Commissioner Richard Glick Statement
October 7, 2020
Docket No. EL16-92-001, EL16-92-003
I dissent from today’s order because it once again 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 that lack market power is nonsensical. Moreover, even when applied to buyers with market power, mitigation must be tailored to and 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, as part of that regime, the Commission imposes illogical offer floors on demand response resources that punish them for earning revenue through retail-level demand response programs. In so doing, today’s order creates far more problems than it solves by approving unworkable rules that will only prop up prices and place the Commission in direct conflict with the State of New York.
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 monopsony power to lower capacity market clearing prices. To the extent the Commission required buyer-side mitigation of capacity market offers, it limited that mitigation to 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, it is not competition that the Commission is promoting.
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 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 disproportionately be 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 at 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, capacity markets will procure unneeded capacity 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 state 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 market power 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 justified 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’ capacity markets, which also have 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.
Today’s Order Is Arbitrary and Capricious
I believe that the foregoing analysis compels the Commission to go back to the basics on buyer-side market power mitigation. Where entities are not buyers, they categorically 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 only when those buyers possess actual market power.
Demand response resources are, by definition, buyers and may conceivably possess market power. As a result, buyer-side market power mitigation of demand response resources is not per se unjust and unreasonable. Nevertheless, any mitigation must be limited to those resources with actual market power and must also be appropriately tailored to the potential exercise of market power if it is to be just and reasonable and not unduly discriminatory or preferential.
Today’s order falls short of that standard. As an initial matter, the buyers in NYISO’s demand response programs (Special Case Resources or SCRs) now subject to mitigation have not been shown to have market power. To the contrary, SCRs are generally individual end-users—e.g., office buildings, industrial facilities, and the like—that lack anything remotely close to market power. As such, they should be categorically excluded from buyer-side market-power mitigation, at least absent a showing to the contrary.
Both the NY Parties and NRDC raise this point on rehearing, arguing that the Commission failed to explain why it is reasonable to subject resources that do not possess both the incentive and the ability to suppress prices to buyer-side market power mitigation. The Commission responds that the payments SCRs receive from retail demand response programs may reduce their capacity market bids and, in turn, the resulting capacity market prices, meaning that, according to the Commission, those SCRs must be subject to mitigation. That cursory response fails to wrestle with the arguments on rehearing that the Commission should not be applying buyer-side market power mitigation to entities that are not buyers with market power or that the Commission’s about-face in the underlying order was an unreasoned departure from its previous policy. Simply reasserting the underlying conclusion is not a reasoned response to specific, carefully crafted and well-supported requests for rehearing.
In addition, the Commission’s approach to establishing the mitigation regime’s offer floors is arbitrary and capricious. In general, the theory behind an offer floor is that it prevents a resource from bidding below its actual costs, which might improperly “suppress” prices, and, in turn, benefit a net buyer of capacity even if the action is otherwise uneconomic. Accordingly, as the Commission observed in the February 2020 Order, offer floors should represent the “incremental costs” of providing the service in question. So long as a resource is bidding above its incremental costs, the theory goes, the resource will not improperly suppress prices.
Demand response resources, however, have vanishingly small incremental costs, which makes a cost-based offer floor an ineffective tool for limiting their participation in wholesale markets. So NYISO has implemented an offer floor for demand response resources that is a function of those resources’ revenue rather than their costs. That approach makes little sense and is inconsistent with the theory of using offer floors to address buyer-side market power since a revenue-based floor is not tied to a resource’s actual costs. Instead, the use of revenue-based offer floors only underscores the extent to which NYISO’s buyer-side market power mitigation has become an exercise in propping up prices, not mitigating market power.
But it gets even worse. SCRs are now required to add any revenue they receive from retail-level demand response programs to their revenue-based offer floor. That means that the more revenue a demand response resource earns outside of NYISO’s demand response program, the higher it must offer into the NYISO market to avoid allegedly “suppressing” prices. Consider a simplistic hypothetical in which a resource splits the revenue it earns providing demand response, keeping 80% for itself and paying 20% to the entity that installs the necessary equipment and facilitates its participation in various demand response programs. Under the current mitigation regime, a demand response resource that expects to make $100 participating as an SCR in the NYISO market would have an offer floor of $80. If the same resource were to also participate in a retail-level demand response program and make $50, it would have to add $40 to its offer floor, meaning that it could not bid below $120 (its revenue) even though its costs would not change. That is simply nonsensical. There is no reason that the measure of the resource’s “incremental costs” should increase because the resource is earning greater revenue in a different market. Put another way, whether the resource makes $80 or $120 in revenue, its ability (and incentive) to bid below its actual costs in the capacity market has not changed. This means that the offer floor is not in any way reasonably tailored to a potential exercise of market power.
Making matters still even worse, if the revenue from the retail-level demand response program is at all significant, this approach will produce an offer floor for demand response resources that is well above capacity market clearing prices. That would effectively block demand response resources from participating in the NYISO capacity market on the sole basis that those resources also provide useful services through retail-level demand response programs. Not only is this outcome nonsensical in the context of market power mitigation, it also is bad for the market and consumers. Demand response is a resource that provides New York with significant economic and reliability benefits, making SCRs exactly the types of resources that we should be encouraging to participate in the capacity market, not excluding based on pretextual justifications like mitigating buyer-side market power.
Finally, today’s order also draws arbitrary distinctions between different types of retail-level demand response programs. As noted, the February 2020 Order concluded that demand response “offer floors should include only the incremental costs of providing wholesale-level capacity services,” which means that the offer floor should not include revenue from “retail-level demand response programs designed to address distribution-level reliability needs.” This order applies that standard to two types of demand response programs: Distribution Load Relief Programs (DLRP) and Commercial System Relief Programs (CSRP). DLRPs and CSRPs are similar programs that New York’s distribution utilities use to maintain the reliability of the distribution system by reducing demand when particular aspects of the distribution system are stressed. The Commission concludes that while DLRPs are intended to address only distribution system needs, CSRPs may be intended to also address transmission system needs. Accordingly, the Commission concludes that the revenues from DLRPs should be excluded from the calculation of the SCR offer floors, but that revenues from CSRPs must be included.
That distinction is unreasoned and inconsistent with the standard articulated in the February 2020 Order. The record before us suggests that both DLRPs and CSRPs are retail-level programs directed at distribution system issues. As the Complainants noted when beginning these proceedings, “[t]he primary purpose of distribution-level Demand Response programs, which include utility-administered distribution-level programs analogous to [the] DLRP and CSRP, is to benefit the administering utilities’ distribution system.”  They do so by having retail customers curtail their consumption in order to reduce the stress on particular elements of the distribution system.
That solves a very different issue than NYISO’s SCR program, which addresses peak demand on and the reliability of the bulk power system by, among other things, calling on demand response to maintain adequate operating reserves. To see that, one need look no further than the fact that the dispatch of DLRPs and CSRPs rarely overlaps NYISO’s SCR dispatch. As the Commission observed in the February 2020 Order, differing dispatch patterns is strong evidence that the different demand response programs address different needs, and therefore any revenue received through the program should be excluded from the offer floor. In addition, the limited overlap in the activation of NYISO’s SCR program and the distribution utilities’ use of CSRPs reflects the fact that high-load days are likely to stress both the transmission and distribution system, not that CSRPs provide wholesale services. That limited overlap does not support the conclusion that CSRPs address the same issues as the SCR program.
It is true that any reduction in demand, including one targeted exclusively at enhancing distribution system reliability, may provide knock-on benefits for resource adequacy and the transmission needs addressed by NYISO. But that is true of any reduction in end-use consumption, regardless of whether it provides “wholesale-level capacity services” or is instead “designed to address distribution-level reliability needs.” Contrary to the Commission’s suggestion, the indirect wholesale benefits of those programs cannot, under the Commission’s own standard, justify mitigation and certainly not mitigation of one program but not the other. Accordingly, mitigating CSRPs because those programs may indirectly benefit the wholesale market is bothunreasoned and inconsistent with the treatment of DLRPs, which are similarly situated for the purposes of the standard articulated in the Commission’s February 2020 Order and can also provide indirect wholesale benefits.
* * *
We have been here before. Today’s order is just the latest in a series of recent Commission orders that aim, clear as day, to stymie New York’s efforts to promote a clean energy future. I continue to believe that those efforts will ultimately fail. But I worry that, in the meantime, the Commission’s quixotic campaign against New York’s environmental goals will raise prices for consumers and do potentially serious damage to the organized markets that we ought to foster and protect. That, suffice it to say, would not be 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 (Calpine v. PJM), r’hrg denied, 171 FERC ¶ 61,035 (2020) (Calpine v. PJM Rehearing) (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 v. PJM Rehearing, 171 FERC ¶ 61,035 (2020) (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% 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 20 months, and it has been more than 15 months 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 the 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, 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. State 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, e.g., 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); see also id. § 824d(a) (similar).
 See id. § 824(b)(1); 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.
 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); see also N.Y. Indep. Sys. Operator, Inc., 172 FERC ¶ 61,206 (2020) (Glick, Comm’r, dissenting at P 1) (“The Commission’s approach is both deeply misguided and will ultimately doom NYISO’s current capacity market construct by forcing New York to choose between the Commission’s constant meddling and the state’s commitment to addressing the existential threat posed by climate change.”).
 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 power, 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. State 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. State Pub. Serv. Comm’n v. N.Y. Indep. Sys. Operator, Inc., 170 FERC ¶ 61,120 (2020) (February 2020 Order) (Glick, Comm’r, dissenting at PP 1, 18-19).
 Id. (Glick, Comm’r, dissenting at P 19).
 Id. (Glick, Comm’r, dissenting at P 19).
 Id. (Glick, Comm’r, dissenting at P 19).
 N.Y. Indep. Sys. Operator, Inc., 172 FERC ¶ 61,058 (2020) (Glick, Comm’r, dissenting at P 1).
 NY Parties Rehearing Request at 11-12, 15-16; NRDC Rehearing Request at 27-29.
 N.Y. State Pub. Serv. Comm’n v. N.Y. Indep. Sys. Operator, Inc., 173 FERC ¶ 61,022, at P 22 (2020) (Order).
 For the reasons discussed above, I continue to believe that this approach does not make sense when applied to resources that are not buyers with market power, but I’ll work within the Commission’s premise for the moment.
 February 2020 Order, 170 FERC ¶ 61,120 at P 18; see Order, 173 FERC ¶ 61,022 at P 20.
 See N.Y. Indep. Sys. Operator, Inc., 131 FERC ¶ 61,170, at PP 132-33 (2010), rh’g 150 FERC ¶ 61,208 (2015); see also N.Y. State Pub. Serv. Comm’n v. N.Y. Indep. Sys. Operator, Inc., 158 FERC ¶ 61,137 at P 3 (summarizing the history of the offer floors applied to SCRs).
 Order, 173 FERC ¶ 61,022 at P 43.
 February 2020 Order, 170 FERC ¶ 61,120 at P 18.
 Id. P 18.
 For example, these programs permit distribution utilities to call upon demand response to alleviate stress upon “feeders, area substations, and/or distribution circuits.” See, e.g., Complainants Br., Ahrens Aff. at 8.
 Order, 173 FERC ¶ 61,022 at PP 57-58.
 For the reasons stated above, I believe the Commission should altogether stop applying buyer-side market power mitigation to resources that are not buyers with market power. But even putting those concerns aside and working within the framework laid out in the February 2020 Order, the distinction that the Commission draws between DLRPs and CSRPs is nonsense, in any case, and irrelevant. The underlying purpose of the program through which the SCR receives revenue does not change in any way the SCR’s ability or incentive to exercise market power in the capacity market.
 N.Y. State Pub. Serv. Comm’n., Complaint, Docket No. EL16-92-000, at 32 (June 24, 2016).
 See, e.g., Complainants Br., Shabalin Aff. at 7 (discussing the use of Consolidated Edison’s retail-level demand response programs). The Commission’s unsupported and unexplained assertion that CSRPs provide “network load relief,” Order, 173 FERC ¶ 61,022 at P 58, is not a reasoned conclusion in response to the heap of evidence explaining how CSRPs are designed to address reliability issues on the distribution system. See Companies Br., Reilly Aff. at PP 5-16, 21-27 (explaining that the “CSRP and DLRP programs are activated to provide load relief at . . . [the] distribution ‘network’ level”); Companies Br., Hilowitz Aff. at PP 7-19, 24-31; Complainants Br., Evans Aff. at PP 5-10, 20-30; Complainants Br., Shabalin Aff. at 7-9.
 See Complainants Br., Hamilton Aff. at P 6.
 See id., Hamilton Aff. at P 9 (“Over the past four years since this docket was initiated, . . . [the relevant New York utilities] have dispatched their distribution-level DR programs a total of sixty-eight times to address distribution system peak demand conditions local constraints or local emergency operating conditions to maintain reliability. Over this same period, NYISO has activated the SCR program to address transmission-level issues once in 2016 across all NYISO zones and three times in 2018 in Zone J only to maintain bulk-system reliability.” (citations omitted)).
 February 2020 Order, 170 FERC ¶ 61,120 at P 18 (noting that “the dispatch of resources enrolled in retail-level demand response programs differs significantly from dispatch under the SCR program, which reflects the fact that each category of program is designed to address needs on distinct systems”).
 Complainants Br., Ahrens Aff. at 7 (“The fact that [SCR and either CSRP or DLRP] programs are activated on the same days should not be interpreted as meaning they are designed to be complementary or achieve the same purpose. The NYISO’s SCR program, as a reliability-related demand response program, is called mostly when demand has the potential to exceed supply, such as during a heat wave. . . . CSRP and DLRP, are called when local network demand is expected to be high or when there are local distribution issues, clearly for very different purposes than the SCR.”).
 February 2020 Order, 170 FERC ¶ 61,120 at P 18; see also EPSA, 136 S. Ct. at 776 (recognizing that the state and federal spheres of authority under the FPA “are not hermetically sealed from each other”).
 Order, 173 FERC ¶ 61,022 at P 58 (“We find that any program that provides reliability benefits to the transmission system does not solely address distribution-level reliability needs.”). Taken seriously, that standard could potentially justify making any retail-based program the basis for mitigating an SCR. That is neither reasonable in its own right, nor consistent with the standard that the Commission articulated in the February 2020 Order, which recognized that revenue from demand response programs that are designed to address distribution system needs should not be included in SCR offer floors. February 2020 Order, 170 FERC ¶ 61,120 at P 18.
 Today’s order also implies that certain utilities have conceded that their “CSRPs are designed to meet transmission and distribution infrastructure investment needs.” Order, 173 FERC ¶ 61,022 at P 58 (citing Companies Br., Reilly Aff. at 4). That misreads the record. As an initial matter, the cited testimony indicated that the use of retail demand response had helped avoid “local transmission and distribution . . . infrastructure investment.” Companies Br., Reilly Aff. at P 9 (emphasis added). Given the design of the grid in parts of New York, including the relatively high operating voltage of the distribution system in New York City, it is hardly clear that that stray sentence could reasonably be construed as a concession that CSRPs are designed to address wholesale market concerns. In fact, the very next sentence in that affidavit notes that “retail [demand response] needs are distinct from wholesale needs” and that CSRPs are focused only on the former. Id. And, elsewhere in that document, the affiant observes that retail demand response programs provide only “distribution system reliability benefits” and help “to avoid, or at a minimum defer, construction of distribution infrastructure upgrades.” Id. at P 6 (emphasis added). Simply put, the Reilly affidavit does not provide substantial evidence in support of the Commission’s conclusion.
 See, e.g., N.Y. Indep. Sys. Operator, Inc., 172 FERC ¶ 61,206 (Glick, Comm’r, dissenting at PP 10, 13); N.Y. Indep. Sys. Operator, Inc., 172 FERC ¶ 61,058 (Glick, Comm’r, dissenting at P 31); February 2020 Order, 170 FERC ¶ 61,120 (Glick, Comm’r, dissenting at P 18).