Skip Navigation
 
Federal Energy Regulatory Commission



Media Statements & Speeches

 
Text Size small medium large

Commissioner Richard Glick Statement
December 19, 2019

Docket No. EL16-49-000
Item No: E-1 PDF

Print this page
Bookmark and Share

Dissent Regarding FERC Directing PJM to Expand Minimum Offer Price Rule

From the beginning, this proceeding has been about two things: Dramatically increasing the price of capacity in PJM and slowing the region’s transition to a clean energy future. Today’s order will do just that. I strongly dissent from today’s order as I believe it is illegal, illogical, and truly bad public policy.

Today’s order has three major elements. First, it establishes a sweeping definition of subsidy that will potentially subject much, if not most, of the PJM capacity market to a minimum offer price rule (MOPR). Second, it creates 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. Third, it unceremoniously discards the so-called “resource-specific FRR Alternative,”1 which had been the crux of the Commission’s proposal in the June 2018 Order that sent us down the current path.2

The order amounts to a multi-billion-dollar-per-year rate hike for PJM customers, which will grow with each passing year. It will increase both the capacity price in the Base Residual Auction as well as the already extensive quantity of redundant capacity in PJM. It is a bailout, plain and simple.

The order will also ossify the current resource mix. It is carefully calibrated to give existing resources a leg up over new entrants and to force states to bear enormous costs for exercising the authority Congress reserved to the states when it enacted the Federal Power Act (FPA). States throughout the PJM region are increasingly addressing the externalities of electricity generation, including the biggest externality of them all, anthropogenic climate change. We all know what is going on here: The costs imposed by today’s order and the ubiquitous preferences given to existing resources are a transparent attempt to handicap those state actions and slow—or maybe even stop—the transition to a clean energy future.

But poor policy is only part of the problem. The Commission has bungled the proceeding from the beginning. The June 2018 Order upended the entire market by finding the PJM Reliability Pricing Model (i.e., the capacity market) unjust and unreasonable based on nothing more than theory and a thin record. It was, as former Commissioner LaFleur aptly described it, “a troubling act of regulatory hubris.”3 The Commission then sent PJM back to the drawing board with only vague guidance and nowhere near the time needed to develop a proper solution. Under those circumstances, it should have been no surprise that the Commission found itself paralyzed and unable to act for more than a year after receiving PJM’s compliance filing. And while that result may not have been surprising, it was deeply unfair to PJM, its stakeholders, and the region’s 65 million customers.

Today’s order is more of the same. The Commission provides almost no guidance on how its sweeping definition of subsidy will work in practice or how it will interact with the complexities posed by a capacity market spanning 13 very different states and the District of Columbia. In addition, the Commission’s abandonment of the resource-specific FRR Alternative—the one fig leaf that the June 2018 Order extended to the state authority—will likely culminate in a system of administrative pricing that bears all the inefficiencies of cost-of-service regulation, without any of the benefits. And despite yet another dramatic change in direction, the Commission provides PJM only 90 days to work out a laundry list of changes that go to the very heart of its basic market design. And so, as we embark on yet another round of poorly conceived policy edicts coupled with too little time to do justice to the details, it seems that the Commission has learned none of the lessons from the last year-and-a-half of this saga. It is not hard to understand why states across the region are losing confidence in the Commission’s ability to ensure resource adequacy at just and reasonable rates.

Today’s Order Unlawfully Targets 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,4 Congress expressly precluded the Commission from regulating “facilities used for the generation of electric energy.”5 Instead, Congress gave the states exclusive jurisdiction to regulate generation facilitates.6

But while those jurisdictional lines are clearly drawn, the spheres of jurisdiction themselves are not “hermetically sealed.”7 One sovereign’s exercise of its authority will inevitably affect matters subject to the other sovereign’s exclusive jurisdiction.8 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.9 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”10 and the natural result of a system in which regulatory authority is divided between federal and state government.11 Maintaining that interplay and permitting each sovereign to carry out its designated role is essential to the dual-federalist structure that Congress made the foundation of FPA.

In recent years, the Supreme Court has repeatedly admonished both the Commission and the states that the FPA does not permit actions that “aim at” or “target” the other sovereign’s exclusive jurisdiction. 12 Beginning with Oneok, the Court has underscored that its “precedents emphasize the importance of considering the target at which the state law aims.”13 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” affected wholesale rates and that the Commission does not regulate or target a matter reserved for exclusive state jurisdiction.14 And in Hughes, the Court again emphasized that a state may not aim at or target the Commission’s jurisdiction, which means that a state cannot not “tether” its policy design to participation in the Commission-jurisdictional wholesale market.15 In the intervening few years, the lower federal courts have carefully followed the Court’s strict prohibition on one sovereign regulating in a manner that aims at or targets the other jurisdiction.16

The Commission’s use of the MOPR in this proceeding violates that principle. By its own terms, the Commission’s “target” or “aim” is the PJM states’ exercise of their exclusive jurisdiction to regulate generation facilities. At every turn, the Commission has focused on the purported problems caused by the states’ decisions to promote particular types of generation resources. For example, the Commission began its determination section in the June 2018 Order by noting that “[t]he records [before it] 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.”17 The Commission noted that state efforts to shape the resource mix are increasing and are projected to increase at an even faster rate going forward.18 The Commission explained that these state actions created “significant uncertainty” and left resources unable to “predict whether their capital will be competing against” subsidized or unsubsidized units.19 And the Commission ultimately found that PJM’s tariff was unjust and unreasonable because of the potential for subsidized resources to participate in and affect the capacity market clearing price20—in other words, the natural consequence of any state regulation of generation facilities.21

Today’s order is even more direct in its attack on state resource decisionmaking. It begins by reiterating the finding that an expanded MOPR is necessary in light of increasing state action to shape the generation mix, “especially out-of-market state support for renewable and nuclear resources.”22 It then asserts that PJM’s existing, limited MOPR is unjust and unreasonable because it does not specifically prevent state actions from keeping existing resources operational or facilitating the entry of new resources through the capacity market.
23 To address those concerns, the Commission adopts a sweeping MOPR that could potentially apply to any conceivable state effort to shape the generation mix. And, tellingly, it rejects the suggestion that the MOPR should apply only to those state policies that actually affect the wholesale rate.24

In fact, the Commission comes right out and acknowledges that its goal is to “send price signals on which investors and consumers can rely to guide the orderly entry and exit of economically efficient capacity resources.” 25 That means the Commission is attempting to establish a set of price signals for determining resource entry and exit that will supersede state resource decisionmaking and better reflect the Commission’s policy priorities. It is hard to imagine how the Commission could much more directly target or aim at state authority over resource decisionmaking. Although the Commission insists that it is not impinging on state authority, it concedes elsewhere in today’s order that the MOPR disregards and nullifies the policies to which it applies.26 And, as if that were not enough, the Commission compounds its intrusion on state authority by substituting its own policy preferences—a peculiar mix of reverence for “competition” and reliance on administrative pricing—to entrench the existing resource mix and trample states’ concerns about the environmental externalities of electricity generation.

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.”27 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,” the state actions are front and center in the Commission’s justification for acting.28 To be sure, the Commission doffs its hat to “price suppression” throughout the order. But repeating the phrase “price suppression” does not change the fact that the Commission’s stated concern in both the June 2018 Order and today’s order is the states’ exercise of their authority to shape the generation mix or that the Commission’s stated goal for the Replacement Rate is to displace 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. That’s the equivalent of saying that a grounded kid 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.

The MOPR’s recent evolution illustrates the extent of the shift in the Commission’s focus from the wholesale market to state resource decisionmaking. The MOPR was originally used to mitigate buyer-side market power within the wholesale market29—a concern at the heart of the Commission’s responsibility to ensure that wholesale rates are just and unreasonable.30 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.31

It was only last year that state resource decisionmaking became the MOPR’s primary target. For the first time, the Commission asserted that the MOPR could be used to block state resource decisionmaking writ large rather than only those state policies that could rationally be aimed at exercising market power in order to depress prices. The Commission has never been able to justify its 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.32 A few months later, at the outset of this proceeding, the Commission abandoned “investor confidence” altogether and asserted 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.33 And today, the Commission adds yet another new twist: That state subsidies “reject the premise the capacity markets.”34 But, as with investor confidence and market integrity, it is hard to know exactly what that premise is. If there is one thing that those inscrutable principles share, it is their inability to conceal, much less justify, the fundamental shift in the Commission’s focus. Whereas the MOPR once targeted efforts to exercise market power on behalf of load and directly reduce the capacity market price, it now targets state resource decisionmaking, and particularly state efforts to address the externalities of electricity generation. That change is one of kind and not just degree. And because that shift in focus is wholly impermissible, the Commission has little choice but to hide behind excuses such as investor confidence, market integrity, and the premise of capacity markets—principles that, as applied here, are so abstract as to be meaningless. The Commission’s effort to recast the MOPR as always having been about price suppression at some level of generality35 obfuscates that point and badly mischaracterizes the recent shift in the MOPR’s focus.36

The consequences of the Commission’s theory of jurisdiction reinforce the extent to which it intrudes on state authority. Taken seriously, today’s order permits the Commission to zero out any state effort to address the externalities associated with sales of electricity. That includes the Regional Greenhouse Gas Initiative (RGGI) a market-based program to reduce greenhouse gas emissions. It would also target any future carbon tax, cap-and-trade program, or clean energy standard—all of which would inevitably affect the wholesale market clearing price. That result is untenable. A theory of jurisdiction that allows the Commission to block any state effort to economically regulate the externalities associated with electricity generation is not a reasonable interpretation of the FPA’s balance between federal and state jurisdiction.37

Today’s Order Does Not Establish a Just and Reasonable Rate


Under the Commission’s Definition, Almost All Capacity in PJM Is a Subsidized Resource

Taking today’s order at face value, much—and perhaps the vast majority—of the capacity in PJM will potentially be subject to the MOPR. That is because the Commission’s broad definition of subsidy encompasses almost any aspect of state resource decisionmaking. Although the Commission’s various exemptions and carve-outs will blunt some of the resulting impact, the definition of subsidy will nevertheless apply to a vast swathe of resources and create enormous uncertainty, even for those resources that eventually manage to escape mitigation. Moreover, as explained in the following sections,38 resources that do not escape mitigation will no longer be competing based on their offers to supply capacity, but rather based on a complex system of administrative pricing whose entire purpose is to increase capacity prices.

It all starts with the Commission’s definition of subsidy. A State Subsidy is A direct or indirect payment, concession, rebate, subsidy, non-bypassable consumer charge, or other financial benefit that is (1) a result of any action, mandated process, or sponsored process of a state government, a political subdivision or agency of a state, or an electric cooperative formed pursuant to state law, and that (2) is derived from or connected to the procurement of (a) electricity or electric generation capacity sold at wholesale in interstate commerce, or (b) an attribute of the generation process for electricity or electric generation capacity sold at wholesale in interstate commerce, or (3) will support the construction, development, or operation of a new or existing capacity resource, or (4) could have the effect of allowing a resource to clear in any PJM capacity auction.39

Let’s begin with the biggest categories of capacity resources newly subject to the MOPR: Resources relied upon by vertically integrated utilities and public power (including municipal utilities and electric cooperatives). Vertically integrated utilities and public power represent nearly a fifth of the capacity in PJM.40 All these entities recover their costs through non-bypassable consumer charges that are the result of “a process of a state government, a political subdivision or agency of a state, or an electric cooperative formed pursuant to state law.”41

In addition, as I noted in my dissent from the underlying order, the PJM states provide dozens of different subsidies and benefits tied to particular generation resources or generation types.42 Those ubiquitous subsidies expose a vast number of resources to potential mitigation. For example, Kentucky exempts companies that use coal to generate electricity (its principal source of electricity43) from paying property taxes,44 while other states provide tax breaks for the fuel types that play an important role in their local economies. 45 All of those programs qualify as subsidies as they are “derived from or connected to the procurement” of electricity or capacity or “could have the effect of allowing a resource to clear in any PJM capacity auction.”46 But those are just some of the obvious State Subsidies. The Commission’s definition will also ensnare a variety of state actions that have little in common with any ordinary use of the word “subsidy.” For example, any resource that benefits from a state carbon tax, cap-and-trade program, or clean energy standard would be subject to mitigation because, as a result of state action, it receives financial benefit (whether direct or indirect) that is connected to electricity generation or an attribute of the generating process. Putting aside the affront to state jurisdiction, consider the mess that would create. Every relatively clean resource would “benefit” from a carbon tax or cap-and-trade system by virtue of becoming more cost-competitive. That benefit would not be limited to zero-emissions resources. Instead, taking the Commission’s definition at face value, every relatively efficient natural gas-fired resource—including existing ones—would be subject to mitigation because they are relatively less carbon-intensive.

That is not an abstract concern. A literal application of the subsidy definition includes RGGI because it provides a financial benefit as a result of state action or state-mandated process. This means that every relatively low-emitting generator in Delaware and Maryland47 will be subject to mitigation. And the same fate may shortly befall relatively clean generators in Virginia, Pennsylvania, and New Jersey—all of which are considering or have announced their intention to join RGGI in the near future.

In addition, the PJM states have a host of idiosyncratic regulatory regimes that may well trigger the MOPR. Case-in-point: The New Jersey Basic Generation Service Electricity Supply Auction (BGS auction). Through this state-mandated process, electric distribution companies solicit offers from resources to serve their load. The plain language of the Commission’s definition of subsidy would treat any resource that serves load through the BGS auction as subsidized and, therefore, subject to the MOPR. That means that PJM and its Market Monitor will need to look behind the results of every BGS auction to determine which resources are receiving a benefit from this state process, which covers nearly 8,000 MW of load.48 That could easily mean that the majority of resources that serve load in New Jersey will now be subject to mitigation. As this example illustrates, even state processes that are open, fair, transparent, and fuel-neutral may be treated as state subsidies, irrespective of the underlying state goals.

Perhaps the Commission will find a way to wiggle out from under its own definition of subsidy in ruling on PJM’s compliance filing or over the course of what will no doubt be years of section 205 filings, section 206 complaints, and requests for declaratory orders addressing the definition of subsidy. But even under the best case scenario, where the Commission provides PJM and its stakeholders with quick and well-reasoned guidance on the meaning of “State Subsidy” (and, based on the Commission’s performance to date in this proceeding, I would not get my hopes up), it will likely be years before we have a concrete understanding of how the subsidy definition works in practice or resources know for sure whether they will be subject to mitigation.

The Replacement Rate Is Arbitrary and Capricious

Although the subsidy definition is broad, it nevertheless contains a number of arbitrary and capricious distinctions exemptions, and classifications. My point is not that the Commission should further expand the MOPR or apply it more stringently. As should by now be clear, I would altogether get out of the business of mitigating public policies. My point here is that the Commission’s arbitrary application of the MOPR only underscores the extent to which it is poor public policy and not the product of reasoned decisionmaking.

The Commission’s Exclusion of Federal Subsidies Is Arbitrary and Capricious

No single determination in today’s order is more arbitrary than the Commission’s exclusion of all federal subsidies. Federal subsidies have pervaded the energy sector for more than a century, beginning even before the FPA declared that the “business of transmitting and selling electric energy . . . is affected with a public interest.”49 Since 1916, federal taxpayers have supported domestic exploration, drilling, and production activities for our nation’s fossil fuel industry.50 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. 51 These policies 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 order—to submit “uncompetitive” bids into PJM’s markets for capacity, energy, and ancillary services. By lowering the marginal cost of fossil fuel-fired units, government policies have allowed these units to operate more frequently and have encouraged the development of more of these units than might otherwise have been built.

Federal subsidies remain pervasive in PJM. The federal tax credit for nonconventional natural gas,52 contributed to the spike in new natural gas-fired power plants between 2000 and 2005,53 by decreasing the cost of operating those plants. Similarly, 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.54 In addition, the domestic nuclear power industry would not exist without the Price-Anderson Act, which imposes indemnity limits for nuclear power generators, enabling them to secure financing and insurance at rates far below what would reflect their true cost.55 Federal subsidies have also promoted the growth of renewable resources through, for example, the production tax credit (largely used by wind resources)56 and the investment tax credit (largely used by solar resources).57 These and other federal government interventions have had a far greater “suppressive” impact on the markets than the “state subsidies” targeted by today’s order, especially when you consider that these resources make up the vast majority of the cleared capacity in PJM.58

The Commission, however, excludes all federal subsidies from the MOPR on the theory that it lacks the authority to “disregard or nullify the effect of federal legislation.”59 That justification is contradictory at best.60 It is, of course, true that the FPA does not give the Commission the authority to undo other federal legislation. But the Commission’s defense of the MOPR when applied to state policies, is that the MOPR neither disregards nor nullifies those policies, but instead addresses only the effects that those policies have on the PJM market.61

If, for the sake of argument, we accept the Commission’s characterization of the MOPR’s impact on state policies, then its justification for exempting federal subsidies from the MOPR immediately falls apart. Under that interpretation the MOPR does not actually disregard or nullify federal policy, but rather addresses only the effects of state policy on federal markets in order to address the concern that resources will “submit offers into the PJM capacity market that do not reflect their actual costs.”62 “But the Commission cannot have it both ways.”63 If the MOPR disregards or nullifies federal policy, it must have the same effect on state policy. And if it does not nullify or disregard state policy, then the Commission has no reasoned justification for exempting federal subsidies from the MOPR.

The Commission cites 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.64 But those general canons provide no response to my concerns. The problem is that the Commission gives the MOPR one characterization in order to stamp out state policies and a different one in order to exempt federal policies. And if we assume that its characterization about the effect of the MOPR on state policies is accurate, then no number of interpretive canons can cure the Commission’s arbitrary refusal to apply the MOPR to federal policies.

The Commission’s Disparate Offer Floors Discriminate Against New Resources

In addition, the differing offer floors applied to new and existing resources are arbitrary and capricious. Today’s order requires 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 suggests that this distinction is appropriate because new and existing resources do not face the same costs.65 In particular, the Commission asserts 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.”66

That distinction does not hold water. As the Independent 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.67 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.

However, as the Independent Market Monitor explains, Net CONE does not reflect how resources actually participate in the market.68 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 is not a reasoned explanation for the differing offer floors applied to new and existing resources.

The Commission Gives No Consideration to the Order’s Impact on Existing Business Models

In its rush to block the impacts of state policies, the Commission ignores the consequences its actions will have on well-established business models. In particular, today’s order threatens the viability, as currently constituted, of (1) aggregated demand response providers; (2) public power; and (3) resources financed in part through sales of voluntary renewable energy credits.

Demand Response

The Commission has long recognized that the end-use demand resources that are aggregated by a Curtailment Service Providers (CSP)—i.e., a demand response aggregator—may not be identified years in advance of the delivery year.69 The PJM market rules have permitted CSPs to participate in the Base Residual Auction without identifying all end-use demand resources.70 That allowance is fundamental to the aggregated demand response business model, since, without it, short-lead time resources might never be able to participate in the Base Residual Auction. Today’s order upends that allowance, extending the MOPR to any end-use demand resource that receives a State Subsidy. In practice, that means that a CSP will have to know all of its end-use demand resources prior to the Base Residual Auction (three years prior to the delivery year). Further complicating matters, today’s order grandfathers existing demand response without indicating whether the grandfathering right attaches to the CSP or the end-use demand resources.

The potential damage to the CSP business model is especially puzzling because PJM indicated that the default offer floor for at least certain demand response resources should be at or near zero,71 suggesting that even if they receive a subsidy, that subsidy would not reduce their offer below what this Commission deems a competitive offer. Demand response has provided tremendous benefits to PJM, both terms of improved market efficiency and increased reliability.72 I see no reason to risk giving up those gains based on an unsubstantiated concern about state policies

Public Power

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.73 Today’s order declares the entire public power model to be an impermissible state subsidy.74 That is a stark departure from past precedent, which recognized that “the purpose and function of the MOPR is not to unreasonably impede the efforts of resources choosing to procure or build capacity under longstanding business models.”75

It is also a fundamental threat to the long-term viability of the public power model. Although today’s order 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.

Voluntary Renewable Energy Credits

Today’s order will also upend the business model of resources that sell renewable energy credits to businesses or individuals that purchase them voluntarily —e.g., in order to meet corporate sustainability goals—rather to comply with a state mandate. Voluntary renewable energy credits have been an important driver behind the deployment of new renewable resources.76 Although the Commission recognizes that a voluntary renewable energy credit is not a state subsidy, it nevertheless subjects resources that will generate them to the MOPR.77 The Commission justifies that choice on the basis that a capacity resource cannot definitively know three years in advance how the credits it generates will ultimately be retired and by whom.78 But that means that today’s order is “mitigating the impact of consumer preferences on wholesale electricity markets”79 just because they may potentially overlap with state policies.

But it is not at all clear why such an all-or-nothing rule is necessary. For example, the Commission could carry over the attestation approach it uses for the Competitive Entry Exemption80 and allow a resource to submit an attestation stating that it will sell voluntary renewable energy credits to resources that are not subject to a state renewable portfolio standard with a contractual rider requiring immediate retirement to prevent any secondary transaction to an entity that may use it to meet its regulatory obligations. Moreover, PJM could presumably play an instrumental verification role since it administers the Generation Attribute Tracking System, the trading platform for renewable energy credits in PJM.81 All told, the Commission’s treatment of voluntary renewable energy credits creates an unnecessary threat to a valuable means of supporting clean energy.

The Commission’s Replacement Rate Does Not Result in a Competitive Market

By this point, the central irony in today’s order should be clear. The Commission began this phase of the proceeding by decrying government efforts to shape the generation mix because they interfere with “competitive” forces. 82 Today, the Commission is solving that “problem” by creating 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 my colleagues claim to value so highly.

As noted, the Commission’s definition of subsidy will encompass 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 almost any resource that benefits from a state effort to directly address the environmental externalities of electricity generation. 83 Moreover, the Commission’s inaptly named Unit-Specific Exemption84—its principal response to concerns about over mitigation—is simply another form of administrative pricing. 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 level, not at the level that they would otherwise participate in the market. 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.85 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 carbon tax, pass or join a cap-and-trade program, or create any other program that the Commission might deem an illicit financial benefit?

To implement this scheme, PJM and the Independent Market Monitor will need to become the new subsidy police, regularly reviewing the laws and regulations of 13 different states and D.C.—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.”86 Identifying the potential subsidies is just the start. Given the consequences of being subsidized, today’s order 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 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 has hardly the most obvious way to harness the forces of competition to benefit consumers, which, after all, is the whole reason these markets were set up in the first place.

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 a 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.87

Today’s Order Is a Transparent Attempt to Slow the Transition to a Clean Energy Future

Today’s order serves one overarching purpose: To slow the 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 order represents 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 order is unmistakable. It helps to rehash in one place what today’s order achieves.

First, after establishing a broad definition of subsidy, the Commission creates several categorical exemptions that overwhelmingly benefit existing resources. Indeed, energy efficiency, and capacity storage resources are all limited to existing resources. 88 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. In addition, new natural gas resources, remain subject to the MOPR and are not eligible to qualify for the Competitive Entry Exemption while existing natural gas resources are eligible.89

Second, as noted in the previous section, the Commission creates different offer floors for existing and new resources.90 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 Independent 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.”91

Third, the mitigation scheme imposed by today’s order will likely cause a large and systematic increase in the cost of capacity—at least 2.4 billion dollars per year.92 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 far less cost to consumers.

And finally, today’s order dismisses, without any real discussion, the June 2018 Order’s fig leaf to state authority: The resources-specific FRR Alternative.93 That potential path for accommodation was what allowed the Commission to profess that it was not attempting to block or (to use the language from today’s order) nullify state public policies.94 And, although implementing that option (or any of the alternative proposals for a bifurcated capacity market currently before us) 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 order, 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 directly targeted 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 is new in today’s order is the extent to which the Commission is willing to go. Whereas the June 2018 Order at least paid lip service to the importance of accommodating state policies,95 today’s order is devoid of any comparable sentiment.

The pattern in today’s order will surely repeat itself in the months to come. The Commission puts almost no flesh on the bones of its subsidy definition and provides precious little guidance how its mitigation scheme will work in practice. Accordingly, most of the hard work will come in the compliance proceedings, not to mention the litany of section 205 filings, section 206 complaints, and petitions for a declaratory order seeking to address 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 order, they will be the path by which the “quiet undoing” of state policies progresses.96

Today’s Order Makes No Effort to Consider the Staggering Cost that the Commission Is Imposing on Ratepayers

Today’s order will likely cost consumers 2.4 billion dollars per year initially, even under conservative assumptions.97 The Commission, however, does not even pretend to consider those costs when establishing the Replacement Rate. It is hard for me to imagine a more careless agency action than one that foists a multi-billion-dollar rate hike on customers without even considering, much less justifying, that financial burden.

And those costs will continue to grow with each passing year. Although today’s order aims to hamper state efforts to shape the generation mix, it 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.”98 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.”99 But that means that, as a resource adequacy construct, the PJM capacity market will increasingly operate in an alternate reality, ignoring more and more capacity just because it receives some form of state support. It also means that customers will increasingly be forced to pay twice for capacity or, in different terms, to buy ever 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.

And those are just the first-order consequences of today’s order. The record before us provides every reason to believe that this approach will lead to many other cost increases. For example, the Commission’s application of the MOPR will exacerbate the potential for the exercise of market power in what PJM’s Independent Market Monitor describes as a structurally uncompetitive market.100 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 changing the opportunity cost of withholding capacity.101 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 out-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.102

Given those potential rate increases, one might think that the Commission would be at pains to evaluate the costs caused by today’s order and to explain why and how the purported benefits of the Replacement Rate justify those costs. Instead, the Commission does not discuss the potential cost increases, much less justify them, even as it assures us that the Replacement Rate is just and reasonable. For an agency whose primary purpose is to protect consumers to so completely ignore the costs of its decision is both deeply disappointing and a total abdication of the responsibilities Congress gave us when it created this Commission.103

PJM and Its Stakeholders Deserve Better

We have been down this road before. In the June 2018 Order, the Commission up ended the PJM capacity market, finding it unjust and unreasonable and providing PJM only vague guidance on how to remedy its concerns and nowhere near enough time to year-and-a-half of indecision and undermined, perhaps fatally, a construct that is supposed to provide predictably and clear signals. Today’s order is much of the same. The Commission is embarking on a quixotic effort to mitigate the effects of any attempt to exercise the authority that Congress reserved to the states when it enacted the FPA. In so doing, the Commission has dropped even the pretense of accommodating states’ exercise of that reserved authority.

104 Instead, the Commission appears dead set on refashioning the PJM capacity market from a construct based primarily on bids determined by the resources themselves to a construct that will inevitably rely on a pervasive program of administrative pricing. It is hard to overestimate the scope or the impact of the changes required by today’s order. Given all that, you would think that the Commission would have learned its lesson from the June 2018 Order and provided PJM and its stakeholders detailed directives and plenty of time to work out the nuances associated with putting those directives into practices.

Instead, the Commission provides only a general definition of what constitutes a subsidy and gives PJM only 90 days to develop and file sweeping changes to the market. That is a patently unreasonable period of time in which to accomplish all that the Commission has put on PJM’s plate. For example, to implement the definition of State Subsidy in today’s order, PJM will have to develop a process to routinely review the regulatory structure of all thirteen PJM states and D.C. to identify every potential benefit available under any state or local law.106 Moreover, the Commission is requiring PJM to produce new zonal default Net CONE and net ACR values for all resource types, many of which have dissimilar cost structures and have never been the subject of this sort of analysis in the past. To properly set a default offer floors and establish a fair and transparent process for conducting unit-specific reviews, PJM needs time to work with its Independent Market Monitor and its stakeholders. Not allowing PJM and its stakeholders to have that time will surely lead to unintended consequences, including, potentially, another round of the delays that have plagued this proceeding ever since the Commission issued the June 2018 Order.

Frankly put, the Commission has bungled this process from the start and today’s order provides little reason for optimism. I have sympathy for anyone (or any state) that is losing confidence in the Commission’s ability to responsibly manage resource adequacy, especially in the age of climate change as more and more states contemplate develop a thoughtful solution. That profound act of “regulatory hubris”

105 led to the last year-and-a-half of indecision and undermined, perhaps fatally, a construct that is supposed to provide predictably and clear signals. Today’s order is much of the same. The Commission is embarking on a quixotic effort to mitigate the effects of any attempt to exercise the authority that Congress reserved to the states when it enacted the FPA. In so doing, the Commission has dropped even the pretense of accommodating states’ exercise of that reserved authority.

106 Instead, the Commission appears dead set on refashioning the PJM capacity market from a construct based primarily on bids determined by the resources themselves to a construct that will inevitably rely on a pervasive program of administrative pricing. It is hard to overestimate the scope or the impact of the changes required by today’s order. Given all that, you would think that the Commission would have learned its lesson from the June 2018 Order and provided PJM and its stakeholders detailed directives and plenty of time to work out the nuances associated with putting those directives into practices.

Instead, the Commission provides only a general definition of what constitutes a subsidy and gives PJM only 90 days to develop and file sweeping changes to the market. That is a patently unreasonable period of time in which to accomplish all that the Commission has put on PJM’s plate. For example, to implement the definition of State Subsidy in today’s order, PJM will have to develop a process to routinely review the regulatory structure of all thirteen PJM states and D.C. to identify every potential benefit available under any state or local law.106 Moreover, the Commission is requiring PJM to produce new zonal default Net CONE and net ACR values for all resource types, many of which have dissimilar cost structures and have never been the subject of this sort of analysis in the past. To properly set a default offer floors and establish a fair and transparent process for conducting unit-specific reviews, PJM needs time to work with its Independent Market Monitor and its stakeholders. Not allowing PJM and its stakeholders to have that time will surely lead to unintended consequences, including, potentially, another round of the delays that have plagued this proceeding ever since the Commission issued the June 2018 Order.

Frankly put, the Commission has bungled this process from the start and today’s order provides little reason for optimism. I have sympathy for anyone (or any state) that is losing confidence in the Commission’s ability to responsibly manage resource adequacy, especially in the age of climate change as more and more states contemplate the type of clean energy programs to which the current Commission is so obviously opposed. I fear that the most likely outcome of today’s order is that more PJM states will contemplate ways to reduce their exposure to the Commission’s hubris, including abandoning the PJM capacity market and potentially exiting PJM altogether. Should that come to pass, the Commission will have no one to blame but itself.

One final point. I fully recognize that the PJM states are doing far more to shape the generation mix than they were when the original settlement established the PJM Reliability Pricing Model in 2006. 107It may well be that a mandatory capacity market is no longer a sensible approach to resource adequacy at a time when states are increasingly exercising their authority under the FPA to shape the generation mix. Indeed, the conclusion that I draw from the record in front of us is not that there is an urgent need to mitigate the effects of state public policies, but rather that we should be taking a hard look at whether a mandatory capacity market remains a just and reasonable resource adequacy construct in today’s rapidly evolving electricity sector. It is a shame that we have not spent the last two years addressing that question instead of how best to stymie state public policies.

For these reasons, I respectfully dissent.






                                               

    1 FRR stands for Fixed Resource Requirement.
    2 Calpine Corp. v. PJM Interconnection, L.L.C., 163 FERC ¶ 61,236 (2018) (June 2018 Order).
    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 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).
    5 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.
    6 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”).
    7 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).
    8 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”).
    9 Zibelman, 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.”).
    10 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”).
    11 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.”).
    12 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))).
    13 Oneok, 135 S. Ct. at 1600 (discussing Northern Natural, 372 U.S. at 94, and Northwest Central, 489 U.S. at 513-14).
    14 EPSA, 136 S. Ct. at 775-77; id. at 776.
    15 Hughes, 136 S. Ct. at 1298, 1299.
    16 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).
    17 June 2018 Order, 163 FERC ¶ 61,236 at P 149.
    18 Id. PP 151-152. Similarly, in explaining its decision to extend the MOPR to existing resources, the Commission relied, not on evidence about how state action might affect clearing prices, but entirely on the fact that state actions were proliferating and that, as a result, resources that it believes ought to consider retiring might not do so. Id. P 153.
    19 Id. P 150.
    20 Id. P 156.
    21 See supra note 9 and accompanying text.
    22 Calpine Corp. v. PJM Interconnection, L.L.C., 169 FERC ¶ 61,239, at P 37 (2019) (Order).
    23 Id. P 37.
    24 Order, 169 FERC ¶ 61,239 at PP 56, 65-75. Imposing a requirement that there be an actual price impact would have brought today’s order far closer to the facts in EPSA. See 136 S. Ct. at 771-72 (explaining that the demand response rule was structured to compensate only those resources whose participation would “result in actual savings to wholesale purchasers”); id. at 776 (noting the entities “footing the bill [for demand response participation] are the same wholesale purchasers that have benefited from the lower wholesale price demand response participation has produced (italics omitted)). Such a requirement would not be especially unusual. Markets throughout the country apply conduct and impact thresholds for mitigation, including in energy, ancillary services, and capacity markets.
    25 Order, 169 FERC ¶ 61,239 at P 40.
    26 The Commission justifies its refusal to extend the MOPR to federal subsidies because to do so would “disregard or nullify the effect of federal legislation.” Order, 169 FERC ¶ 61,239 at P 87. But that can only mean that the Commission is fully aware that this is what it is doing to state policies, notwithstanding its repeated assurances that it respects state jurisdiction over generation facilities. See, e.g., id. n.345.
    27 EPSA, 136 S. Ct. at 776 (citing Oneok, 135 S. Ct. at 1599).
    29 Specifically, those early MOPRs were designed to ensure that net buyers of capacity were not able to deploy market power to drive down the capacity market price. 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 buyer-side mitigation at the Commission).
    30 Cf., e.g., 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.”).
    31 See New Jersey Board of Public Utilities v. FERC, 744 F.3d 74, 106-07 (3d Cir. 2014) (NJBPU).
    32 ISO New England Inc., 162 FERC ¶ 61,205, at P 21 (2018).
    33 June 2018 Order, 163 FERC ¶ 61,236 at PP 150, 156, 161.
    34 Order, 169 FERC ¶ 61,239 at P 17.
    35 Id. at P 136. Saying 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 real goal.
    36 The majority points to the U.S. Court of Appeals for the Third Circuit’s decision in NJBPU, 744 F.3d 74, to argue that at least one court has already blessed extending the MOPR to state-sponsored resources. See Order, 169 FERC ¶ 61,239 at P 7. But NJBPU differs in important respects. First, at that time, the MOPR was still limited to natural gas-fired generators—the resources that could feasibly and rationally be built for the purpose of depressing capacity market prices, see 744 F.3d at 106. In addition, as the court explained, the Commission’s “enumerated reasons for approving the elimination of the state-mandated exception relate directly to the wholesale price for capacity.” Id. at 98. As noted, however, the Commission’s recent application of the MOPR, including in this proceeding, focuses much more broadly on the supposed problems with state subsidies.
    37 Cf. EPSA, 136 S. Ct. at 774 (explaining that the FPA cannot be interpreted in a manner that allows it to “assum[e] near infinite breadth”).
    38 Supra Section II.C.
    39 Order, 169 FERC ¶ 61,239 at P 65.
    40 Monitoring Analytics, 2019 State of the Market Report for PJM: January through September at Tbl. 5-5, available at https://www.monitoringanalytics.com/ reports/PJM_State_of_the_Market/2019/2019q3-som-pjm-sec5.pdf.
    41 Order, 169 FERC ¶ 61,239 at P 65.
    42 June 2018 Order, 163 FERC ¶ 61,236 (Glick, Comm’r, dissenting at 8).
    43 Clean Energy Advocates Protect, Docket No. ER18-1314-000 (2018) App. E (Doug Koplow, Energy Subsidies within PJM: A Review of Key Issues in Light of Capacity Repricing and MOPR-Ex Proposals).
    46 Order, 169 FERC ¶ 61,239 at P 65.
    47 Both of which are RGGI members. The Regional Greenhouse Gas Initiative, https://www.rggi.org/rggi-inc/contact (last visited Dec. 19, 2019) (listing RGGI member states).
    48 This is the total peak load from the tranches in the 2019 BGS auction. The 2019 BGS Auctions, http://www.bgs-auction.com/documents/ 2019_BGS_Auction_Results.pdf (last visited Dec. 19, 2019).
    49 16 U.S.C. § 824 (2018).
    50 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).
    51 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, among other things, 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 June 29, 2018)) (extending the DBL analysis through 2016).
    52 Energy Tax Policy at 2 n.3. That credit has lapsed. Id. at 18.
    53 Natural gas generators make up the largest share of overall U.S. generation capacity, Energy Info. Admin. (Dec. 18, 2017), https://www.eia.gov/todayinenergy/ detail.php?id=34172.
    54 The 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 (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).
    55 42 U.S.C. § 2210(c).
    56 U.S. Department of Energy, 2018 Wind Technologies Market Report. Page 70. (accessed Dec 18. 2019) http://eta-publications.lbl.gov/sites/default/files/ wtmr_final_for_posting_8-9-19.pdf.
    57 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.
    58 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 (reporting that coal, natural gas, and nuclear collectively make up more than three-quarters of the generation mix in PJM).
    59 Order, 169 FERC ¶ 61,239 at P 87.
    60 Cf. EPSA Initial Testimony at 16-19; IPP Coalition Initial Testimony at 11.
    61 Order, 169 FERC ¶ 61,239 at PP 7, 40.
    62 June 2018 Order, 163 FERC ¶ 61,236 at P 153.
    63 Atlanta Gas Light Co. v. FERC, 756 F.2d 191, 198 (D.C. Cir.
    64 Order, 169 FERC ¶ 61,239 n.177.
    65 Id. P 138.
    67 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.”).
    69 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 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).
    70 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.
    71 PJM explains that, beyond the initial costs associated with developing a customer contract and installing any required hardware or software, that 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.
    72 In a 2019 report, Commission staff explained that demand response resources comprised 6.7 percent of peak demand in PJM and that PJM called on load management resources in October of 2019 to reduce consumption during a period of grid stress. See Federal Energy Regulatory Commission, 2019 Assessment of Demand Response and Advanced Metering 17, 20 (2019), available at https://www.ferc.gov/legal/staff-reports/2019/DR-AM-Report2019.pdf. PJM has previously explained that the more that demand actively participates in the electricity markets, the more competitive and robust the market results. Also, if visible and dependable, demand response has proven to be a valuable tool for maintaining reliability both in terms of real-time grid stability and long-term resource adequacy. PJM Interconnection, Demand Response Strategy 1 (2017), available at https://www.pjm.com/~/media/library/reports-notices/demand-response/20170628-pjm-demand-response-strategy.ashx.
    73 American Municipal Power and Public Power Association of New Jersey Initial Brief at 14-15; American Public Power Association Initial Brief at 15.
    74 Order, 169 FERC ¶ 61,239 at P 65.
    75 PJM Interconnection, L.L.C., 117 FERC ¶ 61,331 (2006).
    76 See Advanced Energy Buyers Group Reply Brief at 2.
    77 Order, 169 FERC ¶ 61,239 at P 174.
    79 Clean Energy Industries Initial Testimony at 6.
    80 Order, 169 FERC ¶ 61,239 at P 159.
    81 See Id. n. 314.
    82 June 2018 Order, 163 FERC ¶ 61,236 at P 1.
    83 See Supra Section II.A.
    84 In today’s order, the Commission renames 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.
    85 Order, 169 FERC ¶ 61,239 at P 160.
    86 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.
    87 Moreover, as discussed further below, see infra notes 100-102 and accompanying text, PJM’s capacity market is structurally uncompetitive and lacks any meaningful market mitigation. There is every reason to believe that today’s order will exacerbate the potential for the exercise of market power.
    88 Order, 169 FERC ¶ 61,239 at PP 171, 200, 206.
    89 Id. PP 2, 41.
    90 See supra Section II.B.2.
    91 Internal Market Monitor Reply Brief at 4.
    92 Our estimate of the cost impact of today’s order is a “back-of-the-envelope” calculation. I assume that all previously-cleared nuclear power plants that receive zero-emissions credits in Illinois and New Jersey (totaling 6,670 MW) are unlikely to clear the next auction. I also assume there would be a 25 percent reduction of the demand response resources that previously cleared the Base Residual Auction. See supra Section III.B.3.a. Together, these resources total 9,340 MW of capacity. I relied on PJM’s finding that “[a]dding less than 2% of zero-priced supply to the area outside MAAC, for example, reduces clearing prices in the RTO by 10%” which provides some insight to the slope of the demand curve and the associated price sensitivity. See PJM Transmittal Letter, Docket No. ER18-1314-000, at 28 (2018). Applying this slope to the last capacity auction clearing price of $140/MW-day and removing 9,300 MW, assuming all else remains constant, the capacity clearing price could increase $40/MW-day resulting in a cost of $2.4 billion. 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).
    93 June 2018 Order, 163 FERC ¶ 61,236 at P 157.
    94 See supra Section II.A.
    95 June 2018 Order, 163 FERC ¶ 61,236 at P 161.
    96 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/.
    97 See supra note 92.
    98 N.Y. State Pub. Serv. Comm’n, 158 FERC ¶ 61,137 (2017) (Bay, Chairman, concurring).
    100 “The capacity market is unlikely to ever 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.” Monitoring Analytics, Analysis of the 2021/2022 RPM Base Residual Auction: Revised (2018).
    101 Institute for Policy Integrity Initial Brief at 14-16.
    102 For 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).
    103 See, e.g., California ex rel. Lockyer v. FERC, 383 F.3d 1006, 1017 (9th Cir. 2004); 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)).
    104 June 2018 Order, 163 FERC ¶ 61,236 (LaFleur, Comm’r, dissenting at 5).
    105 Id. P 161.
    106 Recall that the Commission rejects PJM’s proposal to include a de minimus exception in the subsidy definition. Order, 169 FERC ¶ 61,239 at P 96.
    107 PJM Interconnection, L.L.C., 117 FERC ¶ 61,331 (2006).
Print this page