Full opinion text
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. 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. 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.”). 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. 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.” 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. 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 settlement 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. 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. 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, 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. 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). 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. 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”, 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. 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 manner 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. 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. 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”, 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 challenging various aspects of the Orders. A group of energy generation companies has also intervened on Cross-Petitioners’ behalf. 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. 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. 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 costly 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 complaint 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. 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. 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 authority.”). 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. 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 entitl