed at the outset, the FPA divides jurisdiction between the Commission and the states, envisioning an important role for both in ensuring that the electricity sector is regulated in a manner consistent with the public interest. As the Commission explains, Congress enacted Title II of the FPA to fill the “Attleboro Gap” by “allow[ing] the federal government to step in and regulate interstate transactions over which no single state had authority to regulate.” 128 And while the FPA did more than just “fill the gap,” 129 it was nevertheless “‘drawn with meticulous regard for the continued exercise of state power.’” 130 It would be strange if, having so “meticulous[ly]” preserved state authority, Congress believed that the “continued exercise of” that authority would become inherently a problem. 131
And yet that is precisely what the December 2019 Rehearing Order does. It treats many fundamental elements of state regulation as impermissible subsidies simply because the state is involved. Even putting aside the jurisdictional problems with that approach, 132 today’s order does not explain why it is just and reasonable to mitigate any resource that is affected by many of the most foreseeable consequences of the FPA’s jurisdictional framework. Nor does it make any effort to consider the litany of practical challenges and complications that that approach creates, even though many of them were squarely presented on rehearing.
Take the example of state default service auctions. As PJM explained in its rehearing request, state default service auctions are state-directed “mechanisms by which load-serving entities in retail choice states acquire obligations to provide energy and related services to retail customers.” 133 In layman’s terms, that means that they are a market-based mechanism for ensuring that all retail customers have access to reliable and affordable electricity. As the New Jersey Board of Public Utilities—which oversees one of these auctions—explained, these mechanisms are best viewed as hedging constructs that help ensure that state-regulated retail suppliers have access to reliable electricity without wild swings in price. 134 In New Jersey’s case, the default service auction is a voluntary mechanism that will rarely, if ever, produce a state-regulated contract with an actual generator (as opposed to a power marketer—i.e., a middle man) or support the retention or new entry of particular resources 135 —details that are apparently too complicated or too inconvenient for the Commission to wrestle with. Today’s order finds that a state default service auction qualifies as a State Subsidy because it is a state sponsored process that results in indirect payments to various resources. 136
It is not clear from the record before us exactly how far reaching this decision will be. New Jersey alone serves over 7,000 MW of retail load through its BGS auctions, 137 and every indication is that other retail-choice states have similar mechanisms. 138 To start with, the District of Columbia Public Utility Commission and Pennsylvania Public Utility Commission sought clarification and rehearing of the December 2019 Order, understandably concerned that it could mean that any resource that serves load in those states would be subject to the Commission’s administrative pricing regime. 139 In addition, Maryland runs a similar default service auction that procures service for over 50 percent of the state’s retail load. 140 Delaware too has a default service auction, which cleared over 500 MW in the most recent auction. 141 Additionally in Ohio each utility has its own Standard Service Offer auction for retail load. 142 It quickly becomes clear that state default auctions are a commonplace in retail choice states and can often be used to meet the needs of upwards of 50% of retail load. The Commission’s decision to label these auctions—which sometimes cover more than half a state’s retail load—state subsidies could have sweeping consequences for the retail-choice states that make up the majority of PJM states.
And is if that were not bad enough, the Commission makes no effort to wrestle with the practical challenges of its edicts. As the New Jersey Board explained in its rehearing request, the “suppliers” in New Jersey’s default service auction are generally power marketers that rely on either financial or physical hedging and are not necessarily backed by particular physical generators. 143 Do the Commission’s statements in today’s orders mean that PJM, the Market Monitor, or someone else will have to chase down every resource power marketers use to satisfy a default service auction contract? In addition, default service auctions generally do not align with PJM’s annual single-delivery-year capacity auctions. For example, in New Jersey the auction runs annually and covers only one-third of load at time, but with three year contracts. 144 In the District of Columbia the auctions are held annually. 145 And in Pennsylvania they are run “quarterly, or every 6 months.” 146 How will PJM, the Market Monitor, or the Commission sort out which resources are to be mitigated in PJM’s Base Residual Auction based on those differing state calendars?
I find the failure to carefully consider these impacts on a fundamental aspect of state regulation particularly troubling. This Commission has rightly enjoyed a reputation for focusing on the technical and arcane elements of providing reliable electricity at just and reasonable rates rather than on making broad policy pronouncements. Today’s orders will do much to damage that reputation. It makes clear that the Commission is uninterested in the effects its orders may have on how states carry out their basic responsibilities. Instead, it is comfortable pursuing its quixotic quest to rid the wholesale market of state subsidies and leave it to the states to pick up the pieces.
Excluding State Actions That May Equally “Suppress” Prices Is Arbitrary and Capricious
Although the definition of state subsidy is overbroad, it is also irrational. Today’s order on rehearing affirms the December 2019 Order’s unreasoned distinctions drawn among different state public policies. In particular, the Commission expressly excludes state industrial development policies and local siting subsidies from its definition of state subsidy. 147 The rationale, while murky, seems to be that those policies are “too attenuated” from the wholesale rate to constitute an impermissible state policy while other state policies, even ones with a lesser effect on the wholesale rate, are somehow more closely related. 148 That distinction is neither reasonable nor reasonably explained.
Let’s begin with the fact that the distinction drawn is inconsistent with the Commission’s rationale for the new MOPR. As discussed, throughout this proceeding the Commission has asserted that the problem with state policies is their ability to “suppress” the wholesale rate. 149 And, in the December 2019 Rehearing Order, the Commission again dismisses arguments that the MOPR should apply only to state policies that materially affect the capacity price. 150
That is irrational. “General industrial development” policies, such as reduced tax rates, can have an enormous effects on resources’ going forward costs, leading resources to “reduce their offers commensurately to ensure they clear the market,” exactly the way the Commission described state policies that are subject to the new MOPR. 151 Moreover, the ubiquity and potential cumulative effect of these programs—which the Commission does not contest 152 —would seem to suggest that they represent exactly the sort of threat to “market integrity” about which the Commission’s purports to be so concerned. 153 If today’s orders were actually concerned about the price suppressive effects of state policies, general industrial development and local siting policies would have to be front and center in any rational response. The fact that they are not shows the extent to which the new MOPR is a campaign to stamp out disfavored state efforts to shape the generation mix and not to address capacity prices themselves.
The Commission’s effort to justify that arbitrary line drawing only underscores the point. The Commission again asserts that the new MOPR is aimed only at state policies that are “most nearly . . . directed at or tethered to the” wholesale rate. 154 But as discussed above, that awkward repurposing of a preemption term of art does not make things any clearer. 155 It certainly does not explain why it is rational for the Commission to apply the new MOPR only to those state policies that it believes are close-to-but-not-preempted 156 or why the degree of “attenuation” is relevant in a proceeding that is nominally about actual effects on wholesale rates. Indeed, at no point in this proceeding has the Commission explained why, if the “problem” at hand is the effect of state policies on wholesale rates, it is reasonable to target only certain state efforts and not others that may well have a greater wholesale market effect. 157 The failure to do so is arbitrary and capricious.
Addressing Only State Actions that Reduce Cost Is Arbitrary and Capricious
The December 2019 Rehearing Order grants clarification that the Regional Greenhouse Gas Initiative (RGGI) is not an actionable subsidy. 158 I am glad to hear it. Although I maintain that the distinction drawn in today’s order is inconsistent with the most natural reading of the Commission’s subsidy definition, 159 just about anything that limits the extent of the Commission’s interference with state resource decisionmaking is a step in the right direction.
But although that outcome may be a good one, it vividly illustrates the arbitrariness with which the Commission is going after state policies. The Commission’s single-sentence clarification regarding RGGI is a little light on reasoning, but the upshot appears to be that RGGI does not cause problems for “market integrity,” 160 “investor confidence,” 161 “the first principles of capacity markets,” 162 or the “premise of a capacity markets” 163 because it addresses the externality of climate change by raising prices, rather than by lowering them. At no point, however, does the Commission explain why a state effort to tax the harm associated with a market failure is consistent with capacity markets, but a state effort to address the same harm by subsidizing resources that do not contribute to that externality is inconsistent with capacity markets. It may well be that a so-called “Pigouvian tax” is economically preferable to a “Pigouvian subsidy,” 164 but, even if true, that does explain why the former is consistent with the Commission’s various capacity market buzzwords, but the latter is not.
In any case, the Commission’s decision to find one approach inherently problematic and the other acceptable illustrates the extent to which it is meddling directly in state resource decisionmaking. Whatever you think about the economic merits of subsidies versus taxes as ways of addressing externalities,there should be no question that a state’s choice between the two approaches is entirely the state’s to make or that the Commission has no business in enacting regulations that give a preference to one approach over the other. In this example, the Commission’s willingness to pick and choose which of the broadly equivalent state approaches to addressing climate change are allowed to affect the wholesale rate and which are not, is clear and unmistakable evidence of its meddling in decisions that the FPA expressly reserves to the states. The failure to recognize, much less explain, why it is appropriate to pick and choose which state policies are acceptable and which are not is arbitrary and capricious.
And that is particularly so given the structure and purpose of the capacity market, which exists to provide the “missing money. 165 Because the missing money is the net difference between a resource’s revenue and its costs, 166 a resource should be indifferent, for the purposes of the capacity market, between a state policy that forces resources to internalize the cost of the externality or one that achieve the same thing by paying resources for not contributing to the externality. In other words, the Commission is relying on a distinction that is, for our purposes today, without a difference.
Ignoring the Cost Impacts of the New MOPR Is Arbitrary and Capricious
One of the most glaring omissions from the December 2019 order was its failure to make any effort to consider the costs of the new MOPR. 167 As the Commission acknowledges, “[s]etting a just and reasonable rate necessarily ‘involves a balancing of the investor and consumer interests.’” 168 The Commission’s various orders in this proceeding spend plenty of time asserting that investors need sweeping reforms in order to remain “confident” in the PJM capacity market. Unfortunately, the costs to consumers of making investors so confident went unmentioned in both the Commission’s June 2018 and December 2019 orders.
Many parties raised the Commission’s failure to consider consumer interests on rehearing. 169 In response, the Commission recites general propositions about the importance of customer interests only to undercut itself almost immediately thereafter. For example, the Commission begins one paragraph by stating that it “disagree[s] that the Commission failed to consider the costs of the replacement rate.” 170 But it then spends the rest of that paragraph explaining why it did not consider any estimate of the customer impacts before concluding that the resulting costs, whatever they may be, are necessarily just and reasonable because they “protect the integrity of the capacity market, which, in turn, ensures that investors will continue to be willing to develop resources to meet current and future reliability needs.” 171 That sort of conclusory statement is hardly convincing evidence that the Commission actually took a hard look at the costs its orders will impose on customers.
The Commission dismisses as “speculative” any estimates of those costs. It would appear that a fair degree of work went into many of those estimates and I do not see the wisdom in dismissing them out-of-hand just because the details of the new MOPR have yet to be fully worked out. 172 After all, if the record provides enough evidence for the Commission to confidently assess that the costs of its new MOPR are worth it, 173 you would think it would provide enough evidence to at least gauge the likely impact on consumers.
In addition, there is every reason to believe that the actual costs of today’s orders will increase with time. Although these orders aim to hamper state efforts to shape the generation mix, they likely will not snuff them out entirely. In other words, there simply is no reason to believe that the Commission will succeed in realizing its “idealized vision of markets free from the influence of public policies.” 174 As former Chairman Norman Bay aptly put it, “such a world does not exist, and it is impossible to mitigate our way to its creation.” 175
But that means that, as a resource adequacy construct, the PJM capacity market will increasingly operate in an alternate reality, ignoring more and more resources just because they receive some form of state support. That also means that customers will increasingly be forced to pay twice for capacity or, to put it differently, to buy more unneeded capacity with each passing year. I cannot fathom how the costs imposed by a resource adequacy regime that is premised on ignoring actual capacity can ever be just and reasonable.
The Commission responds to this point by asserting that the costs of double-procuring capacity are irrelevant because NJBPU held that states may “appropriately bear the costs” of their resource decisionmaking, including the costs associated with resources whose capacity does not clear in the capacity auction. 176 As noted above, there are good reasons to pause before applying NJBPU whole hog to this proceeding. 177 In any case, the Commission’s citation to that decision’s jurisdictional analysis does not insulate today’s orders from the charge that it is arbitrary and capricious to altogether disregard the costs imposed by forcing the capacity market to ignore resources that actually exist or will developed and procuring additional resources as if those ignored resources did not exist. 178 Those are real costs that are directly traceable to the Commission’s orders and cannot logically be ignored by an agency claiming to balance “consumer interests.” 179
The record before us provides every reason to believe that this approach will lead to other significant cost increases. For example, the new MOPR will exacerbate the potential for the exercise of seller-side market power in what the Market Monitor has described as a structurally uncompetitive market. 180 As the Institute for Policy Integrity explained, expanding the MOPR will decrease the competitiveness of the market, both by reducing the number of resources offering below the MOPR price floor and by changing the opportunity cost of withholding capacity. 181 With more suppliers subject to administratively determined price floors, resources that escape the MOPR—or resources with a relatively low offer floor—can more confidentially increase their bids up to that level, secure in the knowledge that they will still under-bid the mitigated offers. That problem is compounded by PJM’s weak seller-side market power mitigation rules, which include a safe harbor for mitigation up to a market-seller offer cap that has generally been well above the market-clearing price. 182
Disregarding the Effects of the New MOPR on Well-Established Business and Regulatory Models Is Arbitrary and Capricious
The PJM region has long benefitted from a robust participation of demand response resources. That is in part because PJM has had in place rules that accommodate short-lead-time resources. Specifically, the Commission has long recognized that demand response resources may not be identified years in advance of the delivery year. 183 Accordingly, PJM has permitted Curtailment Service Providers (CSP), i.e., a demand response provider, to participate in the Base Residual Auction without identifying all end-use demand response resources at the time of the auction. 184 That has been fundamental to the demand response business model, since, without it, the short-lead time resources on which demand response depends might never be able to participate in the Base Residual Auction. 185
So much for that. The December 2019 Rehearing Order states that the new MOPR “may require aggregators and CSPs to know all of their demand response resource end-users prior to the capacity auction.” 186 In addition, it appears to require that, for each resource with behind-the-meter generation, the CSP must identify the relative share of its capacity that results from demand reduction versus behind-the-meter generation. 187 And the CSP will have to know all of that three years before the delivery year. That is a stunning level of paperwork to impose on CSPs, which may well require many, if not most, of them to fundamentally change or altogether abandon their business model. I fail to see anything in this record that suggests that the Commission’s concerns about state policies justifies that result.
While the grandfathered treatment provided to existing demand response resources could help blunt the impact of the new MOPR, the confusing language in the Commission’s order raises more questions than it answers, leaving CSPs, PJM, and the Market Monitor with little guidance on how to mitigate demand response resources. Rather than explaining that the grandfathered treatment attaches to the resource itself, which would seem the only logical conclusion, the Commission adds that “Aggregators and CSPs will be considered to have previously cleared a capacity auction only if all the individual resources within the offer have cleared a capacity auction.” 188 Why an entire a CSP’s portfolio must receive all-or-nothing treatment is unclear, unexplained and raises fundamental questions about how this will work when resources switch CSPs, as they often do. 189
The bottom line here is that the Commission’s attempt to root out certain state “subsidies” manifests itself as an out-and-out attack on the demand response business model in PJM. 190 That attack is particularly unfortunate as PJM indicated that the default offer floor for at least certain demand response resources should be at or near zero, 191 suggesting that even if demand response resources receive a subsidy, that subsidy would not reduce their offer below what this Commission calls a “competitive offer.” Demand response has provided tremendous benefits to PJM, both terms of improved market efficiency and increased reliability. I see no reason to give up those benefits based on an unsubstantiated concern about state policies.
Today’s order also continues the Commission’s attack on public power, dismissing the entire business model as a state subsidy and jeopardizing the viability of a construct that has long benefited customers. As ill-advised as that attack is, it is equally unsupported. The Commission neither marshals evidence that the existence of public power has actually suppressed prices 192 nor addresses arguments that the type of balanced portfolio typically developed by public power entities will not have that effect. 193 The Commission’s unsupported treatment of public power is, as PJM points out in its rehearing request, “overbroad and unwarranted.” 194
Today’s order leaves public power with few options. Unlike most public utilities, 195 PJM’s existing FRR option is not much good for many public power entities since “participating in the FRR option is an all-or-nothing proposition, and appeals as a practical matter only to large utilities that still follow the traditional, vertically integrated model.” 196 In addition, the Commission concludes that third-party contracts signed by public power entities are also state subsidies. 197 That effectively forces public power to procure capacity based only on the narrow considerations evaluated in the PJM capacity market—a result inimical to the purpose of the public power model.
The public power model predates the capacity market by several decades and is premised on securing a reliable supply of power for each utility’s citizen-owners at a reasonable and stable cost, which often includes an element of long-term supply. 198 The policy affirmed in today’s order is a direct threat to the long-term viability of the public power model in PJM. Although the Commission exempts existing public power resources from the MOPR, it provides that all new public power development will be subject to mitigation. That means that public power’s selection and development of new capacity resources will now be dependent on the capacity market outcomes, not the self-supply model on which it has traditionally relied. That fundamentally upends the public power model because it limits the ability of public power entities to choose how to develop and procure resources over a long time horizon.
The Commission is also arbitrary and capricious in its treatment of energy efficiency resources—e.g., efficient light bulbs, air conditioning units, and water heaters whose installation reduces electricity use. Although energy efficiency resources reduce demand for electricity, they participate in the PJM capacity auction as “supply” for four years so that they can receive compensation for reducing the total amount of capacity needed in the region. 199 To make that work in practice, PJM “adds back” to the demand curve the capacity equivalent of any energy efficiency resources that participate in the auction. 200 Doing so ensures that the capacity provided by energy efficiency resources is not double counted.
Today’s order concludes that any energy efficiency resources that participate in the PJM capacity auction and receive a state subsidy suppress prices and, therefore, must be subjected to the new MOPR. 201 The record does not support that determination. As PJM’s Market Monitor explained, including energy efficiency in the PJM capacity auction—by treating it as supply and then adding it back to the demand curve—actually increases the prices in that auction by roughly 10 percent, all else equal. 202 In other words, the record does not indicate that the energy efficiency resources participating in the capacity market (subsidized or otherwise) are having any price suppressive effect whatsoever. Instead, the record indicates that the only time energy efficiency resources can decrease capacity market prices is when, after four years, those resources no longer participate in the capacity market and are no longer subject to the new MOPR. 203
Today’s order completely fails to address these points even though PJM itself, not to mention several other parties, argued on rehearing that the Commission’s approach to energy efficiency was inconsistent with its own theory of the case and would make a hash of the markets. 204 Instead, the Commission asserts that energy efficiency resources can cause price suppression because, according to the Commission, that is the inevitable result of subsidizing any resource. 205 To support that proposition, the Commission relies on a single piece of irrelevant arithmetic. It multiples the total MWs of energy efficiency that cleared in the capacity market in a given year by the clearing price that year and asserts that the resulting figure shows that energy efficiency “has affected revenues in the PJM capacity market.” 206 That may be true, but it does not shed any light whatsoever on whether energy efficiency, subsidized or not, suppresses the capacity market clearing price. Indeed, the Commission fails to wrestle with the fact that, as a result of the add-back provision, energy efficiency resources will not suppress the capacity clearing price. Calculating their total revenue does not change that fact.
In addition, the Commission blithely asserts that energy efficiency must be subject to the new MOPR because “[d]ecreased demand resulting from a State Subsidy will suppress prices just as a State Subsidy to supply will suppress prices.” 207 That general statement proves too little. It simply cannot be the case that any action a state takes to conserve electricity is a “problem” for the Commission to fix. Instead, the state action can implicate the Commission’s interests through resources’ participation in the capacity market, if at all. As explained above, however, the record is clear that energy efficiency resources’ participation in the capacity market does not have a price suppressive effect; quite the opposite, in fact. The Commission’s failure to wrestle with the actual effects of energy efficiency participating as a capacity resource renders its justification for applying the MOPR to such resources arbitrary and capricious.
Today’s order grants clarification that “purely voluntary transactions for RECs are not considered State Subsidies.” Again, I am glad to hear it. As I explained in my earlier dissent, transactions involving voluntary REC sales would not meet any reasonable definition of subsidy and would instead amount to “mitigating the impact of consumer preferences on wholesale electricity markets just because they may potentially overlap with state policies.” 208 In addition, I noted that there were eminently reasonable ways to address the Commission’s practical concerns about ensuring that voluntary RECs are not eventually used to comply with state mandates. I am glad to see that that view seems to have prevailed.
Nevertheless, today’s order makes clear that voluntary RECs are not out of the woods yet. In a pair of ominous (and redundant) footnotes, the Commission’s goes out of its way to assert that all today’s order concludes is that voluntary RECs are not state subsidies and that, pardon the double negative, that conclusion is not a finding that voluntary RECs do not distort capacity market outcomes. 209 If the question is whether consumers’ voluntary decision to purchase clean energy could “distort” efficient market outcomes, the answer is a straightforward no. The fact that the Commission feels the need to go out of its way to preserve that question for a future proceeding is as ominous as it is unnecessary. It is both notable and concerning that the Commission did not feel the need to preserve the same question when addressing other voluntary out-of-market for capacity resources, such as sales of coal ash, which it describes as “similarly situated” to voluntary REC sales. 210
Applying Different Offer Floors to New and Existing Resources Is Arbitrary and Capricious
As I explained in my dissent from the December 2019 Order, the Commission’s imposition of disparate offer floors for new and existing resources is unjust and unreasonable, unduly discriminatory as well as arbitrary and capricious. Today’s order affirms the decision to require new resources receiving a State Subsidy to be mitigated to Net Cost of New Entry (Net CONE) while existing resources receiving a State Subsidy are mitigated to their Net Avoidable Cost Rate (Net ACR). The Commission suggested that this distinction is appropriate because new and existing resources do not face the same costs. 211 In particular, the Commission suggested that setting the offer floor for new resources at Net ACR would be inappropriate because that figure “does not account for the cost of constructing a new resource.” 212 Today’s order uses more words to make the same points. 213
Regardless, the Commission’s distinction does not hold water. As the Market Monitor explained in his comments, it is illogical to distinguish between new and existing resources when defining what is (or is not) a competitive offer. 214 That is because, as a result of how most resources are financed, a resource’s costs will not materially differ based on whether it is new or existing (i.e., one that has cleared a capacity auction). That means that there is no basis to apply a different formula for establishing a competitive offer floor based solely on whether a resource has cleared a capacity auction. To the extent it is appropriate to consider the cost of construction for a new resource it is just as appropriate to consider the cost of construction for one that has already cleared a capacity auction. That is consistent with Net CONE, which calculates the nominal 20-year levelized cost of a resource minus its expected revenue from energy and ancillary services. Because that number is levelized, it does not change between a resource’s first year of operation and its second.
In addition, as the Market Monitor explains, Net CONE does not reflect how resources actually participate in the market. 215 Instead of bidding their levelized cost, both new and existing competitive resources bid their marginal capacity—i.e., their net out-of-pocket costs, which Net ACR is supposed to reflect. Perhaps reasonable minds can differ on the question of which offer floor formula is the best choice to apply. But there is nothing in this record suggesting that it is appropriate to use different formulae based on whether the resource has already cleared a capacity auction.
It may be true that setting the offer floor at Net ACR for new resources will make it more likely that a subsidized resource will clear the capacity market, MOPR notwithstanding. Holding all else equal, the higher the offer floor, the less likely that a subsidized resources will clear, so a higher offer floor will more effectively block state policies. But that does not justify applying Net ACR to existing resources and Net CONE to new ones.
The purpose of a capacity market, the whole reason the market exists, is to ensure resource adequacy at just and reasonable rates. 216 It is a means, not an end. And for that purpose, a megawatt of capacity provided by a new resource is every bit as effective as a megawatt provided by an existing one. Applying entirely different bid floor formulae based only on whether the resource is new or existing does not further that basic purpose. Instead, as the Commission all but admits, 217 the purpose those disparate bid floors serve is to make it easier to block the entry of state-subsidized resources. A capacity market designed first and foremost for the purpose of blocking state policies is one in which the tail truly wags the dog. 218
Today’s Orders Are Not about Promoting Competition
By this point, the irony of today’s orders should be clear. The Commission spends hundreds of pages decrying government efforts to shape the generation mix because they interfere with “competitive” forces. 219 In order to stamp out those efforts and promote its vision of “competition,” the Commission creates a byzantine administrative pricing scheme that bears all the hallmarks of cost-of-service regulation, without any of the benefits. That is a truly bizarre way of fostering the market-based competition that these orders claim to so highly value.
It starts with the Commission’s definition of subsidy, which encompasses vast swathes of the PJM capacity market, including new investments by vertically integrated utilities and public power, merchant resources that receive any one of the litany of subsidies available to particular resources or generation types, and any resource that benefits even indirectly from one of the many state default service auctions in PJM. 220 Moreover, the Commission’s inaptly named Unit-Specific Exemption 221 —its principal response to concerns about over mitigation—is simply another form of administrative pricing. 222 All the Unit-Specific Exemption provides is an escape from the relevant default offer floor. Resources are still required to bid above an administratively determined price floor, not at the level that they believe would best would best serve their competitive interests. 223 Nor is it clear that this so-called exemption will even be resource-specific. 224 And even resources that might appear eligible for the Competitive Entry Exemption may hesitant to take that option given the Commission’s proposal to permanently ban from the capacity market any resource that invokes that exception and later finds itself subsidized. 225 Are those resources really going to wager their ability to participate in the capacity market on the proposition that their state will never institute a non-bypassable policy that the Commission might deem an illicit financial benefit?
To implement this scheme, PJM and the Market Monitor will need to become the new subsidy police, regularly reviewing the laws and regulations of 13 different states and the District of Columbia—not to mention hundreds of localities and municipalities—in search of any provision or program that could conceivably fall within the Commission’s definition of State Subsidy. “But that way lies madness.” 226 It will also require PJM and the Market Monitor to identify any and all contracts power marketers have with resources that may be used to serve commitments incurred in a state default service auction. Rooting through retail auctions results and hundreds of different sets of laws and regulations looking for anything that might be “nearly tethered” to wholesale rates is hardly a productive use of anyone’s time.
And identifying the potential subsidies is just the start. Given the consequences of being subsidized, today’s orders will likely unleash a torrent of litigation over what constitutes a subsidy and which resources are or are not subsidized. Next, PJM will have to develop default offer floors for all relevant resource types, including many that have never been subject to mitigation in PJM or anywhere else—e.g., demand response resources, energy efficiency resources, or resources whose primary function is not generating electricity. Moreover, given the emphasis that the Commission puts on the Unit-Specific Exemption as the solution to concerns about over-mitigation, we can expect that resources will attempt to show that their costs fall below the default offer floor, with many resorting to litigation should they fail to do so. The result of all this may be full employment for energy lawyers, but it is hardly the most obvious way to harness the forces of competition.
Finally, although this administrative pricing regime is likely to be as complex and cumbersome as cost-of-service regulation, it provides none of the benefits that a cost-of-service regime can provide. Most notably, the administrative pricing regime is a one-way ratchet that will only increase the capacity market clearing price. Unlike cost-of-service regulation, there is no mechanism for ensuring that bids reflect true costs. Nor does this pricing regime provide any of the market-power protections provided by the cost-of-service model. Once mitigated, resources are required to offer no lower than their administratively determined offer floor, but there is no similar prohibition on offering above that floor. 227
Today’s Orders Are Instead All about Slowing the Clean Energy Transition
If they do not promote competition, today’s orders certainly serve an alternative, overarching purpose: Slowing the region’s transition to a clean energy future. Customers throughout PJM, not to mention several of the PJM states, are increasingly demanding that their electricity come from clean resources. Today’s orders represent a major obstacle to those goals. Although even this Commission won’t come out and say that, the cumulative effect of the various determinations in today’s orders is unmistakable. It helps to rehash in one place what the mitigation regime affirmed in the December 201 Rehearing Order will do.
First, after establishing a broad definition of subsidy, the Commission creates several categorical exemptions that overwhelmingly benefit existing resources. Indeed, the exemptions for (1) renewable resources, (2) self-supply, and (3) demand response, energy efficiency, and capacity storage resources are all limited to existing resources. 228 That means that all those resources will never be subjected to the MOPR and can continue to bid into the market at whatever level they choose, while every comparable new resource must run the administrative pricing gauntlet. In addition, new natural gas resources remain subject to the MOPR. 229 All told, those exemptions provide a major benefit to existing resources.
Second, as noted above, the Commission creates different offer floors for existing and new resources. 230 Using Net CONE for new resources and Net ACR for existing resources will systematically make it more likely that existing resources of all types can remain in the market, even if they have higher costs than new resources that might otherwise replace them. As the Market Monitor put it, this disparate treatment of new and existing resources “constitute[s] a noncompetitive barrier to entry and . . . create[s] a noncompetitive bias in favor of existing resources and against new resources of all types, including new renewables and new gas fired combined cycles.” 231
Third, the mitigation scheme imposed by today’s orders will likely cause a large and systematic increase in the cost of capacity. Although that will appear as a rate increase for consumers, it will be a windfall to existing resources that clear the capacity market. That windfall will make it more likely that any particular resource will stay in the market, even if there is another resource that could supply the same capacity at less cost to consumers.
Finally, the December 2019 Order again dismisses the June 2018 Order’s fig leaf to state authority: The resources-specific FRR Alternative. 232 That potential path for accommodation was what allowed the Commission to profess that it was not attempting to "“disregard” or “nullify” state public policies. Although implementing that option would no doubt have been a daunting task, doing so at least had the potential to establish a sustainable market design by allowing state policies to have their intended effect on the resource mix. And that is why it is no longer on the table. It could have provided a path for states to continue shaping the energy transition—exactly what this new construct is designed to stop.
The Commission proposes various justifications for each of these changes, some of which are more satisfying than others. But don’t lose the forest for the trees. At every meaningful decision point in today’s orders, the Commission has elected the path that will make it more difficult for states to shape the future resource mix. Nor should that be any great surprise. Throughout this proceeding, the Commission has focused narrowly on states’ exercise of their authority over generation facilities, treating state authority as a problem that must be remedied by a heavy federal hand. The only thing that was new in the December 2019 order was the extent to which the Commission was willing to go. Whereas the June 2018 Order at least paid lip service to the importance of accommodating state policies, 233 the December 2019 Order—and today’s orders—are devoid of any comparable sentiment.
In addition, in a now-familiar pattern, today’s orders put almost no flesh on the bones of the Commission’s edicts and provide precious little guidance how the new MOPR will work in practice. Most of the actual work will come in the compliance proceedings, not to mention the coming litany of section 205 filings, section 206 complaints, and petitions for declaratory orders seeking guidance on fact patterns that the Commission, by its own admission, has not yet bothered to contemplate. In each of those proceedings, the smart money should be on the Commission adopting what it will claim to be facially neutral positions that, collectively, entrench the current resource mix. Although the proceedings to come will inevitably garner less attention than today’s orders, they will be the path by which the “quiet undoing” of state policies progresses. 234
The December 2019 Rehearing Order is a concerning preview of that process. In the two thousand-plus pages of rehearing requests filed in response to December 2019 Order, parties raised a wide range of concerns. Today’s orders duck almost every single one, falling back on generalizations and a single-minded focus on extirpating the effects of state policies. Although the order is long in pages, it is short on any serious effort to grapple with or explain the implications of the Commission’s actions. Moreover, in the few instances in which the Commission gave ground, such as voluntary RECs, it did so only with an ominous warning that is likely to cause more confusion than it clears up. 235 Everything about today’s orders should concern those with a stake in a durable resource adequacy construct in PJM.
At this point, the die has been cast. Today’s orders make unambiguously clear that the Commission intends to array PJM’s capacity market rules against the interests of consumers and of states seeking to exercise their authority over generation facilities. For all the reasons discussed above, these orders are illegal, illogical, and truly bad public policy.
But, even beyond that, today’s orders are deeply disappointing because they will fracture PJM, the largest RTO in the country. As I predicted in my dissent from the December 2019 Order, states throughout the region are already looking for ways to pull their utilities out of the capacity market rather than remain under rules designed to damage their interests. Today’s orders snuff out what little hope may have remained that the Commission would again change course and adopt a more sensible market design. As a result, states committed to exercising their rights under FPA section 201(b) will have little choice but to exit the capacity market. I strongly urge PJM to work with the states and provide them the time needed to make the transition as smooth as possible.
Fostering large regional markets for energy, ancillary services, and capacity, has been one of the Commission’s principal successes over the last quarter century. I hate to see that success undone based on an obsession with blocking the effects of state public policies. But, unfortunately, the Commission chose the path that it did. In so doing, we have abdicated the leadership role that we ought to have taken in developing a resource adequacy paradigm that accommodates the fundamental changes currently under way in the electricity sector.
The irony in all this is that the Commission asserts that it is acting to “save” the capacity market even as it sets the market on a course toward its eventual demise.
For these reasons, I respectfully dissent.
- 1. 1 Calpine Corp. v. PJM Interconnection, L.L.C., 171 FERC ¶ 61,035 (2020) (December 2019 Rehearing Order); Calpine Corp. v. PJM Interconnection, L.L.C., 171 FERC ¶ 61,034 (2020) (June 2018 Rehearing Order).
- 2. 2 Calpine Corp. v. PJM Interconnection, L.L.C., 163 FERC ¶ 61,236 (2018) (June 2018 Order).<
- 3. 3 Id. (LaFleur, Comm’r, dissenting at 5) (“The majority is proceeding to overhaul the PJM capacity market based on a thinly sketched concept, a troubling act of regulatory hubris that could ultimately hasten, rather than halt, the re-regulation of the PJM market.”).
- 4. 4“FRR” stands for Fixed Resource Requirement.
- 5. 5 Calpine Corp. v. PJM Interconnection, L.L.C., 169 FERC ¶ 61,239 (2019) (December 2019 Order).
- 6. 6 Today’s orders address both the requests filed in response to the June 2018 Order and the December 2019 Order. Unless otherwise indicated, citations to rehearing requests refer to requests filed in response to the December 2019 Order.
- 7. 7 Specifically, the FPA applies to “any rate, charge, or classification, demanded, observed, charged, or collected by any public utility for any transmission or sale subject to the jurisdiction of the Commission” and “any rule, regulation, practice, or contract affecting such rate, charge, or classification.” 16 U.S.C. § 824e(a) (2018); see also id. § 824d(a) (similar).
- 8. 8 See id. § 824(b)(1) (2018); Hughes v. Talen Energy Mktg., LLC, 136 S. Ct. 1288, 1292 (2016) (describing the jurisdictional divide set forth in the FPA); FERC v. Elec. Power Supply Ass’n, 136 S. Ct. 760, 767 (2016) (EPSA) (explaining that “the [FPA] also limits FERC’s regulatory reach, and thereby maintains a zone of exclusive state jurisdiction”); Panhandle E. Pipe Line Co. v. Pub. Serv. Comm’n of Ind., 332 U.S. 507, 517-18 (1947) (recognizing that the analogous provisions of the NGA were “drawn with meticulous regard for the continued exercise of state power”). Although these cases deal with the question of preemption, which is, of course, different from the question of whether a rate is just and reasonable under the FPA, the Supreme Court’s discussion of the respective roles of the Commission and the states remains instructive when it comes to evaluating how the application of a MOPR squares with the Commission’s role under the FPA.
- 9. 9 16 U.S.C. § 824(b)(1); Hughes,136 S. Ct. at 1292; see also Pac. Gas & Elec. Co. v. State Energy Res. Conservation & Dev. Comm’n, 461 U.S. 190, 205 (1983) (recognizing that issues including the “[n]eed for new power facilities, their economic feasibility, and rates and services, are areas that have been characteristically governed by the States”).
- 10. 10 EPSA, 136 S. Ct. at 776; see Oneok, Inc. v. Learjet, Inc., 135 S. Ct. 1591, 1601 (2015) (explaining that the natural gas sector does not adhere to a “Platonic ideal” of the “clear division between areas of state and federal authority” that undergirds both the FPA and the Natural Gas Act).
- 11. 11 See EPSA, 136 S. Ct. at 776; Oneok, 135 S. Ct. at 1601; Coal. for Competitive Elec. v. Zibelman, 906 F.3d 41, 57 (2d Cir. 2018) (explaining that the Commission “uses auctions to set wholesale prices and to promote efficiency with the background assumption that the FPA establishes a dual regulatory system between the states and federal government and that the states engage in public policies that affect the wholesale markets”).
- 12. 12Zibelman, 906 F.3d at 57 (explaining how a state’s regulation of generation facilities can have an “incidental effect” on the wholesale rate through the basic principles of supply and demand); id. at 53 (“It would be ‘strange indeed’ to hold that Congress intended to allow the states to regulate production, but only if doing so did not affect interstate rates.” (quoting Nw. Cent. Pipeline Corp. v. State Corp. Comm’n of Kansas, 489 U.S. 493, 512-13 (1989) (Northwest Central))); Elec. Power Supply Ass’n v. Star, 904 F.3d 518, 524 (7th Cir. 2018) (explaining that the subsidy at issue in that proceeding “can influence the auction price only indirectly, by keeping active a generation facility that otherwise might close . . . . A larger supply of electricity means a lower market-clearing price, holding demand constant. But because states retain authority over power generation, a state policy that affects price only by increasing the quantity of power available for sale is not preempted by federal law.”).
- 13. 13 Hughes, 136 S. Ct. at 1300 (Sotomayor, J., concurring) (quoting Northwest Central, 489 U.S. at 518); id. (“recogniz[ing] the importance of protecting the States’ ability to contribute, within their regulatory domain, to the Federal Power Act’s goal of ensuring a sustainable supply of efficient and price-effective energy”).
- 14. 14 Cf. Star,904 F.3d at 523 (“For decades the Supreme Court has attempted to confine both the Commission and the states to their proper roles, while acknowledging that each use of authorized power necessarily affects tasks that have been assigned elsewhere.”).
- 15. 15 E.g., Hughes, 136 S. Ct. at 1298 (relying on Oneok, 135 S. Ct. at 1599,for the proposition that a state may regulate within its sphere of jurisdiction even if its actions “incidentally affect areas within FERC’s domain” but that a state may not target or intrude on FERC’s exclusive jurisdiction); EPSA, 136 S. Ct. at 776 (emphasizing the importance of “‘the target at which [a] law aims’” (quoting Oneok, 135 S. Ct. at 1600)); Oneok, 135 S. Ct. at 1600 (recognizing “the distinction between ‘measures aimed directly at interstate purchasers and wholesales for resale, and those aimed at’ subjects left to the States to regulate”) quoting N. Nat. Gas Co. v. State Corp. Comm’n of Kan., 372 U.S. 84, 94 (1963) (Northern Natural))).
- 16. 16Oneok, 135 S. Ct. at 1600 (discussing Northern Natural, 372 U.S. at 94, and Northwest Central, 489 U.S. at 513-14).
- 17. 17EPSA, 136 S. Ct. at 775-77; id. at 776.
- 18. 18Hughes, 136 S. Ct. at 1298, 1299. In the intervening few years, the lower federal courts have carefully followed the Court’s discussion of the prohibition on one sovereign regulating in a manner that interferes with the other sovereign’s authority by targeting matters subject to their exclusive jurisdiction. See, e.g., Zibelman, 906 F.3d at 50-51, 53; Star, 904 F.3d at 523-24; Allco Fin. Ltd. v. Klee, 861 F.3d 82, 98 (2d Cir. 2017).
- 19. 19 June 2018 Order, 163 FERC ¶ 61,236 at P 149.
- 20. 20 Id. P 150.
- 21. 21 Id. P 156; EPSA, 136 S. Ct. at 776 (explaining that because the federal and state spheres of jurisdiction “are not hermetically sealed from each other,” “ virtually any action” one sovereign takes pursuant to its authority will have “some effect” on matters within the other’s sphere of jurisdiction).
- 22. 22 December 2019 Order, 169 FERC ¶ 61,239 at P 37.
- 23. 23 Id. P 83; see December 2019 Rehearing Order, 171 FERC ¶ 61,035 at PP 68, 108. The Commission has never attempted to provide a rational justification for that distinction. It certainly did not distinguish between acceptable and unacceptable state policies based on their effects on wholesale rates given that there is no record evidence bearing on that point and certainly no discussion of such a distinction in any of the Commission’s orders in this proceeding. See infra section II.B.1.c. Instead, the Commission asserted that it was concerned only with those state efforts that it determined (again with no analysis) to be “most nearly directed at or tethered to” the wholesale rate. December 2019 Order, 169 FERC ¶ 61,239 at P 68 (internal quotation marks and footnotes omitted); see Clean Energy Advocates Rehearing Request at 32 (“The Commission . . . cobbles together a test of whether policies are ‘nearly directed at’ or ‘tethered to’ new entry or continued operation of generating capacity. This test, too, lacks any substantive articulation of explanation, and the Commission does not establish how or why such policies would have the greatest impact on rates.” (footnotes omitted)). That rather awkward repurposing of a preemption term of art tells us nothing. The term “untethered” first entered the FPA lexicon in Hughes, 136 S. Ct. at 1299, and the specific concept of “tethering” described in that opinion has played an important role in subsequent FPA preemption litigation. E.g., Zibelman, 906 F.3d at 51-55; Star, 904 F.3d at 523-24; Allco, 861 F.3d at 102. But until December 2019, it was never used as the yardstick for targeting particular state policies that are concededly “untethered” to the wholesale rate. It is not obvious, and the Commission certainly does not explain, why being a valid exercise of state jurisdiction that is close-to-but-not preempted should be relevant to our analysis, especially if that analysis is nominally only about wholesale market effects. Preemption is a binary determination, which is distinctly unlike horseshoes or hand grenades. The failure to provide a reasoned basis for distinguishing between acceptable and unacceptable state policies is itself arbitrary and capricious and only underscores the extent to which the Commission’s order targets state jurisdiction, notwithstanding its scattered statements about price suppression and wholesale rates.
- 24. 24 In addition, the disparate treatment that the Commission accords different types of state policies underscores the extent to which it is meddling in state jurisdiction. The new MOPR is laser-focused on mitigating anything that increases a resource’s revenue, but expressly excludes anything that decreases its costs. See infra Section II.B.1.d; December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 390 (explaining that the Commission will not treat the Regional Greenhouse Gas Initiative (RGGI) as a subsidy because it “does not provide payments, concessions, rebates, or other financial benefits to resources” even though it meets every other prong of the Commission’s subsidy definition, see December 2019 Order, 169 FERC ¶ 61,239 at P 67). That means that, in the Commission’s eyes, any state policy that augments a resource’s revenue is a “problem” that must be solved, but that any state policy that decreases its relative costs is not. But, in a construct where offer prices are calculated as costs net of revenues, see infra Section II.B.4, as both the net cost of new entry (Net CONE) and net avoidable cost rate (Net ACR) offer floors are, see Section II.B.4, whether a state policy operates on the revenue or cost side of resource’s equation is utterly immaterial. Putting aside whether that distinction makes any sense, it shows the extent to which the Commission is meddling in state resource decisionmaking by finding that the effects of certain state policies are legitimate while the identical effects of others are not.
- 25. 25 See infra Section II.B.1.a.
- 26. 26 December 2019 Order, 169 FERC ¶ 61,239 at PP 10, 89.
- 27. 27 Id. P 10.
- 28. 28 Id. PP 10, 89.
- 29. 29 Id. P 40.
- 30. 30 As discussed further below, it is hard to tally up the cumulative effect of today’s orders and find that characterization even remotely accurate. In any case, a policy of blocking state efforts to address externalities is itself very much a policy, not the absence thereof. Elsewhere, the Commission suggests that it lacks the authority to directly address any environmental considerations. E.g., December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 41. Assuming, for the moment, the accuracy of that statement, it still does not explain why the Commission should or must affirmatively block state efforts to the same using authority that no one contests they possess.
- 31. 31 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 78; see supra note 23.
- 32. 32 As discussed above, supra note 23 and accompanying text, the Commission’s unexplained focus on only certain state policies, and not others that might equally cause the sort of price suppression about which it purports to be so concerned, lays bare that today’s orders is about blocking disfavored state policies and not wholesale market effects. See December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 106 (“[T]he expanded MOPR is not intended to address all commercial externalities or opportunities that might affect the economics of a particular resource.”).
- 33. 33See infra Section II.B.3.
- 34. 34 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 319 (“Even after the June 2018 Order, certain states pursued new or expanded out-of-market support for preferred resources”). <
- 35. 35 Elsewhere in today’s orders, the Commission suggests that federal subsidies, presumably in contrast to state subsidies, are as “equally valid” as regulations under the FPA. December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 120. There is no basis for the insinuation that state subsidies are somehow less valid than federal ones. Although it is true that state subsidies that directly regulate or aim at the Commission’s exclusive jurisdiction or that conflict with a Commission regulation are preempted, see supra P 7, the December 2019 Rehearing Order deals with state actions that are concededly not preempted and were enacted pursuant to the states exercise of their reserved authority under the FPA. See, e.g., December 2019 Rehearing Order, 171 FERC ¶ 61,035 at PP 76-77. But, although the Commission’s “equally valid” rationale is unhelpful as a statement of law, it is a revealing illustration of the attitude toward state authority that pervades the order.
- 36. 36 See supra P 7.
- 37. 37 EPSA, 136 S. Ct. at 776 (citing Oneok, 135 S. Ct. at 1599).
- 38. 38 Id.
- 39. 39 December 2019 Order, 169 FERC ¶ 61,239 (Glick, Comm’r, dissenting at P 13).
- 40. 40Specifically, those early MOPRs were designed to ensure that net buyers of capacity were not able to use market power to drive down the capacity market price. See N.Y. Indep. Sys. Operator, Inc., 170 FERC ¶ 61,121 (2020) (Glick, Comm’r, dissenting at P 2); see generally Richard B. Miller, Neil H. Butterklee & Margaret Comes, “Buyer-Side” Mitigation in Organized Capacity Markets: Time for a Change?, 33 Energy L.J. 459 (2012) (discussing the history of buyer-side mitigation at the Commission).
- 41. 41 See, e.g., Nat’l Ass’n of Regulatory Util. Comm’rs v. FERC, 475 F.3d 1277, 1280 (D.C. Cir. 2007) (noting that “FERC’s authority generally rests on the public interest in constraining exercises of market power”); Pub. Util. Dist. No. 1 of Snohomish Cty. v. Dynegy Power Mktg., Inc., 384 F.3d 756, 760 (9th Cir. 2004) (explaining that the absence of market power could provide a strong indicator that rates are just and reasonable); Tejas Power Corp. v. FERC, 908 F.2d 998, 1004 (D.C. Cir. 1990) (“In a competitive market, where neither buyer nor seller has significant market power, it is rational to assume that the terms of their voluntary exchange are reasonable, and specifically to infer that the price is close to marginal cost, such that the seller makes only a normal return on its investment.”); see also N.Y. Indep. Sys. Operator, Inc., 170 FERC ¶ 61,121 (Glick, Comm’r, dissenting at P 2) (explaining that “the Commission’s buyer-side market power mitigation regime should focus only on actual market power” a concern that “is both more consistent with the FPA’s dual-federalist design and the Commission’s core responsibility as a regulator of monopoly/monopsony power”).
- 42. 42 See N.J. Bd. of Public Utils. v. FERC, 744 F.3d 74, 106-07 (3d Cir. 2014) (NJBPU) (summarizing the Commission’s reasoning for limiting the MOPR to only natural gas-fired resources). The Commission asserts, without explanation, that there is a “clear tension” between the 2011 order eliminating the public policy exemption to then-limited MOPR and recent state efforts to shape the generation mix. December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 320. Nonsense. The 2011 order specifically exempted all non-natural-gas-fired resources from the MOPR, squarely foreclosing whatever tension the Commission pretends to uncover today. In any case, it is hardly fair to assign states the responsibility for predicting when the Commission will abandon its precedent and entirely reorient its approach to regulating a construct like the PJM capacity market.
- 43. 43 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 45 (stating that “the expanded MOPR does not focus on buyer-side market power mitigation”).
- 44. 44 See ISO New England Inc., 162 FERC ¶ 61,205, at PP 20-26 (2018). That order also came after every existing court case considering the legality of the Commission’s use of the MOPR.
- 45. 45 Id. P 21.
- 46. 46 June 2018 Order, 163 FERC ¶ 61,236 at PP 150, 156, 161.
- 47. 47 December 2019 Order, 169 FERC ¶ 61,239 at P 17.
- 48. 48 E.g., December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 78 (asserting that “[t]he Commission may, as here, take action to protect the integrity of federally-regulated markets against state policies” without explaining what exactly integrity means in this context); id. P 320 (explaining that the various exemptions provided for in the December 2019 Order are for “resources that accept the premise of a competitive capacity market” (quoting December 2019 Order, 169 FERC ¶ 61,239 at P 17)); id. P 337 (asserting that “[t]he replacement rate directed in the December 2019 Order addresses State-Subsidized Resources, which pose a risk to the integrity of competition in the wholesale capacity market”).
- 49. 49 Public Power Entities Rehearing Request at 6-7 (“The Commission did not justify the transformation of the MOPR from a limited mechanism aimed at preventing price suppression by subsidized new entry into a sweeping restriction on almost all forms of non-federal support for generation resources.”).
- 50. 50 December 2019 Order, 169 FERC ¶ 61,239 at 136; see December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 338 (“[T]he December 2019 Order expands the scope of the MOPR, but not its underlying purpose.”). As I noted in my underlying dissent, suggesting that the MOPR has always been about price suppression is the equivalent of saying that speed limits have always been about keeping people from getting to their destination too quickly. There is a sense in which that is true, but it kind of misses the point. December 2019 Order, 169 FERC ¶ 61,239 (Glick, Comm’r, dissenting at n.35).
- 51. 51 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at PP 15-16.
- 52. 52EPSA, 136 S. Ct. at 776 (“[A] FERC regulation does not run afoul of § 824(b)’s proscription just because it affects—even substantially—the quantity or terms of retail sales.”).
- 53. 53 See, e.g. Public Power Entities Rehearing Request at 13-15; Clean Energy Advocates Rehearing Request at 85-89.
- 54. 54 EPSA 136 S. Ct. at 776-77.
- 55. 55 Id. at 776.
- 56. 56 See December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 17.
- 57. 57 See supra P 7; EPSA 136 S. Ct. at 776-77.
- 58. 58 See, e.g., Public Power Entities Rehearing and Clarification Request at 13-16; Clean Energy Associations Rehearing and Clarification Request at 10-11; Maryland Commission Rehearing and Clarification Request at 9-13; see also supra P 7; December 2019 Order, 169 FERC ¶ 61,239 (Glick, Comm’r, dissenting at PP 7-17).
- 59. 59 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 16 (“The court’s decision in NJBPU demonstrates that the findings from the December 2019 Order are within the Commission’s jurisdiction.”); June 2018 Rehearing Order, 171 FERC ¶ 61,034 at P 66.
- 60. 60 See supra PP 16-18 (discussing the MOPR’s evolution).
- 61. 61NJBPU, 744 F.3d at 84-85. In other words, the “aim” or “target” of the MOPR was limited to the exercise of wholesale market power. Id.
- 62. 62See supra note 41.
- 63. 63NJBPU, 744 F.3d at 106 (“[T]he only resources subject to the MOPR are natural gas-fired technologies.”); id. (“FERC asserts that the characteristics of gas units make them more likely to be used as price suppression tools.” (internal quotation marks omitted)).
- 64. 64 Id. at 79.
- 65. 65 PJM Interconnection, L.L.C., 135 FERC ¶ 61022, at P 139 (2011); id. PP 128-138 (discussing the evidence in the record). In Hughes, the Supreme Court subsequently held that the Maryland law, which was functionally identical to the New Jersey law, was preempted because it aimed at FERC’s exclusive jurisdiction over wholesales. 136 S. Ct. at 1928. That the Commission’s elimination of the state resource exemption was both focused exclusively on the exercise of buyer-side market power and in response to a state’s “intrusion” on FERC’s exclusive jurisdiction, id. n.11, only underscores the differences between that decision and today’s orders.
- 66. 66NJBPU, 744 F.3d at 97 (emphasis added).
- 67. 67Id
- 68. 68 See supra P 7; December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 45 (“[T]he expanded MOPR does not focus on buyer-side market power mitigation.”); June 2018 Rehearing Order, 171 FERC ¶ 61,034 at P 56.
- 69. 69EPSA, 136 S. Ct. at 776.
- 70. 70 As noted, this is the Commission’s own term for describing the effect that applying the MOPR has on a particular policy. December 2019 Order, 169 FERC ¶ 61,239 at P 87. On rehearing, several parties identified the tension between the Commission’s assertions that it could not apply the MOPR to federal policies because to do so would “nullify” those policies and its statements that applying the MOPR to state policies has no effect whatsoever. December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 12. Although the Commission summarizes some of those arguments, it does not respond to them.
- 71. 71 See supra P 9 (explaining how the Commission’s orders focus only on state efforts to regulate the generation mix and not on other state efforts that could conceivably have the same price suppressive effects). Even PJM, which brought this problem to our doorstep in 2018, criticizes the Commission for abandoning the MOPR’s role as “guardrail” and turning it into an “over-broad and over-prescriptive” rule that “needlessly interferes with state resource policies.” PJM Rehearing and Clarification Request at 6-9.
- 72. 72 See supra PP 11-12; infra Section II.B.1.d.
- 73. 73See supra P 14.
- 74. 74 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 132.
- 75. 75 Public Power Entities Rehearing Request at 15 (The “expansion of the MOPR fundamentally alters its purposes and impact in a way that impermissibly intrudes on state authority.”).
- 76. 76 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 15 & n.45 (citing Conn. Dep’t of Pub. Util. Control v. FERC, 569 F.3d 477, 481-82 (D.C. Cir. 2009) and Muns. of Groton v. FERC, 587 F.2d 1296, 1301 (D.C. Cir. 1978)).
- 77. 77Connecticut Dep’t, 569 F.3d 481-85; id. at 482 (explaining that Municipalities of Groton “sustained the Commission's jurisdiction to review the ‘deficiency charges’ . . . charged . . . when member utilities failed to live up to their share of NEPOOL's reliability requirement”).
- 78. 78 Id. at 482.
- 79. 79 Id.
- 80. 80 December 2019 Order, 169 FERC ¶ 61,239 at PP 10, 89.
- 81. 81 See supra P 10.
- 82. 82 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 319. The Commission is also fond of pointing to the U.S. Court of Appeals for the Seventh Circuit’s statement, in resolving preemption litigation regarding Illinois’s zero-emissions credits, that the Commission has the authority to make “adjustments” to its regulations in light of state action. Star, 904 F.3d at 524. And indeed it does. But it does not follow that the Commission can make any “adjustment” that it wants, certainly not one inconsistent with Supreme Court’s holdings on the limit of federal authority under the FPA.
- 83. 83 As I have elsewhere explained, the proper role for MOPRs is in combatting exercises of market power, not state efforts to shape the generation mix. N.Y. Indep. Sys. Operator, Inc., 170 FERC ¶ 61,121 (2020) (Glick, Comm’r, dissenting at PP 15-16).
- 84. 84 NJBPU, 744 F.3d at 96-98.
- 85. 85Cf. Hughes,136 S. Ct. at 1299.
- 86. 86 The December 2019 Order also swept beyond what was contemplated in the original Calpine complaint by suggesting that voluntary commercial transactions involving renewable energy credits (RECs) would constitute a state-subsidized transaction and be subject to the MOPR. In response, several parties sought late intervention, which the Commission denies. December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 4. I would have granted those interventions. The December 2019 Order took an approach to mitigation that was far broader than any that had been contemplated to date in this proceeding and, indeed, in the Commission’s history. Under those circumstances, we would be better served by letting would-be parties have their full say, rather than forcing them to sit on the sidelines.
- 87. 87 Emera Maine v. FERC, 854 F.3d 9, 25 (D.C. Cir. 2017) (“[A] finding that an existing rate is unjust and unreasonable is the ‘condition precedent’ to FERC’s exercise of its section 206 authority to change that rate.” (quoting FPC v. Sierra Pac. Power Co., 350 U.S. 348, 353 (1956))).
- 88. 88 E.g., June 2018 Rehearing Order, 171 FERC ¶ 61,034 at P 28 (“It is axiomatic that resources receiving out-of-market subsidies need less revenue from the market than they otherwise would. The rational choice for such resources, given their need to participate in PJM’s capacity market, is to reduce their offers commensurably to ensure they clear in the market.”).
- 89. 89 E.g., id. P 29 (“Rather, the June 2018 Order emphasized the significant and continued growth of out-of-market support. As this growth continues, more subsidized resources will have the ability to offer below their costs and suppress prices” (footnotes omitted)).
- 90. 90 See, e.g., Joint Consumer Advocates June 2018 Order Rehearing Request at 8 (citing PJM 2021/2022 RPM Base Residual Action Results at 1, https://?www.?pjm.com/?-/?media/markets-ops/rpm/rpm-auction-info/2021-2022/2021-2022-base-residual-auction-report.ashx (2021/2022 BRA Summary)); see also 2021/2022 BRA Summary (“The 2021/2022 Reliability Pricing Model (RPM) Base Residual Auction (BRA) cleared 163,627.3 MW of unforced capacity in the RTO representing a 22.0% reserve margin.” (emphasis added)).
- 91. 91 See PJM Interconnection, L.L.C., 171 FERC ¶ 61,040 (2020) (Glick, Comm’r. dissenting).
- 92. 92June 2018 Rehearing Order, 171 FERC ¶ 61,034 at PP 29-30.
- 93. 93 E.g., id. PP 25, 27, 29, 34, 37.
- 94. 94 Assoc. Gas Distributors v. FERC, 824 F.2d 981, 1008 (D.C. Cir. 1987). I cannot help but note the mild irony that the rest of that example of an assumable economic theory is that “competition will normally lead to lower prices,” id. at 29, while the Commission’s theory of the case today rests on the supposedly urgent need to raise prices.
- 95. 95 See, e.g., NextEra Energy Res., LLC v. FERC, 898 F.3d 14, 23 (D.C. Cir. 2018); S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41, 65, 76 (D.C. Cir. 2014) (“[A]t least in circumstances where it would be difficult or even impossible to marshal empirical evidence, the Commission is free to act based on reasonable predictions rooted in basic economic principles.”).
- 96. 96TransCanada Power Mktg. Ltd. v. FERC, 811 F.3d 1, 13 (D.C. Cir. 2015).
- 97. 97 Today’s orders contain several variations on the notion that “adequate reserve margins today do not necessarily mean that such conditions will continue into the future.” June 2018 Rehearing Order, 171 FERC ¶ 61,034 at P 35. Sure. But the burden of proof is on the Commission to show that the current tariff is unjust and unreasonable, not on proponents of the status quo to show that the tariff will necessarily remain just and reasonable in perpetuity. See Emera Maine, 854 F.3d at 24 (“‘The proponent of a rate change under section 206, however, bears “the burden of proving that the existing rate is unlawful.’” (quoting Ala. Power Co. v. FERC, 993 F.2d 1557, 1571 (D.C. Cir. 1993)).
- 98. 98 June 2018 Rehearing Order, 171 FERC ¶ 61,034 at PP 16-17.
- 99. 99 It is certainly possible that the entry of those resources will lower the capacity market clearing price, which should not necessarily be a bad result in the eyes of an agency whose “primary purpose” is to protect customers. See, e.g., City of Chicago, Ill. v. FPC, 458 F.2d 731, 751 (D.C. Cir. 1971) (“[T]he primary purpose of the Natural Gas Act is to protect consumers.” (citing, inter alia, City of Detroit v. FPC, 230 F.2d 810, 815 (1955)).
- 100. 100 See supra P 5.
- 101. 101 Supra P 18.
- 102. 102 E.g., June 2018 Rehearing Order, 171 FERC ¶ 61,034 at P 35 (“[I]nvestors may be hesitant to invest in a market where both new entry and the viability of uneconomic existing resources is dictated largely by state subsidy programs.”); June 2018 Order, 163 FERC ¶ 61,236 at P 150 (similar).
- 103. 103 June 2018 Rehearing Order, 171 FERC ¶ 61,034 at P 28 (noting the potential that state policies will “injure non-subsidized competitors”).
- 104. 104 June 2018 Order, 163 FERC ¶ 61,236 at P 150.
- 105. 105 Id. (Glick, Comm’r, dissenting at 11)
- 106. 106 Advanced Energy Mgmt. All. v. FERC, 860 F.3d 656, 663 (D.C. Cir. 2017) (“When the Commission changes an existing filed rate under section 206, it is ‘the Commission’s burden to prove the reasonableness of its change in methodology.’” (quoting PPL Wallingford Energy L.L.C. v. FERC, 419 F.3d 1194, 1199 (D.C. Cir. 2005))); see also Emera Maine, 854 F.3d at 27 (“‘Although it is not our role to tell the Commission what the correct rate of return calculation is . . . we do have an obligation to remand when the Commission’s conclusions are contrary to substantial evidence or not the product of reasoned decisionmaking.’” (quoting Pub. Serv. Comm’n of N.Y. v. FERC, 813 F.2d 448, 465 (D.C. Cir. 1987))).
- 107. 107 December 2019 Order, 169 FERC ¶ 61,239 at P 89; see December 2019 Rehearing Order, 171 FERC ¶ 61,035 at PP 118-120.
- 108. 108 16 U.S.C. § 824.
- 109. 109 See Molly Sherlock, Cong. Research Serv., Energy Tax Policy: Historical Perspectives on and Current Status of Energy Tax Expenditures 2-3 (May 2011), available at https://fas.org/sgp/crs/misc/R41227.pdf (Energy Tax Policy).
- 110. 110 See Nancy Pfund and Ben Healey, DBL Investors, What Would Jefferson Do? The Historical Role of Federal Subsidies in Shaping America’s Energy Future, (Sept. 2011), available at http://www.dblpartners.vc/wp-content/uploads/2012/09/What-Would-Jefferson-Do-2.4.pdf; New analysis: Wind energy less than 3 percent of all federal incentives, Into the Wind: The AWEA Blog (July 19, 2016), https://www.aweablog.org/ 14419-2/ (citing, inter alia, Molly F. Sherlock and Jeffrey M. Stupak, Energy Tax Incentives: Measuring Value Across Different Types of Energy Resources, Cong. Research Serv. (Mar. 19, 2015), available at https://fas.org/sgp/crs/misc/R41953.pdf; The Joint Committee on Taxation, Publications on Tax Expenditures, https://www.jct.gov/publications.html?func=select&id=5 (last visited Apr. 16, 2020)) (extending the DBL analysis through 2016).
- 111. 111 Energy Tax Policy at 2 n.3. That credit has lapsed. Id. at 18.
- 112. 112The Joint Committee on Taxation, Estimates Of Federal Tax Expenditures For Fiscal Years 2018-2022 at 21-22 (2018); Monitoring Analytics, Analysis of the 2021/2022 RPM Base Residual Auction: Revised 95 (2018), available at https://www.monitoringanalytics.com/ reports/Reports/2018/ IMM_Analysis_ of_the_20212022_RPM_BRA_Revised _20180824.pdf (Market Monitor 2021/2022 BRA Analysis) (reporting that coal, natural gas, and nuclear collectively make up more than three-quarters of the generation mix in PJM); see generally Molly Sherlock, Cong. Research Serv., Energy Tax Policy: Historical Perspectives on and Current Status of Energy Tax Expenditures 2-6 (May 2011) (discussing the history of energy tax policy in the United States).
- 113. 113 42 U.S.C. § 2210(c).
- 114. 114 U.S. Department of Energy, 2018 Wind Technologies Market Report 70, available at http://eta-publications.lbl.gov/sites/default/files/ wtmr_final_for_posting_8-9-19.pdf (last viewed Apr. 16, 2020).
- 115. 115 Solar Energy Industries Assoc., History of the 30% Solar Investment Tax Credit 3-4 (2012), https://www.seia.org/sites/default/files/resources/ History%20of%20ITC%20Slides.pdf.
- 116. 116 Market Monitor 2021/2022 BRA Analysis 95 (reporting that coal, natural gas, and nuclear collectively make up more than three-quarters of the generation mix in PJM).
- 117. 117 December 2019 Order, 169 FERC ¶ 61,239 at P 87; December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 119.
- 118. 118 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at PP 16, 17, 19; December 2019 Order, 169 FERC ¶ 61,239 at PP 7, 40; June 2018 Order, 163 FERC ¶ 61,236 at P 153. The December 2019 Rehearing Order shies away from the words “nullify” and “disregard” that it used (quite accurately) in the underlying order. I can understand why. Those terms so clearly laid bare the glaring inconsistencies in the Commission’s effort to explain why the MOPR did not target state authority, but could not legally be applied to federal subsidies. Nevertheless, the rationale in today’s order is the same: The new MOPR cannot be applied to federal subsidies because doing so would somehow contravene an act of Congress, which is precisely the result that the Commission insists it would not have on state policies.
- 119. 119 Atlanta Gas Light Co. v. FERC, 756 F.2d 191, 198 (D.C. Cir. 1985); Cal. ex rel. Harris v. FERC, 784 F.3d 1267, 1274 (9th Cir. 2015) (same).
- 120. 120 December 2019 Order, 169 FERC ¶ 61,239 at n.177.
- 121. 121 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 120.
- 122. 122 Today, the Commission tries a slightly different tack, responding to rehearing requests raising this very point with the assertion that the cited canons “reflect judicial guidance regarding the appropriate way to reconcile Congressional directives.” December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 120. No doubt they do, but all the interpretive canons in the world cannot explain why it is rational to pretend that applying the MOPR to a federal subsidy has an inherently different effect than applying it to a state subsidy.
- 123. 123 To be clear, I vehemently disagree that is, but I’ll indulge the hypothetical for the moment.
- 124. 124 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 119.
- 125. 125 Complex Consol. Edison Co. of N.Y. v. FERC, 165 F.3d 992, 1013 (D.C. Cir. 1999) (“‘Differences . . . based on relevant, significant facts which are explained are not contrary to the NGA.’” (quoting TransCanada Pipelines Ltd. v. FERC, 878 F.2d 401, 413 (D.C. Cir. 1989)) (emphasis added)).
- 126. 126 December 2019 Order, 169 FERC ¶ 61,239 at P 89; December 2019 Rehearing Order, 171 FERC ¶ 61,035 at PP 118-119 & n.298.
- 127. 127 See supra Section I.
- 128. 128 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at n.298.
- 129. 129New York v. FERC, 535 U.S. 1, 6 (2002) (“[W]hen it enacted the FPA in 1935, Congress authorized federal regulation of electricity in areas beyond the reach of state power, such as the gap identified in Attleboro, but it also extended federal coverage to some areas that previously had been state regulated.” (footnotes omitted)).
- 130. 130 Zibelman, 906 F.3d at 50 (quoting Rochester Gas & Elec. Corp. v. Pub. Serv. Comm’n of N.Y., 754 F.2d 99, 104 (2d Cir. 1985)).
- 131. 131 See supra note 10 and accompanying text.
- 132. 132 See supra Section I.
- 133. 133 PJM Rehearing and Clarification Request at 23.
- 134. 134 New Jersey Board Rehearing Request at 47-48.
- 135. 135 Id. at 48.
- 136. 136 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 386.
- 137. 137 See The 2019 BGS Auctions, www.bgs-auction.com http://www.bgs-auction.com/documents/ 2019_BGS_Auction_Results.pdf (last viewed Apr. 16, 2020).
- 138. 138 See, e.g.,New Jersey Board Rehearing Request at n.260 (“New Jersey is not alone; PJM’s other restructured states follow models similar to the BGS construct.”).
- 139. 139 DC Commission Rehearing and Clarification Request at 1-3; Pennsylvania Commission Rehearing and Clarification Request at 13. As noted, PJM also sought clarification, arguing that “it is not apparent how these auctions amount to a State Subsidy.” PJM Rehearing and Clarification Request at 23.
- 140. 140 See Maryland Public Service Commission, Report to the Governor and the Maryland General Assembly on the Status of Standard Offer Service, the Development of Competition, and the Transition of Standard Offer Service to a Default Service at 5-6 (Dec. 31, 2018), available at https://www.psc.state.md.us/wp-content/uploads/Final-Competition-Report.pdf (discussing Maryland’s default service auction).
- 141. 141 See James Letzelter, The Liberty Consulting Group, Inc., Delmarva Power & Light’s 2020 Request for Proposals for Full Requirements Wholesale Electric Supply for Standard Offer Service (2020), available at https://depsc.delaware.gov/wp-content/uploads/sites/54/2020/02/Liberty-DE-PSC-Technical-Consultant-Final-Report-02-19-2020.pdf.
- 142. 142 See How are electric generation rates set? https://www.puco.ohio.gov/be-informed/consumer-topics/how-are-electric-generation-rates-set/ (last viewed Apr. 16, 2020).
- 143. 143 New Jersey Board Rehearing Request at 48; see Pennsylvania Commission Rehearing and Clarification Request at 13.
- 144. 144 See Overview http://www.bgs-auction.com/ bgs.auction.overview.asp (last visited Apr. 16, 2020) (describing New Jersey’s default service auction).
- 145. 145 DC Commission Rehearing and Clarification Request at 2.
- 146. 146 Pennsylvania Commission Rehearing and Clarification Request at 13.
- 147. 147 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 106.
- 148. 148 Id.
- 149. 149E.g. id. PP 36, 55, 224.
- 150. 150 Id. P 130.
- 151. 151 See id. P 38; see also id. P 130 (rejecting PJM’s proposed materiality threshold because “out-of-market support at any level is capable of distorting capacity prices”).
- 152. 152 At no point in today’s order or the December 2019 Order does the Commission suggest that state industrial development or siting support programs are likely to have less of an effect on wholesale rates than the other state policies targeted by the new MOPR. See, e.g., id. PP 106-108 (discussing the justification for excluding these policies from the new MOPR).
- 153. 153 Id. PP 20, 301. In any case, the District of Columbia Attorney General’s rehearing request details how these programs can provide enormous financial benefits to generators, significantly decreasing their capacity market offers in a way that affects the capacity market rate every bit as much as the state policies targeted by today’s orders. DC Attorney General Rehearing Request at 22-24. In addition, that rehearing request explained how these supposed “generic” subsidies are, in fact, often deployed for the purpose of subsidizing particular resources. Id. at 23-24; see Clean Energy Associations Rehearing and Clarification Request at 40-41. The Commission’s response that general industrial development policies are categorically “too attenuated” to constitute a state subsidy for the purposes of the MOPR fails to wrestle with the evidence and arguments showing the opposite to be true.
- 154. 154 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 106; December 2019 Order, 169 FERC ¶ 61,239 at P 68.
- 155. 155 See supra note 23.
- 156. 156See id.
- 157. 157 Throughout the December 2019 Rehearing Order, the Commission responds to this point by quoting portions of the December 2019 Order that describe the Commission’s action without responding to this argument. See, e.g., December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 106 (“As we said in the December 2019 Order, the expanded MOPR is not intended to address all commercial externalities or opportunities that might affect the economics of a particular resource.”). Although that quote accurately describes what the Commission said in its earlier order, it does not respond to the arguments that the line drawing described in that quote is arbitrary and capricious. That is a not a reasoned response; rehearing orders are an opportunity to further explain the Commission’s analysis, not just regurgitate it.
- 158. 158 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 390.
- 159. 159 December 2019 Order, 169 FERC ¶ 61,239 (Glick, Comm’r, dissenting at P 23).
- 160. 160 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 301; June 2018 Rehearing Order, 171 FERC ¶ 61,034 at P 50; June 2018 Order, 163 FERC ¶ 61,236 at PP 1-2, 150, 156, 161.
- 161. 161 ISO New England Inc., 162 FERC ¶ 61,205 at P 21; see December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 141.
- 162. 162 ISO New England Inc., 162 FERC ¶ 61,205 at P 21.
- 163. 163 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 320; December 2019 Order, 169 FERC ¶ 61,239 at P 17.
- 164. 164 Sylwia Bialek & Burcin Unel, Institute for Policy Integrity, Capacity Markets and Externalities: Avoiding Unnecessary and Problematic Reforms at 6-7 (2018).
- 165. 165 I.e., the capacity revenue a resource needs to be economic over and above what it earns in the energy and ancillary service markets. N.Y. Indep. Sys. Operator, Inc., 170 FERC ¶ 61,121 (2020) (Glick, Comm’r, dissenting at P 4).
- 166. 166 Which is, after all, why the Commission’s orders use net measures as the default offer floors for resources subject to the new MOPR. See infra PP 81-85.
- 167. 167 December 2019 Order, 169 FERC ¶ 61,239 at PP 54-57.
- 168. 168 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 139 (citing NextEra, 898 F.2d at 21).
- 169. 169 Id. at n.330 (non-exhaustive list of fifteen different rehearing requests raising this point).
- 170. 170Id. P 139.
- 171. 171 Id.
- 172. 172 Id. In so doing, the Commission goes out of its way to criticize what I described as a “conservative,” “back-of-the-envelope” calculation meant to help fill the void left by the Commission’s failure to seriously consider the December 2019 Order’s financial impact on customers. Id. n.352. In particular, it points to doubts raised by the Market Monitor about whether that calculation considered the right quantity of to-be-MOPR megawatts of capacity from nuclear generators. Id. I assumed it would be 6,000 MW. The Market Monitor suggested that number would be closer to 4,000 MW. Id. He may be right; it is hard to say how an unprecedented mitigation regime will work in practice. In any case today’s order makes clear that my cost estimate was, if anything, too conservative. For one thing, my estimate did not consider the cost of paying twice for capacity as a result of MOPR’ing the tens of the thousands of megawatts of renewable resources slated to be developed in the region to meet state renewable energy targets over the coming years. Clean Energy Associations estimated that that cost will be between $14 and $24 billion over the next decade. Clean Energy Associations Rehearing and Clarification Request at 22-23. My estimate also did not attempt to assess the effects of the bizarre conclusion, affirmed today, that the default service auctions in PJM retail choice states are somehow “subsidies,” which will subject the resources that serve significant fractions of load in those states to the MOPR. See supra PP 49-51. Those are just two examples, but they illustrate why I remain confident that, when the dust settles, that back-of-the-envelope calculation will prove to have been a conservative one.
- 173. 173 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at PP 139-140 (asserting that while the “actual cost impacts of the replacement rate are speculative at this point,” they will result in a rate increase the Commission deems just and reasonable).
- 174. 174 N.Y. State Pub. Serv. Comm’n, 158 FERC ¶ 61,137 (2017) (Bay, Chairman, concurring).
- 175. 175 Id.
- 176. 176 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 141.
- 177. 177 See supra PP 22-23.
- 178. 178 At various points, the Commission makes assertions, such as even the new MOPR forces customers to “pay twice” for capacity, “preserving the integrity of the capacity market will benefit customers over time by ensuring capacity is available when needed.” December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 223. Conclusory assertions are the same thing as considering customers’ interests.
- 179. 179 Id. P 139.
- 180. 180 See Market Monitor 2021/2022 BRA Analysis 2 (“The capacity market is unlikely ever to approach a competitive market structure in the absence of a substantial and unlikely structural change that results in much greater diversity of ownership. Market power is and will remain endemic to the structure of the PJM Capacity Market . . . . Reliance on the RPM design for competitive outcomes means reliance on the market power mitigation rules.”)
- 181. 181 Institute for Policy Integrity Initial Brief at 14-16.
- 182. 182For example, the RTO-wide market seller offer cap for the 2018 Base Residual Auction $237.56 per MW/day while the clearing price for the RTO-wide zone was $140.00 per MW/day. See PJM Interconnection, 2021/2022 RPM Base Residual Auction Results, https://www.pjm.com/-/media/markets-ops/rpm/rpm-auction-info/2021-2022/2021-2022-base-residual-auction-report.ashx (last visited Dec. 19, 2019).
- 183. 183 For example, recognizing that demand response is a “short-lead-time” resource, the Commission previously directed PJM to revise the allocation of the short-term resource procurement target so that short-lead-time resources have a reasonable opportunity to be procured in the final incremental auction. PJM Interconnection L.L.C., 126 FERC ¶ 61,275 (2009). The Commission subsequently removed the short-term resource procurement target only after concluding that doing so would not “unduly impede the ability of Demand Resources to participate in PJM’s capacity market.” PJM Interconnection, L.L.C., 151 FERC ¶ 61,208, at PP 394, 397 (2015).
- 184. 184 Under PJM’s current market rules, CSPs must submit a Demand Resource Sell Offer Plan (DR Sell Offer Plan) to PJM no later than 15 business days prior to the relevant RPM Auction. This DR Sell Offer Plan provides information that supports the CSP’s intended DR Sell Offers and demonstrates that the DR being offered is reasonably expected to be physically delivered through Demand Resource Registrations for the relevant delivery year. See PJM Manual 18: PJM Capacity Market – Attachment C: Demand Resource Sell Offer Plan.
- 185. 185 As CPower and LSPower explain, such customers typically make participation decisions in a shorter time frame than the three-year forward auction designed to reflect the time needed to develop a new generation facility. CPower/LSPower Rehearing Request at 11.
- 186. 186 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 266.
- 187. 187 In response to requests to clarify offer floors for demand response resources backed by a combination of behind-the-meter generation and reduced consumption, the Commission simply reiterates that the December 2019 Order found that different default offer price floors should apply to demand response backed by behind-the-meter generation and demand response backed by reduced consumption (i.e., curtailment-based demand response programs). December 2019 Rehearing Order, 171 FERC ¶ 61,035 at PP 187-188.
- 188. 188 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at 265 (emphasis added).
- 189. 189 In addition, the December 2019 Rehearing Order concludes that if a demand response resource earns any revenue through a state-sponsored retail demand response program, it is impermissibly subsidized and subject to the new MOPR. Id. P 264. But just a few months ago, the Commission approved rules in NYISO that treat a state retail demand response program as a subsidy for the purposes of the capacity only if the purpose of that state program is to procure demand response for its capacity value. N.Y. Pub. Serv. Comm’n v. N.Y. Indep. Sys. Operator, Inc.,170 FERC ¶ 61,120 (2020) (“[W]e will evaluate retail-level demand response programs on a program-specific basis to determine whether payments from those programs should be excluded from the calculation of SCRs' offer floors.”). Those are radically different approaches to the permissible effects of state retail demand response programs, which cannot be papered over simply by observing that one set of rules apply in PJM and another in NYISO.
- 190. 190 Indeed, buried in footnotes in the December 2019 Rehearing Order, the Commission appears to insinuate that demand response resources, among other resources, should perhaps be kicked out of the capacity market entirely. See December 2019 Rehearing Order, 171 FERC ¶ 61,035 at n.598. (“We pause to note that, as the capacity market has developed, an ever-growing number of resource types have come to participate in the market that were not contemplated. This proceeding . . . does not necessarily resolve issues regarding whether, to what extent, and under what terms resources that are not able to produce energy on demand should participate in the capacity market consistent with the Commission’s mandate to ensure the reliability of the electric system”); id. n.451 (“The Commission is concerned that there may be a point where energy efficiency is unable to supply capacity when needed to maintain system reliability. However, that issue can be pursued in a separate proceeding.”).
- 191. 191 PJM explains that, beyond the initial costs associated with developing a customer contract and installing any required hardware or software, it could not identify any avoidable costs that would be incurred by an existing Demand Resource that would result in a MOPR Floor Offer Price of greater than zero. PJM Initial Brief at 47.
- 192. 192The Commission offers no data, such as sell-offer data of utilities or public power entities or provides any evidence in support of this finding. See SMECO Rehearing Request at 6; Allegheny Rehearing Request at 12.
- 193. 193 After all, public power entities typically procure roughly the amount of supply needed to meet their demand. In response to arguments raising this point and contending that an approach based on net long, net short thresholds (which would formally require a rough equivalence between supply and demand to avoid mitigation) would be just and reasonable and more consistent with Commission precedent, see Public Power Entities Request for Rehearing and Clarification at 30-32; PJM Request for Rehearing and Clarification at 13-14; ODEC Request for Rehearing and Clarification at 7-9, today’s order asserts that “the expanded MOPR is premised on a resource’s ability to suppress price due to the benefit it receives from out-of-market support, not based on the likelihood and ability to exercise of buyer-side market power.” December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 228. But the ability to “exercise” buyer-side market power is the ability to reduce prices. If public power entities’ load equals their supply, their choice of how to serve that load will not cause price suppression plain and simple. The Commission has previously found such thresholds can protect against price suppression. See N.Y. Indep. Sys. Operator, Inc., 170 FERC ¶ 61,121, at P 90 (2020) (discussing buyer-side market power concerns associated with self-supply). It fails to provide a reasoned basis for rejecting the same approach today.
- 194. 194 PJM Rehearing and Clarification Request at 13.
- 195. 195 These terms get confusing quickly. Under the FPA, a “public utility” will typically be privately owned while an entity that is not a “public utility” will often be publically owned. See 16 U.S.C. §§ 824(e) & (f). Accordingly, “public power” is generally made up of non-public utilities.
- 196. 196NJBPU,744 F.3d at 84 (footnote omitted).
- 197. 197 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at PP 243, 325.
- 198. 198 American Municipal Power and Public Power Association of New Jersey Initial Brief at 14-15; American Public Power Association Initial Brief at 15.
- 199. 199 PJM Manual 18B, Energy Efficiency Measurement & Verification 10-13, available at pjm.com/~/media/documents/manuals/ m18b.ashx. After those four years, energy efficiency resources no longer participate in the capacity auction and instead are recognized only as reductions in demand. Id.
- 200. 200 Id. Participate,not clear. That means that if an energy efficiency resource bids into, but does not clear the capacity market, its capacity is still added back to the demand curve. This is because as PJM explains, the auction parameters are adjusted by adding the MWs in approved energy efficiency plans that are proposed for that auction back into the reliability requirements. PJM Rehearing and Clarification Request at 15, n.41. For approved plans, that add back occurs whether or not resources will know if they cleared the auction.
- 201. 201 December 2019 Order, 169 FERC ¶ 61,239 at P 255.
- 202. 202 The Independent Market Monitor for PJM, Analysis of the 2021/2022 RPM Base Residual Auction 20 (2018), available at http://www.monitoringanalytics.com/ reports/Reports/2018/IMM_Analysis_of_the_20212022_RPM_BRA_Revised_20180824.pdf (2018 PJM State of the Market Report).
- 203. 203 At that point, the energy savings from energy efficiency resources are “baked into” PJM’s demand forecast and, thus, the resources are no longer eligible for a capacity payment for reducing demand relative to that projection.
- 204. 204 E.g., PJM Rehearing and Clarification Request at 15 & n.41; Advanced Energy Entities at 12-15; CPower/LSPower Rehearing and Clarification Request at 6-8.
- 205. 205 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 257 (“We reject the contention that energy efficiency’s market participation cannot suppress prices. State Subsidies, if effective, will by their very nature increase the quantity of whatever is subsidized. State subsidies to energy efficiency should result in additional energy efficiency resource participation.”).
- 206. 206 Id. P 256.
- 207. 207 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 257.
- 208. 208 December 2019 Order, 169 FERC ¶ 61,239 (Glick, Comm’r, dissenting at P 41) (footnotes and internal quotation marks omitted).
- 209. 209 See December 2019 Rehearing Order, 171 FERC ¶ 61,035 at n.808 (“The treatment of voluntary RECs in this order is not a determination regarding whether the revenue from voluntary REC transactions results or could result in capacity market distortions.”); id. n.807 (exact same point).
- 210. 210 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 326 (finding “to the extent coal ash sales are purely voluntary, such that they do not fall under the definition of State Subsidy, they are similarly situated to voluntary RECs, which are not mitigated under the replacement rate.”).
- 211. 211 December 2019 Order, 169 FERC ¶ 61,239 at P 140.
- 212. 212 Id.
- 213. 213 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at PP 157-159.
- 214. 214 Independent Market Monitor Brief at 16 (“A competitive offer is a competitive offer, regardless of whether the resource is new or existing.”); id. at 15-16 (“It is not an acceptable or reasonable market design to have two different definitions of a competitive offer in the same market. It is critical that the definitions be the same, regardless of the reason for application, in order to keep price signals accurate and incentives consistent.”).
- 215. 215 Id.
- 216. 216 Cf. December 2019 Rehearing Order, 171 FERC ¶ 61,035 at 230(“The objective of the capacity market is to select the least cost resources to meet resource adequacy goals.”).
- 217. 217 Id. P 158 (“Using Net ACR as the MOPR value for new resources would not serve the purpose of the MOPR, because it does not reflect new resources’ actual costs of entering the market and therefore would not prevent uneconomic State-Subsidized Resources from entering the market.”); December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 159 (“Using Net CONE as the default offer price floor for new resources will ensure that the expanded MOPR achieves its goal and prevents uneconomic new entry from clearing the capacity market as a result of State Subsidies”).
- 218. 218 To appreciate this, one need only look at the Commission’s apparent willingness to set certain resources offer floor—i.e., their Net CONE—above the demand curve’s intercept. That means that the Commission is willing to set price floors that ensure that ensure that those resource can never clear the capacity market, no matter how serious the reliability need and even if that resource is the only that can meet it. See Illinois Commission Rehearing Request at 18. In a choice between ensuring reliability and blocking state policies, the Commission will choose the latter.
- 219. 219 June 2018 Order, 163 FERC ¶ 61,236 at P 1.
- 220. 220 See Supra Section II.B.1.b.
- 221. 221 In the December 2019 Order, the Commission renamed what is currently the “Unit Specific Exception” in PJM’s tariff to be a Unit Specific Exemption. But, regardless of name, it does not free resources from mitigation because they are still subject to an administrative floor, just a lower one. An administrative offer floor, even if based on the resource’s actual costs does not protect against over-mitigation and certainly is not market competition.
- 222. 222 It bears repeating that the Commission has expressly abandoned market-power—the justification for cost-of-service regulation—as the basis for its new MOPR. December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 45 (“[T]he expanded MOPR does not focus on buyer-side market power mitigation.”).
- 223. 223 See Public Power Entities Rehearing Request at 4 (“Ironically, by its latest action, the Commission has removed any remaining genuine market component . . .by requiring all ‘competitive’ offers to be determined administratively in Valley Forge, Pennsylvania.”).
- 224. 224 The Commission is requiring that all new resources, regardless of type, must use a standard asset life. That flouts the entire premise of a Unit-Specific Exemption, which, the Commission reminds us throughout today’s order, is supposed to reflect the specific unit’s costs and expected market revenues. It is particularly, “arbitrary and illogical” to mandate that resources assume a 20-year asset life when most renewable units typical have a useful commercial life of 35 years. See Clean Energy Advocates Rehearing Request at 83. The Commission dismisses such concerns by stating that standardized inputs are a simplifying tool December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 290.
- 225. 225 December 2019 Order, 169 FERC ¶ 61,239 at P 162.
- 226. 226 David Roberts, Trump’s crude bailout of dirty power plants failed, but a subtler bailout is underway (Mar. 23, 2018), https://www.vox.com/energy-and-environment/2018/3/23/17146028/ferc-coal-natural-gas-bailout-mopr.
- 227. 227 Moreover, as discussed above, see supra P 67, PJM’s capacity market is structurally uncompetitive and lacks any meaningful market mitigation. There is every reason to believe that today’s orders will exacerbate the potential for the exercise of market power.
- 228. 228 December 2019 Order, 169 FERC ¶ 61,239 at PP 173, 202, 208.
- 229. 229 Id. PP 2, 42.
- 230. 230See supra Section II.B.4.
- 231. 231 Internal Market Monitor Reply Brief at 4.
- 232. 232 December 2019 Rehearing Order, 171 FERC ¶ 61,035 at P 348; June 2018 Order, 163 FERC ¶ 61,236 at P 157.
- 233. 233 June 2018 Order, 163 FERC ¶ 61,236 at P 161.
- 234. 234 Danny Cullenward & Shelley Welton, The Quiet Undoing: How Regional Electricity Market Reforms Threaten State Clean Energy Goals, 36 Yale J. on Reg. Bull. 106, 108 (2019), available at https://www.yalejreg.com/bulletin/the-quiet-undoing-how-regional-electricity-market-reforms-threaten-state-clean-energy-goals/.
- 235. 235 See supra p 79; see also supra note 190.