New Jersey Board of Public Utilities v. Federal Energy Regulatory Commission

744 F.3d 74

• Court: Court of Appeals for the Third Circuit
• Decided: February 20, 2014
• Docket: 11-4245, 11-4405, 11-4486, 11-4487, 12-1085, 12-1086, 12-1764
• Status: Published

Opinion

OPINION

RENDELL, Circuit Judge:

In what is a relatively unusual task for our court, we are asked to review a ruling of the Federal Energy Regulatory Commission (“FERC”) approving a revised tariff submitted by PJM Interconnection, LLC, that effectively changes several aspects of PJM’s tariff as approved in a prior FERC order. FERC is the independent federal agency tasked under the Federal Power Act (the “FPA”) with, among other things, ensuring that rates charged by public utilities for the transmission and sale of energy in interstate commerce, and the “rules and regulations affecting or pertaining to such rates”, are “just and reasonable.” 16 U.S.C. § 824d.

In 2006, FERC issued an order (the “2006 Order”) approving a new tariff — a set of rules and policies governing the interstate sale of electricity and electric capacity — for the PJM market, a vast region covering thirteen states and the District of Columbia. The terms and policies embodied in the 2006 Order — the result of an extensively negotiated settlement between power providers, utility companies, state and local authorities and other stakeholders in the region — sought to ensure the existence of sufficient power generation facilities to meet the needs of the PJM market. To this end, the order required that load serving entities (LSEs) in the PJM market procure a certain amount of energy capacity — that is, additional generation resources that the market may access during times of peak load. The 2006 Order also contained rules designed to curb the ability of market participants to distort wholesale prices through the exercise of market power. A chief means to that end was the rule that offers for the sale of capacity in the PJM markets at artificially low prices would, with some notable exceptions, be required to be “mitigated”, or raised to a competitive level, based on their costs.

Beginning in April 2011, FERC issued three orders (the “2011 Orders”) that altered the terms of the 2006 Order in several ways, some substantial. Among other things, the 2011 Orders eliminated an exemption from mitigation for resources built pursuant to a state mandate. In addition, the 2011 Orders eliminated a provision that had guaranteed that LSEs that owned their own generation resources, or had procured capacity through bilateral contracts, would be able to use this “self-supply” to satisfy their own capacity obligations. The 2011 Orders also changed several factors used in determining whether a particular offer was subject to mitigation.

As discussed infra, multiple parties have timely filed Petitions for Review of the 2011 Orders. 1 Petitioners New Jersey and Maryland contend that the 2011 Orders amount to direct regulation of power facilities in violation of the FPA, and that FERC acted arbitrarily and capriciously in eliminating the exemption from mitigation for state-mandated resources. Similarly, several municipal and cooperative electric utilities challenge FERC’s elimination of the assurance that LSEs could uge their own self-supply to satisfy their capacity obligations. Finally, various energy providers take issue with new rules governing the calculation of a resource’s net cost of new entry, which is used in determining whether an offer for the sale of capacity will be mitigated, and with FERC’s determination that a new generation resource must clear only one capacity auction in order to avoid further mitigation. We have considered these arguments and find them without merit. Accordingly, we deny the petitions for review.

I.

At the time the FPA was passed in 1935, “most electricity was sold by vertically integrated utilities that had constructed their own power plants, transmission lines, and local delivery systems. Although there were some interconnections among utilities, most operated as separate, local monopolies subject to state or local regulation.” New York v. FERC, 585 U.S. 1, 5, 122 S.Ct. 1012, 152 L.Ed.2d 47 (2002). In 1927 the Supreme Court held in Public Utilities Commission v. Attleboro Steam & Electric Co., 273 U.S. 83, 47 S.Ct. 294, 71 L.Ed. 549 (1927), that only Congress, and not the states, could regulate the sale of electrical power in interstate commerce. To meet this charge, Congress enacted the FPA, which authorized federal regulation of the interstate sale of electricity, and created a new independent agency, the Federal Power Commission (precursor to FERC), to administer the statute. New York, 535 U.S. at 6-7, 122 S.Ct. 1012. Section 201 of the FPA defined the Commission’s jurisdiction as “the transmission of electric energy in interstate commerce and the sale of such energy at wholesale in interstate commerce.... ” 16 U.S.C. § 824(a). The statute gave the Commission regulatory power over “all facilities for such transmission or sale of electric energy”, but withheld jurisdiction over “facilities used for the generation of electric energy” which remained subject to state and local regulation. § 824(b)(1). Section 205 tasked the Commission with ensuring that “[a]ll rates and charges made, demanded or received by any public utility for or in connection with the transmission or sale of electric energy ... and all rules and regulations affecting or pertaining to such rates or charges shall be just and reasonable,” and prohibited utilities engaged in the transmission or sale of energy in interstate commerce from “mak[ingj or granting] any undue preference or advantage to any person or subjecting] any person to any undue prejudice or disadvantage, or [ ] maintaining] any unreasonable difference in rates, charges, service, facilities, or in any other respect, either as between localities or as between classes of service.” § 824d. Section 206 gave the Commission the power to correct rates, or “any rule, regulation, practice, or contract affecting such rate[s]” that it deemed unjust and unreasonable. § 824e(a).

In the nearly eight decades since the FPA was enacted, technological advances have revolutionized the way electric power is generated and transmitted. Transmission grids are now largely interconnected, which means that “any electricity that enters the grid immediately becomes a part of a vast pool of energy that is constantly moving in interstate commerce.” New York, 535 U.S. at 7, 122 S.Ct. 1012. In addition to making the transfer of electricity over long distances more efficient, the development of a national, interconnected grid has made it possible for a generator in one state to serve customers in another, thus opening the door to potential competition that did not previously exist. Id. at 8, 122 S.Ct. 1012. Public utilities still retain ownership over transmission lines, however, and so, until recently, had the ability to stifle competition from new generators by “refus[ing] to deliver energy produced by competitors or [by] delivering] competitors’ power on terms and conditions less favorable than those they apply to their own transmissions.” Id. at 8-9, 122 S.Ct. 1012. Congress changed this with two pieces of legislation — the Public Utility Regulatory Policies Act of 1978 (“PURPA”), Pub.L. 95-617, and the Energy Policy Act of 1992, Pub.L. 102-486. Respectively, those two statutes obligated traditional utilities to purchase electricity from “nontraditional facilities,” and authorized FERC to order utilities to provide transmission services to independent generators. New York, 535 U.S. at 9, 122 S.Ct. 1012. In 1996, FERC issued a landmark ruling requiring the “functional unbun-dling” of wholesale generation and transmission services, and requiring utilities to provide open, nondiscriminatory access to their transmission facilities. 2

In response to the changing conditions in the energy market in recent years, FERC has changed its approach to regulating rates. Rather than setting rates for each public utility, FERC now seeks to ensure that market-based rates are “just and reasonable” largely by overseeing the integrity of the interstate energy markets. See Consol. Edison Co. of N.Y., Inc. v. FERC, 347 F.3d 964, 967 (D.C.Cir.2003) (“The Federal Energy Regulatory Commission oversees this market-based system pursuant to the Federal Power Act”); La. Energy & Power Auth. v. FERC, 141 F.3d 364, 365 (D.C.Cir.1998) (“[T]he Commission approves applications to sell electric energy at market-based rates only if the seller and its affiliates do not have, or adequately have mitigated, market power in the generation and transmission of such energy, and cannot erect other barriers to entry by potential competitors.”). 3

II.

A. PJM Interconnection

Though the grid has become nationally interconnected and competition among generators has increased, transmission lines for a particular geographic area are still typically owned by a single utility company. To manage the complexities of the grid, FERC has encouraged the development of “regional transmission organizations,” or “RTOs,” which are voluntary associations of the owners of transmission lines. Ill. Commerce Comm’n v. FERC, 576 F.3d 470, 473 (7th Cir.2009). RTOs were promoted by FERC to increase competition among energy providers by ensuring that owners of transmission lines provide access in a nondiscriminatory manner. Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361, 1364 (D.C.Cir.2004). Each RTO acts as the system operator in its region, managing the transmission grid on behalf of transmission-owning member utilities. See NRG Power Mktg., LLC v. Me. Pub. Utils. Comm’n, 558 U.S. 165, 169 n. 1, 130 S.Ct. 693, 175 L.Ed.2d 642 (2010). The parties do not dispute that RTOs are “public utilities” under the FPA, and are thus subject to FERC’s regulation.

PJM Interconnection (“PJM”) is the RTO that manages the regional transmission system spanning from New Jersey west to Chicago and south to North Carolina. As such, PJM governs the transmission of electricity to fifty million consumers in thirteen different states and the District of Columbia. One of PJM’s primary responsibilities as system operator is to ensure that there is a sufficient amount of electrical capacity within its system to provide reliable electricity to its consumers during periods of peak demand. “ ‘Capacity is not electricity itself but the ability to produce it when necessary.” Connecticut DPUC v. FERC, 569 F.3d 477, 479 (D.C.Cir.2009). In a reliable transmission system, the full potential of the system is used only during periods of peak demand. That means that much of the rest of the time there will be generation capacity that is idle. One of PJM’s functions is to ensure that there are enough idle generators connected to the transmission grid for the system to function at peak load. It does this by predicting the expected peak load three years in advance and then setting a target level of capacity. The member-utilities that sell electricity to end-use consumers — known in administrative parlance as “load-serving entities,” or “LSEs” — are then each responsible for providing a proportionate share of the capacity target.

PJM is also responsible for administering the regional markets for energy and energy capacity that have developed as competition among generators has increased. Energy — that is, actual electricity — is sold wholesale via a “day-ahead market” and a “real-time market.” See Black Oak Energy, LLC v. FERC, 725 F.3d 230, 233 (D.C.Cir.2013). The term for the market mechanism used to determine energy prices in each area within the PJM region is “Locational Marginal Pricing,” or “LMP.” Id. “Under LMP, the price any given buyer pays for electricity reflects a collection of costs attendant to moving a megawatt of electricity through the system to a buyer’s specific location on the grid.” Id. at 233-34. In some areas, the transmission system is more “congested”, which means that PJM must dispatch more expensive generators to meet the area’s demand. “The cost of congestion results in different prices at different nodes of the system, depending on how congested the wires leading to those nodes are.” Id. at 234.

Energy capacity, on the other hand, is sold in the PJM market at annual capacity auctions, which are the subject of this appeal. Capacity auctions allow LSEs to buy the capacity they need to satisfy PJM’s capacity requirements. Capacity auctions also, at least in theory, incentivize the development of new generation resources by establishing a market-based means by which those resources can recover their investment costs.

Because the energy and energy capacity auctions determine the rates for the transmission and sale of energy in interstate commerce, they are subject to FERC oversight. PJM is therefore obligated to obtain FERC approval of any changes it makes to its “tariff,” which is the term of art used to refer to the “classifications, practices, and regulations” a public utility uses to establish electricity rates. See 16 U.S.C. § 824d(c). FERC reviews PJM’s proposed changes to its own tariff under § 205 of the FPA to determine whether such changes result in rates that are “just and reasonable.” 16 U.S.C. § 824d(a). FERC can also make changes to PJM’s tariff under § 206 of the FPA, either on its own initiative or pursuant to a complaint from a third party, if it determines that the rates produced under the tariff are unjust or unreasonable. Id. § 824e(a).

B. The Reliability Market

Prior to 1999, PJM required LSEs that were unable to provide sufficient capacity in advance of when it was needed to pay a deficiency charge based on the fixed costs of a new generator. In 1999, PJM modified the reliability requirement to allow LSEs to procure capacity up to the day before it was needed, while also instituting market opportunities to purchase “capacity credits.” LSEs that failed to obtain sufficient capacity in those markets were then subject to the deficiency charge. Those methods soon proved inadequate, however, as they resulted in supply insufficiencies and volatile capacity prices in certain locations. In particular, the retirement of many aging generators in the mid-Atlantic resulted in reliability problems throughout the region, and volatile prices made the capacity market ineffective at incentivizmg development of new generation resources. Therefore, in 2000, PJM began negotiating with its stakeholders to reform the capacity market.

In 2006, after a period of extended negotiation, an administrative law judge facilitated a settlement that created the Reliability Market. The settlement was approved with modification by FERC and incorporated into PJM’s tariff in the 2006 Order. See PJM Interconnection, LLC, 117 FERC ¶ 61,331 (2006). Under the FERC-approved tariff that resulted from that settlement, all capacity suppliers (ie., generation and transmission resources) that wish to receive a capacity payment or satisfy an LSE’s capacity obligation are required to offer their available capacity into an auction. 4 Those offers are grouped based on the particular “locational delivery area,” or “LDA,” the resource will serve. Offers are then accepted by the auction, or “cleared”, in order of price, starting with the lowest price offered, and continuing until there is sufficient capacity in the auction to satisfy PJM’s requirements for each LDA. All offers that clear for a given LDA are then paid the “clearing price” for that area, which is equal to the last offer (ie., the highest offer) necessary to meet the area’s reliability needs as determined by P The auction therefore sets the price that the LSEs will pay for capacity in a given area. Only capacity offers that successfully clear the auction can be counted towards an LSE’s capacity requirements. PJM refers to this approach to determining the cost of capacity as the “Reliability Pricing Model,” or “RPM.” 5

Pursuant to the 2006 Order, PJM actually operates two types of capacity auctions: “base residual auctions” and “incremental auctions.” See 2006 Order ¶ 55 (Joint App. 3046-47). Base residual auctions are held three years in advance of when the capacity offered at the auction will be needed. The forward-looking nature of the auctions serves two functions: it provides PJM advance assurance that its system will be reliable, and it allows new generation resources, though not yet complete, to test the market and perhaps obtain financing for their construction. The incremental auctions then allow LSEs to purchase additional capacity if needed to meet greater-than-expected demand. Although both auctions function similarly, the base residual auctions are the primary subject of this appeal.

The capacity auctions are not the only method by which LSEs can satisfy their capacity obligations. If an LSE prefers not to participate in the auctions, it can instead utilize the “Fixed Resource Requirement” (“FRR”) option, which allows an LSE to opt out of the auctions by building or directly contracting with generation resources to meet its capacity obligations. To qualify for the FRR option, however, the LSE must demonstrate to PJM that it has access to sufficient generation and transmission resources to meet projected capacity obligations for a five-year period, beginning three years in the future. If it succeeds in doing so, the LSE can forego the capacity auctions and pay its generation resources whatever price the parties agree to. However, if an LSE chooses the FRR option, it loses the ability to participate in the auctions during that five-year period; it cannot buy additional capacity, nor can it “defray the costs of new resources” it builds by offering their excess capacity into the auctions. See PJM Interconnection, LLC, 135 FERC ¶ 61,022 (Apr. 12, 2011) [hereinafter, “April 12 Order”] (Joint App. 81-82 n. 98). In other words, participating in the FRR option is an all-or-nothing proposition, and appeals as a practical matter only to large utilities that still follow the traditional, vertically integrated model. 6

C. The Minimum Offer Price Rule

In addition to establishing the capacity auctions, the 2006 Order created several mechanisms designed to prevent market manipulation in those auctions. First, to prevent sellers from exercising monopoly power, the 2006 Order imposed a rigid price cap on all offers. Second, the settle ment provided for a “Minimum Offer Price Rule,” or “MOPR,” that is designed to curb monopsony power, ie., the power of a buyer facing many sellers and little to no competition from other buyers. 7 The exercise of buyer market power is possible in part because many utility companies are both buyers and sellers of capacity in the capacity auctions. If, for example, an LSE owns a small generator, the LSE must offer that generation capacity into the auction in order for it to count towards the LSE’s capacity obligation. To fully satisfy that obligation, however, the same LSE may also have to purchase additional capacity from the auction. When such LSEs buy more capacity than they offer into the auction, they have an incentive to keep auction prices as low as possible. Theoretically, those net-buyers can achieve that objective by offering their capacity at artificially low prices that are sure to clear the auction. Such offers crowd out other capacity that is priced at a higher, cost-based rate, and thus result in a lower overall clearing price. To counteract that manipulation of the market, the MOPR seeks to identify uneconomic offers and “mitigate” them by raising them to a price that more accurately approximates their net costs.

Under the original MOPR approved by FERC in the 2006 Order, offers for capacity were subject to mitigation if they failed three “screens”: a conduct screen, an impact screen, and an incentive screen (also known as the “net-short test”). The conduct screen identified offers that might be artificially low by comparing them to a “threshold” price, which was based on PJM’s estimate of the net cost of new entry into the market, or net “CONE,” for the relevant LDA. 8 PJM determined the estimated net CONE for two types of generators — combustion turbines (“CT” generators) and combined cycle turbines (“CC” generators) — both of which are gas-fired generators. The threshold price for each of those generators was either 70% or 80% of its estimated net CONE (depending on the type of resource). Any offer that was below the threshold price would fail the “conduct screen.”

Offers that failed the conduct screen would then be subject to the “impact screen,” which was conducted by rerunning the auction to determine whether the offer would reduce the clearing price by 20% to 30% in the relevant LDA, or by $25/MW-day 9 , whichever was greater. Put more simply, the impact screen determined whether a below-cost offer actually affected the clearing price in a substantial way. If it did, then the offer would be subjected to the final screen, the “net-short test”, in which PJM determined whether the seller had an incentive to depress prices. Specifically, PJM would determine whether the seller was in a “net-short position”, that is, whether the seller bought substantially more capacity from the auction than it sold, and thus had the incentive to reduce the clearing price. An offer that failed all three screens would then be “mitigated” by raising it to 80% or 90% of the estimated net CONE, depending on the resource type. That adjusted offer could still clear the auction, but only if it was at or below the clearing price.

Importantly, however, not all offers were subject to the MOPR. First, the MOPR applied only to new entrants to the market, not to existing resources. Although existing resources, like all available capacity, had to be offered into the auction, they could be offered at any price below the upper limit. In fact, because existing resources already incurred the costs needed to generate capacity, and could thus often afford to offer capacity at very low prices, they were permitted to offer their capacity at a price of zero dollars, which would ensure that it cleared the auction and received the clearing price. The MOPR also did not apply to upgrades or additions to existing resources. Second, certain types of resources were never subject to the MOPR, including nuclear, coal, and hydroelectric resources. Third, the MOPR exempted from its operation “any planned resource being developed in response to a state regulatory or legislative mandate to resolve a projected capacity shortfall.” April 12 Order ¶ 124 (Joint App. 61-62). In order for an offer to qualify for that exemption, the state’s capacity shortfall had to be established “pursuant to a state evidentiary proceeding that includes due notice, PJM participation and an opportunity to be heard.” Id.

The original MOPR also provided special treatment to resources designated as “self-supply,” which are capacity resources that an LSE builds to serve its own load. Such a resource had to offer its capacity into the auction, and the resource had to clear the auction, in order for it to be counted toward the LSE’s capacity obligation. Unlike the three types of resources described above, self-supply resources were not listed among the exemptions to the MOPR, and so could be subject to mitigation if they failed the three screens. But the MOPR went on to state that, after offers were mitigated as needed and the clearing price was determined, PJM must accept capacity offers in the following order:

(i) first, all Sell Offers in their entirety designated as self-supply committed regardless of price; (ii) then, all Sell Offers of zero ... and (in) then all remaining Sell Offers in order of the lowest price....

PJM Tariff Attachment DD, Section 5.14(h)(4) (emphasis in original). The MOPR therefore suggested that self-supply offers would clear the auction before all other offers, even if the self-supply offers were actually higher than the clearing price. In other words, although they were not “exempt” from the MOPR, and thus could be mitigated, self-supply offers were entitled to what amounted to automatic clearance. 10

For all resources, the original MOPR only applied the first time a resource was offered at an auction, regardless of whether it cleared the auction. Resources that failed to clear the first time could therefore be offered at subsequent auctions without facing the three screens and potential mitigation.

In sum, the original MOPR would mitigate first-time offers from certain resources that had the potential to manipulate the market through the exercise of buyer market power. The original MOPR did not affect resources that were built pursuant to a state mandate intended to correct a capacity deficiency, and it appeared to allow self-supply offers to clear regardless of price. Notably, during the entire period it was in effect, the original MOPR was never triggered, meaning that no offer was subject to mitigation.

III.

A. The New Jersey and Maryland Initiatives

The chain of events leading up to FERC’s 2011 Orders was set in motion by the efforts of two states — New Jersey and Maryland — to invoke the MOPR’s exemption for state-mandated resources, efforts which, if successful, would result in the introduction of thousands of megawatts of subsidized capacity into the PJM market. On January 28, 2011, New Jersey Governor Chris Christie signed into law the “Long-Term Capacity Agreement and Pilot Program” (“LCAPP”), 2011 N.J. Sess. Law Serv. Ch. 9 (codified at N.J. Stat. Ann. § 48:3-98.2 (2011)), which launched a state initiative to develop new generation resources. According to the statute, New Jersey faced an “electrical power capacity deficit” due to transmission system overloads and aging generation facilities. Id. § 48:3-98:2(e), (h). Because PJM’s “reliability pricing model [had] not resulted in large additions of’ generation facilities or load resources, “the construction of new, efficient generation [had to] be fostered by State policy.” Id. § 48:3 — 98.2(b), (d). 11

Pursuant to the LCAPP, the New Jersey Board of Public Utilities would conduct a competitive bidding process, in which it would evaluate proposed resources based on their “environmental, economic, and community benefits.” Id. § 48:3-98.3(b)(2). Winning bidders would then enter into longterm contracts with New Jersey’s four electric public utilities, pursuant to which they would build new capacity resources in exchange for payments at a specified rate. Id. § 48:3-51; id. § 48:3-98.3(c)(9). The new generation resources would be required by those contracts to attempt to clear the PJM base residual auction. Id. § 48:3-98.3(c)(12). Once a resource cleared, New Jersey’s public utilities would then pay the generators the difference between the contract price and the amount they were able to receive from the auction, or if the clearing price was higher than the contract price, the generators would reimburse the public utilities for the excess payment. Id. at (c)(4). To ensure that its resources would clear, New Jersey intended to offer the capacity into the base residual market at a price below their actual cost.

Spurred to action by similar concerns regarding longterm reliability needs and the suspension of a key transmission project, the Maryland Public Service Commission (PSC) in December 2010 released a draft Request for Proposals (“RFP”) for Generation Capacity Resources Under Long-Term Contract. The RFP contemplated that the PSC would conduct an evidentiary hearing to determine whether it would, similarly to New Jersey, require Maryland’s electric distribution companies (EDCs) to enter into long-term contracts to purchase new capacity, or to construct new generation on their own. After the close of briefing in this matter, the PSC did issue a Generation Order directing each of three Maryland EDCs to contract with Commercial Power Ventures (CPV) Maryland. See Nazarian, 974 F.Supp.2d at 795-96, 2013 WL 5432346 at *1. As in New Jersey, the Maryland contracts require CPV to sell capacity in the PJM markets, and for the EDCs to pay CPV any difference between the price received in the market and a predetermined contract price. 12 Like New Jersey, Maryland intended to offer its new capacity resources into the PJM market at a price below its actual cost to ensure that they would clear.

B. The P3 Complaint and PJM’s Revisions to the MOPR

Shortly after the LCAPP was enacted, an association of PJM’s power providers, known as “P3” 13 , filed a complaint with FERC under § 206 of the FPA, arguing that the MOPR implemented in the 2006 Order was not an effective tool for curbing buyer market power. Specifically citing the New Jersey and Maryland initiatives, P3 urged that “without effective mitigation, the exercise of buyer market power will sound the death knell of competitive markets — and with them the cost savings that markets create for consumers.” (Joint App. 204) Accordingly, P3 urged PJM to eliminate the MOPR’s exemption for state-mandated resources.

P3 also requested other reforms of the MOPR in its complaint, all geared toward mitigating buyer-side market power: (1) adjustment of the conduct screen so that any offer that was less than 100% of the estimated net CONE would trigger the MOPR; (2) elimination of the two subsidiary screens (the impact screen and the net-short test) entirely; (3) elimination of the exemption for self-supply (to the extent that one existed); (4) addition of a requirement that a new resource successfully clear two auctions before becoming exempt from the MOPR; and (5) addition of an exemption to the MOPR “for any new resource whose sponsor affirms it will not receive any form of out-of-market subsidy or preferential treatment by state regulators,” which it called a “No-Subsidy Off-Ramp”. P3Br. 19.

On February 11, 2011, in response to P3’s complaint, PJM submitted to FERC proposed changes to its tariff that had incorporated the original MOPR, under § 205 of the FPA. The original MOPR, PJM explained, was designed to “address a concern that some market participants might have an incentive to depress market clearing prices by offering some self-supply at less than a competitive level.” (Joint App. 393 (internal quotation marks omitted)). Because the original MOPR had never been triggered, PJM urged that the existing rule was not adequate to serve these purposes. PJM also noted that “state programs intended to support new generation entry through out-of-market payments to the generator” — like those developed by New Jersey and Maryland— had the potential to “raise the price-suppression concerns that MOPR-type provisions are intended to address.” (Id.)

The reforms PJM proposed differed somewhat from the changes P3 suggested, however. PJM adopted P3’s recommendations that the MOPR be amended to eliminate the impact screen and the net-short requirement, and “to clarify that self-supply offers are subject to the MOPR.” (Id. at 411). According to PJM, self-supply offers were never intended to be exempt from the MOPR, and the additional screens made the MOPR too lenient and “too easily gamed”. (Id. at 406) PJM also accepted, with some significant changes, P3’s proposals that the state-mandated exemption be eliminated, that the conduct screen threshold be increased, and that a resource be required to clear an auction before becoming exempt from the MOPR. Specifically, (1) rather than simply eliminating the state-mandated exemption, PJM proposed to amend the MOPR to provide that a resource that failed the conduct screen could, via a § 206 filing, justify the state program to FERC and seek an individual exemption from the MOPR; (2) PJM agreed to increase the conduct screen threshold to 90% of the estimated net CONE, rather than to 100% of that value, as proposed by P3, explaining that net CONE “is merely an estimate,” and that “[a] 90% factor strikes the right balance” between granting some wiggle room for slightly below-CONE offers and minimizing “the risk that a seller can evade the MOPR and use a below-cost price to suppress clearing prices for all sellers.” (Id. at 401-02); (3) PJM agreed that a new resource should have to actually clear an auction, and not merely participate in one, to become exempt from the MOPR in future auctions. PJM went further than P3 requested, however, proposing that a resource be required to clear three times before becoming exempt, rather than merely twice. The only P3 proposal that PJM rejected in its entirety was P3’s proposed “No-Subsidy Off-Ramp,” by which any new resource could avoid the MOPR by affirming that its sponsor had not received an out-of-market subsidy.

PJM also incorporated several changes to the MOPR that P3 had not suggested. First, it added wind and solar resources to the list of resources that would always be exempt from the MOPR, and thus could offer their capacity at prices as low as zero. As a result of those additions, the MOPR would only apply to new gas-fired facilities. Second, PJM explained for the first time how an offer that fails the MOPR can nonetheless avoid mitigation by demonstrating to FERC under § 206 that the MOPR screen is unjust and unreasonable “as applied to its specific costs and its specific revenue expectations.” (Id. at 404)

Third, PJM clarified and amended the method used to determine the estimated net CONE for each LDA. Relevant here, it defined the method for calculating “energy and ancillary services offsets” to be used in determining the MOPR trigger threshold for a new resource. 14 Under the existing guidelines used to construct the VRR Curve, “PJM associate^] the gross CONE in [an LDA] ... with the energy revenues calculated for a zone within that area.” (Id. at 400) PJM proposed an approach similar to this methodology with one adjustment. Instead of basing revenues on the zone in which a generic “reference resource” was located — the method used in the VRR Curve guidelines — PJM would instead use the revenues earned by resources in the highest-earning “zone” within the LDA. In other words, all new resources in a given LDA would be presumed to have the same earning potential as the highest-earning generators in the LDA. PJM was concerned that, if the presumed location of a “reference resource” were used to determine energy and ancillary services revenues, a new entrant might “fail the MOPR screen merely because it is located in a zone with higher [marginal prices] than the zone in which the hypothetical reference resource was assumed to be built.” (Joint App. 400) PJM therefore erred on the side of allowing more resources to avoid mitigation. PJM also provided that those prices would be based on the prices for energy in the “real-time” energy market, as opposed to the “day-ahead” market.

PJM’s tariff revisions prompted numerous comments, protests, answers, and cross-answers from interested parties. Several states and LSEs argued that “eliminating the state-mandated exemption and other related MOPR conditions would transform [the capacity auctions] from a residual market into the primary market for securing new capacity,” and would im-permissibly interfere with legitimate state policies. (Petitioners/Cross Respondents’ Joint Statements 17-18) Similarly, several municipal and rural cooperative utility companies “protested that eliminating automatic clearance for self-supply resources would undermine their traditional business models.” (Id. at 18) PJM responded to those protests in two filings with FERC in March of 2011, but it did not propose any furthér revisions to the MOPR.

C. FERC’s MOPR Orders

On April 12, 2011, FERC issued the April 12 Order, accepting, with some modifications, PJM’s revised tariff as “just and reasonable.” 135 FERC ¶ 61,022 (2011). FERC agreed with PJM that it was just and reasonable to: (1) calculate energy and ancillary services revenues in the man ner PJM proposed (using real-time energy-prices and the highest-priced zones within an LDA); (2) raise the conduct screen to 90% of the estimated net CONE; (3) eliminate the net-short screen and the impact screen; (4) add exemptions for wind and solar generation resources; and (5) clarify that self-supply resources are subject to the MOPR. FERC disagreed, however, with three components of the revised MOPR: (1) the method by which a resource can obtain an individual exemption to the MOPR; (2) the replacement for the state-mandated exemption; and (3) the number of auctions a resource must clear before becoming exempt from the MOPR.

With regard to individual exemptions to the MOPR, FERC found unjust and unreasonable PJM’s proposal to require parties to submit at the outset a § 206 filing with FERC to demonstrate that a sell offer was consistent with the project’s costs. FERC agreed that offers that were in fact competitive and cost-based should not be mitigated, but it found unreasonable the “complex and lengthy litigation” that could result from the § 206 review process. Instead, FERC directed PJM to modify the tariff to provide that PJM and its Independent Market Monitor would review such cost justifications. 15 Put more simply, FERC wanted PJM, not FERC, to conduct the review process. FERC concluded that, with the unit-specific cost review process in place, P3’s proposed “No-Subsidy Off-Ramp” was unnecessary.

As for the state-mandated exemption, FERC agreed in part with PJM, concluding that the exemption needed to be eliminated due to “mounting evidence of risk from what was previously only a theoretical weakness in the MOPR rules,” namely, that state-subsidized resources would suppress auction prices. April 12 Order ¶ 139 (Joint App. 66). FERC disagreed with PJM’s proposed replacement mechanism, however. Specifically, it declined to adopt a formal process for a state to justify its initiative and thus obtain an exemption from the MOPR. FERC explained that states, like all parties, were free to file for an exemption from the MOPR under § 206. But FERC concluded that there was no need for a review process like the one PJM had proposed, which would have balanced the state’s interests against the adverse price effects of below-cost offers, because “there is no valid state interest” in ensuring that uneconomic offers would clear the auction. Id. at ¶ 142 (Joint App. 68). Accordingly, FERC declined to ac- ' cord states an opportunity to justify their initiatives on policy grounds, instead removing the state exemption and requiring them to submit cost-based offers like other entrants or suffer the consequences of mitigation.

Finally, FERC rejected PJM’s proposal that the MOPR be applied to a given resource until that resource has cleared the auction three times. Instead, FERC concluded that the MOPR should apply only until a resource clears an auction once, because by clearing one auction “the resource demonstrates that its capacity is needed by the market at a price near its full entry cost....” Id. at ¶ 176 (Joint App. 76). In so concluding, FERC partially adopted a recommendation submitted by the Independent Market Monitor. FERC rejected the second component of the Independent Market Monitor’s proposal, however, which would have continued to impose the MOPR in later auctions unless the resource could “show it is not receiving discriminatory subsidies.” Id. at ¶ 177 (Joint App. 77). FERC declined to adopt that requirement because “even if discriminatory subsidies are being received, if the resource is needed at the MOPR bid then it is a competitive resource and should be permitted to participate in the auction regardless of whether it also receives a subsidy.” Id. On May 12, 2011, PJM submitted a compliance filing that responded to FERC’s instructions in the April 12 Order.

Following FERC’s ruling, numerous parties sought rehearing. In response to those requests, FERC convened a technical conference on July 28, 2011, to explore the issues raised on rehearing, specifically on issues regarding the MOPR’s applicability to self-supply. After the technical conference, parties submitted formal comments for FERC to consider.

On November 17, 2011, FERC issued an “Order on Compliance Filing, Rehearing, and Technical Conference.” 137 FERC ¶ 61,145 (November 17, 2011) [hereinafter, “November 17 Order”]. Although that order slightly modified some of the revisions approved in its April 12 Order, FERC did not change its fundamental position on any of the issues relevant to this appeal. Rather, it reaffirmed its commitment to its initial reaction to the revised tariff, explaining that, although the capacity auctions had generally been successful since their adoption, the MOPR had to be amended to prevent “subsidized entry supported by one state’s or locality’s policies” from “disrupting the competitive price signals [the auction] is designed to pro-duee....” November 17 Order ¶3 (Joint App. 105-06). FERC emphasized that offers that fail the conduct screen (that is, appear to be below-cost) have two options for avoiding mitigation: they can appeal to PJM through the unit-specific cost justification process or they can seek an exemption from FERC by using § 206 of the FPA. FERC further explained that if an LSE does not want to be subject to the MOPR at all, it can utilize the FRR option. FERC therefore continued to find the majority of the revisions approved in the April 12 Order “just and reasonable.”

Several parties sought rehearing of FERC’s November 17 Order, which FERC denied on March 15, 2012. See “Order on Rehearing”, PJM Interconnection, LLC, 138 FERC ¶ 61,194 (March 15, 2012) [hereinafter “March 15 Order”].

D. Petitions for Review

Numerous parties have timely petitioned for review of the 2011 Orders. 16 Specifically, Petitioners in this appeal are the New Jersey Board of Public Utilities and the New Jersey Division of Rate Counsel (collectively, “New Jersey”), the Maryland Public Service Commission (“Maryland”), a group of governmentally-owned utilities and rural cooperative utilities referred to as the “Load Petitioners” 17 , and Hess Corporation (“Hess”). Intervening on those Petitioners’ behalf is CPY Power Development, Inc., which is the parent corporation of two companies that have received contracts from New Jersey and Maryland to build new generation resources. In addition, P3 has filed a cross-petition challeng ing various aspects of the Orders. A group of energy generation companies has also intervened on Cross-Petitioners’ behalf. 18 Both PJM and FirstEnergy Solutions Corp., another energy provider (“FirstEnergy”) have intervened on FERC’s behalf.

As discussed infra, Petitioners and Cross-Petitioners challenge different provisions of the MOPR. Petitioners take issue with: (1) the elimination of the exemption for state-mandated resources; (2) FERC’s decision that the MOPR did not provide for automatic clearance for self-supply offers; and (3) the addition of solar and wind-powered generators to the list of resources that are exempt from the MOPR.

Cross-Petitioners, on the other hand, challenge: (1) the policy of basing the calculation for energy and ancillary services offsets on the zone with the highest revenues; and (2) the policy of exempting resources from the MOPR once they have cleared only one capacity auction.

Cross-Petitioners’ Petition for Review originally challenged three additional components of the revised MOPR: (1) the decision to set the conduct screen at 90% of estimated net CONE, rather than 100%; (2) the use of real-time prices, rather than day-ahead prices, in calculating energy and ancillary services offsets; and (3) the rejection of the “No-Subsidy Off-Ramp” proposal. Since this petition was filed, however, FERC has further altered the MOPR to effectively adopt P3’s positions on these issues. 19 After determining that the existence of these provisions did not cause any economic harm to them in the 2011 and 2012 annual auctions, P3 no longer seeks redress on these points.

In addition to these changes, in a May 2, 2013 Order [hereinafter, the “2013 Order”], FERC also provided, for the first time, a limited exemption from MOPR mitigation for resources designated as self-supply. Rather than merely providing for guaranteed clearing for self-supply resources, which Load Petitioners argue existed under the 2006 MOPR, FERC’s 2013 Order finds just and reasonable PJM’s proposal to completely exempt self-supply from mitigation, subject to net-short and net-long tests. 20 In other words, if a sponsor LSE introduces new self-supply but can demonstrate that it is not a net buyer of capacity (and therefore does not have an incentive to artificially lower the clearing price), the self-supply will be exempt from mitigation under the MOPR. This new rule, in essence, enables self-supply resources to be “price-takers”, ie., new self-supply resources may be entered into the auction at artificially low costs, with the expectation that they not be the most cost ly offer, and therefore will not set the clearing price. Rather, they will take whatever clearing price results from the auction. It does not appear that the Load Petitioners have sought rehearing on this issue.

IV.

This Court reviews FERC Orders under § 313(b) of the FPA, 16 U.S.C. § 8252(b) and § 10(e) of the Administrative Procedure Act (APA), 5 U.S.C. § 706(2). Under the FPA, FERC’s factual findings are determinative as long as they are supported by substantial evidence. 16 U.S.C. § 825Z(b). The “substantial evidence” standard “ ‘requires more than a scintilla, but can be satisfied by something less than a preponderance of the evidence.’ ” La. PSC v. FERC, 522 F.3d 378, 395 (D.C.Cir. 2008); accord Mars Home for Youth v. NLRB, 666 F.3d 850, 853 (3d Cir.2011) (“Substantial evidence is more than a mere scintilla. It means such relevant evidence as a reasonable mind might accept as adequate to support a conclusion.” (internal citation and quotation marks omitted)). If the evidence is susceptible to more than one rational interpretation, we must uphold the agency’s determination. Fla. Mun. Power Agency v. FERC, 315 F.3d 362, 368 (D.C.Cir.2003) (“The question we must answer ... is not whether record evidence supports [petitioner]^ version of events, but whether it supports FERC’s.”).

In reviewing FERC’s orders, the Court must determine “whether a rational basis exists for a conclusion, whether there has been an abuse of discretion, or ... whether the Commission’s order is arbitrary or capricious or not in accordance with the purpose of the [FPA].” Cities of Newark v. FERC, 763 F.2d 533, 545 (3d Cir.1985) (internal quotation marks omitted). “ ‘We affirm the Commission’s orders so long as FERC examined the relevant data and articulated a rational connection between the facts found and the choice made.’ ” Sacramento Mun. Util. Dist. v. FERC, 616 F.3d 520, 528 (D.C.Cir.2010) (quoting Alcoa Inc. v. FERC, 564 F.3d 1342, 1347 (D.C.Cir.2009) (internal alterations omitted)). FERC’s decisions regarding wholesale rate issues are entitled to broad deference. See Morgan Stanley Capital Grp., Inc. v. Public Util. Dist. No. 1, 554 U.S. 527, 532, 128 S.Ct. 2733, 171 L.Ed.2d 607 (2008) (“The statutory requirement that rates be ‘just and reasonable’ is obviously incapable of precise judicial definition, and we afford great deference to the Commission in its rate decisions.”); Md. Pub. Serv. Comm’n v. FERC, 632 F.3d 1283, 1286 (D.C.Cir.2011) (“[Because issues of rate design are fairly technical and, insofar as they are not technical, involve policy judgments that lie at the core of the regulatory mission, our review of whether a particular rate design is just and reasonable is highly deferential.” (internal quotation marks and citations omitted)); see also N. Penn. Gas Co. v. FERC, 707 F.2d 763, 766 (3d Cir.1983) (FERC’s exercise of its expertise carries “a presumption of validity”).

Under § 205 of the FPA, 16 U.S.C. § 824d, public utilities may change their rates unilaterally, upon 60 days’ notice to FERC, which then reviews the changed rates to ensure that they are “just and reasonable.” It is not necessary, in a filing pursuant to § 205, that FERC find that the previous rate was unjust or unreasonable. See Atl. City Elec. Co. v. FERC, 295 F.3d 1, 9-10 (D.C.Cir.2002) (with respect to a filing under § 205, “FERC plays ‘an essentially passive and reactive role.’ ”) (quoting City of Winnfield v. FERC, 744 F.2d 871, 876 (D.C.Cir.1984)). In contrast, under § 206, FERC may change a rate in response to a com plaint or on its own motion, only if the moving party demonstrates that the existing rate is unjust and unreasonable and the proposed alternative is just and reasonable. 16 U.S.C. § 824e.

A. Petitioners’ Arguments

1. The Elimination of the Exemption for State-Mandated Resources

State Petitioners’ attack on the elimination of the exemption for state-mandated resources contains two overarching arguments: (1) that the MOPR changes amount to direct regulation of generating facilities, which FERC is prohibited from doing under § 201 of the FPA; and (2) that FERC erred in approving PJM’s elimination of the state-mandated exemption as just and reasonable by failing to sufficiently explain its reasons for departing from the 2006 Order, which arbitrarily and capriciously denies the exception upon which they had relied. We address each of these in turn.

a. FERC’s Jurisdiction

New Jersey Petitioners urge that, by eliminating the state-mandated exemption, FERC effectively attempts to substitute its own power supply preferences for those of the states and LSEs in violation of § 201 of the FPA, which provides that states retain authority over “facilities used for the generation of electric energy”. See 16 U.S.C. § 824(b)(1). New Jersey asserts that FERC’s elimination of the state-mandated exemption thus goes “beyond protecting the wholesale rates against the effects of’ the entry of uneconomic resources, and instead “seeks to prevent the entry itself.” N.J. Br. 24. Relatedly, New Jersey argues that in mandating that state-sponsored capacity resources clear based on cost and cost alone, FERC has usurped the state’s right to rely on integrated resource planning. The state argues that cost should not be the only permissible consideration in choosing among capacity suppliers because “[technology and fuel diversity are essential to ensuring that customers avoid both price and reliability risks from over-dependence on a single supply input.” N.J. Reply Br. 4-5.

FERC responds that the FPA bestows on it broad authority over rules affecting wholesale rates. It argues that courts have consistently upheld its jurisdiction over its “regulation of capacity markets, including charges, requirements, and market rules, as practices ‘affecting’ rates.... ” FERC Br. 40. In the FERC Orders at issue in this action, FERC repeatedly asserts jurisdiction to review PJM’s proposed change to the state-mandated exemption as a rule affecting prices paid for energy in interstate commerce. See, e.g., April 12 Order ¶ 143 (Joint App. 68) (“Because below-cost entry suppresses capacity prices and because the Commission has exclusive jurisdiction over wholesale rates, the deterrence of uneconomic entry falls within the Commission’s jurisdiction, and we are statutorily mandated to protect the RPM against the effects of such entry.”); November 17 Order ¶ 89 (Joint App. 130) (“[T]he MOPR does not interfere with states or localities that, for policy reasons, seek to provide assistance for new capacity entry if they believe such expenditures are appropriate for then-state. We seek only to ensure the reasonableness of the wholesale, inter-state prices determined in the markets PJM administers.”).

Under the APA, we are charged with reviewing whether an agency action is “in excess of statutory jurisdiction, authority, or limitations, or short of statutory right”. 5 U.S.C. § 706(2)(C). The Supreme Court recently confirmed that an agency’s assertion of jurisdiction is entitled to Chevron deference. See City of Arling ton v. FCC, 569 U.S. —, 133 S.Ct. 1863, 1868-69, — L.Ed.2d — (2013).

After reviewing the FERC Orders at issue here and the relevant case law, we conclude that FERC did not exceed its jurisdiction in eliminating the state-mandated provision. Under the FPA, FERC has jurisdiction over rules affecting the rates of the transmission or sale of energy in interstate commerce. See 16 U.S.C. § 824d. Here, it is undisputed that New Jersey and Maryland’s plans to introduce thousands of megawatts of new capacity into the Base Residual Auction would have had an effect on the prices of wholesale electric capacity in interstate commerce. See Mississippi Power & Light Co. v. Mississippi, 487 U.S. 354, 374, 108 S.Ct. 2428, 101 L.Ed.2d 322 (1988) (holding, among other things, that FERC had jurisdiction over power allocations that affect wholesale rates, and stating that “[sjtates may not regulate in areas where FERC has properly exercised its jurisdiction to determine just and reasonable wholesale rates or to insure that agreements affecting wholesale rates are reasonable.”) (emphasis added); Municipalities of Groton v. FERC, 587 F.2d 1296, 1302 (D.C.Cir.1978) (rejecting jurisdictional challenge to FERC’s authority to levy deficiency charges on utilities that failed to procure generating capacity sufficient to meet its load requirements, and stating that, “[i]t is sufficient for jurisdictional purposes that the deficiency charge affects the fee that a participant pays for power and reserve service, irrespective of the objective underlying that charge.”).

In Connecticut Department of Utility Control v. FERC, 569 F.3d 477 (D.C.Cir.2009), the Court of Appeals for the D.C. Circuit rejected a similar argument to the one New Jersey makes here with respect to the New England capacity market. In that case, the Connecticut Department of Public Utility Control (“DPUC”) challenged FERC’s authority to require it to obtain specific amounts of capacity and to adjust resource offer prices to levels where the supply of available capacity meets the pre-determined demand. Id. at 480. 21 The Connecticut DPUC argued that any movement upward in the capacity requirement mandated by the New England-area RTO amounted to a requirement that LSEs install new capacity, and therefore contravened Section 201 of the FPA, which states that FERC “shall not have jurisdiction ... over facilities used for the generation of electric energy.” Id. at 481 (internal quotation marks omitted) (alteration in original) (citing 16 U.S.C. § 824(b)(1)).

The court rejected Connecticut DPUC’s claim that FERC’s approval of the capacity requirement imposed by the ISO-NE (the New England area’s equivalent to PJM) amounted to direct regulation of generation facilities. First, the court pointed out that the mechanism did not actually require the installation of additional capacity at all; rather, it merely set a peak demand estimate, and employed market forces to locate a price at which market incentives were sufficient to meet that demand. Id. at 481-82. State and local authorities retained control over their power plants, including, among other things, forbidding new entrants from providing new capacity, limiting new construction, and requiring retirement of existing generators, without interference from FERC. Id. at 481. However, states were still required to shoulder the economic consequences of their choices — decisions to limit the amount of capacity in the market in turn affected the market clearing price for capacity. Id.

In addition, the court pointed out that FERC was not seeking to impose a capacity requirement at all. Rather, FERC was merely seeking to “ensure that the capacity charges actually imposed by ISO-NE are fair to suppliers and consumers. That reasonable concerns about system adequacy might factor into the fairness of those charges is precisely what brings them within the heartland of [FERC’s] jurisdiction.” Id. at 483. In other words, FERC had the duty to ensure that the mechanism employed by the ISO-NE to determine the clearing price would yield rates that were just and reasonable. Because ISO-NE’s preferred mechanism employed a capacity requirement, FERC was within its jurisdiction in reviewing and approving that capacity requirement.

New Jersey attempts to distinguish Connecticut Department of Utility Control, urging that, in that case, FERC “did not seek to dictate which resources LSEs used to fulfill their capacity obligations,” N.J. Br. 26 (emphasis in original), while here, FERC is preventing New Jersey from using the resources it has chosen to promote. But FERC is doing no such thing. The states may use any resource they wish to secure the capacity they need. The elimination of the state-mandated exemption means only that if the states wish to use a new generation resource to satisfy their capacity obligations required under the Reliability Pricing Model, the resource must clear the Base Residual Auction at or near its net cost of new entry. Such a requirement ensures that the new resource is economical — i.e., that it is needed by the market — and ensures that its sponsor cannot exercise market power by introducing a new resource into the auction at a price that does not reflect its costs and that has the effect of lowering the auction clearing price. Furthermore, even if the states’ preferred generation resources fail to clear the auction, the states are free to use them anyway; the only caveat is that the states cannot use the resources to offset their capacity obligations in the RPM, as such obligations can only be satisfied by resources that are demanded by the capacity market at a price reflecting their cost. Thus, as in Connecticut Department of Utility Control, New Jersey and Maryland are free to make their own decisions regarding how to satisfy their capacity needs, but they “will appropriately bear the costs of [those] decisions],” id. at 481, including possibly having to pay twice for capacity. 22

FERC’s enumerated reasons for approving the elimination of the state-mandated exception relate directly to the wholesale price for capacity, which is squarely, and indeed exclusively, within FERC’s jurisdiction. See id. at 484 (“Where capacity decisions about an interconnected bulk power system affect FERC-jurisdictional transmission rates for that system without directly implicating generation facilities, they come within the Commission’s author ity.”). 23 New Jersey Petitioners argue that, unlike in Connecticut DPUC, “FERC here interferes directly and materially with state efforts to sponsor new capacity resources precisely because those efforts could affect market prices.” N.J. Reply Br. 15. New Jersey Petitioners are wrong; what FERC has actually done here is permit states to develop whatever capacity resources they wish, and to use those resources to any extent that they wish, while approving rules that prevent the state’s choices from adversely affecting wholesale capacity rates. 24 Such action falls squarely within FERC’s jurisdiction.

b. Whether the Elimination of the State-mandated Exemption was Arbitrary and Capricious

Having concluded that accepting PJM’s elimination of the state-mandated exemption was within FERC’s jurisdiction, we now turn to whether the agency has adequately justified its reasoning for rescinding the exemption it previously deemed “just and reasonable” at the very moment states began to make use of it.

As an initial matter, New Jersey claims a procedural defect in FERC’s elimination of the state-mandated exemption. New Jersey urges that FERC improperly eliminated the exemption as part of its review process under the guise of § 205, whereas this effected a change that could only be accomplished under § 206 based on a finding that the prior provision was “unjust and unreasonable.” Because PJM did not actually propose to eliminate the exemption entirely — but just made it subject to FERC review — New Jersey urges, FERC could not accept one part without the other.

FERC responds that it was correct in applying the § 205 “just and reasonable” standard to each part of PJM’s proposal— both the elimination of the existing exemption and PJM’s proposed replacement mechanism — and was therefore entitled to accept the former and reject the latter. Moreover, the elimination of PJM’s provision for FERC to assess the adequacy of a state’s procedures was inconsequential since the right to petition the Commission under § 206 for an exemption from the rules was preserved in any event as a statutory right. We agree with FERC because the agency’s refusal to adopt PJM’s replacement mechanism does not limit states in any way that they would not otherwise be limited if FERC had accepted PJM’s proposal in full. But in any case, we need not decide whether FERC is entitled to parse a particular proposal contained in a tariff filing and analyze each part under § 205’s “just and reasonable” standard because, as we explain below, we hold that FERC acted reasonably in eliminating the state-mandated exemption under either § 205 or § 206.

New Jersey and Maryland strenuously object to the elimination of the state-mandated exemption as arbitrary and capricious and an unjustified departure from the terms of the 2006 settlement that created the Reliability Pricing Model. New Jersey insists that “fostering development of the selected [state-mandated] resources would address New Jersey’s reliability concerns while furthering the state’s environmental and economic goals.” N.J. Br. 6; see also Md. Br. at 6 (“[T]he Maryland PSC submitted extensive, uncontested evidence” regarding the state’s “serious and significant longterm reliability needs.... ”). It is necessary, the states argue, that these new resources be offered into PJM’s auction at below-cost prices to ensure that they will clear. New Jersey Petitioners claim that the new, gas-fired resources it seeks to build are needed to address New Jersey’s capacity deficiency, and are “valuable enough to warrant long-term contracts even if the resources might not be — in the short run — the cheapest options available.” Id. at 8. In other words, the states acknowledge that then-selected resources might not be economic — that is, they might not be able to clear the PJM auction if offered at a price reflecting cost. Nevertheless, the states assert that the new capacity they seek to build is justified, arguing that new resources “are developed for many reasons, including meeting non-cost environmental, siting and infrastructure goals.” N.J. Reply Br. 13 n. 26; see also Md. Reply Br. 6 (“FERC’s refusal to consider ... non-cost factors ... constitutes arbitrary and capricious decision-making.”).

Despite its admission that the new generating plants it seeks to build may not be the lowest cost option, New Jersey persuasively argues that “every fact that FERC identifies as rendering the existing tariff unjust and unreasonable was present when FERC approved the state exemption.” N.J. Br. at 21. Though FERC cites the New Jersey and Maryland initiatives as evidence that the possibility of price suppression as a result of the state-mandated exemption was no longer merely “theoretical”, FERC does not explain why it failed initially to foresee that providing state-mandated resources with an exemption to the MOPR would lead states to structure their contracts in a way that would result in the suppression of clearing prices. 25

Though we are not unsympathetic to New Jersey’s and Maryland’s arguments that they reasonably relied on the availability of the state-mandated exemption in contracting for the construction of new capacity resources, we find no fault with FERC’s ability to, and reasons for, eliminating the state-mandated exemption. Courts have repeatedly held that an agency may alter its policies despite the absence of a change in circumstances. See Motor Vehicle Mfrs. Ass’n of United States, Inc. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 57, 103 S.Ct. 2856, 77 L.Ed.2d 443 (1983) (“ ‘An agency’s view of what is in the public interest may change, either with or without a change in circumstances.’ ”) (quoting Greater Bos. Television Corp. v. FCC, 444 F.2d 841, 852 (D.C.Cir.1970)). Accordingly, in reviewing FERC’s action here, we ask only whether FERC’s factual conclusions were based on substantial evidence, whether, taking into account that evidence, each of the changes it made to the MOPR in its orders had a rational basis and were not arbitrary or capricious, and whether FERC adequately explained its reasoning. See Nat’l Cable & Telecomms. Ass’n v. FCC, 567 F.3d 659, 669 (D.C.Cir.2009) (“[T]he existence of contrary agency precedent gives us no more power than usual to question the Commission’s substantive determinations. We still ask only whether the Commission has adequately explained the reasons for its current action and whether those reasons themselves reflect a ‘clear error of judgment.’ ”) (quoting DIRECTV v. FCC, 110 F.3d 816, 826 (D.C.Cir.1997)). See also Elec. Consumers Res. Council v. FERC, 407 F.3d 1232, 1239 (D.C.Cir.2005) (court’s deference to FERC on complex rate market design “is based on the understanding that the Commission will monitor its experiment and review it accordingly.”).

With our limited scope of review in mind, we conclude that FERC sufficiently explained its reasoning for eliminating the state-mandated exemption as unjust and unreasonable. FERC’s decision rested mainly upon the “mounting evidence of risk” that the state-mandated exemption could permit uneconomic entry into the RPM capacity market. Such “mounting evidence” was sufficient, FERC said, to cause the agency to reconsider its prior approval of the exemption in the 2006 RPM settlement. See FERC Br. 50:

Thus, the actual prospect of thousands of megawatts of new generation, developed under arrangements that would explicitly subsidize the resources regardless of Auction price, potentially being offered into the Reliability Market at a zero bid brought into focus the distortive effect — no longer “theoretical” — that the state exemption could have on market prices for all capacity.

In the April 12 Order, FERC explained that “[bjecause below-cost entry suppresses capacity prices ... [it was] statutorily mandated to protect the RPM against the effects of such entry.” April 12 Order ¶ 143 (Joint App. 68). FERC further noted its agreement with its Independent Market Monitor that “permitting a state exemption may in fact, over the long run, result in less investment in capacity and demand-side resources and the need in the future for additional subsidies from the state.” November 17 Order ¶ 97 (Joint App. 132). In addition, FERC took into particular consideration the concern, as ex pressed by the Pennsylvania Public Utility Commission, that the state exemption could adversely affect other states that wished to rely on prices in the capacity market to incentivize new entry, as opposed to relying on state subsidies. See April 12 Order ¶ 142 (Joint App. 67-68); November 17 Order ¶ 96 (Joint App. 132). In sum, FERC noted that while its “intent [was] not to pass judgment on state and local policies and objectives with regard to the development of new capacity resources, or unreasonably interfere with those objectives”, the agency was “forced to act, however, when subsidized entry supported by one state’s or locality’s policies has the effect of disrupting the competitive price signals that PJM’s RPM is designed to produce, and that PJM as a whole, including other states, rely on to attract sufficient capacity.” November 17 Order ¶ 3 (Joint App. 106).

In addition, FERC adequately responded to various arguments against eliminating the exemption. In response to arguments from New Jersey and Maryland that eliminating the state exemption would do away with a state’s bargained-for ability to generate resources the state believed the RPM process had failed to provide, FERC noted that “any state is free to seek an exemption from the MOPR under section 206,” if it believes that the resources available through RPM are not adequately fulfilling its capacity needs. See April 12 Order ¶ 143 (Joint App. 68). FERC opined that the states’ right to petition for an individual exemption under § 206 preserved their ability to provide for new generation entry while avoiding interfering with FERC’s “duty under the FPA to assure just and reasonable rates in wholesale markets.” Id. In response to concerns about timing, FERC pointed out that states are free to file for an exemption under § 206 prior to initiating the process to select new resources. November 17 Order ¶ 99 (Joint App. 133). In response to arguments from various parties, including Petitioners in this case, that the RPM’s emphasis on cost alone ignored other important state objectives, including “environmental or technological goals, [and] reliability concerns beyond a three-year forecast,” FERC invited PJM stakeholders to propose a solution. See November 17 Order ¶ 90 (Joint App. 130): “If PJM market participants agree that RPM should account for resource attributes that reflect broader objectives than three-year forward reliability, then PJM and its stakeholders should begin a process to consider how to incorporate these features into RPM’s market design.” Id. However, FERC counseled that such solution must not “undermine the objective of RPM to procure the least-cost, competitively-priced combination of resources necessary to meet the region’s reliability objectives on a three-year forward basis.” Id.

We note briefly that our conclusion that FERC’s elimination of the state-mandated exemption was justified does not rely upon the existence or availability of the FRR alternative. In its Orders, FERC pointed out that states and LSEs “seeking full independence in resource procurement choices” could opt out of the RPM altogether through the FRR, and forego the opportunity to purchase or sell any capacity through the RPM market. See, e.g., April 12 Order ¶ 137 (Joint App. 65); id. at ¶ 193 (Joint App. 81) (“The FRR option is the alternative for load serving entities that wish to secure their own capacity resources outside of a competitive market, whether as directed by state-authorized integrated resource plans, or pursuant to other considerations.”). 26

In its briefing and throughout the record, FERC notes the existence of the FRR as an “alternative” to the Reliability Market in responding to states’ and LSEs’ concerns regarding the MOPR. Petitioners New Jersey and Maryland and the Load Petitioners all provide convincing evidence, however, that the FRR is not a viable alternative for them. 27 FERC does not counter this evidence; rather the agency merely responds that it never indicated that the FRR would be a “desirable or appropriate” alternative for all states or LSEs. See FERC Br. 39-40. We agree with Petitioners that the agency has given short shrift to their arguments that the FRR is simply not a feasible alternative for them. But Petitioners provide no authority for the proposition that FERC is actually required, to provide states and LSEs wishing to purchase or sell capacity in interstate commerce with an alternative to the Reliability Market. Absent such authority, we cannot hold that the lack of a feasible alternative that would allow states and LSEs to avoid having their capacity sell offers mitigated is fatal to FERC’s Orders here.

FERC’s reasoning repeatedly refers to the economic harm that could result from the potential price suppression permitted by the state-mandated exemption. The agency explicitly cites the “mounting evidence of risk” that the state-mandated exemption “could allow uneconomic entry” to the RPM. April 12 Order ¶ 139 (Joint App. 66). Although it could easily be argued that this danger was foreseeable in 2006 when the MOPR was first approved, FERC has adequately advanced a rationale for its about-face — namely, that states were actually structuring contracts for the development of new resources in a way that would substantially suppress prices, threatening imminent economic harm. The speculation has become reality. As such, it cannot be said that FERC acted without substantial evidence.

It is more than mildly disturbing that, by endorsing a state-mandated exemption with perfectly predictable incentives, FERC would allow sovereign states and private parties to be drawn into making complex and costly investments, only to later pull the rug out from under those who were persuaded that the exemption was somehow real. That FERC has done so based on little more than the claim that the agency had an “ah ha” moment when foreseeable outcomes approached fruition only makes matters worse. Our power to rein in bureaucratic behavior like this is, however, constrained. The “arbitrary and capricious” standard of the APA is a high bar indeed, and many agency actions worthy of condemnation are not so deficient that they can be said to cross it. Such is the case here.

2. Automatic Clearance for Self-Supply

As noted supra, prior to the 2011 MOPR reforms at issue in this matter, PJM’s tariff provided that, in the Base Residual Auction, PJM would accept “first, all Sell Offers in their entirety designated as self-supply committed regardless of price; (ii) then, all Sell Offers of zero, prorating to the extent necessary, and (iii) then all remaining Sell Offers in order of the lowest price.... ” PJM Tariff Attachment DD, Section 5.14(h)(4) (emphasis in original). In its original § 206 filing with FERC, P3 construed this language in PJM’s tariff as providing a complete exemption from the MOPR for resources designated as self-supply. Accordingly, in its revised tariff filing, PJM proposed to delete this subsection. PJM claimed that in eliminating this language, it sought merely to “clarify” that self-supply offers were not exempted from the MOPR. April 12 Order ¶ 184 (Joint App. 78). FERC accepted this “clarification”, stating that it “agree[d] with PJM that its current tariff does not exempt resources that are planned to be self-supply from the MOPR and therefore agree[d] that the current revisions do not change the tariff.” Id. at ¶ 139 (Joint App. 80-81). Furthermore, FERC held, “even if this did constitute a change,” the agency “agree[d] with PJM that planned generation designated by a load serving entity as self-supply should be classified as a capacity resource and be subject to an offer floor based on its entry costs until it clears in the base residual auction.” Id. (Joint App. 81).

Load Petitioners take issue with FERC’s characterization of this as a “clarification”. Load Petitioners urge that FERC, in approving PJM’s change, has essentially set up a straw-man argument by considering and rejecting a complete exemption for self-supply from the MOPR. Load Petitioners argue that, by gearing its response to an argument that self supply investment should receive a complete exemption from the MOPR — an argument that Load Petitioners never made — FERC failed to address Load Petitioners’ real concerns regarding the elimination of guaranteed clearance for self-supply. 28 In doing so, Load Petitioners argue, FERC acted arbitrarily and capriciously, and without substantial evidence.

Indeed, FERC based much of its reasoning for accepting PJM’s elimination of this provision on economic arguments that assumed that the language as it previously existed might be interpreted to mean that such offers would not be subject to price mitigation. See April 12 Order ¶ 195 (Joint App. 81-82) (“[PJermitting new self-supply to compete as a price-taker in RPM impermissibly shifts the investment costs of self-supply to competitive supply by suppressing market clearing prices.... ”); November 17 Order ¶ 205 (Joint App. 163) (“[W]e reaffirm the Commission’s finding in the April 12 Order that a blanket, across-the-board MOPR exemption for re sources designated as self-supply would allow for an unacceptable opportunity to exercise buyer market power and thus could inhibit competitive investment.”)- 29

It was not until the Order on Rehearing that FERC addressed Load Petitioners’ arguments that the original MOPR guaranteed that self-supply would clear the auction, albeit at a potentially mitigated price. See March 15 Order ¶ 27 (Joint App. 192) (dismissing the “assertion that the Commission erred by not guaranteeing clearance for all self-supply sell offers that receive an adjusted, unit-specific offer floor.”). FERC asserted that guaranteed clearance for self-supply would not serve the goals of the MOPR, because “[sjimply receiving an adjusted unit-specific floor does not mean that the market requires that unit at the adjusted floor bid. Assuring every unit with an adjusted unit-specific floor that it will clear the market could result in PJM rejecting the offer from a less expensive unit that otherwise would have cleared.” March 15 Order ¶ 28 (Joint App. 193). Even while purporting to consider and reject these arguments, however, FERC’s Orders never actually addressed the plain language of the original MOPR, which unambiguously stated that, in Base Residual Auction, PJM must accept “first, all Sell Offers in their entirety designated as self-supply committed regardless of price ”. 30 In approving the removal of that provision, FERC eliminated guaranteed clearance for self-supply offers, fundamentally changing the MOPR’s treatment of self-supply, but barely acknowledging that it was making any change at all. One strains to accept such scant treatment as “reasoned analysis” sufficient to satisfy the demands of the APA. See State Farm, 463 U.S. at 57, 103 S.Ct. 2856 (“[A]n agency changing its course must supply a reasoned analysis” for the change) (internal quotation marks omitted); FCC v. Fox Television Stations, Inc., 556 U.S. 502, 515, 129 S.Ct. 1800, 173 L.Ed.2d 738 (2009) (requiring agencies to generally “display awareness” of a change in position); Nat’l Cable & Telecomms. Ass’n v. FCC, 567 F.3d at 667 (an agency departing from its prior position must “supplfyj a reasoned analysis ... showing that prior policies and standards are being deliberately changed, not casually ignored.”) (internal quotation marks and citations omitted); Greater Bos. Television, 444 F.2d at 852 (“[I]f an agency glosses over or swerves from prior precedents without discussion it may cross the line from the tolerably terse to the intolerably mute.”). 31

But while we have concerns about FERC’s decision-making process in this regard, we do not have jurisdiction to review its action, because while this petition was pending, FERC has again changed its stance on the proper treatment of self-supply, rendering the Load Petitioners’ challenge moot. As noted supra, FERC recently approved an exemption to the MOPR for self-supply resources. 143 FERC ¶ 61,090 (May 2, 2013). Specifically, it decided that “providing exemptions for resources properly designated as self-supply when they meet suitable [requirements] is reasonable.” Id. at ¶ 108. Although the Load Petitioners are not satisfied with the new exemption, PJM’s treatment of self-supply resources has fundamentally changed. Under the 2011 orders challenged here, self-supply offers received no special treatment, but rather were forced to compete at cost-based prices. Under the 2013 Order, such offers are exempt from mitigation entirely if they satisfy proposed “net-short” and “net-long” tests. Id. at ¶ 107. Indeed, in justifying its proposed change to FERC, PJM emphasized the importance of protecting “traditional business models” by exempting “projects developed as self-supply by municipals, cooperative utilities, and vertically integrated utilities operating under integrated resource plans developed under state-approved rules.” Id. at ¶ 81.

Such “a fundamental change in the state of affairs” renders our review of this issue moot. See Motor & Equip. Mfrs. Ass’n v. Nichols, 142 F.3d 449, 459 (D.C.Cir.1998). The Load Petitioners may still have complaints about PJM’s treatment of self-supply, but the nature of that treatment is completely different than it was under the challenged orders. “The old set of rules, which are the subject of this lawsuit, cannot be evaluated as if nothing has changed.” Nat'l Min. Ass’n v. U.S. Dept. of Interior, 251 F.3d 1007, 1011 (D.C.Cir.2001). Rather, because “[a] new system is now in place,” id., our review of the old system would merely be advisory, unless the Load Petitioners suffered a redressa-ble injury while the old system was in place. See Freeport-McMoRan Oil & Gas Co. v. FERC, 962 F.2d 45, 46 (D.C.Cir.1992) (concluding that a case was “plainly moot” because the challenged orders had been “superseded by a subsequent FERC order, and while the challenged orders were in effect petitioners suffered no injury this court can redress”). The record does not show any injury-in-fact that the Load Petitioners experienced during the 2011 and 2012 capacity auctions, and at oral argument the only possible injury they could point to was having to briefly negotiate with the Independent Market Monitor before their offered resources successfully cleared an auction. Although that negotiation may have been frustrating to the Load Petitioners, it does not amount to “a concrete and particularized invasion of a legally protected interest.” Motor & Equip., 142 F.3d at 457 (citing Lujan v. Defenders of Wildlife, 504 U.S. 555, 560, 112 S.Ct. 2130, 119 L.Ed.2d 351 (1992)). Therefore, as “interim ... events have completely and irrevocably eradicated the effects of the alleged violation,” id. at 459, we conclude that the Load Petitioners’ challenge to FERC’s treatment of self-supply resources is moot.

3. Undue Discrimination

a. Exemption for Solar and Wind Powered Resources

From its inception, the PJM Reliability Market has exempted from the MOPR nuclear, coal and hydroelectric generation, permitting those resources to bid zero-price offers into the Auction. In the 2011 Orders, FERC accepted PJM’s proposal to add wind and solar facilities to this list of exemptions. As a result, the only resources subject to the MOPR are natural gas-fired technologies. New Jersey, Hess Corporation, and Intervenor CPV Power urge that targeting only gas-fired resources for mitigation amounts to undue discrimination in violation of the FPA. They argue that “[b]elow-eost offers from gas, nuclear, hydroelectric, wind, or solar facilities all have the same ‘price suppression’ impacts”, N.J. Br. 28, and therefore, subjecting only gas-fired resources to the MOPR undermines the competitive goals FERC is purportedly trying to achieve.

New Jersey does not attempt to argue that FERC failed to justify its decision to apply the MOPR to gas-fired resources and not to other types of generation. The state admits that FERC “asserts that the characteristics of gas units make them more likely to be used as price suppression tools.” Id. at 28; see also id. at 29 (noting FERC’s recognition that gas units “are relatively large and can be developed quickly”). New Jersey merely asserts that those very characteristics make them useful in abating New Jersey’s energy crisis, and therefore are “useless in distinguishing legitimate from illegitimate intent.” Id. at 29.

FERC points out that the FPA prevents only “undue” discrimination, and that “according different treatment to different classes of entities ... does not amount to undue discrimination under the FPA when the classes are not similarly-situated.” November 17 Order ¶ 109 (Joint App. 135). In the April 12 Order, FERC set out its reasoning for sanctioning PJM’s proposal:

[Gas-fired generators] have the shortest development time to respond to capacity needs and thus are more efficient resources to suppress capacity prices. In addition, ... wind and solar resources are a poor choice if a developer’s primary purpose is to suppress capacity market prices. Due to the intermittent energy output of wind and solar resources, the capacity value of these resources is only a fraction of the nameplate capacity. This means that wind and solar resources would need to offer as much as eight times the nameplate capacity of a [gas-fired] resource in order to achieve the same price suppression effect.

April 12 Order at ¶ 153 (Joint App. 70); see also November 17 Order at ¶ 111 (Joint App. 136) (“In accepting PJM’s proposal to subject [gas-fired] resources to the MOPR, the Commission’s focus was on those factors that could contribute to price suppression.”). FERC also notes that gas-fired resources can be constructed within the three-year time frame between the auction and the time the resource must be put into use. Accordingly, the net incremental costs of a gas-fired resource at the time of the first auction in which it participates are near its full construction costs. Other resources, on the other hand, take longer to build and therefore must begin construction well in advance of entering the capacity market. By the time they participate in an auction, they have much lower incremental costs and would therefore have a minimum price floor substantially below full construction cost. In addition, the short build, time of gas-fired resources means that sponsors of such projects are able to offer bids which, if they do not clear, may be reassessed or abandoned, whereas other resources may already have invested significant capital by the time they are required to offer their capacity into the auction. For all of these reasons, FERC argues, the exempted resources are not similar to gas-fired resources; accordingly, the MOPR’s disparate treatment of the various types of capacity resources does not constitute undue discrimination.

In sum, FERC fully explained its reasons for approving PJM’s proposal to subject gas-fired resources to the MOPR while exempting other types of generation; New Jersey’s disagreement with FERC’s justification does not render the agency’s decision arbitrary and capricious.

b. Discrimination Against New Subsidized Entry

New Jersey also argues that the new unit-specific review process, which permits a seller to justify a sell offer below the MOPR trigger threshold based on the resource’s competitive cost advantages, permits undue discrimination based on the type of subsidy a resource receives. PJM provided examples of the types of “competitive cost advantages” it would view as legitimately lowering the offer price of a resource, including “costs resulting from the capacity market seller’s business model, financial condition, tax status, access to eapital[, ... and] net revenues that are reasonably demonstrated, under the MOPR, to be higher than estimated for the MOPR screen.” See November 17 Order ¶ 213 (Joint App. 166). In effect, PJM would “evaluate whether a subsidy, grant, or revenue is of the type customarily enjoyed by the type of seller at issue and whether the cost or revenue item preexisted RPM.” Id. at ¶245 (Joint App. 176). On the other hand, PJM would not view as legitimately lowering cost “claimed cost savings or revenue sources that appear irregular or anomalous, that do not reflect arm’s-length transactions, or that are not in the ordinary course of the seller’s business.” Id. at ¶ 213 (Joint App. 66). Presumably, the state initiatives in New Jersey and Maryland would fit into the latter category. New Jersey argues that this is unduly discriminatory, because “‘new’ and ‘customary’ subsidies do not differ in their effects” on competition. New Jersey asserts that FERC “wrongly treat[s] a subsidy’s vintage as indicating whether it was motivated to suppress RPM prices or to accomplish a legitimate purpose.” N.J. Br. 32.

Here again, FERC fully explained its reasons for permitting PJM, in administering the unit-specific review process, to view some methods of cost-savings differently from others. FERC notes that “the MOPR was not intended to change the long-standing business models parties use to support investment in specific capacity procurement projects.” November 17 Order ¶ 242 (Joint App. 175). FERC agreed with PJM that the unit-specific review process “appropriately recognizes varying long-standing business structures and practices [such as tax status, access to capital, and other advantages customarily enjoyed by that type of seller] while also protecting against attempts to exercise buyer market power.” Id. at ¶ 244 (Joint App. 175). In other words, FERC recognized the desire of generators to retain the cost-saving advantages they had traditionally enjoyed since before the RPM came into existence, and balanced this desire against the danger that some entities would provide “irregular and anomalous” subsidies not available to other resources in an attempt to exercise buyer market power. FERC’s asserted reason for this differing treatment is not arbitrary or capricious, and is consistent with its statutory duty to protect the integrity of the capacity markets.

B. Cross-Petitioners’Arguments

1. Calculation of Energy and Ancillary Services Offsets

PJM’s § 205 filing for the first time defined a method for calculating “energy and ancillary services offsets,” which are the expected revenues a new generation resource will likely earn from the sale of energy and ancillary services. These revenues are used to “offset”, ie., are subtracted from, a resource’s estimated construction costs to determine the resource’s net CONE — the higher the estimated revenues, the lower the net CONE, and therefore the lower the threshold used to determine whether a new resource will trigger the MOPR. Prior to the 2011 Orders, PJM’s tariff did not provide for any method for estimating energy and ancillary services offsets. In its § 205 filing, PJM proposed to calculate these offsets for a given resource based on the revenues earned by the highest-earning resources in the PJM zone where the resource is located. This calculation would, presumably, lead the resource to be assigned a lower net CONE and, consequently, a lower mitigation threshold.

P3 assails the “zonal” approach as unjust and unreasonable. It argues that the artificially low mitigation threshold “will ... permit uneconomic resources to enter, clear the Base Residual Auction and artificially suppress prices. This outcome is neither administratively necessary nor just, reasonable and non-discriminatory.” (Joint App. 1572) P3 argues that FERC instead should have directed PJM to calculate energy and ancillary services offsets using a “nodal” approach, which would base expected revenues on the actual location of the new resource. 32

FERC’s justification for finding PJM’s proposal just and reasonable is two-fold. First, FERC asserted that PJM’s proposed method for calculating revenues is consistent with the existing VRR Curve guidelines, which are used to construct the simulated demand curve used in PJM’s capacity auctions. See November 17 Order ¶ 30 (Joint App. 113) (“[W]e find that use of zonal LMPs, rather than nodal LMPs, for the MOPR screens is appropriate, given this methodology’s consistency with PJM’s existing VRR Curve guidelines.”). P3 asserts that this justification for using the zonal approach must be rejected because the zonal methodology is not actually the same as that used to construct the VRR curve, and notes that PJM itself described the zonal approach as an “adjustment” to the VRR Curve guidelines. See P3 Br. 48. FERC responds that it did not condition its approval on the new approach being identical to the VRR Curve guidelines; rather it noted that PJM’s proposed approach was “consistent” with the guidelines, and indeed it expressly approved PJM’s proposed “adjustment” from the guidelines’ approach. FERC Br. 81. Furthermore, FERC argues that P3 waived this argument by failing to raise it on rehearing. P3 disagrees that it waived the argument, stating that the April 12 Order did not sufficiently put P3 on notice that consistency with VRR Curve guidelines was a basis for FERC’s approval of the zonal approach, and therefore P3 could not have been expected to contest this rationale on rehearing.

We agree with P3 that FERC did not clearly tie the VRR Curve consistency justification to the zonal approach in the April 12 Order, and therefore P3’s argument is not waived. We further agree with P3 that the zonal approach appears to be no more “consistent” with the methodology used in the VRR Curve guidelines than P3’s proposed nodal approach. However, FERC advanced an additional rationale for finding PJM’s proposed zonal approach just and reasonable, and for rejecting P3’s preferred approach. Namely, FERC urged that “the use of nodal LMP values could trigger the market power screen even though the resource was simply using its historical energy and ancillary services revenues offset for its zone.” April 12 Order ¶ 47 (Joint App. 41). In other words, FERC agreed with PJM that the methodology for calculating energy and ancillary services offsets — a calculation that is, after all, merely an estimate— should make it easier, and not more difficult, for a resource to avoid mitigation.

P3 argues that structuring the calculation to permit more resources to pass the MOPR screens “is not a proper objective”. P3 Br. 45. However, P3 fails to explain why erring on the side of allowing more resources to avoid mitigation is not a permissible policy. Surely FERC is permitted to weigh the danger of price suppression against the counter-danger of over-mitigation, and determine where it wishes to strike the balance. See NRG Power Marketing, LLC v. FERC, 718 F.3d 947, 961 (D.C.Cir.2013) (declining to “review FERC’s balancing of competing interests”); Sacramento Mun. Util. Dist., 616 F.3d at 541-42 (upholding FERC’s tariff order where the agency “reflected on the competing interests at stake to explain why it struck the balance it did”).

P3 may be correct that basing energy and ancillary services offsets on a resource’s actual location results in a more accurate calculation of net CONE. However, the fact that there may be a better, or more accurate, calculation does not render PJM’s proposal unjust or unreasonable, or FERC’s approval of it arbitrary and capricious. FERC noted as much in its November 17 Order, stating that “[tjhere may be more than one method that provides a reasonably accurate forecast of future revenues over time. The relevant question here is whether PJM’s proposed method is likely to provide a reasonably accurate forecast.” 33 November 17 Order ¶ 28 (Joint App. 113). See ExxonMobil Gas Mktg. Co. v. FERC, 297 F.3d 1071, 1084 (D.C.Cir.2002) (“The burden is on the petitioners to show that the Commission’s choices are unreasonable and its chosen line of demarcation is not within a zone of reasonableness as distinct from the question of whether the line drawn by the Commission is precisely right.”) (internal quotation marks omitted); Serono Labs., Inc. v. Shalala, 158 F.3d 1313, 1321 (D.C.Cir.1998) (“[C]ourts are bound to uphold an agency interpretation as long as it is reasonable' — regardless of whether there may be other reasonable, or even more reasonable, views.”). FERC has articulated legitimate reasons for finding PJM’s preferred method for calculating energy and ancillary services offsets just and reasonable, and that is all that is required to do.

2. Single-Auction Clearance Requirement

Prior to the 2011 MOPR revisions, new resources were automatically exempt from mitigation after participating in, but not necessarily clearing, one auction. Asserting that such allowance “rendered the MOPR toothless,” P3 instead urges in its § 206 complaint that a new resource should be required to clear two annual auctions. See P3 Br. 49. In support of this position, P3 notes that such an approach would closely approximate FERC’s recently approved standard for the NYISO (the New York area equivalent of PJM). In its § 205 filing, PJM itself proposed an even stronger rule, by which the MOPR would apply to a new resource up to and including the second successive annual auction after a resource first clears. Finally, PJM’s Independent Market Monitor proposed a hybrid rule permitting a new resource to clear only one auction, as long as it also demonstrated that it was not receiving any out-of-market subsidies.

FERC did not accept any of these proposals in its entirety. Rather, FERC decided that a new resource would no longer be subject to mitigation after it cleared one auction at an offer price near its full cost of entry. FERC’s rationale was that a resource that has successfully cleared an auction at or near its cost is “needed” by the market and is therefore economic. It does not matter, FERC ruled, whether or not the resource later receives a subsidy.

P3 claims that FERC’s decision was arbitrary and capricious. First it argues that though FERC purported to be adopting the recommendation of the Independent Market Monitor, the agency in fact adopted only part of the Market Monitor’s recommendation (the one-auction requirement) while declining to adopt the other, key part: that the resource not receive any subsidies from outside the PJM market. P3 contends that “[t]hat cherry picking left FERC standing alone, adopting a proposal supported by no party, testimony, or evidence.” Id. at 51. Second, P3 argues that by allowing a resource to receive discriminatory subsidies after clearing only one auction, FERC is essentially sanctioning the exercise of buyer-side market power. Third, P3 asserts that FERC’s decision “departs, without reasoned explanation” from the rule it recently approved for the NYISO. Id. at 53. P3 cites testimony from its own expert, who urged that, because NYISO’s monthly auctions and PJM’s annual auction are both “driven by the requirement to meet peak demand in the summer”, NYISO’s rule is “directly analogous” to a two-year auction clearing rule. Id. at 54. 34 P3 argues that FERC’s application of a different standard for PJM than the one it applied for the NYISO represents a “ehang[e] in course,” and that FERC must supply a reasonable analysis for the differential treatment. See Motor Vehicle Mfrs. Ass’n, 463 U.S. at 57, 103 S.Ct. 2856.

FERC has adequately responded to P3’s arguments. First, as FERC points out, P3 does not provide any support for its suggestion that FERC must adopt a third party’s proposal in full in order to meet the “substantial evidence” standard. Under § 206, FERC may act on its own accord to change any practice that, in its opinion, renders a rate, charge or classification unjust, unreasonable, or discriminatory. 16 U.S.C. § 824e. In doing so, it is free to eschew the proposals of other parties and invoke its own expertise, as long as it does so in a manner that is not arbitrary or capricious. See EarthLink, Inc. v. FCC, 462 F.3d 1, 12 (D.C.Cir.2006) (“[A]n agency’s predictive judgments about areas that are within the agency’s field of discretion and expertise are entitled to particularly deferential review, as long as they are reasonable....”) (internal citations omitted) (alteration in original).

In the 2011 Orders, FERC described the reasons it chose to require a new capacity resource to clear one auction before escaping mitigation under the MOPR. Namely, FERC concluded that “once a new resource has cleared in one auction at the offer price floor, the resource has demonstrated that it is needed by the market and it is therefore economic.” See April 12 Order ¶ 175 (Joint App. 76). FERC believed that applying the MOPR after that point “could therefore inefficiently discourage the entry of a new capacity that is economic.” Id. Furthermore, FERC explained its reasons for declining to implement the other component of the Independent Market Monitor’s proposal because “even if discriminatory subsidies are being received, if the resource is needed at the MOPR bid then it is a competitive resource and should be permitted to participate in the auction regardless of whether it also receives a subsidy.” Id. at ¶ 177 (Joint App. 77). 35 FERC further addressed P3’s arguments at length in the November 17 Order. See November 17 Order ¶¶ 130-133 (examining how P3’s proposal would function under various market conditions and concluding that clearing in one auction at a price approximating its full cost of entry demonstrates that a new resource is needed by the market and should not be subject to further mitigation). See Tenn. Gas Pipeline Co. v. FERC, 400 F.3d 23, 27 (D.C.Cir.2005) (“The court properly defers to policy determinations invoking the Commission’s expertise in evaluating complex market conditions.”).

Nor was FERC required to replicate the standard it approved for NYISO. P3 offers no authority for the proposition that FERC must apply the same mitigation period for all RTOs under its jurisdiction; after all, under § 205, these organizations are largely tasked with coming up with their own rates, rules, and procedures, subject only to FERC’s determination that such rates, rules and procedures are “just and reasonable.” 16 U.S.C. § 824d. Indeed, the two RTOs employ substantially different auction processes— PJM’s capacity auctions are annual (or incremental), while NYISO holds auctions on a monthly basis. Accordingly, it would be impossible for FERC to apply the exact same mitigation rules (with respect to both mitigation period and number of auctions a resource is required to clear) in both regions. Nor do the decisions cited by P3 indicate that FERC’s approval of a different mitigation period for PJM than for NYISO would require remand. See P3 Br. 54. None involved an agency’s application of differing procedures in different regions, each with its own unique circumstances, and each largely tasked with formulating its own rules and procedures, subject only to the qualification that they be just and reasonable. 36

y.

For the foregoing reasons, we deny the petitions for review of the 2011 Orders.

1 . We have jurisdiction to review FERC’s orders under FPA § 313(b), 16 U.S.C. § 8251(b), which provides that, "[a]ny party to a proceeding under this chapter aggrieved by an order issued by the Commission in such proceeding may obtain a review of such order in the United States Court of Appeals for any circuit wherein the licensee or public utility to which the order relates is located or has its principal place of business, or in the United States Court of Appeals for the District of Columbia, by filing in such court, within sixty days after the order of the Commission upon the application for rehearing, a written petition praying that the order of the Commission be modified or set aside in whole or in part.” 16 U.S.C. § 8257(b). New Jersey, Maryland, Hess Corporation, and Load Petitioners filed petitions for review in this Court. Cross-Petitioners PJM Power Providers Group and PSEG Energy Resources & Trade, LLC (collectively, "P3”) filed petitions for review in the D.C. Circuit. On December 8, 2011, the U.S. Judicial Panel on Multidistrict Litigation consolidated all petitions for review in this Court.

2 . Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities and Recovery of Stranded Costs by Public Utilities, Order No. 888, FERC Stats. & Regs. Preambles ¶ 31,036 (1996), aff'd in relevant part, Transmission Access Policy Study Grp. v. FERC, 225 F.3d 667 (D.C.Cir.2000), aff'd sub nom., New York v. FERC, 535 U.S. 1, 122 S.Ct. 1012, 152 L.Ed.2d 47 (2002).

3 . See also Order Directing Submission of Information with Respect to Internal Processes for Reporting Trading Data, 103 FERC P61,-089, ¶ 11 (April 30, 2003) ("This Commission has a statutory obligation to ensure the justness and reasonableness of rates for wholesale electric power,.... In this regard, ... the Commission’s vision has been to ensure the delivery of dependable, affordable energy through reliance on sustained competitive markets rather than through a rigid adherence to strict-cost-of service principles.”).

4 . As discussed herein, some LSEs supply their own capacity — that is, they own their own generation resources, which they use to fulfill their capacity obligations. In order to have those resources counted toward their capacity obligations, however, the LSE must introduce them into the auction. See Initial Order on Reliability Pricing Model, 115 FERC ¶ 61,079, at ¶ 115 (Apr. 20, 2006) ("To prevent physical withholding, all existing generator capacity resources have a must offer requirement with regard to all unsold capacity. To encourage compliance with the must offer rule, generators that fail to comply in each auction will not be allowed to use its [sic] resource to satisfy any capacity requirement or receive any capacity payments in the Delivery Year.”).

5 . The price and amount of annual capacity needed for each LDA is set using the Variable Resource Requirement ("VRR'') Curve, which is a construct meant to mimic a demand curve that can show the price PJM expects to pay for capacity based on the amount of capacity available in the market. Under the VRR curve, the price for capacity will decrease as more supply enters the market, up until the point at which PJM's capacity objective is fully satisfied. To ensure reliability in the transmission system, there must be more capacity available than is generally needed by consumers. PJM thus artificially creates the demand for capacity, and it now does so via the VRR curve.

6 . The record indicates that the FRR was incorporated into the 2006 Order at the request of American Electric Power (AEP), one of the country's largest utilities, and AEP is the only utility that has used the FRR option in recent years.

7 . Technically, a monopolist is a single seller and a monopsonist is a single buyer, see Black’s Law Dictionary 1028 (8th ed.2004), but the terms are used loosely by the parties to mean, respectively, sellers and buyers who exercise disproportionate power in imperfectly competitive markets. More particularly, they use the term "monopsony” to mean net-buyers in the auction who sell into the auction at artificially low prices in order to depress the clearing price. We adopt that imprecise usage.

8 . Like the VRR Curve, the net CONE is an administrative construct. PJM arrives at the net CONE figure by estimating the costs needed to build a particular type of generation resource, and then deducting from those costs the estimated revenue the new unit would receive through sales of "energy and ancillary services”, discussed infra. In other words, the more revenue a new generator is expected to make through energy sales, the larger the amount deducted from the costs of developing the resource. For example, if a new resource costs $100 to build, and is expected to earn $25 in energy sales, its net CONE would be $75. The net CONE and the VRR Curve are also related concepts. As discussed supra, the VRR Curve is meant to demonstrate the change in expected capacity prices as the amount of capacity in the market increases. Those expected prices — the "y axis” for a curve — are determined by PJM’s estimate of the net CONE (the "x axis” being quantity of capacity).

9 .Capacity is measured in megawatt-days (MW-day) and bid into the RPM market as a dollar amount per megawatt-day. See PPL Energyplus, LLC v. Nazarian, 974 F.Supp.2d 790, 808-09, Civil Action No. MJG-12-1286, 2013 WL 5432346, at *13 (D.Md. Sept. 30, 2013).

10 . The original MOPR’s treatment of self-supply offers is a subject of some disagreement among the parties. FERC, PJM, and Cross-Petitioners P3 claim that the original MOPR was ambiguous as to whether there was an exemption for self-supply. The Load Petitioners, on the other hand, urge that the provision is clear — there was no exemption from mitigation, but all self-supply offers would clear the auction. We discuss this in detail infra.

11 . FERC disagrees that the RPM has failed to secure sufficient capacity in the PJM region. See, e.g., "Order on Compliance Filing, Rehearing, and Technical Conference”, 137 FERC ¶ 61,145 (November 17, 2011), ¶3 ("[T]he evidence before us suggests that RPM has in fact succeeded in securing sufficient capacity to meet reliability requirements for the PJM region.”). (Joint App. 105)

12 . We note that, since oral argument in this case, two federal district courts have issued decisions invalidating the New Jersey and Maryland initiatives on the ground that they seek to legislate or regulate wholesale prices for energy in interstate commerce, a field occupied exclusively by FERC, in violation of the Supremacy Clause. See generally PPL Energyplus, LLC v. Nazarian, supra; PPL Energy-Plus, LLC v. Hanna, 977 F.Supp.2d 372, Civil Action No. 11-745, 2013 WL 5603896 (D.N.J. Oct. 11, 2013). While we are mindful of the implications of these decisions on certain issues in this case, we deal here with the legality of actions taken by FERC, not of those taken by the states. Accordingly, we do not address those decisions.

13 . P3 is a nonprofit organization of PJM stakeholders consisting of Calpine Corporation; DPL Energy, LLC; Edison Mission Group; EquiPower Resources Corp.; Essential Power, LLC; Exelon Corp.; GDF SUEZ North America, Inc.; Homer City Generation, L.P.; NextEra Energy Resources, LLC; NRG Energy Inc.; PPL Corporation; and PSEG Energy Resources & Trade LLC (PSEG). It appears that P3 had a slightly different membership when it filed its initial complaint with FERC, see April 12 Order ¶ 2 n. 4 (Joint App. 27) (listing members of P3, some of which differ from the membership listed in P3's brief). However, no party has asserted that this apparent membership change has any relevance for purposes of our review. We further note that in its brief, despite listing PSEG as a member of P3 in its corporate disclosure statement, P3 at various points refers to "P3 and PSEG” as if they are distinct from one another. See, e.g., P3 Br. 2, 63. PSEG also filed its own petition for review separate from the other members of P3. However, because PSEG did not file a brief independently from the other members of P3, and because PSEG does not appear to make any independent arguments in addition to those made by P3, we assume for purposes of this opinion that PSEG is a member of P3.

14 . The original MOPR referred to energy and ancillary services offsets, but "never explained] how the energy and ancillary service revenues [would] be determined.” (Joint App. 399)

15 . Despite numerous references to the Independent Market Monitor in their briefing, the parties have not done the Court the favor of explaining the precise role of this entity. In-tervenor First Energy Solutions Corp. helpfully describes the Independent Market Monitor as "a neutral entity that monitors compliance with PJM’s market rules.” (FirstEnergy Br. 12)

16 . All Petitioners and Cross-Petitioners challenge the April 12 and November 17 Orders. Load Petitioners additionally challenge the March 15 Order.

17 . Specifically, the Load Petitioners are Old Dominion Electric Cooperative, American Public Power Association, National Rural Electric Cooperative Association, North Carolina Electric Membership Corporation, Delaware Municipal Electric Corporation, American Municipal Power, Inc., and Southern Maryland Electric Cooperative, Inc.

18 . Those companies are PPL Electric Utilities Corporation; PPL EnergyPlus, LLC; PPL Brunner Island, LLC; PPL Holtwood, LLC; PPL Martins Creek, LLC; PPL Mountour, LLC; PPL Susquehanna, LLC; Lower Mount Bethel Energy, LLC; PPL New Jersey Solar, LLC; PPL New Jersey Biogas, LLC; PPL Renewable Energy, LLC; and Electric Power Supply Association.

19 . See PJM Interconnection, LLC, 138 FERC ¶ 61,062, at Ml 17, 67, 144 (Jan. 30, 2012) (approving a change in methodology for calculating revenues to determine net CONE to consider day-ahead prices); PJM Interconnection, LLC, 143 FERC ¶ 61,090 (May 2, 2013), at ¶ 24 (approving PJM’s proposal to exempt from mitigation resources that do not receive out-of-market subsidies) and ¶¶ 183, 195 (approving PJM’s proposal to increase MOPR benchmark values to 100% of net CONE).

20 .Again, a "net-short” position "refers to the circumstance where an LSE owns and/or contracts for an amount of capacity ... that is less than its capacity needs....”. On the other hand, a "net-long" position "refers to the circumstance where an LSE owns or contracts for generation in excess of its capacity needs....” 2013 Order ¶ 25 n. 19.

21 . As in the instant matter, New England’s Forward Capacity Market, like the Reliability Market at issue here, was the result of a settlement among power system stakeholders. Connecticut DPUC, 569 F.3d at 481.

22 . New Jersey also cites Maine Public Utilities Commission v. FERC, 520 F.3d 464 (D.C.Cir.2008) for the point that FERC’s jurisdiction to approve the capacity requirements in the New England market depended on the fact that LSEs were free to satisfy their capacity obligations by building their own capacity or entering into long-term bilateral contracts. N.J. Reply Br. 11 n. 23. But there is no indication in Maine Public Utilities Commission that this was essential to FERC's jurisdiction in that case. Indeed, the court in Maine Public Utilities Commission noted that "[t]he protracted litigation over Must-Run agreements, the locational installed capacity market, and the Forward Market is fundamentally a dispute over the rates that will be paid to suppliers of' capacity”, a concern squarely within FERC’s jurisdiction. Me. PUC, 520 F.3d at 479.

23 . The remaining cases cited by New Jersey do not dictate otherwise. Pacific Gas & Electric Co. v. State Energy Resources Conservation & Development Commission, 461 U.S. 190, 103 S.Ct. 1713, 75 L.Ed.2d 752 (1983) dealt with a state’s authority to halt the construction of new nuclear plants for environmental reasons. While noting the multiple aspects of power generation over which states retained control, the Court specifically excepted "the broad authority of the ... Federal Energy Regulatory Commission, over the need for and pricing of electrical power transmitted in interstate commerce....” Id. at 205, 103 S.Ct. 1713. Nor is Otter Tail Power Co. v. Federal Power Commission, 473 F.2d 1253 (8th Cir.1973), helpful to New Jersey’s argument, as FERC is not requiring the state to enlarge its generating facilities or to purchase standby facilities. Finally, FERC's opinion in Ameren Energy Marketing Co., 96 FERC ¶ 61,-306 (Sept. 14, 2001) is in no way contrary to our holding here. In that opinion, FERC clarified that its previous order approving market-based rates in a contract for the sale of capacity between affiliates did not preclude the Missouri Public Service Commission from inquiring into the reasonableness of the public utility's decision to enter into the contract with its affiliate. The language in Ameren that "wholesale ratemaking does not, as a general matter, determine whether a purchaser has prudently chosen from among available supply options”, meant simply that FERC does not dictate the particular supplier from which a buyer must purchase capacity.

24 . Cross-Petitioners P3 urge that "affecting capacity rates is precisely what New Jersey and Maryland intended to do” with their state initiatives. See P3 Br. 66 and n. 16. It is not necessary for us to pass upon whether the states' intention was valid, as neither New Jersey nor Maryland contest that their initiatives would affect clearing prices in the base residual auction. The states’ intent is not relevant for purposes of FERC’s jurisdiction or the reasonableness of the agency’s actions. See November 17 Order ¶ 3 (Joint App. 105— 06) ("Our intent is not to pass judgment on state and local policies and objectives with regard to the development of new capacity resources or unreasonably interfere with those objectives. We are forced to act, however, when subsidized entry supported by one state’s or locality's policies has the effect of disrupting the competitive price signals that PJM’s RPM is designed to produce, and that PJM as a whole, including other states, rely on to attract sufficient capacity.”).

25 . When the original state exemption was adopted, P3 members raised the possibility that states would mandate new reliability projects that could reduce clearing prices far below cost and urged that the MOPR did not sufficiently address this problem. (Joint App. 2993) Opponents also discussed pending efforts by the state of Connecticut to procure new capacity, which was to be bid into New England’s capacity market at low, subsidized prices. (Id. at 2478-79) These facts demonstrate that FERC was aware of possible price suppression concerns relating to the state exemption, but nonetheless found PJM’s tariff, including the exemption, just and reasonable. {Id. at 2480-81)

26 . Exclusion from the RPM market for entities using the FRR option is necessary to ensure that sponsoring entities cannot take advantage of the market-based nature of the RPM while withholding its own supply sources. See April 12 Order ¶ 193 (Joint App. 81) ("To protect the integrity of PJM’s wholesale capacity markets under RPM ..., new self-supply seeking to participate in the RPM market must compete with other planned generation on the same competitive basis.”); see also P3 Br. 81 ("[I]f [the FRR] alternative were designed to require procurement of only a subset of the buyers' capacity needs, the buyer could segment its purchasing activities, reducing the volume of its purchase through RPM in order to reduce auction clearing prices, while using the FRR process for the remainder.”).

27 . As noted supra, Petitioners argue that, because it requires an LSE to demonstrate to PJM that it can use its self-supply to meet projected capacity obligations for an entire five-year period, and to forego the ability to buy or sell capacity in the PJM auctions during that time, the FRR option is a viable alternative only for large utilities that still follow the vertically integrated model.

28 . Namely, Load Petitioners contend that FERC’s approval of the elimination of guaranteed clearance for self-supply "departs from its prior orders that consistently recognized self-supply as the preferred capacity source for LSEs” and "disregards reasons rational LSEs have long chosen self-supply— including long-term cost and revenue benefits, increased long-term reliability, economic development, and resource diversity.” Load Petitioners’ Br. 12, 21. They argue that FERC’s action was in contradiction to FERC's own determination that self-supply offers should not be "automatically suspect.” Id. at 20. Furthermore, they assert that while existing resources are shielded from competition, consumers served by self-supplying LSEs may have to pay twice for their capacity if the self-supply resources fail to clear the auction. Accordingly, as the LSEs see it, FERC’s elimination of guaranteed clearance for self-supply provision violated antitrust principles by favoring existing competitors. Id. at 24-30.

29 .Indeed, in its briefing before this Court, FERC continued to assert arguments as to why the MOPR should not afford self-supply a complete exemption from mitigation. See, e.g., FERC Br. 4 (describing the issue for review as whether FERC reasonably determined "that revising the tariff to clarify that the Minimum Offer Price Rule applies to planned resources designated as self-supply was just and reasonable"). Furthermore, the policy reasons FERC advances against guaranteed clearance for self-supply deal with preventing artificial price suppression. FERC fails to explain why the danger of such price suppression would remain even where self-supply offers were subject to the MOPR’s mitigation features. Id.

30 . Although reviewing courts "generally give[ ] substantial deference to [FERC’s] interpretation of filed tariffs, even where the issue simply involves the proper construction of language ... we do not defer to FERC’s interpretation when the tariff language is unambiguous.” Old Dominion Elec. Coop., Inc. v. FERC, 518 F.3d 43, 48 (D.C.Cir.2008) (internal quotations marks and citations omitted).

31 . In contrast to FERC’s light treatment of the issue, PJM provided an extensive response to Load Petitioners’ arguments regarding automatic clearing of self-supply. See Answer of PJM to Comments and Protests, March 21, 2011 (Joint App. 2269-72); see also PJM Intervenor Brief 23-29. PJM’s argument is es sentially that (1) the provision as it existed was ambiguous; and (2) in light of this ambiguity, this Court should agree with PJM that the provision did not guarantee automatic clearance for self-supply. As to the latter point, PJM argues .against interpreting the provision to guarantee clearance because such interpretation would have so contradicted the purposes of the MOPR that it could not have possibly been correct. Id. at 28. We cannot accept PJM's argument for several reasons. First, as we have previously noted, the language of the provision itself, requiring PJM to accept "first, all Sell Offers in their entirety designated as self-supply committed regardless of price ”, was not ambiguous. See PJM Tariff Attachment DD, Section 5.14(h)(4) (emphasis in original). Second, PJM's claim that it would never have provided for guaranteed clearance due to the economic inefficiencies of such policy is undermined by the fact it has since revised the MOPR to guarantee a more extensive exemption than Load Petitioners had originally urged. Even if FERC had expressly adopted PJM’s policy-based arguments against guaranteed clearing for self-supply, we would have a difficult time agreeing that such adoption was the subject of a reasoned analysis absent an acknowledgment that such treatment constituted a fundamental change in the MOPR’s treatment of such resources.

32 . The parties appear to agree that location-specific “nodal” data is readily available.

33 . In the November 17 Order, FERC stated that it was "not required to consider whether additional, alternative approaches might also have been reasonable.” November 17 Order ¶ 30 (Joint App. 113). According to P3, this statement indicates that FERC had incorrectly characterized its proposed approach as a § 206 challenge to PJM’s tariff, as conditionally approved on April 12, 2011, and therefore inappropriately placed the burden on P3 to demonstrate that PJM's proposal was unjust and unreasonable. P3 cites several cases to support the general principle that FERC, before choosing a particular course of action, must consider facially reasonable alternatives. See P3 Br. at 46-47 and n. 12. None of the cases cited, however, actually involves FERC's application of the "just and reasonable” standard under § 205, pursuant to which a utility proposes revisions to its own tariff, and FERC’s review is limited to determining whether the utility’s preferred revision is just and reasonable. FERC denies that it construed P3's challenge to the tariff revision as a § 206 challenge and argues that P3 simply fails to understand the burden-shifting mechanism under § 205, whereby PJM had the burden of showing that its tariff proposal was just and reasonable, after which the burden then shifted to P3 to demonstrate that PJM’s proposed approach was unjust and unreasonable. FERC determined that PJM carried its burden, and P3 did not. We believe that FERC has the better argument on this point, and in any case, FERC adequately, albeit succinctly, responded to P3's criticisms.

34 . See NYISO Mitigation Enhancements Order, 133 FERC ¶ 61,178. Under the rule FERC originally approved for NYISO, resources become exempt after clearing at least twelve of the previous 24 monthly auctions. P3 alleges that this clearance requirement was also subject to a minimum period of six "capability periods”, or approximately three years. P3 Br. 53-54. However, FERC asserts that P3 misunderstands this portion of its ruling, and that FERC actually "expressly rejected any minimum” and instead "allowed resources to become permanently exempt from mitigation after clearing the market for one year (12 monthly auctions in the New York market).” FERC Br. 88 (citing 133 FERC ¶ 61,178 at ¶ 51).

35 . P3 generally argues that FERC’s one-auction clearing requirement is discriminatory because it permits a new resource to receive subsidies, and therefore bid into the auction at an artificially low cost, only one year after clearing its first auction. They argue that allowing a new resource to receive discriminatory subsidies in its second auction would affect the clearing price in the second year in the same way a below-cost offer would have done in the first year the resource was implemented. Of course, if FERC had adopted P3’s proposal that a new resource escape mitigation after clearing two auctions, then such procedure could be criticized for permitting discriminatory subsidies in the third year. Accordingly, P3’s argument here is less about the number of auctions a new resource must clear before being subject to mitigation, than a rehashing of its complaints regarding FERC's rejection of the No-Subsidy Off-Ramp. As discussed supra, FERC's decision not to adopt the No-Subsidy Off-Ramp was originally one of P3’s five independent chai- lenges to FERC’s 2011 Orders. In its 2013 Order, as described supra, FERC has now adopted a form of the No-Subsidy Off-Ramp. Accordingly, P3 has dropped its challenge to that particular part of the 2011 Orders. Its challenge to the one-auction clearing rule, however, remains alive.

36 . Finally, P3 urges us to remand FERC’s orders in light of FERC's subsequent order in Astoria Generating Co. v. New York Independent System Operator, Inc., 140 FERC ¶ 61,-189 (2012), where FERC required NYISO to apply a market power screen that would subject a capacity resource to an offer floor despite the fact that the resource had already cleared in several auctions. We are not convinced that Astoria is inconsistent with the FERC order at issue here, as the capacity resource in that matter had cleared the NYI-SO auctions without being subject to an offer floor. See id. at ¶ 141. On the contrary, the FERC rule at issue here requires that a new resource clear the PJM auction at or near its net cost of new entry once before escaping mitigation in subsequent auctions. In any case, as P3 acknowledges, "[a]n agency’s decision is not arbitrary and capricious merely because it is not followed in a later adjudication.” Brooklyn Union Gas Co. v. FERC, 409 F.3d 404, 406 (D.C.Cir.2005) (quoting MacLeod v. ICC, 54 F.3d 888, 892 (D.C.Cir.1995)).