Commissioner Richard Glick
July 16, 2020
Docket Nos. ER16-1404-001, ER16-1404-002
I dissent from today’s order because it perverts buyer-side market power mitigation into a series of unnecessary and unreasoned obstacles to New York’s efforts to shape the resource mix. Buyer-side market power mitigation should be all about and only about buyers with market power. Applying buyer-side market power mitigation to entities that are not buyers or buyers that lack market power is nonsensical. Moreover, even when applied to buyers who may have market power, mitigation must reasonably address their potential to exercise that market power.
In this order, the Commission continues to apply buyer-side market power mitigation where it does not belong. In addition, the Commission also adopts a series of unreasoned and over-the-top restrictions on public power entities under the guise of mitigating market power. The sum total effect of these changes is to frustrate New York’s efforts to achieve its environmental goals while at the same time increasing costs to consumers. That is not just and reasonable.
Buyer-Side Market Power Mitigation Should be Limited to Buyers with Market Power
When first introduced, buyer-side market power mitigation rules were (as their name would suggest) aimed squarely at mitigating the exercise of buyer-side market power—i.e., the ability of a large buyer of capacity to exercise its monopsony power to lower the capacity market clearing price. To the extent that the Commission required buyer-side mitigation of capacity market offers, it limited the mitigation to only resources that could be used effectively for the purpose of depressing capacity market prices or to resources with both the incentive and ability to depress capacity market clearing prices. In short, buyer-side market power mitigation was all about and only about the exercise of buyer-side market power.
The Commission has abandoned that narrow focus. It no longer requires a resource to be a buyer, much less a buyer with market power, before subjecting that resource to buyer-side market power mitigation. Buyer-side market power rules—often referred to as minimum offer price rules or MOPRs—that were once intended only as a means of preventing the exercise of market power have evolved into a scheme for propping up prices, freezing in place the current resource mix, and blocking states’ exercise of their authority over resource decisionmaking. The result is an ever-expanding system of administrative pricing that is, ironically enough, justified on the basis that it promotes competition. But, in reality, the Commission is not promoting anything remotely resembling actual competition.
The basic premise of market competition is that sellers should compete to offer the best terms, including price, to provide a particular product or service. And the purpose of capacity markets is to provide the “missing money” that resources need to remain viable, but are unable to earn by providing energy and ancillary services due to various limitations in the markets for those services. That means that capacity market competition should follow a single ‘first principle’: Enabling resources to vie with each other to require as little missing money as possible in order to cover their going forward costs, receive a capacity commitment, and help to ensure resource adequacy. For the market to be truly competitive, resources must have the flexibility to reflect their own expertise, experience, technology, risk tolerance and whatever else might provide them with a competitive advantage in the quest to provide capacity at the lowest possible cost. True competition can produce enormous benefits for consumers by shifting risk to investors, facilitating the entry of relatively efficient resources (and the retirement of inefficient ones), and spurring the development and deployment of new technologies and business models—all while procuring the lowest-cost set of resources needed to keep the lights on.
Instead of promoting true competition, the Commission’s approach to buyer-side market power has degenerated into a scheme for propping up prices, protecting incumbent generators, and impeding state clean energy policies. Although the specifics of the mitigation regimes vary among the eastern RTOs, they all generally force new entrants to bid at or above an administratively determined estimate of what a new resource “should” cost, while existing resources are permitted to bid at a lower level. In practice, those administrative pricing regimes create a systemic bias in favor of existing resources and curtail resources’ incentive and ability to compete across all possible dimensions. Moreover, because potential new entrants to the capacity markets tend to be disproportionately made up of new technologies and resources needed to satisfy state or federal public policies, the Commission’s use of MOPRs also has the unmistakable effect (and, recently, the intent) of slowing the transition to a cleaner, more advanced resource mix.
That type of quasi-competition does not lead to an efficient market outcome. To achieve an efficient outcome, resources’ capacity market offers must reflect all relevant costs minus all relevant revenues, including costs and revenues that are not derived directly from Commission-jurisdictional markets. If the market ignores some of those costs and revenues, then the set of resources selected will not actually reflect the lowest-cost or most efficient means of ensuring resource adequacy. And yet that is where we find ourselves: All three eastern RTOs now force new resources to compete based on administratively determined estimates of their costs and revenues rather than their own estimates of what they need to make up the missing money. The result is neither a competitive market nor an efficient outcome.
We got to this point largely because of the Commission’s misguided belief that it must “protect” capacity markets from the influence of state public policies. However, as explained below, the Commission’s efforts to prop up prices by mitigating the effects of state public policies upset the jurisdictional balance that is the heart of the FPA and interfere with capacity markets’ ability to produce efficient market outcomes.
The FPA is clear. The states, not the Commission, are 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, Congress expressly precluded the Commission from regulating “facilities used for the generation of electric energy.” Congress instead gave the states exclusive jurisdiction to regulate generation facilitates.
But while those jurisdictional lines are clearly drawn, the spheres of jurisdiction themselves are not “hermetically sealed.” One sovereign’s exercise of its authority will inevitably affect matters subject to the other sovereign’s exclusive jurisdiction. 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. 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” and the natural result of a system in which regulatory authority over a single industry is divided between federal and state government. Maintaining that interplay and permitting each sovereign to carry out its designated role is essential to the cooperative federalism regime that Congress made the foundation of the FPA.
When the Commission tries to prevent a state public policy from having an inevitable, but indirect effect on a capacity market, it takes on the role that Congress reserved for the states. That is true even where the Commission claims that its only “policy” is to block the effects of state public policies, not the state policies themselves. After all, a federal policy of eliminating the effects of state policies is itself a form of public policy—just not one that Congress gave the Commission authority to pursue.
Moreover, as former Commission Chairman Norman Bay correctly observed, an “idealized vision of markets free from the influence of public policies . . . does not exist, and it is impossible to mitigate our way to its creation.” Instead, public policy and energy markets are inextricably intertwined. Nearly every aspect of the electricity market is affected by at least one—and more often many—federal, state, or local policies. Even if the Commission is successful in ferreting out state efforts to shape the generation mix, the result will not be a “competitive” market. Instead, the market will remain a reflection of public policy, but will ignore the effects of the very policy decisions that Congress expressly gave the states the authority to make. And while that might further the Commission’s goal of increasing prices and slowing the transition to a cleaner energy mix, it will not establish a market based on anything close to actual competition, much less one that is insulated from public policy.
And the end result will be profoundly inefficient, no matter how many times my colleagues use the words “market” and “competition.” The resources procured through that market will require considerably more missing money than would the set of resources procured in the absence of this kind of over-mitigation. Moreover, the mitigation regimes that the Commission has approved will, by design, ignore resources that must be built because they are necessary to satisfy state public policies. As a result, the capacity markets will procure more capacity than the regions actually need and customers will be left paying twice for capacity. That means customers will be paying for more of the more expensive capacity than they should.
In addition, widespread mitigation undermines a capacity market’s ability to establish price signals that efficiently guide resource entry and exit. States will continue to exercise their authority over the resource mix no matter how hard the Commission tries to frustrate those efforts, especially given the ever-growing threat posed by climate change. A capacity construct that ignores those states’ public policies will produce price signals that do not reflect the factors that are actually influencing the development of new resources. Those misleading price signals will encourage the participation of the wrong types of resources or resources that are not needed at all. It is hard for me to see how a price signal that encourages redundant investment is a “competitive” or desirable outcome, much less a just and reasonable one.
The Commission has suggested that if it succeeds in blocking state policies, then capacity markets will become efficient, little islands unto themselves. But a capacity market is a means to an end, not an end in itself. It is a construct that is supposed to minimize the amount of money that customers spend on capacity in order to meet a target reserve margin. A capacity market that does not serve that purpose and is “efficient” only if you disregard the fact that, in the real-world, it produces inefficient results is a market that we ought to reject out-of-hand.
Instead of interfering with state public policies, the Commission’s buyer-side market power mitigation regime should be all about—and only about—buyers with market power. In the event that a resource is not a buyer with market power, its capacity market offer should not be subject to buyer-side mitigation. That result is both more consistent with the FPA’s federalist foundation and the Commission’s core responsibility as a regulator of monopoly/monopsony power. That approach would also be a great deal simpler and would get the Commission out of these interminable disputes about who gets mitigated, when, and to what level. In short, I believe that buyer-side market power mitigation rules that are not limited only to market participants with actual buyer-side market power are per se unjust and unreasonable and should be abandoned immediately.
“Actual” is an important distinction here. The Commission has at times suggested extending buyer-side market power mitigation to resources that receive state subsidies on the basis that the state is like a quasi-buyer that looks out for the interests of all consumers in the state. We should abandon that notion as well. States regulate for a variety of reasons and acting as if any regulation is an exercise of market power fundamentally misunderstands the role Congress reserved for the states under the FPA. Philosophical market power—as distinguished from actual market power—should have no place in the Commission’s regulatory regime. In any case, to the extent that a state is directly targeting the wholesale market price, then the law in question is preempted and there is no need to muddle things up with a MOPR.
Some argue that Commission intervention is necessary to “protect” the market from states’ exercise of their authority under the FPA. But if we ever reach a point where the only way to “save” a capacity market is to unmoor it from reality by blocking the effects of state policies, then it will be past time to find an alternative approach to ensuring resource adequacy—one whose feasibility does not depend on inefficient real-world outcomes or the Commission usurping the role that Congress reserved for the states.
Indeed, the Commission’s efforts to “save” capacity markets are more likely to hasten their eventual demise. The more the Commission interferes with state public policies under the pretext of mitigating buyer-side market power, the more it will force states to choose between their public policy priorities and the benefits of the wholesale markets that the Commission has spent the last two decades fostering. Although that should be a false choice, the Commission is increasingly making it into a real one. New York provides the perfect example as the Public Service Commission has begun a proceeding to consider “taking back” from NYISO the responsibility for ensuring resource adequacy. And numerous states are considering leaving the other eastern RTOs, both of which have capacity rules that hinder states’ exercise of their resource decisionmaking authority. The Commission’s overreach, affirmed in today’s order, will no doubt create greater momentum in that direction.
As I explained in my dissent from the underlying order, I continue to believe that the foregoing analysis ought to compel the Commission to get back to the basics on buyer-side market power mitigation. Where entities are not buyers they simply should not be subject to buyer-side market power mitigation. End of discussion. And where entities are buyers, the Commission should impose buyer-side market power mitigation measures only when those buyers possess actual market power and, even then, the mitigation must be reasonably tailored to the potential for the exercise of market power.
Today’s order is completely at odds with those principles, as it continues to apply buyer-side market power measures to resources that are not buyers. In addition, the Commission makes a hash out of the mitigation regimes applied through this order. As discussed in the following sections, the draconian measures imposed on the New York Power Authority (NYPA) are illogical and unreasoned, while the further limitations accepted regarding the already-miserly renewables exemption only add insult to injury.
The Commission’s Treatment of NYPA Is Arbitrary and Capricious
Self-supply entities are, by definition, buyers. As a result, they can have market power and, where they do, mitigation may be appropriate. But whatever mitigation is applied in those instances must be just and reasonable and take account of the circumstances of the mitigated resources. Consistent with that principle, the Commission previously concluded in this proceeding that “applying NYISO’s buyer-side market power mitigation rules to certain self-supply resources would be unjust, unreasonable, or unduly discriminatory or preferential pursuant to section 206 of the FPA, because such resources, narrowly defined, have limited or no incentive and ability to exercise buyer-side market power to artificially suppress ICAP market prices.” Accordingly, the Commission directed NYISO to implement a self-supply exemption utilizing appropriate net-short and net-long thresholds. In the resulting compliance order, however, the Commission effectively excluded public power self-supply entities from that exemption on the theory that because their mission is to benefit residents of the state as a whole, there is no way to protect the market from their actions.
That decision was arbitrary and capricious. As an initial matter, it assumes, based on a website alone, that NYPA would disadvantage its own customers for the benefit of other residents of the state that it does not serve. As the NY Entities point out, NYPA’s mission statement does not demonstrate an “intent to achieve the agency’s public policy purposes and goals through any and all means, regardless of rules, norms of ethical behavior, and integrity.” A single hortatory statement of purpose is hardly substantial evidence suggesting that NYPA will act against its customers for the benefit of other load-serving entities’ customers.
Once you let go of that borderline offensive idea, the Commission has no support for its conclusion that the self-supply exemption thresholds are insufficient to adequately protect against the exercise of market power by NYPA, especially when those thresholds are combined with the requirement that only entities that operate “under a long-standing business model to meet more than fifty percent of its Load obligations through its own generation” qualify for the self-supply exemption. Instead of explaining its concern with the mitigation thresholds, the Commission simply insists that they are insufficient to protect against the exercise of market power. It should go without saying that repeating the decision without any reasoning is not reasoned decisionmaking.
In any case, the record suggests that the proposed thresholds for the self-supply exemption would adequately protect against a state instrumentality, such as NYPA, exercising market power—indeed that was the very purpose for which they were designed. As noted, the requirement that only entities that operate “under a long-standing business model to meet more than fifty percent of its Load obligations through its own generation” qualify for the self-supply exemption prevents states from creating a new load-serving entity that would uneconomically self-supply its entire capacity obligation. In addition, the net-long threshold prevents self-supply entities from purchasing capacity in excess of the amounts required to serve their customers, preventing the self-supply entity from significantly affecting capacity market prices. Consider how those thresholds work in practice: As the NY Entities explain, the net-long threshold for a load-serving entity with 1,000 MW of load in New York City creates a self-supply exemption for only an additional 15.6 MW of capacity—hardly a major loophole. In the face of such evidence, the Commission’s failure to do more than simply insist that those thresholds are insufficient is arbitrary and capricious.
The Commission’s Treatment of the Renewables Exemption Is Arbitrary and Capricious
Today’s order also addresses the mechanics of NYISO’s renewable resource exemption from its buyer-side market power mitigation provisions. Although, as noted, I would altogether get out of the business of mitigating resources that are not buyers, much less buyers with market power, a few of the additional flaws in the Commission’s reasoning deserve further discussion. In particular, I disagree with the Commission’s rejection of NYISO’s original proposal to establish a 1,000 MW cap on the volume of intermittent renewable resources in each class year. The crux of the Commission’s reasoning is that the proposed cap was not based “on the mitigated capacity zones” but rather on “historical entry of all resource types across the entire New York Control Area.” The Commission’s cursory rejection ignored the details of the proposal and supporting material, which explained how the cap was developed with an eye toward both NYISO-wide and the mitigated capacity zones.
The approved Renewables Exemption Limit is determined in large part by what is called “Incremental Regulatory Retirements.” This allows the renewables exemption to offset only retirements that are substantially caused by “new or amended” laws and regulations or statutes, or other regulatory or related actions that target generator emissions, operating permits, fuel supply, property taxes or retirement compensation and other incentives outside of the ISO markets. This is a far more fundamentally flawed approach than the one the Commission previously rejected. Those flaws include an unreasonably narrow definition of incremental retirements, a failure to recognize permanent reductions in UCAP that are not directly linked to retirements, and an unreasonable limitation on connecting retirements to actual legislation or regulatory action. Let’s take those flaws in turn.
As I understand it, the theory of the cap is to limit renewable resources’ impact on capacity market clearing prices by ensuring that the MW capacity of new renewables does not exceed the MW capacity of resources retiring due to state regulation. I fail to see why, if the Commission were truly concerned with preventing renewables from suppressing prices, as it claims, it would makes sense to limit the MW quantity of new renewables to the MW quantity of all incremental retiring resources rather than attempting to limit it to those retirements due to state actions. After all, as Clean Energy Advocates explain, “[i]f the [MW] value for renewable exemptions is tied to the total quantity of retiring resources, the net effect of retirements and exempt renewable generators that enter the market is that suppliers in the market experience no change in market prices over time.” In short, there is no price-based justification for limiting the exemption cap on new renewables to only those retirements caused by state action. Instead, this unnecessary exercise in parsing out a resource’s motivation for retiring only muddies the analysis and takes the Commission further afield from the buyer-side market power concerns that it purports to be addressing through these proceedings.
Even if you accept the flawed premise that new renewable supply should not exceed exiting supply caused by state action, this will not permit even that level of entry. Today’s order approves a cap that accounts only for retirements rather than quantifiable reductions in UCAP supply, even when those reductions can be tied to “direct” regulatory actions. Whether supply declines due to a retirement, a seasonal retirement, or a permanent de-rate should be irrelevant for a Commission truly concerned about the changes that supply can have to the clearing price of the market. A MW reduction is a MW reduction, regardless of what the resource owner does with the rest of its facility. In ignoring every action short of a full retirement, the Commission overlooks what may be very real and permanent reductions in capacity, such as those caused by resources that, for example, respond to annual emissions limitations by operating only seasonally or derating their capacity in order to comply with emissions limitations. Nothing in today’s order justifies that arbitrary distinction.
Finally, the Commission adopts NYISO’s proposal that the retirement must be the result of “new or amended” regulations, statutes, or related actions. Quite honestly, I have no idea what that means. And the Commission’s only response—that a temporal limitation is necessary to avoid some unspecified burden on NYISO—does not shed any further light on the matter. Such obvious ambiguity is a recipe for endless litigation. In any case, retirements can often lag significantly behind the motivating regulatory action. Consider the case of the Indian Point Energy Center which is retiring its two units in 2020 and 2021, pursuant to an agreement reached in 2017. No one with any understanding of the circumstances surrounding Indian Point’s retirement would argue that it is a “burden” to understand why the Indian Point units are retiring. I see no reason—and the Commission presents none—for why, in a situation like that, the time between the agreement to retire and the actual date of retirement should be relevant to whether the capacity counts towards the renewables exemption.
* * *
We should not lose the forest for the trees. New York City and the down-state area are about to experience an unprecedented number of retirements, including Indian Point, which itself represents more than 2,000 MW of capacity. In addition, to meet NOx limits under the Clean Air Act, the New York State Department of Environmental Conservation adopted a rule that may lead to the retirement of over 3,000 MW of peaking units, almost all of which are in New York City and Long Island. Meanwhile, New York State has passed ambitious legislation to address climate change, among other environmental concerns, by shifting its generation mix to cleaner resources. Today’s order undermines New York’s ability to achieve those environmental goals by obstructing the entry of new resources at a time when significant new capacity may be needed to address the unprecedented retirements in the downstate region. That is not just and reasonable.
 See, e.g., PJM Interconnection, L.L.C., 117 FERC ¶ 61,331, at PP 34, 103-04 (2006) (discussing the buyer-side market power mitigation provisions imposed as part of the settlement that created the Reliability Pricing Model); see also Richard B. Miller, Neil H. Butterklee & Margaret Comes, “Buyer-Side” Mitigation in Organized Capacity Markets: Time for a Change?, 33 Energy L.J. 449, 460-61 (2012) (Time for a Change?) (discussing the Commission’s early approach to buyer-side market power mitigation).
 See, e.g., PJM Interconnection, L.L.C., 117 FERC ¶ 61,331 at P 104 (“The Commission finds the Minimum Offer Price Rule a reasonable method of assuring that net buyers do not exercise monopsony power by seeking to lower prices through self supply.”); N.Y. Indep. Sys. Operator, Inc., 122 FERC ¶ 61,211, at P 106 (2008) (explaining that buyer-side market power “mitigation is aimed at preventing uneconomic entry by net buyers of capacity, the only market participants with an incentive to sell their capacity for less than its cost.”).
 See Calpine Corp. v. PJM Interconnection L.L.C., 169 FERC ¶ 61,239, r’hg denied, 171 FERC ¶ 61,035 (2020) (Calpine v. PJM) (Glick, Comm’r, dissenting at P 4); see also Miller, Butterklee & Comes, Time for a Change?, 33 Energy L.J. at 461 (“[B]uyer mitigation has effectively become new entrant mitigation under which all new entrants are subject to mitigation unless otherwise exempted because they have somehow demonstrated that their new facility is not ‘uneconomic.’”).
 See, e.g., Calpine v. PJM, 169 FERC ¶ 61,239 at P 38 (discussing the Commission’s finding on the need to maintain the “integrity of competition”); id. P 17 n.38 (“This Commission determined many years ago that the best way to ensure the most cost-effective mix of resources is selected to serve the system’s capacity needs was to rely on competition.”); ISO New England Inc., 162 FERC ¶ 61,205, at P 24 (2018) (asserting that states’ exercise of their authority over generation facilities “raises a potential conflict with . . . competitive wholesale electric markets”).
 See Calpine Corp. v. PJM Interconnection, 171 FERC ¶ 61,035 (2020) (Calpine v. PJM Rehearing) (Glick, Comm’r, dissenting at P 3) (explaining that the Commission’s [PJM MOPR orders] “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”). It is also worth noting that this Commission’s infatuation with mitigation only goes one way. It is interested in mitigation only when it raises prices. While the Commission has devoted untold resources to pursuing illusory concerns about monopsony power, it has so far refused to take a hard look at seller-side market power. One example is the Chairman’s premature termination of the enforcement process regarding the nearly 1,000 percent year-over-year increase in prices in MISO Zone 4 and the Commission’s failure to provide any justification for its finding that such a rate is just and reasonable. See Pub. Citizen, Inc. v. Midcontinent Indep. Sys. Operator, Inc., 168 FERC ¶ 61,042 (2019) (Glick, Comm’r, dissenting at PP 4-5). Another example is the Commission’s failure over the course of the last year to take any action on the complaints regarding PJM’s Market Seller Offer Cap. Those complaints allege that PJM’s current rules allow for the exercise of market power, which increase the total cost of capacity by more than a billion dollars. See PJM Independent Market Monitor Complaint, Docket No. EL19-47-000 at 11-12 (Feb. 21, 2019). That complaint has now sat before the Commission for more than 15 months, and it has been more than a year since the last substantive filing was made in that docket.
 See, e.g., James F. Wilson, “Missing Money” Revisited: Evolution of PJM’s RPM Capacity Construct 1 (2016), https://www.publicpower.org/system/ files/documents/markets-rpm_missing_money_revisited_wilson.pdf (discussing the concept of missing money and the origin of capacity markets in the eastern RTOs); Roy J. Shanker Comments, Docket No. RM01-12-000 (Jan. 10, 2003) (discussing the idea of missing money).
 Calpine v. PJM, 169 FERC ¶ 61,239 (Glick, Comm’r, dissenting at P 4).
 In previous orders, the Commission has made much out of so-called unit-specific exemptions, which permit a resource to bid below a default offer floor if it can convince the relevant market monitor that its estimated net going-forward costs are below that floor. If the resource succeeds in that endeavor, the market monitor permits the resource to bid at a lower, but still administratively determined, level. That is still administrative pricing. See Calpine v. PJM Rehearing, 171 FERC ¶ 61,035 (Glick, Comm’r dissenting at P 86).
 In ISO New England and NYISO, existing resources are exempt from mitigation. N.Y. Pub. Serv. Comm’n v. N.Y. Indep. Sys. Operator, Inc., 170 FERC ¶ 61,119, at P 38 (2020) (NYPSC v. NYISO) (“NYISO’s buyer-side market power mitigation measures are applied to all new entrants in the mitigated capacity zones[.]”); ISO New England Inc., 162 FERC ¶ 61,205 at P 3 (“ISO-NE utilizes a minimum offer price rule, or MOPR, that requires new capacity resources to offer their capacity at prices that are at or above a price floor set for each type of resource[.]”). The Commission’s recent order in PJM applied the MOPR to existing resources, but makes them subject to a different—and generally more favorable—pricing regime than new resources. Calpine v. PJM, 169 FERC ¶ 61,239 at P 2 (“[T]he default offer price floor for applicable new resources will be the Net Cost of New Entry (Net CONE) for their resource class; the default offer price floor for applicable existing resources will be the Net Avoidable Cost Rate (Net ACR) for their resource class.” (footnotes omitted)); id. (Glick, Comm’r, dissenting at PP 32-35) (criticizing the Commission for using different offer floor formulae for existing and new resources).
 See Calpine v. PJM, 169 FERC ¶ 61,239 (Glick, Comm’r, dissenting at P 4).
 The periodic demand curve resets that occur in the eastern RTOs illustrate the variety of factors that go into determining the missing money. For example, the development of net CONE in NYISO’s most recent demand curve reset addressed factors ranging from federal, state, and local requirements related to environmental considerations, regional differences in capital and labor costs, as well differences in social justice requirements. See NYISO Transmittal, Docket No. ER17-386-000, Ex. D (Nov. 18, 2016) (Analysis Group, Inc. study addressing demand curve parameters). Those factors affect not only what resource you build and where you can build it, but also how you can operate that resource and, therefore, what revenues you can expect to earn and what costs you can expect to incur. Considering all those factors is necessary to produce efficient price signals guiding when and where to site new capacity, notwithstanding the fact that they are not derived from Commission-jurisdictional markets.
 See, e.g., NYPSC v. NYISO, 170 FERC ¶ 61,119 at P 37; Calpine v. PJM, 169 FERC ¶ 61,239 at P 5 (explaining that the Commission is applying a MOPR to state-sponsored resources in order to “protect PJM’s capacity market from the price-suppressive effects of resources receiving out-of-market support”); ISO New England Inc., 162 FERC ¶ 61,205 at P 24 (“It is . . . imperative that such a market construct include rules that appropriately manage the impact of out-of-market state support[.]”).
 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).
 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.
 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.”).
 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).
 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[.]”).
 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 (“[I]t 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.”).
 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 [FPA]’s goal of ensuring a sustainable supply of efficient and price-effective energy.”).
 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.”).
 N.Y. State Pub. Serv. Comm’n v. N.Y. Indep. Sys. Operator, Inc., 158 FERC ¶ 61,137 (2017) (Bay, Chairman, concurring at 2).
 As the FPA itself recognizes, “the business of transmitting and selling electric energy for ultimate distribution to the public is affected with a public interest.” 16 U.S.C. § 824 (2018).
 See Calpine v. PJM, 169 FERC ¶ 61,239 (Glick, Comm’r, dissenting at PP 27-28) (discussing the scope of federal and state subsidies affecting the PJM capacity market); Calpine Corp. v. PJM Interconnection, L.L.C., 163 FERC ¶ 61,236 (2018) (Glick, Comm’r, dissenting at 6-9) (explaining how “[g]overnment subsidies pervade the energy markets and have for more than a century”); ISO New England Inc., 162 FERC ¶ 61,205 (Glick, Comm’r, dissenting in part and concurring in part at 3) (“Our federal, state, and local governments have long played a pivotal role in shaping all aspects of the energy sector, including electricity generation.”).
 That is particularly true given that the Commission permits a resource to increase its estimated costs due to state policy and environmental goals (e.g., the increased fixed and variable costs associated with selective catalytic reduction, see NYISO Transmittal, Docket No. ER17-386-000 at 2), but not its revenue derived from state public efforts that may happen to be aimed at the exact same environmental goals.
 See, e.g., Calpine v. PJM, 169 FERC ¶ 61,239 (Glick, Comm’r, dissenting at P 55).
 Calpine v. PJM, 169 FERC ¶ 61,239 at P 5; ISO New England Inc., 162 FERC ¶ 61,205 at P 21.
 See supra P 5.
 State polices that exceed the states’ jurisdiction because they set or aim at wholesale rates would, of course, remain preempted. See, e.g., Hughes, 136 S. Ct. at 1298.
 Cf. Nat’l Ass’n of Reg. 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”).
 In dissents from previous Commission orders addressing MOPRs, I have also argued that the Commission’s policy in those particular cases exceeded its jurisdiction because it directly targeted state policies. E.g., Calpine v. PJM Rehearing, 171 FERC ¶ 61,035 (Glick, Comm’r, dissenting at PP 5-25). I still believe that to be true. But my point today is a broader one: The Commission should altogether abandon the use of buyer-side market power mitigation regimes to address something other than actual buyer-side market, even putting aside whether the Commission’s application of those regimes exceeds its jurisdiction in the first place.
 See, e.g., NYPSC v. NYISO, 170 FERC ¶ 61,119 at PP 37, 39; see also N.Y. State Pub. Serv. Comm’n v. N.Y. Indep. Sys. Operator, Inc., 158 FERC ¶ 61,137 (Bay, Chairman, concurring at 3) (“The MOPR is not applied to the state, which may not actually be a buyer and which is acting on behalf of its citizenry, but to the resource, which is offering to sell capacity to the market and which may be a commercial entity. The theory, in other words, assumes such a congruence of interests between the state and the resource that the resource is mitigated for the conduct of the state.”).
 See Hughes, 136 S. Ct. at 1298 (“States may not seek to achieve ends, however legitimate, through regulatory means that intrude on FERC’s authority over interstate wholesale rates[.]”); see also New England Ratepayers Ass’n, 168 FERC ¶ 61,169, at PP 41-46 (2019) (finding a state policy preempted because it sets a wholesale rate).
 N.Y. Pub. Serv. Comm’n, Case 19-E-0530, Order Instituting Proceeding and Soliciting Comments (Aug. 8, 2019), http://documents.dps.ny.gov/public/Common/ ViewDoc.aspx?DocRefId=%7b1D25F4BE-9A05-463F-A953-790D36E318BC%7d.
 N.Y. Indep. Sys. Operator, Inc., 170 FERC ¶ 61,121 (2020) (February 2020 Order) (Glick, Comm’r, dissenting at PP 19-20).
 Id. P 19.
 Id. P 20.
 N.Y. Pub. Serv. Comm’n v. N.Y. Indep. Sys. Operator, Inc., 153 FERC ¶ 61,022, at P 61 (2015).
 Id. P 62.
 February 2020 Order, 170 FERC ¶ 61,121 at P 67.
 Id. P 67 & n.144.
 NY Entities Rehearing Request at 27.
 N.Y. Indep. Sys. Operator, Inc. Compliance Filing, Docket No. ER16-1404, at 18 (Apr. 13, 2016) (April 2016 Compliance Filing).
 N.Y. Indep. Sys. Operator, Inc., 172 FERC ¶ 61,058, at P 15 (2020) (Order).
 N.Y. Pub. Serv. Comm’n v. N.Y. Indep. Sys. Operator, Inc., Complaint, Docket No. EL15-64-000, Ex. B, Cadwalader Aff. ¶ 43 (May 8, 2015).
 See APPA Rehearing Request at 9.
 NY Entities Rehearing Request at 25.
 Order, 172 FERC ¶ 61,058 at P 20.
 April 2016 Compliance Filing, Attach. V, Bouchez Aff. ¶ 13 (“allowing this quantity of ICAP MW to receive a Renewable Exemption in a given Class Year would be reasonable because it would not be likely to result in the artificial suppression of capacity prices in Mitigated Capacity Zones and it would not overly restrict the availability of Renewable Exemptions”)
 April 2020 Compliance Filing at 15.
 February 2020 Order, 170 FERC ¶ 61,121 at P 48 (“a MW cap limits the risk that the renewable resources exemption will significantly impact market prices and it is such limitation that makes this tariff revision just and reasonable”).
 Clean Energy Advocates Protest at 6.
 As the Clean Energy Advocates explain, “[r]etirement decisions are made after accounting for many factors, such as state and federal laws and policies, fuel prices, projected energy demand, competition, [and] revenue needs.” Id.
 See Clean Energy Advocates Protest at 7.
 For example, the Indicated NYTOs explain that several generators have adopted plans to materially deactivate during certain months to avoid contributing to ozone violations. Indicated NYTOs Protest at 13.
 Order, 172 FERC ¶ 61,058 at P 58.
 Indicated NYTOs Protest at 4.