South Carolina Public Service Authority v. Federal Energy Regulatory Commission

This case involves challenges to the most recent reforms of electric transmission planning and cost allocation adopted by the Federal Energy Regulatory Commission pursuant to the Federal Power Act, 16 U.S.C. § 791 a et seq. In Order No. 1000, as reaffirmed and clarified in Order Nos. 1000-A and 1000-B (together, “the Final Rule”), the Commission required each transmission owning and operating public utility to participate in regional transmission planning that satisfies specific planning principles designed to prevent undue discrimination and preference in transmission service, and that produces a regional transmission plan. The local and regional transmission planning processes must consider transmission needs that are driven by public policy requirements. Transmission providers in neighboring planning regions must collectively determine if there are more efficient or cost-effective solutions to them mutual transmission needs. The Final Rule also requires each planning process to have a method for allocating ex ante among beneficiaries the costs of new transmission facilities in the regional transmission plan, and the method must satisfy six regional cost allocation principles. Neighboring transmission planning regions also must have a common interregional cost allocation method for new interregional transmission facilities that satisfies six similar allocation principles. Additionally transmission providers are required to remove from their jurisdictional tariffs and agreements any provisions that establish a federal right of first refusal to develop transmission facilities in a regional transmission plan, subject to individualized compliance review.

Forty-five petitioners and sixteen inter-venors (hereinafter “petitioners”) include state regulatory agencies, electric transmission providers, regional transmission organizations, and electric industry trade associations. They challenge the Commission’s authority to adopt these reforms, and they contend that the Final Rule is arbitrary and capricious and unsupported by substantial evidence. For the following reasons, we conclude them contentions are unpersuasive. We hold in Part II, that the Commission had authority under Section 206 of the Federal Power Act to require transmission providers to participate in a regional planning process. In Part III, we conclude that there was substantial evidence of a theoretical threat to support adoption of the reforms in the Final Rule. In Part IV, we hold that the Commission had authority under Section 206 to require removal of federal rights of first refusal provisions upon determining they were unjust and unreasonable practices affecting *49 rates, and that determination was supported by substantial evidence and was not arbitrary or capricious; we further hold that the Mobile-Sierra objection to the removal is not ripe. In Part V, we hold that the Commission had authority under Section 206 to require the ex ante allocation of the costs of new transmission facilities among beneficiaries, and that its decision regarding scope was not arbitrary or capricious. In Part VI, we hold that the Commission reasonably determined that regional planning must include consideration of transmission needs driven by public policy requirements. In Part VII, we hold that the Commission reasonably relied upon the reciprocity condition to encourage non-public utility transmission providers to participate in a regional planning process. Accordingly, we deny the petitions for review of the Final Rule. 1

I.

A brief overview of the Federal Power Act (“FPA”) and subsequent changes to the electric industry sets the background for petitioners’ challenges to the Final Rule. Upon enacting the FPA, Congress determined that federal regulation of interstate electric energy transmission and its sale at wholesale is “necessary in the public interest,” FPA § 201(a), 16 U.S.C. § 824(a), and vested the Commission with “jurisdiction over all facilities for such transmission or sale,” id. § 201(b)(1), 16 U.S.C. § 824(b)(1). The States would retain authority over “any other sale of electric energy” and facilities used for “generation of electric energy,” “local distribution,” or “transmission of electric energy in intrastate commerce.” Id. The Commission was directed “to divide the country into regional districts for the voluntary interconnection and coordination of facilities for the generation, transmission, and sale of electric energy,” and assigned the “duty” to “promote and encourage such interconnection and coordination.” FPA § 202(a), 16 U.S.C. § 824a(a). Such public utilities, in turn, were required to file new rates for Commission approval, and Congress directed that “[a]ll rates and charges made, demanded, or received by any public utility for or in connection with the [jurisdictional] transmission or sale of electric energy ... shall be just and reasonable,” and that “[n]o public utility shall, with respect to any [jurisdictional] transmission or sale ... subject any person to any undue prejudice or disadvantage” or “maintain any unreasonable difference in rates, charges, service, facilities, or in any other respect, either as between localities or as between classes of service.” FPA § 205(a)-(b), 16 U.S.C. § 824d(a)-(b). Additionally, Congress empowered the Commission to take action on its own motion in order to ensure that such rates, charges, and classifications, as well as “any rule, regulation, practice, or contract affecting such rate, charge, or classification,” are not “unjust, unreasonable, unduly discriminatory or preferential.” FPA § 206(a), 16 U.S.C. § 824e(a).

When Congress enacted the FPA in 1935, electric utilities were mostly vertically integrated firms that constructed and operated their own generation, transmission, and distribution facilities. See New York v. FERC, 535 U.S. 1, 5, 122 S.Ct. 1012, 152 L.Ed.2d 47 (2002). The firms acted as separate, local monopolies, and consumers paid a single “bundled” rate for delivered electricity. Id. Sixty years later, the electric industry had experienced fundamental changes: Electric systems had *50 become increasingly interconnected, long-distance transmission had become increasingly economical, and smaller, lower-cost power plants had begun to emerge as competitors to the vertically integrated utilities. See Order No. 888, Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities, F.E.R.C. Stats. & Regs. ¶ 31,036 at pp. 31,639-44, 61 Fed.Reg. 21,540, 21,543-46 (1996).

The Commission responded to these changes and market conditions by adopting reforms to the electric industry that were modeled after those it had adopted for the natural gas industry pursuant to the Natural Gas Act, 15 U.S.C. § 717 et seq. See generally Associated Gas Distribs. v. FERC, 824 F.2d 981 (D.C.Cir.1987) (reviewing Order No. 436). The Commission concluded that the economic self-interest of electric transmission monopolists lay in denying transmission or offering it only on inferior terms to emerging competitors. See Order No. 888 at p. 31,682, 61 Fed.Reg. at 21,567. Given this intrinsic defect in how the market was shaping the electric industry, the Commission acted to foster “a successful transition to competitive wholesale electricity markets.” Id. at p. 31,652, 61 Fed. Reg. at 21,550. In Order No. 888, the Commission required each jurisdictional electric public transmission provider to “functionally] unbundle]” its wholesale generation and transmission services and file an open-access transmission tariff (“OATT”) containing minimum terms of non-discriminatory transmission service. Id. at pp. 31,635-36, 31,653-54, 61 Fed. Reg. at 21,541, 21,551-52. Through these structural changes, the Commission sought to open the electric grid to all sources of electric power and thereby “ensure that customers have the benefits of competitively priced generation.” Id. at p. 31,652, 61 Fed.Reg. at 21,550. To promote development of competitive markets, the Commission encouraged the formation of regional transmission organizations (“RTOs”) and independent system operators (“ISOs”) to coordinate transmission planning, operation, and use on a regional and interregional basis. Id. at pp. 31,655, 31,854-55, 61 Fed.Reg. at 21,552, 21,666-67. This court in Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C.Cir.2000) (“TAPS”), aff'd sub nom. New York, 535 U.S. 1, 122 S.Ct. 1012, upheld Order No. 888 in nearly all respects, concluding that the Commission had authority under FPA Section 206 to require open access as a generic remedy for systemic anti-competitive behavior, see id. at 685-87.

Congress also acted to spur investment in the electric transmission grid. Under the Electricity Modernization Act of 2005, enacted as Title XII of the Energy Policy Act of 2005, Pub.L. No. 109-58, 119 Stat. 594, 941, the Commission was authorized: to grant permits for construction of interstate transmission facilities in “national interest electric transmission corridors,” id. § 1221(b) (codified at FPA § 216(b), 16 U.S.C. § 824p(b)); to subsidize the development of technology that would increase the capacity, efficiency, or reliability of transmission facilities, id. §§ 1223-24 (codified at 42 U.S.C. §§ 16422-23); to provide incentive-based rates for investments in transmission infrastructure, id. § 1241 (codified at FPA § 219, 16 U.S.C. § 824s); and to require each “unregulated transmitting utility” to provide transmission services on terms and conditions “comparable to those under which [it] provides transmission services to itself and that are not unduly discriminatory or preferential,” id. § 1231, (codified at FPA § 211A(b), 16 U.S.C. § 824j-l(b)). Further, the Commission was instructed to exercise its authority under the FPA “in a manner that *51 facilitates the planning and expansion of transmission facilities to meet the reasonable needs of load-serving entities.” Id. § 1233 (codified at FPA § 217(b)(4), 16 U.S.C. § 824q(b)(4)). The Commission was to establish mandatory reliability standards for “bulk power system” operators in conjunction with the North American Electric Reliability Corporation (“NERC”), the industry’s self-regulatory organization. Id. § 1211(a) (codified at FPA § 215, 16 U.S.C. § 824o); see N. Am. Elec. Reliability Corp., 116 F.E.R.C. ¶ 61,062 at ¶ 240 (July 20, 2006).

In 2007, the Commission issued Order No. 890, Preventing Undue Discrimination and Preference in Transmission Service, F.E.R.C. Stats. & Regs. ¶ 31,241, 72 Fed.Reg. 12,266 (2007). Noting that the United States had “witnessed a decline in transmission investment relative to load growth,” the Commission found that the resulting grid congestion “can have significant cost impacts on consumers.” Id. ¶¶ 60, 421, 72 Fed.Reg. at 12,276, 12,318. Concluding that transmission providers lacked incentives to plan and develop new transmission facilities in a manner consistent with the public interest, the Commission found that the “lack of coordination, openness, and transparency” in transmission planning had “result[ed] in opportunities for undue discrimination” because “participants ha[d] no means to determine whether the plan developed by the transmission provider in isolation is unduly discriminatory.” Id. ¶¶ 57-61, 421-425, 72 Fed.Reg. at 12,275-76, 12,318. To “remedy these transmission planning deficiencies” and “prevent undue discrimination in the rates, terms and conditions of public utility transmission service,” Order No. 890 required each transmission provider to establish an open, transparent, and coordinated transmission planning process that complied with nine planning principles. Id. ¶ 425 & app. C, attachment K, 72 Fed.Reg. at 12,318, 12,531. Transmission providers were also required “to open their transmission planning process to customers, coordinate with customers regarding future system plans, and share necessary planning information with customers.” Id. ¶ 3, 72 Fed.Reg. at 12,267.

By late 2008, the electric industry was reporting that an estimated $298 billion of investment in new electric transmission facilities would be needed between 2010 and 2030 to maintain current levels of reliable electric service across the United States. See Marc W. Chupka et al., Transforming America’s Power Industry: The Investment Challenge 2010-2030, at 37 (Nov. 2008). NERC, the electric industry’s self-regulator, projected that in the next decade a 9.5% to 15% increase in circuit miles of transmission would be needed to maintain reliability and to “unlock” and integrate renewable resources like wind generation that are likely to be remote from demand centers. NERC, 2009 Long-Term Reliability Assessment 26 (Oct. 2009); NERC, 2008 Long-Term Reliability Assessment 15 (Oct.2008). The Energy Department had similarly determined that “under any future electric industry scenario,” a “[significant expansion of the transmission grid will be required” to “increase reliability, reduce costly congestion and line losses, and supply access to low-cost remote resources, including renewables.” Dep’t of Energy, 20% Wind Energy by 2030: Increasing Wind Energy’s Contribution to U.S. Electricity Supply 93 (July 2008).

In September 2009, the Commission convened three regional technical conferences to “examine whether existing transmission planning processes adequately consider needs and solutions on a regional or interconnection-wide basis to ensure adequate and reliable supplies at just and reasonable rates.” FERC, Notice of Tech *52 nical Conferences, Docket No. AD09-8-000, at 2 (June 30, 2009). The conferences were also to “explore whether existing processes are sufficient to meet emerging challenges to the transmission system, such as the development of interregional transmission facilities, the integration of large amounts of location-constrained generation, and the interconnection of distributed energy resources.” Id. While the Commission was evaluating the adequacy of Order No. 890’s reforms, Congress provided $80 million to the Department of Energy “for the purpose of facilitating the development of regional transmission plans,” through analysis of future demand and transmission requirements and technical assistance to transmission providers in developing interconnection-based transmission plans for the Eastern, Western, and Texas Interconnections. American Recovery and Reinvestment Act of 2009, Pub.L. No. 111-5, div. A, 123 Stat. 115, 139.

In June 2010, the Commission published a Notice of Proposed Rulemaking. Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, 131 F.E.R.C. ¶ 61,253, 75 Fed.Reg. 37,884 (2010) (“NPRM”). The Commission explained that although substantial improvements in the transmission planning process had occurred as a result of compliance with Order No. 890, “significant changes in the nation’s electric power industry” since then required consideration of additional reforms. See id. ¶ 33, 75 Fed.Reg. at 37,889. Among other things, the Commission identified “a trend of increased investment in the country’s transmission infrastructure” due principally to investment in transmission of renewable energy sources. Id. ¶ 33 & n. 41, 75 Fed.Reg. at 37,889. Although governmental reforms and market forces had resulted in expansion of the transmission grid, the Commission concluded that this positive trend highlighted deficiencies in existing transmission planning and cost allocation processes that would inhibit the construction of new transmission facilities and adversely affect rates if left unremedied. See id. ¶¶ 32-42, 75 Fed.Reg. at 37,889-90. The Commission identified five general deficiencies in Order No. 890, see id. ¶¶ 35-41, 75 Fed.Reg. at 37,889-90, and proposed additional reforms “to correct [those] deficiencies ... so that the transmission grid can better support wholesale power markets and thereby ensure that Commission jurisdictional services are provided at rates, terms and conditions that are just and reasonable and not unduly discriminatory or preferential,” id. ¶ 1, 75 Fed.Reg. at 37,885.

In August 2011, the Commission issued Order No. 1000, which adopted the proposed reforms. Transmission Planning and Cost Allocation by Transmission Ovming and Operating Public Utilities, F.E.R.C. Stats. & Regs. ¶ 31,323, 76 Fed. Reg. 49,842 (2011). Under Order No. 1000:

(1) Each transmission provider must participate in a regional transmission planning process that complies with the planning principles in Order No. 890, produces a regional transmission plan for development of new regional transmission facilities, and includes procedures to identify transmission needs driven by public policy requirements established by federal, state, or local laws or regulations and evaluate potential solutions to those needs. Id. ¶¶ 2, 146, 203-05, 76 Fed.Reg. at 49,845, 49,867, 49,876-77.

(2) Neighboring transmission planning regions must establish interregional coordination procedures that provide for sharing information and planning data as well as the identification and joint evaluation of interregional trans *53 mission facilities that could address transmission needs more efficiently or cost-effectively than separate regional transmission facilities. Id. ¶¶ 393, 396, 76 Fed.Reg. at 49,907.

(3) Transmission providers must remove from jurisdictional tariffs and agreements any provisions that establish a federal right of first refusal for an incumbent transmission developer to construct new regional transmission facilities included in a regional transmission plan. Id. ¶ 313, 76 Fed.Reg. at 49,895-96. An “incumbent” transmission provider refers to a public utility transmission provider that develops a transmission project within its own retail distribution service territory, while a “non-incumbent” transmission provider refers to either a transmission developer without a retail distribution service territory or a public utility transmission provider that proposes a transmission project outside its existing retail distribution service territory. Id. ¶ 225, 76 Fed.Reg. at 49,880.

(4) Each transmission provider must demonstrate that the regional planning process in which it participates has established appropriate qualification criteria for transmission developers, identified the information that a transmission developer must submit in proposing a regional transmission project, and has a selection process for transmission projects that is transparent and not unduly discriminatory. Id. ¶¶ 323-31, 76 Fed. Reg. at 49,897-99.

The cost-allocation reforms in Order No. 1000 require each transmission provider to include in its OATT a method (or set of methods) for allocating ex ante the costs of new regional transmission facilities that complies with six regional cost allocation principles. Id. ¶ 558, 76 Fed.Reg. at 49,929. Those principles include cost causation, under which “[t]he cost of transmission facilities must be allocated to those within the transmission planning region that benefit from those facilities in a manner that is at least roughly commensurate with estimated benefits.” Id. ¶ 586, 76 Fed.Reg. at 49,932. Transmission providers in neighboring transmission planning regions are similarly required to establish a common method (or set of methods) for allocating ex ante the costs of a new transmission facility to be located in both planning regions that complies with interregional cost allocation principles closely tracking the regional cost allocation principles. Id. ¶¶ 578, 611, 76 Fed. Reg. at 49,931, 49,936. Participant funding of new transmission facilities (ie., allocating the costs of a transmission facility only to entities that volunteer to bear those costs) is not permitted as a regional or interregional cost allocation method. Id. ¶¶ 723-25, 76 Fed.Reg. at 49,949-50.

Upon rehearing, the Commission clarified and reaffirmed the reforms in Order No. 1000. See Order No. 1000-A, 139 F.E.R.C. ¶ 61,132, 77 Fed.Reg. 32,-184 (2012); Order No. 1000-B, 141 F.E.R.C. ¶ 61,044, 77 Fed.Reg. 64,890 (2012). The Commission rejected requests to eliminate or substantially modify Order No. 1000 and provided clarifications relating to scope, terminology, and underlying reasons for certain reforms. See, e.g., Order No. 1000-A ¶¶ 3, 190, 204, 216, 77 Fed.Reg. at 32,186, 32,215, 32,217, 32,219. Notably, the Commission stated that it was “not requiring ... providers to eliminate a federal right of first refusal before the Commission makes a determination regarding whether an agreement is pro *54 tected by a Mobile-Sierra[ 2 ] provision.” Id. ¶ 389, 77 Fed.Reg. at 32,245. In Order No. 1000-B, the Commission provided clarifications and restated that the obligation to remove federal rights of first refusal would arise only after an individualized determination. See Order No. 1000-B ¶¶ 8, 11, 40, 72, 77 Fed.Reg. at 64,892, 64,897, 64,902.

Petitioners challenge the Final Rule on the grounds that the Commission lacked statutory authority, made factual findings that were unsupported by substantial evidence, and acted in a manner that was arbitrary or capricious or contrary to law. In addressing these contentions, the court is bound to apply the following standards of review.

The court reviews challenges to the Commission’s interpretation of the FPA under the familiar two-step framework of Chevron U.S.A. Inc. v. Natural Resources Defense Council, Inc., 467 U.S. 837, 104 S.Ct. 2778, 81 L.Ed.2d 694 (1984). If the court determines “Congress has directly spoken to the precise question at issue,” and “the intent of Congress is clear, that is the end of the matter.” Id. at 842, 104 S.Ct. 2778. If, however, “the statute is silent or ambiguous with respect to the specific issue,” then the court must determine “whether the agency’s answer is based on a permissible construction of the statute.” Id. at 843, 104 S.Ct. 2778. “No matter how it is framed, the question a court faces when confronted with an agency’s interpretation of a statute it administers is always, simply, whether the agency has stayed within the bounds of its statutory authority,” City of Arlington v. FCC, — U.S. -, 133 S.Ct. 1863, 1868, — L.Ed.2d - (2013) (emphasis omitted), and the court will defer to the Commission’s reasonable interpretation of statutory ambiguities concerning both the scope of its statutory authority and the application of that authority, see id.

The court must uphold the Final Rule unless it is arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law. See Midwest ISO Transm. Owners v. FERC, 373 F.3d 1361, 1368 (D.C.Cir.2004) (citing 5 U.S.C. § 706(2)(A)). The Commission must “examine the relevant data and articulate a satisfactory explanation for its action including a rational connection between the facts found and the choice made.” Motor Vehicle Mfrs. Ass’n of U.S., Inc. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43, 103 S.Ct. 2856, 77 L.Ed.2d 443 (1983) (internal quotation marks omitted). The Commission’s factual findings are conclusive if supported by substantial evidence. 16 U.S.C. § 825Z (b). Substantial evidence “is such relevant evidence as a reasonable mind might accept as adequate to support a conclusion,” Murray Energy Corp. v. FERC, 629 F.3d 231, 235 (D.C.Cir.2011) (internal quotation marks omitted), and requires “more than a scintilla” but “less than a preponderance” of evidence, Fla. Gas Transm. Co. v. FERC, 604 F.3d 636, 645 (D.C.Cir.2010) (quoting FPL Energy Me. Hydro LLC v. FERC, 287 F.3d 1151, 1160 (D.C.Cir.2002)). When applied to rulemaking proceedings, the substantial evidence test “is identical to the familiar arbitrary and capricious standard,” which “requires the Commission to specify the evidence on which it relied and to explain how that evidence supports the conclusion it reached.” Wis. Gas Co. v. FERC, 770 F.2d 1144, 1156 (D.C.Cir.1985) (internal quotation marks omitted).

Furthermore, in rate-related matters, the court’s review of the Commis *55 sion’s determinations is particularly deferential because such matters are either fairly technical or “involve policy judgments that lie at the core of the regulatory mission.” Alcoa Inc. v. FERC, 564 F.3d 1342, 1347 (D.C.Cir.2009) (internal quotation mark omitted). The court owes the Commission “great deference” in this realm because “[t]he statutory requirement that rates be ‘just and reasonable’ is obviously incapable of precise judicial definition,” Morgan Stanley Capital Grp. Inc. v. Pub. Util. Dist. No. 1, 554 U.S. 527, 532, 128 S.Ct. 2733, 171 L.Ed.2d 607 (2008), and “the Commission must have considerable latitude in developing a methodology responsive to its regulatory challenge,” Am. Pub. Gas Ass’n v. FPC, 567 F.2d 1016, 1037 (D.C.Cir.1977) (citing Permian Basin Area Rate Cases, 390 U.S. 747, 790, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968)).

II.

Mandatory Regional Planning: Statutory Authority. In adopting the transmission planning reforms in the Final Rule, the Commission relied on FPA Section 206. See Order No. 1000 ¶ 99, 76 Fed.Reg. at 49,860. Petitioners contend that although “[FPA] Sections 205 and 206 empower [the Commission] to ensure that transactions involving voluntary planning arrangements are just, reasonable, and nondiseriminatory,” the Commission lacks authority “to mandate transmission planning in the first instance” because the FPA “only allows [the Commission] to regulate existing voluntary commercial relationships.” Pet’rs’ Threshold Br. 3. Petitioners also contend that Sections 201 and 202(a) preclude the Commission’s planning mandate.

In addressing issues of statutory interpretation, the court must begin with the text, turning as need be to the structure, purpose, and context of the statute. See Caraco Pharm. Labs., Ltd. v. Novo Nordisk A/S, — U.S. -, 132 S.Ct. 1670, 1680-81, 182 L.Ed.2d 678 (2012); N.Y. State Conference of Blue Cross & Blue Shield Plans v. Travelers Ins. Co., 514 U.S. 645, 655, 115 S.Ct. 1671, 131 L.Ed.2d 695 (1995); Petit v. U.S. Dep’t of Educ., 675 F.3d 769, 781-82 (D.C.Cir.2012).

A.

Section 206(a) provides, in relevant part: Whenever the Commission, after a hearing held upon its own motion or upon complaint, shall find that any rate, charge, or classification, demanded, observed, charged, or collected by any public utility for any transmission or sale subject to the jurisdiction of the Commission, or that any rule, regulation, practice, or contract affecting such rate, charge, or classification is unjust, unreasonable, unduly discriminatory or preferential, the Commission shall determine the just and reasonable rate, charge, classification, rule, regulation, practice, or contract to be thereafter observed and in force, and shall fix the same by order.

16 U.S.C. § 824e(a)(emphasis added). By its plain terms, Section 206 instructs the Commission to remedy “any ... practice” that “affect[s]” a rate for interstate electricity transmission services “demanded” or “charged” by “any public utility” if such practice “is unjust, unreasonable, unduly discriminatory or preferential.” Id. The text does not define “practice,” although use of the word “any” amplifies the breadth of the delegation to the Commission. See United States v. Gonzales, 520 U.S. 1, 5, 117 S.Ct. 1032, 137 L.Ed.2d 132 (1997).

In the Final Rule, the Commission identified underlying problems with “existing *56 transmission planning processes” and found that those processes “have a direct and discernable affect [sic] on rates,” explaining that “[i]t is through the transmission planning process that ... providers determine which transmission facilities will more efficiently or cost-effectively meet the needs of the region, the development of which directly impacts the rates, terms and conditions of jurisdictional service.” Order No. 1000 ¶¶ 112, 116, 76 Fed.Reg. at 49,862. The Commission concluded that “for the pro forma OATT (and, consequently, public utility transmission providers’ OATTs) to be just and reasonable and not unduly discriminatory or preferential, it must be revised.” Id. ¶ 116, 76 Fed. Reg. at 49,862. To remedy the identified systemic problems, the Commission mandated that all transmission providers not only participate in a planning process that is open and transparent as Order No. 890 requires, but also one that is regional in scope and produces a transmission plan whereby providers have the information needed to determine which projects satisfy local and regional needs more efficiently and effectively. Also, the plan must consider transmission needs driven by public policy requirements, not be impeded by federal rights of first refusal allowing preferences in favor of incumbents, and allocate ex ante among beneficiaries the costs of new transmission facilities. See id. ¶¶ 146-48, 151, 203, 313, 499, 76 Fed.Reg. at 49,867-68, 49,876, 49,895-96, 49,921.

Petitioners challenge neither the Commission’s conclusion that the current transmission planning processes are “practices” under Section 206, see, e.g., id. ¶ 58, 76 Fed.Reg. at 49,853, nor its conclusion that such transmission planning practices directly affect rates, see id. ¶ 112, 76 Fed. Reg. at 49,862; see also Oral Arg. Tr. at 10:5-19. Neither can they dispute that the Commission is obligated by the plain text of Section 206 to ensure that such practices are just and reasonable and not unduly discriminatory or preferential. Instead petitioners maintain essentially that a lack of regional transmission planning was not an existing practice subject to the Commission’s authority under Section 206, and that “the decision whether to coordinate planning is left, in the first instance, to utilities.” Pet’rs’ Threshold Br. 8. Petitioners rely on Atlantic City Electric Co. v. FERC, 295 F.3d 1, 10 (D.C.Cir.2002), for the proposition that the Commission is “limited under section 206 to investigating] the reasonableness of the terms of existing utility-customer relationships.” Pet’rs’ Threshold Br. 8. But in Atlantic City the court stated that Section 206 permits the Commission “to initiate changes to existing utility rates and practices,” 295 F.3d at 10, which is what the Commission claims to have done in the Final Rule. Petitioners’ reliance on Atlantic City is misplaced because it begs the question of what “practice” means.

The authority and obligation that Congress vested in the Commission to remedy certain practices is broadly stated and the only question is what limits are fairly implied. On the one hand, Section 206 cannot be fairly viewed as the type of “subtle device” at issue in MCI Telecommunications Corp. v. AT&T Co., 512 U.S. 218, 224, 231, 114 S.Ct. 2223, 129 L.Ed.2d 182 (1994), on which petitioners rely. There, the Supreme Court rejected the agency’s attempt to interpret its statutory authority to “modify any requirement” to extend to a fundamental change to a tariff-filing requirement of “enormous importance to the statutory scheme.” Id. On the other hand, in California Independent System Operator Corp. v. FERC, 372 F.3d 395, 398 (D.C.Cir.2004) (“CAISO ”), this court held that the Commission had exceeded its authority under Section 206 by calling for the replacement of a public utility’s board of *57 directors. The court explained that “[t]he word ‘practices’ is a word of sufficiently diverse definitions that the only realistic approach to determining Congress’s ‘plain meaning,’ if any, is to regard the word in its context.” Understood in the context of Section 206’s transactional terms, the court observed, “[i]t is quite a leap” to move from the authority to regulate rates, charges, classifications and closely related matters to “an implication that by the word ‘practice,’ Congress empowered the Commission ... to reform completely the governing structure of [an ISO].” Id. Significantly for present purposes, the court distinguished such an expansive interpretation of the word “practices” from Commission action to “effect a reformation of some ‘practice’ in a more traditional sense of actions habitually being taken by a utility in connection with a rate found to be unjust or unreasonable.” Id.

Reforming the practices of failing to engage in regional planning and ex ante cost allocation for development of new regional transmission facilities is not the kind of interpretive “leap” that concerned the court in CAISO but rather involves a core reason underlying Congress’ instruction in Section 206. This is illustrated by the court’s decision in TAPS, 225 F.3d 667. There, the court upheld Order No. 888 mandating the unbundling of generation and transmission services and the filing of OATTs as a remedy for the refusal of transmission-owning facilities to offer transmission to emerging competitors on non-discriminatory terms. The Commission found that these facilities “c[ould] be expected to act in their own interest to maintain their monopoly” by either “denying transmission access outright” or “by providing transmission services to competitors only at comparatively unfavorable rates, terms, and conditions.” Id. at 683-84. Although some facilities had voluntarily opened their transmission facilities to third parties, the Commission concluded that “relying upon voluntary arrangements ... would not remedy the fundamentally anticompetitive structure of the transmission industry.” Id. at 684. The court deferred to the Commission’s reasonable interpretation that it had “authority under FPA §§ 205 and 206 to require open access as a generic remedy to prevent undue discrimination.” Id. at 687. Notably, then, in TAPS, the court agreed with the Commission’s interpretation here that a failure to act qualifies as a “practice” under Section 206 that it must remedy when the failure to act is “unjust, unreasonable, unduly discriminatory or preferential,” 16 U.S.C. § 824e(a), and directly affects or is closely related to jurisdictional rates, see CAISO, 372 F.3d at 403.

Petitioners attempt to distinguish TAPS by characterizing regional transmission plans as “regional planning agreements” and “[ajgreements to coordinate transmission planning” that require transmission providers to take on “binding” commercial obligations. See Oral Arg. Tr. at 3:19-21, 11:6-13; Pet’rs’ Threshold Br. 13. They rely on Otter Tail Power Co. v. United States, 410 U.S. 366, 93 S.Ct. 1022, 35 L.Ed.2d 359 (1973), for the proposition that Congress intended the formation of such agreements to be “voluntary” and “governed in the first instance by business judgment,” id. at 374, 93 S.Ct. 1022; see Oral Arg. Tr. at 3, 11:6-13; Pet’rs’ Threshold Br. 8, 13. This misperceives what the Commission has required in the Final Rule. In Order No. 1000, the Commission expressly “decline[d] to impose obligations to build or mandatory processes to obtain commitments to construct transmission facilities in the regional transmission plan.” Order No. 1000 ¶ 159, 76 Fed.Reg. at 49,-870. More generally, the Commission disavowed that it was purporting to “determine what needs to be built, where it *58 needs to be built, and who needs to build it.” Id. ¶ 49, 76 Fed.Reg. at 49,852. As the Commission explained on rehearing, “Order No. 1000’s transmission planning reforms are concerned with process” and “are not intended to dictate substantive outcomes.” Order No. 1000-A ¶ 188, 77 Fed.Reg. at 32,215. The substance of a regional transmission plan and any subsequent formation of agreements to construct or operate regional transmission facilities remain within the discretion of the decision-makers in each planning region.

In TAPS, the court rejected petitioners’ interpretation of Otter Tail. That was an antitrust enforcement action in which the Supreme Court held that an electric power company was not, by reason of the Commission’s authority under the FPA to compel involuntary interconnections of power, immune from antitrust regulation for its refusals to sell at wholesale or to transfer power to municipalities. 410 U.S. at 373, 93 S.Ct. 1022. The Court noted that, as originally proposed, the FPA would have made public utilities common carriers and empowered the Commission to order the wheeling of power if it was “necessary or desirable in the public interest,” but these provisions were eliminated and replaced by involuntary wheeling authority “subject to limitations unrelated to antitrust considerations” in order to “preserve the voluntary action of the utilities.” Id. at 373-74, 93 S.Ct. 1022 (internal quotation marks omitted). Based on this legislative history, the Court explained that “Congress rejected a pervasive regulatory scheme for controlling the interstate distribution of power in favor of voluntary commercial relationships,” and that “[w]hen these relationships are governed in the first instance by business judgment and not regulatory coercion, courts must be hesitant to conclude that Congress intended to override the fundamental national policies embodied in the antitrust laws.” Id. at 374, 93 S.Ct. 1022 (emphasis added). In TAPS, this court concluded that “while Otter Tail may represent a general rule that [the Commission]’s authority to order open access is limited, the FPA, like the [Natural Gas Act], makes an exception to that rule where [the Commission] finds undue discrimination.” 225 F.3d at 686-87 (citing Associated Gas Distributors, 824 F.2d at 998). The court thus recognized that Otter Tail did not ipurport to limit the Commission’s Section 206 authority to remedy practices affecting rates that are unduly discriminatory. Rather, the Supreme Court in Otter Tail concluded that the FPA does not preempt the field of electric utility regulation.

In their Reply Brief, petitioners attempt to inject another reason the Commission lacked authority under Section 206, maintaining that the Commission’s regional planning mandate “is not requiring a change to existing practices,” but is instead “a directive to engage in new practices by unlawfully compelling formation of new commercial relationships,” i.e., “coordinated planning arrangements.” Pet’rs’ Threshold Reply Br. 11. The court ordinarily refuses to address arguments first presented in a reply brief, see Domtar Me. Corp. v. FERC, 347 F.3d 304, 309-10 (D.C.Cir.2003), because the opposing party has no opportunity to respond. We note, however, that to the extent this is not a reiteration of petitioners’ Otter Tail argument, it is based on a false premise. Commission-mandated transmission planning is not new. See Order No. 890 ¶ 3, 72 Fed. Reg. at 12,267. The Final Rule builds on Order No. 890’s requirements in light of changed circumstances and is- simply the next step in a series of related reforms that began no later than Order No. 888. See Order No. 1000 ¶ 99, 76 Fed.Reg. at 49,860. For the reasons discussed, we conclude, consistent with the deferential *59 standard in step two of the Chevron analysis, 467 U.S. at 843, 104 S.Ct. 2778, that the Commission reasonably interpreted Section 206 to authorize the Final Rule’s planning mandate. See TAPS, 225 F.3d at 687, aff'd sub nom. New York, 535 U.S. 1, 122 S.Ct. 1012.

B.

Petitioners’ principal objection, in any event, is that Section 202(a) bars the Commission from mandating transmission planning.

Section 202(a) provides, in relevant part: For the purpose of assuring an abundant supply of electric energy throughout the United States with the greatest possible economy and with regard to the proper utilization and conservation of natural resources, the Commission is empowered and directed to divide the country into regional districts for the voluntary interconnection and coordination of facilities for the generation, transmission, and sale of electric energy .... It shall be the duty of the Commission to promote and encourage such interconnection and coordination within each such district and between such districts.

16 U.S.C. § 824a(a) (emphasis added). The Commission concluded Section 202(a) posed no bar to adoption of the challenged transmission planning reforms because “coordination” refers to the coordinated operation of existing transmission facilities, not to the planning of future facilities. See Order No. 1000 ¶ 100, 76 Fed.Reg. at 49,860; Order No. 1000-A ¶ 123, 77 Fed. Reg. at 32,206. The Commission explained that the coordinated operation contemplated by Section 202(a), as a practical matter, “can occur only after the facilities are interconnected.” Order No. 1000-A ¶ 124, 77 Fed.Reg. at 32,206. By contrast, “[t]he planning of new transmission facilities occurs before they can be interconnected,” and thus “any transmission planning relevant to [new transmission] facilities occurs prior to those matters that [Section 202(a) ] mandates be voluntary.” Id. ¶ 125, 77 Fed.Reg. at 32,206.

In petitioners’ view, the meaning of “coordination” is “selfevident,” Pet’rs’ Threshold Br. 11, and Central Iowa Power Cooperative v. FERC, 606 F.2d 1156 (D.C.Cir.1979), confirms that Section 202(a) precludes the Commission from requiring planning arrangements. Petitioners contend that “coordination” plainly encompasses transmission planning because “the coordination of transmission facilities is exactly what is done in transmission planning.” Pet’rs’ Threshold Br. 11. The statutory text, however, does not unambiguously establish the meaning of “coordination” that petitioners advance. As the Supreme Court has observed, “context matters,” Caraco Pharm., 132 S.Ct. at 1681, and “ ‘[a] word is known by the company it keeps’ — a rule that ‘is often wisely applied where a word is capable of many meanings in order to avoid the giving of unintended breadth to the Acts of Congress,’ ” Dolan v. U.S. Postal Serv., 546 U.S. 481, 486, 126 S.Ct. 1252, 163 L.Ed.2d 1079 (2006) (quoting Jarecki v. G.D. Searle & Co., 367 U.S. 303, 307, 81 S.Ct. 1579, 6 L.Ed.2d 859 (1961)). The “coordination” addressed in Section 202(a) is textually limited to coordination for purposes of generation, transmission and sale, all activities that require operating facilities. Section 202(a) is silent regarding the Commission’s authority with respect to pre-operational planning designed as a remedy to practices affecting rates that are unjust, unreasonable, or unduly discriminatory or preferential; that authority is addressed in Section 206. Petitioners’ suggestion that “[r]eading ‘coordination’ to exclude coordinated transmission planning *60 undermines the [FPA]’s purpose to preserve the voluntary nature of [commercial] relationships,” Pet’rs’ Threshold Br. 13, misperceives the nature of the Final Rule, which, as discussed, addresses process. By characterizing mandated transmission planning as mandating binding commercial relationships, petitioners’ approach fails for the same reasons their reliance on Otter Tail is unavailing.

Central Iowa, 606 F.2d 1156, is not dis-positive of the meaning of “coordination” in the context of planning for new transmission facilities. There, the court rejected challenges to the Commission’s approval, pursuant to Section 205, of a power-pooling agreement that “provide[d] a mechanism for coordinated daily operation of generation facilities” but did not establish a fully integrated electric system with central dispatch of generating units. Id. at 1161. In addressing objections on antitrust grounds, the court observed that “Congress has decided, as a matter of general policy, that power pooling arrangements, rather than unrestrained competition between electric facilities, are in the public interest,” id. at 1162, and that in enacting Section 202(a) “Congress was ‘confident that enlightened self-interest will lead the utilities to cooperate ... in bringing about the economies which can alone be secured through ... planned coordination.’ ” Id. (quoting S.Rep. No. 74-621, at 49 (1935)). Although “Section 202(a) recognizes that power pooling can yield benefits of efficiency and economy,” nonetheless “Congress decided to make such coordination voluntary, with limited exceptions.” Id. at 1167 (emphasis added). Because of the “expressly voluntary nature of coordination under section 202(a),” the court held that “the Commission could not have mandated adoption of the [power pooling] Agreement, and failure ... to establish a fully integrated electric system could not justify rejection of the Agreement filed.” Id. at 1168 (footnote omitted). The court acknowledged, however, that the Commission had authority under Section 206 “to order changes in the limited scope of the Agreement ... if, in the absence of such modifications, the Agreement presented ‘any rule, regulation, practice or contract [that was] unjust, unreasonable, unduly discriminatory or preferential.’ ” Id. (alteration in original) (quoting 16 U.S.C. § 824e(a)). The court cautioned that “a pooling plan is [not] unlawful under section 206 merely because a more comprehensive arrangement might better achieve the purposes of section 202(a).” Id.

Petitioners maintain that Central Iowa “left no doubt that ‘coordination’ encompassed joint transmission planning” because the court “quot[ed] approvingly the definition found in [the Commission’s] own 1970 National Power Survey.” Pet’rs’ Threshold Br. 9. That definition stated that “[a]s used in this chapter, [c]oordination is joint planning and operation of bulk power facilities by two or more electric systems for improved reliability and increased efficiency which would not be attainable if each system acted independently.” Central Iowa, 606 F.2d at 1168 n. 36 (emphasis in original) (quoting FPC, The 1970 National Power Survey 1-17-1 to I-17-2 (1971)). The survey describes different degrees of power pooling among operating facilities, noting variables, including “managerial views with respect to planning, marketing, competition, and retention of prerogatives.” Id. Neither the definition nor the description is inconsistent with the Commission’s interpretation of Section 202(a) in the Final Rule. The court, in any event, did not present the quotation as a definitive interpretation of the meaning of “coordination” as would bar the Commission’s adoption of planning reforms under Section 206. To the extent the *61 court in Central Iowa interpreted Section 202(a) to mean that “Congress intended coordination and interconnection arrangements be left to the ‘voluntary’ action of the utilities,” Atlantic City, 295 F.3d at 12, there is nothing to suggest that the court purported to interpret the meaning of “coordination” in regard to the planning of future facilities. Petitioners’.view of Central Ioioa thus fails to “trump[ ] [the Commission’s permissible] construction” of “coordination.” Nat’l Cable & Telecomms. Ass’n v. Brand X Internet Servs., 545 U.S. 967, 982, 125 S.Ct. 2688, 162 L.Ed.2d 820 (2005).

Similarly, petitioners’ several grammatical objections to the Commission’s interpretation of Section 202(a) fail to demonstrate it is impermissible. Although the Commission acknowledged that “coordination,” viewed in isolation, might be read to include regional transmission planning, the Commission relied on other textual cues to conclude that “coordination” instead referred only to coordinated operation. Section 202(a) identified two activities that the Commission was to encourage — the “interconnection and coordination of facilities.” From the sequence of these terms, the Commission concluded that “coordination” referred to the coordination of operations that could occur only after facilities were interconnected. See Order No. 1000-A ¶¶ 123-25, 77 Fed.Reg. at 32,206. Petitioners suggest the Commission’s “artificial reliance on the sequence of the terms ‘interconnection’ and ‘coordination’ ... creates an unnatural reading.” Pet’rs’ Threshold Br. 13. Because “interconnection and coordination” are “phrased in the conjunctive,” petitioners conclude that there “is no logical or grammatical reason why the term coordination should be qualified by the term interconnection.” Id. at 14. But reliance on the text and its structure to discern congressional intent is a well-recognized method of statutory interpretation. See, e.g., U.S. Nat’l Bank of Or. v. Indep. Ins. Agents of Am., Inc., 508 U.S. 439, 455, 113 S.Ct. 2173, 124 L.Ed.2d 402 (1993); see also Antonin Scalia & BRYAN A. GaeneR, Reading Law: The Interpretation of Legal Texts 167 (2012). It is neither ungrammatical nor unnatural to read “and” to suggest a chronological sequence. See David Crystal, The Cambridge EnoyClope-dia of the English Language 213 (1995); 2 George O. Curme, A Grammar of the English Language: Syntax 162 (1980). “Nouns joined by coordinating conjunctions are usually treated as a single, compounded unit, and a postmodifying prepositional phrase is most naturally read to modify that single unit.” ConocoPhillips Co. v. EPA, 612 F.3d 822, 839 (5th Cir.2010) (footnotes omitted) (citing Sidney Greenbaum, Oxford English Grammar 233 (1996)). Petitioners so fail to demonstrate that the Commission impermissibly construed “interconnection and coordination” as a single, sequential unit modified by the clause “of facilities for the generation, transmission, and sale of electric energy.” Petitioners likewise fail to show that the Commission impermissibly construed Section 202(a) to refer only to currently operating facilities; the post-modifying prepositional phrase contains only operational nouns (“generation, transmission, and sale”), as opposed to preoperational nouns (e.g., “planning,” “development,” or “construction”).

Neither do petitioners demonstrate that the Commission’s interpretation of Section 202(a) was arbitrary and capricious because it departed from a prior interpretation without explanation. Pointing to the Commission’s references to “coordination” in other contexts, they show no “flip flop,” Pet’rs’ Threshold Br. 16, requiring further explanation by the Commission. For example, the Commission’s statement that *62 “[l]ong-range planning is an indispensable element to the accomplishment of the objective of Section 202(a),” Order No. 383-4, Reliability and Adequacy of Electric Service Reporting Data, 56 F.P.C. 3547, 3548 (1976), is not inconsistent with interpreting Section 202(a) to refer to operating facilities. The Commission’s statement in Public Service Co. of Indiana, 59 F.P.C. 1351, 1355 (1977), that “[t]he importance of encouraging coordinated planning and operation of bulk power supply systems has been a cornerstone of Commission policy for many years,” refers to a package of activities and was not addressing whether mandated pre-operational transmission planning is barred by Section 202(a). Neither did the Commission determine in Mid-Continent Area Power Pool Agreement, 58 F.P.C. 2622 (1977), “that directing joint transmission planning was beyond its authority,” Pet’rs’ Threshold Br. 16-17; instead the Commission found that a lack of single-system planning was not unjust, unreasonable, or unduly discriminatory, see 58 F.P.C. at 2637.

C.

Petitioners contend that even if Section 206 does not bar the Commission from mandating regional transmission planning, FPA Section 201(a) does. Section 201(a) authorizes the Commission to regulate “transmission of electric energy in interstate commerce” but also provides that this authority “extend[s] only to those matters which are not subject to regulation by the States.” 16 U.S.C. § 824(a). Petitioners assert that the mandate infringes on the States’ traditional regulation of transmission planning, siting, and construction, violating the federalism principle recognized in Section 201(a). We disagree.

Petitioners’ contention that the challenged orders intrude on the States’ traditional role in regulating siting and construction requires little discussion. Even assuming arguendo that siting and construction are matters “subject to regulation by the States” within the meaning of Section 201(a), petitioners’ contention simply cannot be squared with the language of the orders, which expressly and repeatedly disclaim authority over those matters. See, e.g., Order No. 1000 ¶¶ 107, 156, 227, 253 n. 231, 257, 259, 287, 337, 339, 76 Fed.Reg. at 49,861, 49,869, 49,880, 49,885-87, 49,891, 49,899-900; Order No. 1000-A ¶¶ 105, 186-94, 377-79, 77 Fed.Reg. at 32,-203, 32,215-16, 32,243-44. The orders neither require facility construction nor allow a party to build without securing necessary state approvals. See Order No. 1000 ¶¶ 66, 159, 227, 76 Fed.Reg. at 49,854, 49,870, 49,880; Order No. 1000-A ¶¶ 186-91, 377-79, 77 Fed.Reg. at 32,215-16, 32,-243-44.

Petitioners’ argument that the orders interfere with state regulation of planning, however, poses a closer question. Petitioners correctly contend that the Commission used the challenged orders to further regulate the transmission planning process. And, petitioners maintain, because state regulators were already substantially involved in regulating that process, 3 the orders encroach on their authority in violation of Section 201(a)’s statement that the Commission’s authority “extend[s] only to those matters which are not subject to regulation by the States.” 16 U.S.C. § 824(a). But while petitioners’ argument is not without force, relevant *63 precedent suggests that Section 201(a) does not stand in the way of the orders’ planning mandate.

In New York v. FERC, 535 U.S. 1, 122 S.Ct. 1012, the Court rejected a state’s argument that Section 201(a) barred the Commission from ordering certain utilities to “transmit competitors’ electricity over [their] lines on the same terms that the utilit[ies] applie[d] to [their] own energy transmissions.” Id. at 4-5, 20-24, 122 S.Ct. 1012. The Court’s substantial discussion of Section 201 yields several insights into the provision’s meaning that are helpful in resolving petitioners’ argument.

First, the Commission possesses greater authority over electricity transmission than it does over sales. See id. at 17, 19-20, 122 S.Ct. 1012. Even though Section 201(b) does “limit FERC’s sale jurisdiction to that at wholesale,” there is no textual warrant for the suggestion that the Commission lacks jurisdiction over retail transmission. Id. at 17, 122 S.Ct. 1012. That is, the FPA preserves for the States relatively more sales authority than transmission authority.

Second, Section 201(a)’s reference to a sphere of state authority is “a mere policy declaration” that should not be read in derogation of other specific provisions granting the Commission authority, including Section 201(b)’s grant of authority over “transmission of electric energy in interstate commerce.” Id. at 17, 22, 122 S.Ct. 1012 (internal quotation marks omitted). As long as the Commission’s activity falls within one of these specific jurisdictional grants, the “prefatory language of section 201(a)” does “not undermine FERC’s jurisdiction.” Id. at 22, 122 S.Ct. 1012. And the authority that Section 201(b) affords to the Commission has expanded over time because transmissions on the interconnected grids that have now developed “constitute transmissions in interstate commerce.” Id. at 7, 16, 122 S.Ct. 1012.

Taken together, these points support the Commission’s assertion of authority over transmission planning matters in the challenged orders, notwithstanding petitioners’ contention that the orders intrude on the States’ authority. First, because the planning mandate relates wholly to electricity transmission, as opposed to electricity sales, it involves a subject matter over which the Commission has relatively broader authority. 4 Second, because the orders’ planning mandate is directed at ensuring the proper functioning of the interconnected grid spanning state lines, cf. Duke Power Co. v. FPC, 401 F.2d 930, 935 (D.C.Cir.1968) (explaining that the “major emphasis” of the FPA “is upon federal regulation of those aspects of the industry which- — for reasons either legal or practical — are beyond the pale of effective state supervision”), the mandate fits comfortably within Section 201(b)’s grant of jurisdiction over “the transmission of electric energy in interstate commerce.” Cf. New York v. FERC, 535 U.S. at 15, 122 S.Ct. 1012 (recognizing that the Court has “construed broadly” the grant of jurisdiction in Section 201); United States v. Pub. Utils. Comm’n of Cal., 345 U.S. 295, 299, 73 S.Ct. 706, 97 L.Ed. 1020 (1953) (recognizing that federal authority under the FPA extends to the “transmission of electric energy in interstate commerce” and that FPA Section 206 is among those provisions that grant “authority in connection with such interstate transmission opera *64 tions”). Given that fit, New York v. FERC teaches that there is no reason to think that the “prefatory” statement of federalism “policy” in Section 201(a) poses an obstacle to the Commission’s assertion of authority. See 535 U.S. at 17, 22, 122 S.Ct. 1012. Accordingly, we reject petitioners’ challenge because Section 201 does not preclude the Commission’s regulation of transmission planning in the Final Rule.

Because we hold that the Final Rule does not interfere with the traditional state authority that is preserved by Section 201, and that the Commission permissibly interpreted “coordination” in Section 202(a) to refer to existing facilities, we turn in Part III to petitioners’ contention that the Commission failed to meet its evidentiary burden under Section 206.

III.

“Theoretical Threat” as a Basis for Section 206 Rulemaking. The Commission concluded that “the narrow focus of current planning requirements and shortcomings of current cost allocation practices create an environment that fails to promote the more efficient and cost-effective development of new transmission facilities, and that addressing these issues is necessary to ensure just and reasonable rates.” Order No. 1000 ¶ 52, 76 Fed.Reg. at 49,852. It described the problem to be remedied as a “theoretical threat” that was “significant enough to justify the requirements] imposed by th[e] Final Rule.” Id. (citing Nat’l Fuel Gas Supply Corp. v. FERC, 468 F.3d 831 (D.C.Cir.2006)). The Commission concluded that the threat “stem[med] from the absence of planning processes that take a sufficiently broad view of both the tasks involved and the means of addressing them.” Id. Although maintaining that the “actual experiences of problems cited in the record ... provide additional support for [its] action,” the Commission stated its remedy was “justified sufficiently by the ‘theoretical threat.’ ” Id. ¶ 53, 76 Fed.Reg. at 49,852-53; see Order No. 1000-A ¶ 57, 77 Fed. Reg. at 32,195.

Petitioners contend that the “theoretical threat” described by the Commission fails to satisfy its evidentiary burden under Section 206, and therefore the Final Rule does not constitute reasoned decisionmaking. They also contend the Commission failed to give reasoned consideration to objections that the Final Rule violates FPA Section 217(b)(4), 16 U.S.C. § 824q(b)(4), which requires the Commission to facilitate the planning and expansion of transmission to meet the needs of load-serving entities. Neither contention withstands analysis.

A.

Petitioners maintain both that the Commission relied solely upon speculation to conclude existing transmission planning practices were deficient, and that the Commission is improperly seeking to optimize already just and reasonable planning practices. Similarly, they maintain that the Commission relied on speculation in concluding the remedies imposed by the Final Rule will be economically beneficial. In petitioners’ view, the Commission has not met the “high bar” identified in National Fuel for agency action “based solely on theory” because it has failed to explain why evidence of abuse is undetectable, why the cost of the Final Rule is justified, and why case-specific resolution is not feasible. See Pet’rs’ Threshold Br. 28 (citing National Fuel, 468 F.3d at 844-45). Petitioners have misconceived the nature of the Commission’s evidentiary burden.

To regulate a practice affecting rates pursuant to Section 206, the Commission must find that the existing prac *65 tice is “unjust, unreasonable, unduly discriminatory or preferential,” and that the remedial practice it imposes is “just and reasonable.” 16 U.S.C. § 824e(a). These findings must be supported by “substantial evidence,” 5 U.S.C. § 706(2)(E), which the court has long held does not necessarily mean empirical evidence. Where the “[p]romulgation of generic rate criteria clearly involves the determination of policy goals or objectives, and the selection of means to achieve them,” the “[c]ourts reviewing an agency’s selection of means are not entitled to insist on empirical data for every proposition on which the selection depends.” Associated Gas Distributors, 824 F.2d at 1008. So long as a prediction is “at least likely enough to be within the Commission’s authority” and it is based on reasonable economic propositions, the court will uphold it. Id. “Agencies do not need to conduct experiments in order to rely on the prediction that an unsupported stone will fall; nor need they do so for predictions that competition will normally lead to lower prices.” Id. at 1008-09; see FPC v. Transcon. Gas Pipe Line Corp., 365 U.S. 1, 29, 81 S.Ct. 435, 5 L.Ed.2d 377 (1961); Interstate Natural Gas Ass’n of Am. v. FERC, 285 F.3d 18, 37-38 (D.C.Cir.2002); Am. Pub. Gas, 567 F.2d at 1037; cf. Stilwell v. Office of Thrift Supervision, 569 F.3d 514, 519 (D.C.Cir.2009); Chamber of Commerce of U.S. v. SEC, 412 F.3d 133, 142 (D.C.Cir.2005).

1. Prior to Order No. 1000, the deficiencies in transmission planning and cost allocation practices were well-understood and not based on guesswork, as petitioners claim. For example, the Commission addressed the dangers posed by inadequate planning in Order No. 888 when it encouraged transmission providers to form RTOs and ISOs. See supra Part I. Growth in demand without growth in transmission investment led to the Commission’s adoption of the transmission planning reforms in Order No. 890. These reforms addressed congestion as well as the lack of specificity regarding how customers and other stakeholders should be treated in the transmission planning process. See id.; Order No. 890 ¶¶ 422-25, 72 Fed.Reg. at 12,318. Industry consultants thereafter projected that considerable expansion of the electric transmission grid was likely to occur between 2010 and 2030. See supra Part I. The Department of Energy reached a similar conclusion. See id. At the Commission’s 2009 technical conferences, participants confirmed problems with existing and non-existing regional planning and cost allocation practices in the electric industry. See, e.g., Ron Lehr of Am. Wind Energy Assoc, on behalf of Interwest Energy Alliance & W. Grid Grp. (Sep. 3, 2009 Technical Conference in Phoenix, AZ) (commenting on difficulty, absent regional planning, of renewable suppliers entering the planning process to challenge incumbents); Steve Gaw, Policy Dir., Wind Coalition (Sept. 10, 2009 Technical Conference in Atlanta, GA) (opening remarks identifying significant cost implications of the lack of a policy on interre-gional cost allocation).

Comments during the rulemaking, including comments from the regulated industry, referred to similar problems. For example, industry economists at The Brat-tle Group “identified approximately 130 mostly conceptual and often overlapping planned transmission projects,” with a total cost of over $180 billion, and concluded that “a large portion of these projects will not be built due to overlaps and deficiencies in transmission planning and cost allocation processes.” Order No. 1000 ¶ 38, 76 Fed.Reg. at 49,850. Other commenters agreed that existing transmission planning and cost allocation practices were deficient and “provide[d] specific examples of developments ... demonstrating] the need for *66 reform.” Id. ¶¶ 32-37, 76 Fed.Reg. at 49,-849-50 (summarizing comments from, inter alia, Colorado Independent Energy Association- and Iberdrola Renewables). The Commission rejected comments characterizing factual examples as “anecdotal,” emphasizing that “[a] wide range of concerns have been raised by commenters,” who “have experienced unjust and unreasonable, or unduly discriminatory or preferential practices in the transmission planning aspects of the transmission service provided by public utility transmission providers.” Id. ¶¶ 50, 58, 76 Fed.Reg. at 49,-852-53.

The threat to just and reasonable rates arose, in the Commission’s judgment, from existing planning and cost allocation practices that could thwart the identification of more efficient and cost-effective transmission solutions. In proposing reforms to the planning requirements of Order No. 890, the Commission identified “significant changes in the nation’s electric power industry,” including the proliferation of renewable energy resources whose viability depended upon the development of new transmission facilities. NPRM ¶¶ 33 & n. 41, 150-53, 75 Fed.Reg. at 37,889, 37,904. These changes presented “significant challenges” to the development and cost allocation of interstate transmission projects. Id. ¶¶ 33-34 & n. 41, 152-54, 75 Fed.Reg. at 37,889, 37,904. They also’ highlighted deficiencies in Order No. 890’s transmission planning and cost allocation processes, which the Commission identified as: (1) the lack of a requirement for a regional transmission plan, (2) the failure of current transmission planning processes to account for transmission needs driven by public policy requirements (e.g., State renewable energy standards), (3) the failure to address obstacles to non-incumbent transmission project developers’ participation in regional transmission planning processes, (4) the relative lack of coordination between transmission planning regions, and (5) the lack of rate structures that provide for the allocation and recovery of costs for transmission projects located either within a non-RTO transmission planning region or in more than one transmission planning region. See id. ¶¶ 35411, 75 Fed.Reg. at 37,889-90.

Additionally, the recent increase in transmission investment reported by the Edison Electric Institute and NERC indicated the need “to ensure that ... transmission planning and cost allocation requirements are adequate to support more efficient and cost-effective investment decisions moving forward.” Order No. 1000 ¶ 44, 76 Fed.Reg. at 49,851. Industry also had reported a longer-term period of investment in new transmission facilities was on the horizon, driven “in large part” by “changes in the mix of generation resources” as a result of increasing reliance on natural gas and large-scale renewable generation. See id. ¶¶ 44-45, 76 Fed.Reg. at 49,851 (collecting sources). The Commission noted that “[transmission planning is a complex process that requires consideration of a broad range of factors” and that “the development of transmission facilities can involve long lead times and complex problems.” Id. ¶ 50, 76 Fed.Reg. at 49,852. Under the circumstances, the Commission concluded that the threat to just and reasonable rates was acute. See id. ¶¶ 43-46, 76 Fed.Reg. at 49,851.

2. Yet petitioners contend that a nationwide rulemaking was not appropriate. Initially they suggest that the Commission’s statement in issuing Order No. 1000 that “transmission planning processes have seen substantial improvements” since Order No 890 was issued, Order No. 1000 ¶ 43, 76 Fed.Reg. at 49,851, was an acknowledgment that' “existing voluntary planning processes work quite well,” Pet’rs’ Threshold Br. 22, and no reform is *67 needed. Current transmission planning practices, they maintain, “cannot be unreasonable simply because they may not produce an optimal outcome” or “some alternative might produce a better or ‘more efficient’ outcome.” Id. at 23 (emphasis in original). Petitioners also contend that the Commission “largely ignored evidence of existing, successful planning processes” in some parts of the country, such as the Southeast. Id. at 28. Neither contention is persuasive.

As discussed, the Commission explained why existing transmission planning and cost allocation practices were inadequate. Order No. 890, for example, did not require transmission providers to “identify and evaluate transmission alternatives at the regional level that may resolve the region’s needs more efficiently or cost-effectively than solutions identified in the local transmission plans of individual public utility transmission providers.” Order No. 1000 ¶ 78, 76 Fed.Reg. at 49,856. Without “a robust process [] in place to identify and consider regional solutions to regional needs,” id. ¶ 320, 76 Fed.Reg. at 49,897, the Commission concluded that some transmission providers were merely “confirming] the simultaneous feasibility of transmission facilities contained in their local transmission plans” and overlooking more efficient or cost-effective regional transmission alternatives, id. ¶¶ 78-80, 320, 76 Fed.Reg. at 49,856-57, 49,897.

Furthermore, in deciding to proceed by a nationwide rule rather than case-by-case adjudication, the Commission did not ignore that “some current practices in some regions” may have already been satisfying “a minimum set of requirements that must be met” under the Final Rule. Order No. 1000-A ¶ 66, 77 Fed.Reg. at 32,196. Rather, it understood that “the present is not a prediction of the future” and emphasized that “all of these requirements are not satisfied in all regions.” Id. ¶¶ 65-66, 77 Fed.Reg. at 32,196. Although recognizing that concerns driving the need for reforms “may not affect each region of the country equally,” the Commission stated it “remain[ed] concerned” that the requirements under Order No. 890 “are inadequate to ensure the development of more efficient and cost-effective transmission.” Order No. 1000 ¶ 60, 76 Fed.Reg. at 49,853.

Based on its expertise and experience, the Commission’s determination that the current planning and cost allocation practices were unjust or unreasonable “warrants substantial deference from this court.” Cities of Bethany v. FERC, 727 F.2d 1131, 1137 (D.C.Cir.1984). “[T]he Commission may rely on ‘generic’ or ‘general’ findings of a systemic problem to support imposition of an industry-wide solution.” Interstate Natural Gas, 285 F.3d at 37 (citing TAPS, 225 F.3d at 687-88, and Wisconsin Gas, 770 F.2d at 1166 & n. 36). Its acknowledgment of relative improvement since Order No. 890 did not demonstrate that the Commission abused its discretion in deciding to proceed by rulemaking, having concluded that “existing transmission planning processes are unjust and unreasonable or unduly discriminatory or preferential.” Order No. 1000 ¶ 116, 76 Fed.Reg. at 49,862. That some commenters may engage in sufficient transmission planning processes “is as unastonishing as it is irrelevant,” Wisconsin Gas, 770 F.2d at 1157, because petitioners have not shown that the deficiencies identified by the Commission “exist[ ] only in isolated pockets,” Associated Gas Distributors, 824 F.2d at 1019. Absent such an extreme “disproportion of remedy to ailment,” the Commission could reasonably proceed to address a systemic problem with an industry-wide solution. Id.; see also Interstate Natural Gas, 285 F.3d at 37-38; infra Part III.C.

*68 B.

No more persuasive is petitioners’ position that, absent empirical evidence of planning abuses, the Commission relied only on speculation to conclude that the reforms required by the Final Rule are just and reasonable. Petitioners point in particular to the Commission statements that its planning and cost allocation reforms “might,” “may,” or “could” improve outcomes. E.g., Order No. 1000 ¶¶ 6, 47, 81, 148, 76 Fed.Reg. at 49,845, 49,852, 49,-857, 49,868. Citing Algonquin Gas Transmission Co. v. FERC, 948 F.2d 1305, 1313-14 (D.C.Cir.1991), petitioners contend that the use of such conditional words shows that “there is no underlying theory at all, only conjecture about how utility practices might change for the better if [the Final Rule’s] mandates are adopted.” Pet’rs’ Threshold Br. 24-25.

The Commission’s reticence to make definitive claims about the future does not make its determination legally deficient because “a forecast of the direction in which future public interest lies necessarily involves deductions based on the expert knowledge of the agency.” Transcontinental Gas, 365 U.S. at 29, 81 S.Ct. 435. The Commission explained that its use of such words must be understood in context: “When making a generic factual prediction, one is not predicting what will occur with certainty in every instance but rather what it is reasonable to conclude will occur with sufficient frequency and to a sufficient degree to conclude that the reforms are needed.” Order No. 1000-A ¶ 73, 77 Fed.Reg. at 32,197. Although qualified statements, like economic models, “do not always have the reassuring concreteness of empirical observations,” Am. Pub. Gas, 567 F.2d at 1037, the Commission, as was true in Associated Gas Distributors, 824 F.2d at 1008-09, based its remedial findings on “well-established general principles” — for example, that competition will normally lead to lower prices. See Order No. 1000-A ¶ 70, 77 Fed.Reg. at 32,197; see also id. ¶ 60, 77 Fed.Reg. at 32,195. The analysis by The Brattle Group confirms that it required no speculation by the Commission to conclude, “based on [its] expertise and knowledge of the industry, ... that regional transmission planning is more effective if it results in a transmission plan, is open and transparent, and considers all transmission needs.” Id. ¶ 60, 77 Fed.Reg. at 32,195. Similarly, the Commission’s predictive judgment that “the presence of multiple transmission developers would lower costs to customers,” Order No. 1000 ¶ 268, 76 Fed.Reg. at 49,-888 (internal quotation marks omitted), was permissibly grounded in basic economic principles. As the Commission observed, petitioners’ reference to “unsupported assertion[s],” Algonquin Gas, 948 F.2d at 1313, “confuse[s] a theoretical threat, [which is] a potential threat that has not yet materialized, with a theory used in an academic discipline, [which is] an area of activity that is not comparable to the tasks or responsibilities entrusted to a regulatory agency.” Order No. 1000-A ¶ 70, 77 Fed.Reg. at 32,197. See generally Sacramento Mun. Util. Dist. v. FERC, 616 F.3d 520, 530-31 (D.C.Cir.2010).

Petitioners maintain as well that the Commission’s underlying theory is “significantly] flaw[ed]” because its finding that competition in the electricity transmission market will be beneficial fails to recognize that electric transmission is a natural monopoly. Pet’rs’ Threshold Br. 31-32. They suggest there would be no construction of competing transmission systems and firms would not compete by charging lower prices to consumers. Yet this misconceives the basis for the competitive benefits predicted by the Commission. The leading antitrust treatise, on which petitioners rely, instructs that “competí *69 tion for a natural monopoly can be just as beneficial to consumers as competition within an ordinary market.” III Phillip E. ArEEDA & HERBERT HOVENKAMP, ANTItrust Law ¶ 658b3 (3d ed.2008); accord Herbert Hovenkamp, Federal ANTITRUST PoliCY: The Law of Competition and Its PractiCE 34 (4th ed.2011). Known as the theory of contestable markets, the principle states that even in a naturally monopolistic market the threat of competitive entry (e.g., through competitive bidding) will lead firms to lower their costs, which thereby generally lowers cost-based utility rates. See generally Hovenkamp, Federal ANtitrust Policy at 34; Harold Demsetz, Why Regulate Utilities?, 11 J.L. & Econ. 55 (1968). For example, the comments of LS Power Transmission, LLC (“LS Power”), a non-incumbent transmission developer, provided specific examples of non-incumbent developers submitting substantially lower cost estimates for transmission projects than incumbents: In the Texas Competitive Renewable Energy Zone program, “some entities attempted to distinguish themselves through return on equity concessions or other rate-related proposals,” including one proposal estimated to save customers 8-10% annually compared to incumbent provider rates. Reply Comments of LS Power Transmission, LLC at 24 n. 80 (Nov. 12, 2010). LS Power’s own experience in proposing a transmission project in the Midwest ISO region was that its per-mile estimated cost was nearly half that of the incumbent developer’s. See Comments of LS Power Transmission, LLC at 7-9 & n. 15 (Nov. 23, 2009).

Because petitioners point to no “inexplicable distortion” in the competition theory that would render the Commission’s determination arbitrary and capricious, see Associated Gas Distributors, 824 F.2d at 1008 (citing Elec. Consumers Res. Council v. FERC, 747 F.2d 1511, 1514 (D.C.Cir.1984)), the court appropriately defers to the Commission’s expertise and experience, and holds that the Commission has met its burden to support the remedies in the Final Rule with substantial evidence.

C.

Petitioners’ reliance on National Fuel, 468 F.3d 831, is misplaced. There, the Commission had sought to expand standards of conduct based on a “theoretical threat of undue preferences and a claimed record of abuse,” id. at 839 (emphasis added), but failed to cite a single example of abuse by the parties to whom the extended standards would apply, id. at 841. Having failed to support both grounds on which it had purported to act, the Commission failed, the court held, to meet the substantial evidence test. See id. at 843-44. In remanding the case, the court volunteered “guidance” in the event that the Commission decided to proceed solely on the basis of a “theoretical threat.” Id. at 844. Petitioners here contend that the Commission failed to meet National Fuel’s “high bar” in promulgating the Final Rule. Pet’rs’ Threshold Br. 28.

The “guidance” in National Fuel did not purport to establish a generally applicable standard for agency regulation based on a “theoretical threat.” Rather, it was designed to “merely illustrate the kind of analysis” the Commission might undertake on remand. National Fuel, 468 F.3d at 845. But even were the court to assume that the three-part guidance applied, the Commission met that burden. First, petitioners misread National Fuel as requiring the Commission to “explain why evidence of abuse is undetectable.” Pet’rs’ Threshold Br. 28. All the court said was that “[i]f [the Commission] believes that the nature of the alleged misconduct renders it undetectable,” then the Commission “would have to say, for example, why such *70 evidence of abuse was detected [earlier].” National Fuel, 468 F.3d at 844. The Commission made no such claim here; it identified the conduct that led it to conclude the requirements of Order No. 890 were inadequate to meet current and future challenges in the electric transmission industry. See supra Part III.A.

Second, the Commission reasonably balanced the costs stemming from deficient transmission planning and cost allocation practices against the growth in demand for transmission service, concluding that the public interest in just and reasonable electricity rates outweighed claimed burdens and warranted implementing the reforms now. See Order No. 1000-A ¶¶ 91-94, 77 Fed.Reg. at 32,200-01. The Brattle Group’s report was but one example of record evidence documenting the costs of inefficient and irregular planning. Industry projections, and the reasons therefor, established the likelihood of huge growth in demand for electric service. The Commission concluded that the required reforms “will promote considerable economic benefits in the form of lower congestion, greater reliability, and greater access to generation resources.” Id. ¶ 586, 77 Fed.Reg. at 32,275. It also concluded that it was “prudent” to act now rather than “wait for systemic problems to undermine transmission planning.” Order No. 1000 ¶ 50, 76 Fed.Reg. at 49,852. Further, while acknowledging that the mandated transmission planning process, like most high-stakes processes, may engender some disagreements or conflicts, id. ¶ 330, 76 Fed. Reg. at 49,898, the Commission encouraged transmission providers to consider ways to minimize disputes (e.g., through additional transparency mechanisms). Id. And it anticipated that some reforms, particularly to cost allocation practices, would reduce conflicts and “aid in the development and construction of new transmission, as stakeholders will be able to see clearly who is benefitting from, and subsequently who has to pay for, the transmission investment.” Id. ¶ 669, 76 Fed.Reg. at 49,943. Through these reforms, then, stakeholders will “necessarily” determine ex ante “that the benefits associated with [a particular] set of transmission facilities outweigh the costs.” Id. ¶499, 76 Fed. Reg. at 49,921.

Petitioners err in suggesting that the Commission ignored the loss of efficiencies caused by undermining vertical integration, see Pet’rs’ Threshold Br. 34-37, which “occurs when a firm provides for itself some input that it might otherwise purchase on the market.” III.B. Areeda & Hovenxamp ¶ 755a. The Commission acknowledged the potential efficiencies of vertical integration but concluded they provided “no basis for claiming that vertical integration requires the exclusion of nonincumbent transmission developers.” Order No. 1000-A ¶ 90, 77 Fed.Reg. at 32,200. The Commission observed it “would expect that vertically-integrated public utilities will be well positioned to compete in a transmission development process that is open to nonincumbent transmission developers.” Id. Petitioners not only miseharacterize the Commission’s response as an attempt to shift the burden on incumbent providers to justify maintaining vertical integration, see Pet’rs’ Threshold Reply Br. 3, 18-19, their reliance on authority dealing with “vertical integration between a [natural gas] pipeline and its affiliates,” National Fuel, 468 F.3d at 840 (emphasis added), is misplaced, see Pet’rs’ Threshold Br. 34. Based on its experience and expertise, the Commission anticipated that natural market forces would indicate whether vertical integration provides any net competitive advantage in the context of transmission development. See Order No. 1000-A ¶ 90, 77 Fed.Reg. at 32,200. Petitioners offer no basis for con- *71 eluding that the Commission’s judgment regarding the role that vertical integration will play in a competitive transmission planning process is arbitrary and capricious. On rehearing the Commission also observed that “[t]he existence of vertical integration does not imply that the vertically integrated public utility must be a monopoly.” Order No. 1000-A ¶ 90, 77 Fed.Reg. at 32,200; see IIIB Aheeda & Hovenxamp ¶ 759e5. Petitioners’ response that the Commission’s analysis “has conflated the concepts of monopoly and vertical integration,” Pet’rs’ Threshold Br. 36, is ipse dixit contradicted by the Areeda treatise upon which it relies.

Third, the Commission explained that the problem it was addressing was “systemic,” Order No. 1000 ¶ 50, 76 Fed.Reg. at 49,852, and “not one that can be addressed adequately or efficiently through the adjudication of individual complaints,” which “by their nature focus on discrete questions of a specific case,” id. ¶ 52, 76 Fed.Reg. at 49,852. In the Commission’s judgment, “[r]ules setting forth general principles are necessary to ensure that adequate planning processes are in place.” Id. “[T]he decision whether to proceed by rulemaking or adjudication lies within the broad discretion of the agency,” and deference to the Commission’s decision here is “particularly appropriate” because “ ‘the breadth and complexity of the Commission’s responsibilities demand that it be given every reasonable opportunity to formulate methods of regulation appropriate for the solution of its intensely practical difficulties.’ ” Wisconsin Gas, 770 F.2d at 1166 (quoting Permian Basin Area Rate Cases, 390 U.S. at 790, 88 S.Ct. 1344) (citing SEC v. Chenery Corp., 332 U.S. 194, 202-03, 91 L.Ed. 1995 (1947)).

Finally, petitioners’ reliance on FPA Section 217(b)(4) is also misplaced. That provision, in pertinent part, requires the Commission to exercise its authority “in a manner that facilitates the planning and expansion of transmission facilities to meet the reasonable needs of load-serving entities to satisfy the[ir] service obligations.” 16 U.S.C. § 824q(b)(4). Petitioners maintain “[i]t is implausible to characterize load serving entities’ loss of control over the development of needed facilities as ‘facilitating’ their ability to plan and expand the transmission system.” Pet’rs’ Threshold Br. 40-41. The Commission determined, however, that “[g]reater participation by transmission developers in the transmission planning process may lower the cost of new transmission facilities, enabling more efficient or cost-effective deliveries by load serving entities and increased access to resources.” Order No. 1000 ¶291, 76 Fed.Reg. at 49,892; see Order No. 1000-A ¶ 178, 77 Fed.Reg. at 32,213-14. Petitioners offer no basis to reject the Commission’s conclusion that the Final Rule “supports the development of needed transmission facilities, which ultimately benefits loadserving entities,” and that “servfing] the interests of other stakeholders ... does not place [the Final Rule] in conflict with section 217.” Order No. 1000 ¶ 108, 76 Fed.Reg. at 49,861; see also infra Part VLB.

IV.

Removal of Federal Rights of First Refusal. In addition to attacking the transmission planning mandate generally, petitioners raise a host of challenges to the requirement that public utilities remove certain rights of first refusal from their tariffs and agreements. 5 See Order *72 No. 1000 ¶¶ 67, 225, 76 Fed.Reg. at 49,854, 49,880. We conclude that the removal mandate is a legitimate exercise of the Commission’s authority and reject petitioners’ arguments.

A.

Prior to the removal mandate, utilities’ tariffs and agreements routinely included rights of first refusal. These rights gave incumbent utilities the option to construct any new transmission facilities in their particular service areas, even if the proposal for new construction came from a third party. In practice, incumbents were likely to exercise their rights of first refusal once the benefits of a new project were demonstrated. In this way, rights of first refusal discouraged non-incumbents from proposing transmission facilities. 6 Not only would nonincumbents be unlikely to recoup the full benefits of their proposal, but they would not even be able to recoup the costs of identifying the need and making a proposal that would address it. Id. ¶¶ 256-57, 76 Fed.Reg. at 49,886.

The Commission feared that this lack of an incentive for non-incumbents to propose needed infrastructure would ultimately give rise to unlawful rates for customers. By deterring proposals from non-incumbents, rights of first refusal would impede the identification of some cost-efficient projects, resulting in the development of transmission facilities “at a higher cost than necessary.” Id. ¶¶ 228-30, 76 Fed. Reg. at 49,880-81. Those higher costs would then be passed on to customers, yielding rates that were “not just and reasonable,” id., in violation of the FPA. The Commission’s concerns were particularly acute in light of its expectation that a massive amount of transmission facility development would take place during the next two decades as renewable energy sources were integrated into the grid. See id. ¶¶ 29, 44-47, 76 Fed.Reg. at 49,849, 49,851-52.

To address this problem created by rights of first refusal, the Commission proposed requiring their elimination. NPRM ¶ 89, 75 Fed.Reg. at 37,896. The Federal Trade Commission submitted comments supporting the Commission’s proposal, observing that rights of first refusal reduce investment opportunities for non-incumbents. Several state utility commissions and municipal utilities echoed that view. See Order No. 1000 ¶¶ 231-37, 76 Fed.Reg. at 49,881-82.

A number of incumbents responded that there was no need for the removal mandate because current processes were working well and attracting new developers. Id. ¶ 239, 76 Fed.Reg. at 49,882-83. Banning rights of first refusal, argued the incumbents, would require empirical evidence that they were adversely affecting rates. Such evidence did not exist, they claimed, because incumbents were better suited to develop transmission infrastructure, due to their expertise and relationships with state regulators. Any lower costs the Commission anticipated from removing rights of first refusal from tariffs and agreements would be offset by ineffi *73 ciencies in the transmission planning process — such as a loss of economies of scale and scope — that would necessarily accompany the entry of new players less experienced in the development of transmission than the incumbents. Moreover, the incumbents contended, removing rights of first refusal posed significant risks to transmission system reliability and integrity, since nonincumbents might lack the financial backing or technical expertise necessary to complete projects on time. Id. ¶¶ 240-50, 76 Fed.Reg. at 49,883-85.

The Commission proceeded with the proposed ban, id. ¶¶ 253-56, 76 Fed.Reg. at 49,885-86, but limited its reach to those facilities whose costs would be allocated according to the principles established in the regional transmission plan. This limitation was born of the Commission’s concern that a complete ban could potentially threaten grid reliability if nonincumbents failed to complete needed projects in a timely fashion. The upshot was that rights of first refusal could be retained for facilities located wholly within the service territory of an incumbent whose development costs would not be spread to other parties (which the challenged orders refer to as “local transmission facilities]”). Id. ¶¶ 63, 258, 76 Fed.Reg. at 49,854, 49,886.

The Commission further addressed reliability concerns with several additional requirements. For example, the Commission required each region to craft “criteria for determining an entity’s eligibility to propose a transmission project for selection in the regional transmission plan,” contemplating that these criteria would serve as benchmarks for prospective developers, who would be required to “demonstrate ... the necessary financial resources and technical expertise to develop, construct, own, operate and maintain transmission facilities.” Id. ¶¶ 323-24, 76 Fed.Reg. at 49,897. The Commission also required each region to implement procedures for periodically reevaluating its transmission plan to determine if development delays required identification of alternative solutions, id. ¶¶ 263, 329, 76 Fed. Reg. at 49,887, 49,898, thereby increasing the likelihood that potential threats to reliability would be identified and mitigated before they materialized.

On rehearing, the Commission responded to objections by some incumbents who argued that the Commission could not lawfully strip them of their rights of first refusal without finding that those rights harmed the public interest. Specifically, they asserted that their rights were protected by the Mobile-Sierra doctrine. See NRG Power Mktg., LLC v. Me. Pub. Utils. Comm’n, 558 U.S. 165, 167, 130 S.Ct. 693, 175 L.Ed.2d 642 (2010). The Commission promised to consider the petitioners’ Mobile-Sierra arguments when it reviewed the new OATTs that they were required to file to comply with the orders. Order No. 1000-A ¶¶ 388-89, 77 Fed.Reg. at 32,245.

B.

Petitioners rest their first challenge to the right of first refusal mandate on FPA Section 206. The Commission concluded that including rights of first refusal in tariffs and agreements was a “practice ... affecting ... rate[s]” within the meaning of the statute. Petitioners, who bear the burden of demonstrating agency error, see Telecomms. Research & Action Ctr. v. FCC, 801 F.2d 501, 510 (D.C.Cir.1986), challenge that determination, but we uphold it under the Chevron framework, see, e.g., Bhd. of R.R. Signalmen v. Surface Transp. Bd., 638 F.3d 807, 811 (D.C.Cir.2011).

We begin by asking whether “Congress has .directly spoken” to the issue of whether the inclusion of rights of first refusal in tariffs and agreements constitutes a prac *74 tice that affects rates. See Bhd. of R.R. Signalmen, 638 F.3d at 811 (internal quotation marks omitted). If it has, we give effect to Congress’s unambiguously expressed intent. Id. On its face, Section 206 seems ambiguous. Not only does it say nothing about rights of first refusal, but it does not even tell us what constitutes a practice affecting rates. Even so, petitioners raise two arguments that the statute unambiguously forecloses the Commission’s mandate.

Petitioners first argue that the relationship between rights of first refusal and rates is too attenuated to trigger the Commission’s authority under Section 206, which is limited to practices “affecting” a rate. Petitioners rely primarily on CAISO, 372 F.3d 395. In that case, the court explained that the Commission’s Section 206 authority “is limited to those methods or ways of doing things on the part of the utility that directly affect the rate or are closely related to the rate, not all those remote things beyond the rate structure that might in some sense indirectly or ultimately do so.” Id. at 403. The structure of a corporate board, we held, was too far removed from the rates that would ultimately be charged by a utility to qualify as a “practice ... affecting” a “rate” within the meaning of Section 206. See id.

Petitioners contend that the relationship between rights of first refusal and rates is just as attenuated. We disagree. Unlike the corporate governance matters at issue in CAISO, a generally accepted principle of economics directly connects rights of first refusal to rates. Transmission service providers recoup the costs of their transmission facilities through their rates. See, e.g., Pub. Serv. Comm’n of Wis. v. FERC, 545 F.3d 1058, 1060-61 (D.C.Cir.2008). The lower those costs, the lower their rates. See NEPCO Mun. Rate Comm. v. FERC, 668 F.2d 1327, 1335 (D.C.Cir.1981) (“[A] regulated utility is allowed to recover from ratepayers all of its expenses, including income taxes, plus a reasonable return on capital invested in the enterprise and allocated to public use.”). And basic economic principles make clear that rights of first refusal are likely to have a direct effect on the costs of transmission facilities because they erect a barrier to entry: namely, non-incumbents are unlikely to participate in the transmission development market because they will rarely be able to enjoy the fruits of their efforts. See II.B. Phillip E. Areeua et al„ Antitrust Law 71 (3d ed. 2007) (“[A] barrier to entry is best defined as any factor that permits firms already in the market to earn returns above the competitive level while deterring outsiders from entering. In the perfectly competitive model, prices above the competitive level attract entry until the newcomers restore total market output to the competitive level, thus bringing about competitive performance.” (footnote omitted)). See generally 2 The New Palgrave: A Dictionary of Economics 156 (John Eatwell et al. eds., 1987) (“Entry — and its opposite, exit— have long been seen to be the driving forces in the neoclassical theory of competitive markets.”).

The relationship between rights of first refusal and rates is far more direct than the relationship between corporate governance and rates. See Order No. 1000 ¶ 289, 76 Fed.Reg. at 49,891; Order No. 1000-A ¶¶ 76-90, 77 Fed.Reg. at 32,198-200. Nothing suggests that replacing the members of a board will necessarily affect rates. The new board members may manage the company well, manage it poorly, or merely stay the course. We simply do not know. The challenged orders here provide what was lacking in CAISO: an economic principle that directly ties the practice the *75 Commission sought to regulate to rates. Compare CAISO, 372 F.3d at 403. 7

Petitioners’ next argument is based on a comparison of the FPA and the Natural Gas Act (“NGA”). The NGA contains a provision analogous to Section 206 of the FPA that gives the Commission authority to regulate “practice[s] ... affecting ... rate[s]” for natural gas. See 15 U.S.C. § 717d. But the NGA also contains a separate provision expressly authorizing the Commission to regulate certain matters relating to the construction of natural gas pipelines. See id. § 717f (allowing the Commission to order “a natural-gas company to extend or improve its transmission facilities” or to “establish physical connection of its transportation facilities with the facilities of’ other natural gas distributors). Petitioners argue that the existence of this separate “construction” provision proves that the Commission’s “practices affecting rates” power under the NGA does not authorize regulation of gas pipeline construction matters: if it did, there would be no need for the separate provision. See Corley v. United States, 556 U.S. 303, 314, 129 S.Ct. 1558, 173 L.Ed.2d 443 (2009) (“[A] statute should be construed so that effect is given to all its provisions, so that no part will be inoperative or superfluous, void or insignificant.” (internal quotation marks omitted)). Pointing to statements in our case law observing the similarity between the NGA and FPA and suggesting that interpretations of one should strongly inform interpretations of the other, see, e.g., Ky. Utils. Co. v. FERC, 760 F.2d 1321, 1325 n. 6 (D.C.Cir.1985), petitioners contend that the same “practices affecting rates” language in Section 206 of the FPA must likewise not include a grant of authority to the Commission to regulate the building of transmission infrastructure on the grid.

Petitioners’ argument is unconvincing and certainly does not demonstrate that Section 206 unambiguously precludes the Commission’s assertion of authority. In the first place, although we have observed the similarity between the FPA and NGA, and posited that the two statutes “should be interpreted consistently,” TAPS, 225 F.3d at 686, where the texts of the acts differ in some material respect, interpretations will diverge as well. Perhaps petitioners’ real point is that the NGA demonstrates that any time that Congress wants to give the Commission authority over construction matters, it does so clearly and directly. But the superfluity canon does not compel such an expansive reading of the NGA “construction” provision that petitioners invoke. Rather than give the Commission blanket authority over all construction-related matters, the provision instead authorizes it to order “a natural-gas company to extend or improve its transmission facilities” or “establish physical connection of its transportation facilities with the facilities of’ other natural gas companies. See 15 U.S.C. § 717f(a). And the challenged orders do not require transmission providers to do either of these activities. Thus, even assuming an absolute obligation to interpret the NGA and FPA in lockstep, there would be no superfluity. The NGA “construction” provision *76 gives the Commission authority over different matters than those it addressed in the challenged orders.

Because Section 206 does not unambiguously resolve the question of whether rights of first refusal are practices affecting rates, we move to Chevron step two, which requires us to uphold an agency’s reasonable interpretation of a statute it administers. See Brand X Internet Servs., 545 U.S. at 980, 125 S.Ct. 2688. As is clear from our discussion above, we think that the Commission’s reading of Section 206 is reasonable. Petitioners give us no persuasive reason to think otherwise. The only Chevron step two argument that they advance maintains that the Commission’s construction of Section 206 interferes with the States’ traditional authority to deny or approve transmission facility siting and construction. 8 But, as discussed already, see supra Part II.C, the challenged orders take great pains to avoid intrusion on the traditional role of the States, making clear that although federal rights of first refusal were being removed, “nothing in th[e] Final Rule is intended to limit, preempt, or otherwise affect state or local laws or regulations with respect to construction of transmission facilities, including but not limited to authority over siting or permitting of transmission facilities.” Order No. 1000 ¶ 227, 76 Fed.Reg. at 49,880. Thus, States retain control over the siting and approval of transmission facilities. Even if the Commission’s mandate opens up opportunities for nonincumbents, such developers must still comply with state law.

In sum, Section 206 is ambiguous, and the Commission reasonably concluded that inclusion of rights of first refusal in tariffs and agreements is a “practice ... affecting [a] rate.” The Commission therefore was authorized to regulate rights of first refusal to the extent it found their inclusion was unjust or unreasonable, which brings us to petitioners’ next challenge.

C.

Petitioners contend that the Commission did not support with substantial evidence, see 16 U.S.C. § 825J (b), its finding that the practice of including rights of first refusal in Commission tariffs and agreements was unjust or unreasonable. Although the Commission was not required to do more than “specify the evidence on which it relied and ... explain how that evidence supported] the conclusion it reached,” see Wisconsin Gas, 770 F.2d at 1156 (internal quotation marks omitted), petitioners claim that the right of first refusal removal mandate does not clear even that low hurdle. They contend that the mandate rested on a mere prediction, which can never support a finding that a “practice” is “unjust” or “unreasonable.” But this argument is one we have already addressed and rejected. See supra Part III. To repeat: at least in circumstances where it would be difficult or even impossible to marshal empirical evidence, the Commission is free to act based upon reasonable predictions rooted in basic economic principles. See Order No. 1000-A ¶ 80, 77 Fed.Reg. at 32,199 (responding to the argument that “the Commission has not identified an instance where federal rights of first refusal have led to advérse effects on rates” by noting that “[w]e do not think it is surprising that there is limited evidence of exclusion of nonincum- *77 bent transmission developers” given that rights of first refusal give rise to a “situation that discourages [nonincumbents] from proposing projects in the first place”). In this case, the Commission rested its right of first refusal ban on competition theory, determining that rights of first refusal posed a barrier to entry that made the transmission market inefficient, that transmission facilities would therefore be developed at higher-than-necesshry cost, and that those amplified costs would be passed on to transmission customers.

Petitioners argue, however, that reliance on competition theory is misplaced. They contend that because transmission is a natural monopoly, the right of first refusal ban is really nothing more than a regulation that makes non-incumbents eligible to own transmission lines, and argue that there is no reason to think that who owns a line will affect rates. But much more is at work in the orders than this argument assumes. While they undoubtedly will have some effect on line ownership, the focus of the orders is on improving the process through which needed infrastructure is identified and planned. As already explained, there is ample reason to think that injecting competition into the planning process will help to ensure that rates remain just and reasonable. See supra Parts III.B. and IV.B.

In response, petitioners offer two reasons to doubt the effect of competition on rates. Neither is persuasive. First, they argue that Commission rules predating the challenged orders that required transmission providers to seek and accept input from interested stakeholders in planning for transmission infrastructure development already made likely that cost-effective solutions to transmission needs would be identified. Although petitioners are no doubt correct that the previous regime improved transmission planning, non-incumbent developers were not likely to participate in that regime because rights of first refusal left them with little to gain. See Order No. 1000 ¶ 229, 76 Fed.Reg. at 49, 881. By removing a pre-existing barrier to entry, the orders make it more likely that those key parties will actually join that process, making the transmission development process more competitive, which, in the Commission’s reasoned expert judgment, will help to ensure that rates are just and reasonable. See id. ¶¶ 256-57, 76 Fed.Reg. at 49,886; see also Order No. 1000-A ¶¶ 76-90, 77 Fed.Reg. at 32,198-200.

Petitioners also argue that the- market for infrastructure development was already competitive prior to the challenged orders because non-incumbents have always been allowed to pursue so-called “merchant transmission projects,” whose construction costs are “recovered through negotiated rates instead of cost-based rates.” Order No. 1000 ¶ 119, 76 Fed.Reg. at 49,863; see also Blumenthal v. FERC, 552 F.3d 875 (D.C.Cir.2009) (discussing the difference between these types of rates). But those pursuing merchant projects are limited to charging what the market will bear, whereas other developers are guaranteed rates that both compensate for their costs and provide a reasonable rate of return. The risk of a merchant project is substantially greater than the risk of a project eligible for cost-based rates (the type of project the right of first refusal ban targets), see Order No. 1000 ¶ 163, 76 Fed.Reg. at 49,870, making it significantly less likely that merchant projects will be proposed (as a higher anticipated payout would be needed to justify taking on additional risk). Petitioners give no persuasive reason to doubt that the right of first refusal ban targeted a real deficiency in the transmission infrastructure development market and thus fail to satisfy their *78 “burden of demonstrating” that the Commission erred. See Nat’l Small Shipments Traffic Conference, Inc. v. ICC, 725 F.2d 1442, 1455 (D.C.Cir.1984). We accordingly reject petitioners’ challenges regarding the Commission’s Section 206 authority to require removing rights of first refusal.

D.

Petitioners next contend that even if the Commission had the necessary authority, its ban on rights of first refusal was “arbitrary, capricious ... or otherwise not in accordance with law” for a variety of reasons. See 5 U.S.C. § 706(2)(A). But petitioners have failed to shoulder their burden of demonstrating that the Commission misstepped. See Lomak Petroleum, Inc. v. FERC, 206 F.3d 1193, 1198 (D.C.Cir.2000).

1. Petitioners first argue that the Commission failed to consider the costs of the ban, claiming that they swamp any anticipated competitive benefit. Petitioners point to the loss of the advantages of vertical integration, interference with existing planning processes which allegedly were open and collaborative, and a reduction of transmission system reliability. Contrary to petitioners’ claim, however, the Commission squarely addressed each of these costs, satisfying its obligation to engage in reasoned decision-making. See State Farm, 463 U.S. at 43, 103 S.Ct. 2856.

As to the asserted loss of the benefits of vertical integration, the Commission explained that removing rights of first refusal did not “diminish[] the importance” of factors such as incumbents’ “unique knowledge of their own transmission systems, familiarity with the communities they serve, economies of scale, experience in building and maintaining transmission facilities, and access to funds needed to maintain reliability.” Order No. 1000 ¶ 260, 76 Fed.Reg. at 49,887. Even with the ban, incumbents remained “free to highlight [their] strengths to support transmission project(s)” during the regional transmission planning process, such that there was no need to categorically exclude non-incumbent transmission developers from “presenting [their] own strengths in support of ... proposals or bids.” Id.

Although the Commission shared the view of the petitioners that the “collaborative nature of current regional transmission planning processes” was valuable and worthy of preservation, it did not expect the ban to disrupt those processes. Id. ¶ 258, 76 Fed.Reg. at 49,886. Earlier planning mandates had already required transmission providers to implement measures for weighing alternative solutions and deciding which ones would best meet the region’s needs. See id. Petitioners contend, however, that the challenged orders are nearly certain to disrupt existing planning processes because they create a perverse incentive for incumbents to avoid participating fully in that planning. Petitioners predict that incumbents will now prefer to construct only projects for which they may retain rights of first refusal, projects which must be both wholly located within the incumbent’s service territory and not submitted for regional cost allocation, in order to minimize encroachment on their service territory. But this argument overlooks that the Commission determined that, even with the ban, incumbents have incentives to propose projects in the regional transmission planning process. Only such projects are eligible for mandatory cost allocation, which allows the incumbent to spread the costs of new infrastructure among all who benefit from it. See Order No. 1000-A ¶¶ 179, 423, 77 Fed. Reg. at 32,214, 32,251.

The petitioners also argued before the Commission that the non-incumbents’ lack of experience might so delay the develop *79 ment of transmission infrastructure that capacity would be unavailable when needed. The Commission reasonably rejected this argument, concluding that several aspects of the Final Rule adequately addressed reliability concerns. First, the orders anticipate that some non-incumbents might not be up to the task and call for each region to establish minimum standards designed to ensure that those selected to build new infrastructure have the necessary resources and expertise. Second, the orders require regions to put in place processes for monitoring the progress of projects in their region and assessing whether unanticipated delays require alternative solutions. 9 Third, the orders sought to minimize the risk that the non-incumbents’ poor performance would harm incumbents by limiting the ban’s scope, permitting incumbents to retain rights of first refusal for upgrades to their existing transmission facilities and for “local” facilities. Fourth, the orders require “all entities” that operate regional transmission facilities, “incumbent and nonincumbent alike” to register with NERC and comply with all applicable reliability standards. See Order No. 1000 ¶¶260, 262-64, 266, 342, 76 Fed.Reg. at 49,887-88, 49,900; Order No. 1000-A ¶¶ 425, 428, 442-43, 77 Fed.Reg. at 32,251-52, 32,254. The Commission carefully considered the risk that its right of first refusal ban might harm grid reliability and responded with a paek-age of reforms designed to prevent that risk from materializing. 10

2. Section 215 of the FPA directs the Commission to designate an Electric Reliability Organization (ERO) to “establish and enforce reliability standards for the bulk-power system, subject to Commission review.” 16 U.S.C. § 8240(a)(2). The Commission has designated NERC as the ERO. See generally Alcoa, 564 F.3d at 1344-45 (providing background about NERC). NERC, not the Commission, has primary responsibility for creating mandatory standards designed to “provide for an adequate level of reliability of the Bulk-Power System.” See N. Am. Electric Reliability Corp., 116 F.E.R.C. ¶ 61,062 at ¶ 25. In fact, when the Commission disapproves of a NERC reliability standard, it can only remand the standard to NERC. 16 U.S.C. § 824o(d)(4). It may not modify the standard directly. The Commission may, however, order NERC to address specific problems on remand. Id. § 824o(d)(5). Importantly, though, FPA Section 215 does not authorize the Commission or NERC to “order the construction of additional generation or transmission capacity.” Id. § 824o(i)(2).

The petitioners argue that several components of the ban on rights of first refusal violate Section 215. They first target the requirements that transmission providers must (1) periodically evaluate the progress *80 of infrastructure construction projects that could impact system reliability, and (2) submit a NERC mitigation plan designed to prevent any reliability concerns from materializing. Operating from the premise that these requirements are new, petitioners argue that only NERC, and not the Commission, could impose them. But their argument fails because its premise is false. Existing NERC reliability standards already required such monitoring and mitigation. See Order No. 1000-A ¶ 479, 77 Fed.Reg. at 32,259; see also Cal. Indep. Sys. Operator Corp., 143 F.E.R.C. ¶ 61,057 at ¶ 269 (Apr. 18, 2013). See generally NERC Reliability Standards for the Bulk Electric Systems of North America, Transmission Planning and Facilities Connection Series, available at http://www. nerc.com/pa/Stand/Pages/AHReliability Standards.aspx?jurisdiction=UnitedStates (last visited Aug. 1, 2014). Thus, because the challenged orders did not modify NERC’s reliability standards, the Commission did not need to follow the process prescribed by Section 215 for changing them. 11

Petitioners also argue that the orders’ duty to develop mitigation plans runs afoul of Section 215’s declaration that it “does not authorize [NERC] or the Commission to order the construction of additional ... transmission capacity.” 16 U.S.C. § 824o(i)(2). They contend that a non-incumbent’s failure to complete a transmission project might require an incumbent to step in and complete construction. But though this may be the ideal method of mitigation, other approaches are also possible. See, e.g., Conn. Dep’t of Pub. Util. Control v. FERC, 569 F.3d 477, 480 (D.C.Cir.2009) (explaining that certain end users of power can “reduce their demand during shortages”); see also Electric Power Supply Ass’n v. FERC, 753 F.3d 216, 221 (D.C.Cir.2014) (“Demand response will also increase system reliability.”). More importantly, the challenged orders repeatedly make clear that incumbents are never required to mitigate by constructing new capacity. See Order No. 1000 ¶ 344, 76 Fed.Reg. at 49,900; Order No. 1000-A ¶ 490, 77 Fed.Reg. at 32,260. Accordingly, the challenged orders do not violate Section 215’s bar against requiring construction.

In comments submitted during the rule-making process, incumbents expressed concern that they might be penalized by NERC for reliability violations stemming from the failures of non-incumbents beyond their control. The Commission responded by promising not to penalize incumbents for such reliability violations. See Order No. 1000-A ¶ 480, 77 Fed.Reg. at 32,259. Petitioners contend that this promise was incompatible with Section 215 because NERC, not the Commission, is the entity directed to police reliability standards and NERC lacks authority to waive noncompliance penalties. What petitioners miss, however, is that even if NERC imposed such a penalty on an incumbent, the Commission, which is authorized to review all NERC penalties, would be able to honor the promise it made in the challenged orders by freeing that incumbent from the penalty. See 16 U.S.C. *81 § 824o(e)(2). Petitioners thus fail to demonstrate that the challenged orders violate Section 215.

3. According to the petitioners, the orders’ right of first refusal removal mandate violates the Mobile-Sierra doctrine, which presumes that freely-negotiated wholesale-energy contracts are just and reasonable unless found to seriously harm the public interest. See NRG Power Mktg., 558 U.S. at 167, 130 S.Ct. 693. Some of the petitioners argue that the Commission unlawfully deprived them of their rights of first refusal without making the finding required to rebut the Mobile-Sierra presumption. But this argument misconstrues the challenged orders, which, as noted already, make clear that the Commission will hear the petitioners’ Mobile-Sierra arguments when it reviews the new OATTs that utilities must file to comply with the orders. Order No. 1000-A ¶¶ 388-89, 77 Fed.Reg. at 32,245; cf. also Mobil Oil Exploration & Producing Se. Inc. v. United Distrib. Cos., 498 U.S. 211, 230, 111 S.Ct. 615, 112 L.Ed.2d 636 (1991) (explaining that an agency has “broad discretion in determining how best to handle related, yet discrete, issues in terms of procedures” and that an agency is free to treat a particular issue in a “different proceeding” where that “proceeding would generate more appropriate information and where the agency was addressing the question”); TAPS, 225 F.3d at 709.

To the extent petitioners are asking us to weigh in now on whether or how Mobile-Sierra will ultimately apply to particular contracts, we decline their invitation. Given that the Commission deferred consideration of the issue, the “decision has [not yet] been formalized and its effects [have not been] felt in a concrete way by the challenging parties.” Associated Gas Distributors, 824 F.2d at 1007 (internal quotation marks omitted). Thus, our involvement would be premature. See Nevada v. Dep’t of Energy, 457 F.3d 78, 85-86 (D.C.Cir.2006) (clarifying that an issue is not “fit for judicial review” where “further administrative action is needed to clarify the agency’s position” (internal quotation marks omitted)).

We also see no need to enter an order precluding the Commission from holding, in later proceedings, that petitioners may not raise their argument because it is collaterally barred. As explained, the challenged orders make clear that the Commission will consider the issue during compliance. See Order No. 1000 ¶ 292, 76 Fed.Reg. at 49,892; Order No. 1000-A ¶¶ 388-89, 77 Fed.Reg. at 32,245. We have no reason to doubt that the Commission will honor its promise. See Comcast Corp. v. FCC, 526 F.3d 763, 769 n. 2 (D.C.Cir.2008) (explaining that this court presumes that an “agency acts in good faith”). If it fails to do so, its decision will be reviewable.

Finding no merit in any of petitioners’ right of first refusal challenges, we deny those portions of their petitions that attack the ban.

y.

Cost Allocation. As a key element of the regional planning process, the Final Rule requires transmission providers to devise methods for allocating the costs of certain new transmission facilities to those entities that benefit from them. In keeping with the overall approach of the transmission planning reforms, the Final Rule uses a light touch: it does not dictate how costs are to be allocated. Rather, the Rule provides for general cost allocation principles and leaves the details to transmission providers to determine in the planning processes.

*82 Two groups of petitioners challenge the cost allocation provisions on nearly opposite grounds. One, the Joint Petitioners, contends that the Commission lacks sufficient statutory authority to adopt the cost allocation requirements. The other, the International Transmission Company Petitioners (“ITC Petitioners”), asserts that the Commission acted arbitrarily and capriciously in adopting them, essentially because the agency did not go far enough. We disagree on both counts.

A.

Before the current reforms, the Commission did not mandate that the costs of new transmission facilities be allocated ex ante to those who would benefit from those facilities. The Commission has since concluded that the lack of any method or process to ensure that new facilities were paid for by those that benefitted from them created perverse incentives — indeed, a sort of tragedy of the transmission commons.

As the Commission explained, the challenges associated with allocating the cost of new or improved transmission facilities have become more pressing as the need for such infrastructure has grown. Order No. 1000 ¶ 485, 76 Fed.Reg. at 49,919. That is because “constructing new transmission facilities requires a significant amount of capital and, therefore, a threshold consideration for any company considering investing in transmission is whether it will have a reasonable opportunity to recover its costs.” Id. In the Commission’s view, the lack of methods that ascertain the beneficiaries of new and improved transmission facilities and allocate costs to entities that benefit “creates significant risk for transmission developers that they will have no identified group of customers from which to recover the cost of their investment.” Id. The Commission reasoned:

[T]he risk of the free rider problems associated with new transmission investment is particularly high for projects that affect multiple utilities’ transmission systems and therefore may have multiple beneficiaries. With respect to such projects, any individual beneficiary has an incentive to defer investment in the hopes that other beneficiaries will value the project enough to fund its development.... [O]n one hand, a cost allocation method that relies exclusively on a participant funding approach, without respect to other beneficiaries of a transmission facility, increases this incentive and, in turn, the likelihood that needed transmission facilities will not be constructed in a timely manner. On the other hand, if costs would be allocated to entities that will receive no benefit from a transmission facility, then those entities are more likely to oppose selection of the facility in a regional transmission plan for purposes of cost allocation or to otherwise impose obstacles that delay or prevent the facility’s construction.

Id. ¶ 486, 76 Fed.Reg. at 49,919 (footnote omitted).

The Commission anticipated that such misalignment of incentives would become more acute due to the “growing need for new transmission facilities [including those] that cross ... regions” created by “the expansion of regional power markets.” Id. ¶ 484, 76 Fed.Reg. at 49,919. In addition, the Commission noted that the “increasing adoption of state resource policies, such as renewable portfolio standards, has contributed to the rapid growth of renewable energy resources that are frequently remote from load centers.” Id. In short, the Commission recognized that, unless costs were allocated to those who benefit, needed expansion and improve *83 ment of the power grid would not likely occur. The Commission accordingly concluded that “existing cost allocation methods may not appropriately account for benefits associated with new transmission facilities and, thus, may result in rates that are not just and reasonable or are unduly discriminatory or preferential.” Id. ¶ 487, 76 Fed.Reg. at 49,919.

For these reasons, in the Final Rule, the Commission required each public utility transmission provider to participate in a regional transmission planning process that includes, with regard to cost allocation, both:

(1) “[a] regional cost allocation method for the cost of new transmission facilities selected in a regional transmission plan for purposes of cost allocation”; and

(2) “an interregional cost allocation method for the cost of certain new transmission facilities that are located in two or more neighboring transmission planning regions and are jointly evaluated by the regions in the interregional transmission coordination procedures required by this Final Rule.”

Order No. 1000 Summary, 76 Fed.Reg. at 49,842.

The reforms do not require any particular provider to pay for new facilities or dictate precisely how costs must be allocated. Instead, the Commission requires public utilities to have in place a method or methods for allocating the costs of new transmission facilities “in a manner that is at least roughly commensurate with the benefits received by those who will pay those costs,” and for ensuring that costs are not “involuntarily allocated to entities that do not receive benefits.” Id. ¶ 10, 76 Fed.Reg. at 49,846.

To implement these reforms, the Commission requires each public utility transmission provider to include in its OATT both “a method, or set of methods, for allocating the costs of new transmission facilities selected in the regional transmission plan” and “a method or set of methods for allocating the costs of new interre-gional transmission facilities.” Id. ¶ 482, 76 Fed.Reg. at 49,918. Each utility in a region “must include the same cost allocation method or methods adopted by the region.” Id. ¶ 482, 76 Fed.Reg. at 49,919; Order No. 1000-A ¶ 528, 77 Fed.Reg. at 32,266. The Commission also required both regional and interregional cost allocation method(s) to adhere to six specified principles, including, for example, that costs must be allocated roughly commensurately with benefits, that those entities that receive no benefit must not be involuntarily allocated costs, and that the allocation method(s) for the costs of a regional facility must assign costs within the transmission planning region unless entities outside the region voluntarily assume them. See Order No. 1000 KH586-87, 76 Fed.Reg. at 49,982-33.

Thus, although the Final Rule requires each public utility in a region to include the same cost allocation method(s) in its OATT, it does not dictate either how the costs should be allocated in any more detail than those general principles, nor does the Rule specify how costs should be recovered (i. e., how the new facilities should be paid for). The Commission, moreover, requires cost allocation only for new transmission facilities that are chosen for cost allocation during the regional planning process — meaning that cost allocation will be triggered only in cases in which the transmission providers in a region, in consultation with stakeholders, evaluate a given facility and determine that its benefits merit cost allocation under the regional cost allocation method(s). - Id. ¶ 539, 76 Fed.Reg. at 49,926-27; Order No. 1000-A ¶ 579, 77 Fed.Reg. at 32,274.

*84 B.

Petitioners dispute the Commission’s authority to adopt the cost allocation reforms under Section 206 of the FPA. The key inquiry here, as in Parts II.A and IV.B supra is whether cost allocation constitutes a “practice” “affecting ... rate[s]” under Section 206 of the FPA such that the Commission may fix it by order. 16 U.S.C. § 824e(a).

Petitioners do not dispute that the allocation of costs of new transmission facilities is a “practice” that at least in principle can “affect” a “rate.” This court has previously held that the Commission has “clear” authority to reallocate capacity and production costs. La. Pub. Serv. Comm’n v. FERC, 522 F.3d 378, 389-90 (D.C.Cir.2008); Miss. Indus. v. FERC, 808 F.2d 1525, 1540 (D.C.Cir.1987) (“[D]istribution of [a facility’s] costs and capacity in [a cost-sharing agreement] inevitably affects [the allocated companies’] generation costs and, by extension, their wholesale rates.”). Indeed, quite recently we noted that “in principle, a ‘beneficiary pays’ approach is a just and reasonable basis for allocating the costs of regional transmission projects, even if it leads to reallocating sunk costs.” FirstEnergy Serv. Co. v. FERC, 758 F.3d 346, 354-55, No. 12-1461, 2014 WL 3538062, at *1 (D.C.Cir. July 18, 2014).

The central thrust of Joint Petitioners’ statutory argument is that Section 206 does not authorize the Commission to require utilities to pay for the costs of transmission facilities developed by entities with whom they have no prior contractual or customer relationship and from whom they do not take transmission service. Joint Br. of Pet’rs/Intervenors Concerning Cost Allocation 2 (“Joint Pet’rs’ Br.”). In the Joint Petitioners’ view, Section 206 unambiguously forecloses the Commission from mandating the allocation of costs beyond pre-existing commercial relationships, and the cost allocation reforms thus fail at Chevron step one.

No such limitation exists in the statutory text. Section 206 empowers the Commission to fix any “practice” affecting rates, and the Commission reasonably understood beneficiary-based cost allocation — or its absence — to be a practice affecting rates. Section 206 nowhere limits cost allocation to entities with preexisting commercial relationships. To the contrary, it empowers the Commission to fix “any rate” “demanded, observed, charged, or collected by any public utility for any transmission ... subject to the jurisdiction of the Commission,” and “any ... practice” “affecting such rate.” 16 U.S.C. § 824e(a) (emphasis added). The use of “any” to describe “rate,” “public utility,” and “transmission” bestows authority on the Commission that is not cabined to preexisting commercial relationships of any given utility. See Gonzales, 520 U.S. at 5, 117 S.Ct. 1032. The beneficiary-based cost allocation reforms are not clearly a “remote thing[] beyond the rate structure,” as was the personnel and structure of the corporate board in CAISO, 372 F.3d at 403. Instead, “the statute is silent or ambiguous with respect to the specific issue.” Chevron, 467 U.S. at 843, 104 S.Ct. 2778; see also supra Part II.A.

We therefore defer, at Chevron step two, to the Commission’s interpretation of the Act if it is permissible. Chevron, 467 U.S. at 843, 104 S.Ct. 2778; TAPS, 225 F.3d at 694; see also City of Arlington, 133 S.Ct. at 1868; Brand X Internet Servs., 545 U.S. at 980, 125 S.Ct. 2688. We believe that it is.

First, as noted above, nothing in the statutory language or context limits the Commission’s authority to fixing only practices affecting pre-existing commercial relationships.

*85 Second, the Commission’s adoption of a beneficiary-based cost allocation method is a logical extension of the cost causation principle. Under that basic tenet, which we have repeatedly embraced, “costs are to be allocated to those who cause the costs to be incurred and reap the resulting benefits.” Nat’l Ass’n of Regulatory Util. Commis. v. FERC, 475 F.3d 1277, 1285 (D.C.Cir.2007) (“NARUC ”). And we have “endorsed the approach of ‘assign[ing] the costs of system-wide benefits to all customers on an integrated transmission grid.’ ” Id. (alteration in original) (quoting W. Mass. Elec. Co. v. FERC, 165 F.3d 922, 927 (D.C.Cir.1999)).

The physics of electrical transmission supports the Commission’s conclusion that even transmission providers distant from new transmission facilities- — including those that do not have pre-existing commercial relationships with a transmission developer — may benefit from those new facilities. Because “there is no way to determine what path electricity actually takes between two points [on a power grid] or indeed whether the electricity at the point of delivery was ever at the point of origin,” “all of the individual facilities used to transmit electricity are treated as if they were part of a single machine.” N. States Power Co. v. FERC, 30 F.3d 177, 179 (D.C.Cir.1994). And because “a transmission system performs as a whole[,] the availability of multiple paths for electricity to flow from one point to another contributes to the reliability of the system as a whole.” Id. The Commission accordingly determined that “in an interconnected electric transmission system, the enlargement of one path between two points can provide greater system stability, lower line losses, reduce reactive power needs, and improve the throughput capacity on other facilities.” Order No. 1000-A ¶ 562, 77 Fed.Reg. at 32,271. There is a strong scientific basis for the Commission’s conclusion that “[e]ntities that contract for service on the transmission grid cannot ‘choose’ to affect only the transmission facilities for which they have entered into a contract” and “cannot claim that they are not using or benefiting from such transmission facilities simply because they did not enter a contract to use them.” Id. ¶ 561, 77 Fed.Reg. at 32,271.

As the Commission recognized, the free rider problem it identified stems from the fact that an entity that uses part of the transmission grid may obtain benefits from improvements to and expansion of transmission facilities on another part of that grid, regardless of whether that entity has a contract for service on the improved part of the grid. Id. ¶ 562, 77 Fed.Reg. at 32,271. The Commission therefore reasonably identified the lack of beneficiary-based cost allocation as a practice likely to result in rates that are not just and reasonable or are unduly discriminatory or preferential. Order No. 1000 ¶ 487, 76 Fed.Reg. at 49,919. And, as explained in Part II.A supra, whether a threat of unjust or unreasonable rates derives from a practice or the absence thereof, Section 206 empowers the Commission to address it.

The plain text of the statute and the Commission’s reasoning show the Commission’s construction to be wholly reasonable. Joint Petitioners point to a number of cases for the contrary conclusion, none of which requires a different result.

First, Joint Petitioners contend that the Mobile-Sierra line of cases prevents the Commission from requiring cost allocation other than as established by voluntary contractual or commercial relationships. The Mobile-Sierra cases neither govern our inquiry nor require that conclusion. Mobile and Sierra address the Commission’s authority “to modify rates set bilaterally *86 by contract rather than unilaterally by tariff.” Morgan Stanley, 554 U.S. at 532, 128 S.Ct. 2733 (addressing the scope of the Mobile-Sierra doctrine); see also Mobile, 350 U.S. 332, 76 S.Ct. 373; Sierra, 350 U.S. 348, 76 S.Ct. 368. Neither Mobile-Sierra nor their progeny addressed the issue here: the Commission’s power under Section 206 to require public utilities to include in their OATTs rate-affecting provisions, such as cost allocation method(s) that may be adopted during regional transmission planning. The precedents relevant to that issue establish that the Commission may act by generic rule, as it did here, without first finding that the rates charged by individual utilities are unjust or unlawful when it “conclu[des] that any tariff violating the rule would have such adverse effects on the interstate gas [or energy] market as to render it ‘unjust and unreasonable.’ ” Associated Gas Distributors, 824 F.2d at 1008; see also Interstate Natural Gas, 285 F.3d at 37-38; cf. Entergy Servs., Inc. v. FERC, 319 F.3d 536, 545 (D.C.Cir.2003).

The contract cases do not bear the weight Joint Petitioners place on them. They reflect a premise of the FPA’s regulatory system in which contractual agreements voluntarily devised by regulated companies coexist with tariffs. See Morgan Stanley, 554 U.S. at 531-34, 128 S.Ct. 2733. But Mobile and Sierra do not wall off certain “private commercial matters,” Joint Pet’rs’ Br. 10, as beyond the Commission’s authority where those matters are unjust, unreasonable, or unduly discriminatory “practice[s]” “affecting” “rate[s]” pursuant to Section 206. See 16 U.S.C. § 824e(a). The statutory question here is instead one we review under Chevron, and, as explained above, we conclude that the Commission’s interpretation is reasonable.

Second, to the extent petitioners rely on Fort Pierce Utilities Authority v. FERC, 730 F.2d 778 (D.C.Cir.1984), for the proposition that the cost allocation reforms are impermissible as tantamount to joint rates, that assertion is unpersuasive. In Fort Pierce, several Florida municipal electric utilities (“Florida Cities”) sought review of a Commission order establishing the transmission rates of the largest electric utility in Florida, Florida Power & Light. Id. at 779-80. The Florida Cities claimed that those rates were excessive and discriminatory, in violation of the FPA, because the Commission had failed to order Florida Power & Light to file joint rates with a second large utility, Florida Power Corporation. Id. This court upheld the Commission’s adoption of separate, not joint, rates. Id. Due to the methodology used to calculate the rates of each transmission provider, the Commission concluded and this court agreed that to permit the Cities to pay only a joint (or averaged) rate instead of the sum of two individual rates would have the effect of discriminating against non-joint-rate customers by forcing them to subsidize the Cities’ rates for no justifiable reason. Id. at 783-84.

The cost allocation reforms here are not tantamount to mandating joint rates under Fort Pierce. The Commission in Fort Pierce rejected the Cities’ proposal of a joint rate because, due to the rate formula used, such a rate would discriminatorily shift costs away from the beneficiaries of transmission service. Id. at 783. By contrast, the cost allocation reforms here are aimed at ensuring that the costs of new transmission services are in fact allocated to those that benefit from them. Order No. 1000 ¶ 10, 76 Fed.Reg. at 49,846. In any event, the reforms do not require any rate, joint or otherwise, to be paid; indeed, they do not require any utility to pay any cost or define the mechanism for doing so, leaving to the transmission providers to *87 devise for themselves cost allocation methodologies and recovery mechanisms.

We therefore reject the Joint Petitioners’ challenges to the Commission’s authority to adopt the cost allocation reforms under Section 206.

C.

In contrast to the Joint Petitioners, the ITC Petitioners contend that the cost allocation requirements adopted in the Final Rule were arbitrary and capricious because the Commission did not mandate further cost allocation reforms. Specifically, the ITC Petitioners argue that the Commission acted arbitrarily and capriciously by (1) failing to require the allocation of the costs of extra-high voltage (“EHV”) electrical transmission lines between regions, and (2) requiring interre-gional transmission lines to be approved by each transmission planning region in which the line is located. Br. of Pet’rs Int’l Transmission Co. 2 (“ITC Br.”). The ITC Petitioners complain that the Final Rule fails to require cost allocation to extra-regional beneficiaries.

Principle 4 of the six regional cost allocation principles directs that the allocation method for “the cost of a regional facility must allocate costs solely within that transmission planning region unless another entity outside the region or another transmission planning region voluntarily agrees to assume a portion of those costs.” Order No. 1000 ¶ 586, 76 Fed.Reg. at 49,-932; see also id. ¶ 657, 76 Fed.Reg. at 49,941. The Final Rule specifies that “an interregional transmission facility must be selected in both of the relevant regional transmission plans for purposes of cost allocation in order to be eligible for in-terregional cost allocation pursuant to an interregional cost allocation method required under this Final Rule.” Id. ¶ 400, 76 Fed.Reg. at 49,908. And “public utility transmission providers in a transmission planning region will not be required to accept allocation of the costs of an interre-gional transmission project unless the region has selected such transmission facility in the regional transmission plan for purposes of cost allocation.” Id. ¶443, 76 Fed.Reg. at 49,914.

The Commission thus limited required cost allocation to within regions, noting that doing so, “may lead to some beneficiaries of transmission facilities escaping cost responsibility because they are not located in the same transmission planning region as the transmission facility.” Id. ¶ 660, 76 Fed.Reg, at 49,942. It chose this approach because “allowing one region to allocate costs unilaterally to entities in another region would impose too heavy a burden on stakeholders to actively monitor transmission planning processes in numerous other regions, from which they could be identified as beneficiaries and be subject to cost allocation.” Id.; see also Order No. 1000-A ¶¶ 507-12, 707-12, 77 Fed.Reg. at 32,-263-64, 32,291-92. The Commission declined to require cost allocation more broadly because “the resulting regional transmission planning processes would aniount to interconnectionwide transmission planning with corresponding cost allocation, albeit conducted in a highly inefficient manner.” Order No. 1000 ¶ 660, 76 Fed.Reg. at 49,942.

The ITC Petitioners contend that Cost Allocation Principle 4 is inconsistent with the cost causation principle and is therefore presumptively unjust. The cost causation principle requires costs “to be allocated to those who cause the costs to be incurred and reap the resulting benefits.” NARUC, 475 F.3d at 1285; see also K N Energy, Inc. v. FERC, 968 F.2d 1295, 1300 (D.C.Cir.1992). “Not surprisingly, we evaluate compliance with this unremarkable principle by comparing the costs as *88 sessed against a party to the burdens imposed or benefits drawn by that party. Also not surprisingly, we have never required a ratemaking agency to allocate costs with exacting precision.” Midwest ISO Transmission Owners, 373 F.3d at 1368-69 (citation omitted).

The ITC Petitioners urge that Cost Allocation Principle 4 is arbitrary and capricious because it is inconsistent with the cost causation principle, insofar as the Final Rule does not fully allocate costs to those out-of-region entities who benefit simply because they are not within the same “rather arbitrar[ily]” drawn region in which the new facility is located. ITC Br. 17. The ITC Petitioners further argue that the Commission’s concern about the monitoring burden that extra-regional cost allocation would create is exaggerated and could be mitigated by, for example, limiting out-of-region cost allocation to EHV facilities or to adjacent regions, because (1) only a small number of EHV lines are likely to have benefits beyond the region in which they are located; and (2) those benefits would extend only to adjacent regions. Id. at 6.

In the Final Rule, the Commission recognized both that Cost Allocation Principle 4 may lead to some beneficiaries escaping cost responsibility, Order No. 1000 ¶ 660, 76 Fed.Reg. at 49,942, and that limiting involuntary interregional cost allocation to EHV lines or adjacent regions “might mitigate” the monitoring burden on some stakeholders, Order No. 1000-A ¶ 711, 77 Fed.Reg. at 32,292. But nothing requires the Commission to ensure full or perfect cost causation. Rather, the cost causation principle requires that “all approved rates reflect to some degree the costs actually caused by the customer who must pay them.” K N Energy, 968 F.2d at 1300 (emphasis added); see also Pub. Serv. Comm’n of Wis., 545 F.3d at 1066-67.

We recognize that “feasibility concerns play a role in approving rates,” such that the Commission “is not bound to reject any rate mechanism that tracks the cost-causation principle less than perfectly.” Sithe/Independence Power Partners, L.P. v. FERC, 285 F.3d 1, 5 (D.C.Cir.2002); see also Carnegie Natural Gas Co. v. FERC, 968 F.2d 1291, 1293-94 (D.C.Cir.1992) (noting that there is “no requirement in the Act itself that rates precisely match cost causation and responsibility” and that instead “the Commission may rationally emphasize other, competing policies and approve measures that do not best match cost responsibility and causation”). The Commission is, moreover, “free to undertake reform one step at a time,” and “[w]e can overturn its gradualism only if it truly yields unreasonable discrimination or some other kind of arbitrariness.” Interstate Natural Gas, 285 F.3d at 35. As such, the Commission’s balancing of the competing goals of reducing monitoring burdens and adopting policies that ensure that cost allocation maximally reflects cost causation is wholly reasonable under the deferential review we accord in rate-related matters. See Alcoa, 564 F.3d at 1347.

The ITC Petitioners’ second contention is that the requirement that interregional facilities be approved by each region in order to qualify for cost allocation is redundant with the required interregional coordination and will stifle the sorts of interregional solutions that the Final Rule aims to foster. But as laid out in the Rule, the bulk of planning occurs within regions. The Commission adopted region-based planning for interregional facilities on the basis that doing so would give stakeholders “the opportunity to participate fully in the consideration of interregional transmission facilities” and that “stakeholder participation in the various regional transmission planning processes will enhance *89 the effectiveness of interregional transmission coordination.” Order No. 1000 ¶ 465, 76 Fed.Reg. at 49,916-17. This was neither arbitrary nor capricious. The Commission reasonably concluded that requiring neighboring regions to share regional plans and jointly evaluate potential in-terregional facilities was complementary to, rather than redundant with, regional planning.

We therefore reject the challenges to the cost allocation reforms.

YI.

Public Policy Requirement. Petitioners raise three challenges to the orders’ requirement that regions establish procedures that account for the impact federal, state, and local laws and regulations (ie., public policy requirements) will have on transmission systems. None is persuasive. According to the Commission, this mandate responds to a recent proliferation of laws and regulations affecting the power grid. For example, the Commission expects that many States will require construction of new transmission infrastructure to integrate sources of renewable energy, such as wind farms, into the grid and that new federal environmental regulations will shape utilities’ decisions about when to retire old coal-based generators. Plans that fail to account for such laws and regulations, the Commission reasoned, would not adequately reflect future needs. See Order No. 1000-A ¶¶ 205-06, 336, 77 Fed. Reg. at 32,217-18, 32,236.

The orders allow regions to address in a flexible manner the impact such public policy requirements will have on transmission. Rather than mandating any particular outcome, the challenged orders require transmission providers to establish procedures to address the effects of public policy on the electricity grid. See Order No. 1000 ¶¶ 109, 111, 206-10, 76 Fed.Reg. at 49,861-62, 49,877-78; Order No. 1000-A ¶¶ 209, 318-21, 77 Fed.Reg. at 32,218, 32,-234. A utility must “describe these procedures in sufficient detail in its OATT such that the process for stakeholders to provide input and offer transmission proposals regarding transmission needs they believe are driven by public policy requirements in the regional transmission planning process is transparent to all interested stakeholders.” Nor thWestern Corp., 143 F.E.R.C. ¶ 61,056 at ¶ 84 (2013). Plans are not required to take every need into account, see Order No. 1000-A ¶¶ 320-21, 77 Fed.Reg. at 32,234; instead, regions must only create procedures to “identify, out of the larger set of potential transmission needs driven by public policy requirements that may be proposed, those transmission needs for which transmission solutions will be evaluated in the ... regional transmission planning process.” NorthWestern Corp., 143 F.E.R.C. ¶ 61056 at ¶ 85.

A.

Petitioners assert that the Commission lacks statutory authority to promote the public welfare. See NAACP v. FPC, 425 U.S. 662, 669-70, 96 S.Ct. 1806, 48 L.Ed.2d 284 (1976) (noting that the FPA did not grant the Commission “a broad license to promote the general public welfare”). It is difficult to understand petitioners’ precise argument, but they seem to argue that the Commission can only exercise authority to promote goals specified in the FPA and that the public policy mandate cannot be justified with respect to any of those goals. This argument misunderstands the nature of the mandate. It does not promote any particular public policy or even the public welfare generally. The mandate simply recognizes that state and federal policies might affect the transmission market and directs transmission providers to consider that impact in their planning decisions. In *90 this regard, the requirement is no different from other facets of the planning process. The providers assess what transmission capacity is required to fulfill a variety of needs (such as reliability of the grid, geographic expansion, and now public policy requirements) and then plan how to develop that capacity. See Order No. 1000 ¶¶ 11, 21, 76 Fed.Reg. at 49,846, 49,848. This fits comfortably within the Commission’s authority under Section 206. Unlike the employment discrimination by power companies that the Court held was beyond the Commission’s jurisdiction in NAACP, the public policy mandate bears directly on the provision of transmission service. Petitioners’ argument that the orders seek to unlawfully promote the general welfare is misplaced.

B.

Petitioners next argue that the orders’ public policy mandate violates Section 217(b)(4) of the FPA, which states that the Commission “shall exercise [its authority] under this chapter in a manner that facilitates the planning and expansion of transmission facilities to meet the reasonable needs of loadserving entities to satisfy [their] service obligations.” 16 U.S.C. § 824q(b)(4). 12 Petitioners argue that by failing to require regions to specifically consider the needs of load-serving entities, the Commission unlawfully demoted those needs in violation of the plain meaning of Section 217(b)(4).

This contention, however, misses the mark. Section 217(b)(4) creates a requirement for the Commission, not for utilities. It requires that the Commission act in such a way to facilitate “the planning and expansion of transmission facilities to meet the reasonable needs of load-serving entities to satisfy [their] service obligations.” This section would only be violated if the Commission exercised its authority in a manner that was at odds with the needs of load-serving entities. Here, however, the Commission did no such thing. The ability of load-serving entities to meet their service obligations depends on their ability to deliver power when it is needed. A failure to meet those obligations occurs when the utility must engage in practices such as rolling blackouts because of insufficient transmission capacity. Thus, Section 217(b)(4) requires the Commission to facilitate the planning of a reliable grid, which is exactly what the Commission has done in the challenged orders. The orders seek to ensure that adequate transmission capacity is built to allow load-serving entities to meet their service obligations. See Order 1000 ¶¶ 44-46, 76 Fed.Reg. at 49,851; Order 1000-A ¶¶ 170, 173, 77 Fed.Reg. at 32,213. The Commission has therefore “facilitate^]” the planning of a more reliable grid and thus complied with the dictates of Section 217(b)(4).

Petitioners also appear to make a separate argument that the Commission acted arbitrarily and capriciously by abandoning without explanation a previous interpretation of Section 217(b)(4). According to petitioners, the Commission previously held that Section 217(b)(4) requires a categorical preference for load-serving entities, which it failed to incorporate into the challenged orders. They cite Order No. 681, in which the Commission concluded that Section 217(b)(4) creates a “general ‘due’ preference for load serving entities to obtain long-term firm transmission service.” See Long-Term Firm Transmission Rights in Organized Electricity Markets, F.E.R.C. Stats. & Regs. ¶ 31,226, at ¶ 320, *91 71 Fed.Reg. 43,564, 43,597 (2006). But we defer to the Commission’s reasonable interpretation of Order No. 681, see Indiana Util. Regulatory Comm’n v. FERC, 668 F.3d 735, 740 (D.C.Cir.2012), and the Commission explains in the challenged orders that Order No. 681 did not establish that Section 217(b)(4) creates a preference for load-serving entities in the “broader context of planning new transmission capacity.” Order 1000-A ¶ 171, 77 Fed.Reg. at 32,213 (emphasis added). Instead, the Commission says, Order No. 681 established a preference for load-serving entities only with regard to existing capacity. Id. This interpretation is reasonable. So limited, Order No. 681 is not inconsistent with Order No. 1000 regarding the meaning of Section 217(b)(4). See Order 1000-A ¶¶ 171-72, 77 Fed.Reg. at 32,213.

C.

Petitioners also argue that the orders’ public policy mandate is too vague, complaining that transmission providers will have great difficulty discerning exactly what the orders require of them. Their chief concern is that the Commission did not provide guidance on how regions should weigh and reconcile competing public policy requirements.

But petitioners’ attack is once again based on a misunderstanding of the orders. The orders merely require regions to establish processes for identifying and evaluating public policies that might affect transmission needs. See Order No. 1000 ¶¶ 205-11, 214-16, 76 Fed.Reg. at 49,877-79; Order No. 1000-A ¶¶ 318, 327-29, 332-33, 77 Fed.Reg. at 32,234-36. The regions are free to choose their own manner of determining how best to identify and accommodate these policies. Our precedent makes clear that the Commission’s choice to afford regions such broad discretion does not render its mandate impermissibly vague. See Am. Exp.-Isbrandtsen Lines, Inc. v. Fed. Mar. Comm’n, 389 F.2d 962, 967 (D.C.Cir.1968). In American Export, the petitioners argued that an agency order directing them to modify certain parts of their tariffs was void for vagueness because it left “unanswered such questions as: What will be the measure of damages and what sort of tribunal will fix them? What is an unusual delay? Who shall have the burden of proof of causation?” Id. “Despite these questions,” however, the court found “no legitimate basis for complaint about the order’s indefiniteness.” Id. Instead, the court suggested that the “petitioners should welcome the leeway and flexibility the Commission has given them in framing a ... rule. Any vagueness in the Commission’s order should make compliance with it that much easier.... It hardly behooves them to complain that they have been left too many options in undertaking this task.” Id. Likewise, here, allowing regional flexibility does not make the mandate impermissibly vague. Utilities must come up with a procedure for evaluating needs driven by public policy, just as they evaluate needs driven by economic and reliability concerns. The details of the procedure, and how the utilities consider or weigh different needs, are left to their discretion.

To show that the public policy mandate has sown confusion, petitioners point to tariffs rejected by the Commission for failure to comply with this requirement. But the Commission found no fault in the adequacy of the utilities’ procedures; the Commission rejected the tariffs because they failed to include, in certain respects, any procedures at all. See, e.g., S. Carolina Elec. & Gas Co., 143 F.E.R.C. ¶ 61,-058 at ¶ 119 (2013) (“While SCE & G states in its transmittal letter that proposed transmission solutions to address transmission needs driven by public policy *92 requirements will be evaluated in the same open and nondiseriminatory manner as other proposed regional transmission solutions for purposes of cost allocation, such information is not set forth in its tariff.” (footnote omitted)); NorthWestern Corp., 143 F.E.R.C. ¶ 61,056 at ¶ 84 (“Northwestern has not established actual procedures in its OATT to identify at the regional level those transmission needs driven by public policy requirements for which potential transmission solutions will be evaluated. For example, it is not clear in NorthWestern’s OATT when and how stakeholders can propose transmission needs driven by public policy requirements for potential evaluation in the ... regional transmission planning process.”). Rejection of tariffs that utterly fail to establish the procedures required by the public policy mandate tells us nothing about whether the mandate is impermissibly vague.

We find all of the challenges to the public policy mandate to be without merit and thus uphold the mandate.

VII.

Reciprocity. Petitioners raise two challenges to the Final Rule’s reciprocity condition. The reciprocity principle, instituted by the Commission in the Final Rule and two prior orders, requires non-public utility transmission providers that choose to access a public utility’s transmission lines to provide in exchange “reciprocal” transmission service, that is, service provided on comparable terms. See Order No. 1000 ¶¶ 818-19, 76 Fed.Reg. at 49,961; Order No. 890 ¶¶ 162-192, 72 Fed.Reg. at 12,290-94; Order No. 888 at pp. 31,690-92, 61 Fed.Reg. at 21,541-42. The Final Rule includes as part of the reciprocity condition that non-public utilities must participate in transmission planning and cost allocation in exchange for open access. Order No. 1000 ¶¶ 818-19, 76 Fed. Reg. at 49,961.

Two groups of petitioners attack the Rule’s reciprocity condition on nearly opposite grounds. The Joint Petitioners argue that the Commission changed course from past practice without reasoned explanation by expanding the previous reciprocity condition to include planning and cost allocation requirements. The Edison Electric Institute (“Edison”), by contrast, contends that the Commission did not go far enough. Edison claims that the Commission acted arbitrarily and capriciously by allowing non-public utilities to participate voluntarily in the planning and cost allocation requirements of the orders, whereas Edison contends their participation should be mandatory. In particular, Edison asserts that the Commission should have invoked its power under Section 211A of the FPA to require non-public utility participation. Both contentions miss the mark.

The reciprocity condition before us is fundamentally the same as that contained in two prior Commission orders, Order Nos. 888 and 890. None requires nonpublic utilities to take any particular action. But all require such utilities, if they choose to take transmission service from a public utility, to provide reciprocal transmission service on comparable terms. The current orders simply apply that principle to transmission planning and cost allocation, such that any utility drawing from a public utility’s transmission lines must participate in planning and cost allocation processes. The Commission provided a reasoned and adequate basis for doing so, and was not arbitrary or capricious in deciding to stop at a conditional rather than a categorical requirement for non-public utilities. Section 211A does not require the Commission to mandate non-public utility participation in planning and cost allocation, *93 and the Commission reasonably declined invoke its Section 211A authority to adopt such a mandate in favor of the order’s incremental and incentive-based approach.

A.

The Commission first established the reciprocity condition in Order No. 888 as part of its “ambitious program of market-based reforms.” Morgan Stanley, 554 U.S. at 535, 128 S.Ct. 2733. As previously discussed, Order No. 888 required each transmission provider to file a pro forma OATT offering transmission service to all customers on an equal basis. In efforts to further open access to transmission services, the Commission established that, when non-public utilities use the open public lines, they are subject to the same conditions as public utilities. See Order No. 888 at p. 31,760, 61 Fed.Reg. at 21,613 (stating that “[a]ny public utility that offers non-discriminatory open access transmission for the benefit of customers should be able to obtain the same non-discriminatory access in return”). That reciprocity condition, which is carried forward in Order Nos. 890 and 1000, appears in section 6 of the pro forma OATT and authorizes public utilities to refuse to offer non-public utilities access unless the non-public utilities reciprocate by “agreeing] to provide comparable transmission service to” the transmission-providing public utilities “on similar terms and conditions.” Id. app. D Pro Forma OATT § 6, 61 Fed.Reg. at 21,710; see also Order No. 890 ¶ 163, 72 Fed.Reg. at 12,290.

Non-public utilities are not subject to Section 206 of the FPA, and so are not directly governed by Order No. 1000 and its planning and cost allocation requirements. By conditioning non-public utilities’ access to the open systems of public utilities on the former’s adherence to the planning and cost allocation requirements, however, the Final Rule encourages nonpublic utilities to participate in planning and cost allocation. See Order No. 1000-A ¶ 773, 77 Fed.Reg. at 32,301 (“[T]hose [including non-public utilities] that ‘take advantage of open access, including improved transmission planning and cost allocation, should be expected to follow the same requirements as public utility transmission providers.’ ” (quoting Order No. 1000 ¶ 818, 76 Fed.Reg. at 49,961)).

In proposing that reciprocity condition, the Commission explained that, under Order No. 890, both public and non-public utilities had collaborated in a number of regional transmission planning processes. Encouraged by that collaboration, the Commission employed that voluntary and incentive-based approach in the orders now under review. NPRM ¶ 43, 75 Fed.Reg. at 37,890; see also Order No. 1000 ¶ 815, 76 Fed.Reg. at 49,960. The Commission concluded that it was not “necessary at this time to invoke [the] authority under FPA section 211 A, which allows [the Commission] to require non-public utility transmission providers to provide transmission services on a comparable and not unduly discriminatory or preferential basis.” NPRM ¶ 43, 75 Fed.Reg. at 37,890; see also Order No. 1000 ¶ 815, 76 Fed.Reg. at 49,960. Instead, it chose to wait to “exercise its authority under FPA section 211A on a case-by-case basis” if it “finds on the appropriate record that non-public utility transmission providers are not participating in the regional transmission planning and cost allocation processes.” NPRM ¶43, 75 Fed.Reg. at 37,890; see also Order No. 1000 ¶ 815, 76 Fed.Reg. at 49,960.

In justifying the revised reciprocity condition, the Commission explained that:

[N]on-public utility transmission providers will benefit greatly from the improved transmission planning and cost *94 allocation processes required for public utility transmission providers because a well-planned grid is more reliable and provides more available, less congested paths for the transmission of electric power in interstate commerce. Those that take advantage of open access, including improved transmission planning and cost allocation, should be expected to follow the same requirements as public utility transmission providers.

Order No. 1000 ¶ 818, 76 Fed.Reg. at 49,-961.

In Order No. 1000-A, the Commission denied rehearing on Order No. 1000’s reciprocity requirement, again emphasizing that the reciprocity requirement it adopted was unchanged from that in Order Nos. 888 and 890. Order No. 1000-A ¶¶754, 771, 77 Fed.Reg. at 32,297-98, 32,300.

B.

The Joint Petitioners challenge the reciprocity condition, urging that the Commission expanded it beyond prior orders, without reasoned explanation, by including within it the planning and cost allocation requirements. We reject this contention.

The requirement of reciprocity in the Final Rule is the same as in the prior orders. The Final Rule changes the condition only by altering the substantive requirements of the pro forma OATT, centrally by requiring public utilities to engage in transmission planning and cost allocation. As noted above, it does not require non-public utilities to take any action unless they choose to obtain transmission service from a public utility. Order No. 1000 ¶ 819, 76 Fed.Reg. at 49,-961.

The Joint Petitioners contend that the previous orders limited a non-public utility’s reciprocity obligation to the public utility that provided it with transmission access, and that the orders here impermis-sibly alter that scope without reasoned basis. The Joint Petitioners misconstrue the prior orders as limiting reciprocity to two utilities — -a non-public utility and the public utility from which it takes transmission. The prior orders were not as narrowly bilateral as the Joint Petitioners assert. Instead, Order No. 890 required non-public utilities that were either members of, or took transmission service from, a power pool, Regional Transmission Group (“RTG”), RTO, ISO, or other such group to provide in return comparable services to all members of such groups. Order No. 890 app. C Pro Forma OATT § 6, 72 Fed.Reg. at 12,509; see also Order No. 888 app. D Pro Forma OATT § 6, 61 Fed.Reg. at 21,710; id. at p. 31,760, 61 Fed.Reg. at 21,613 (Order No. 888’s reciprocity condition required reciprocal transmission to any power pool or RTG of which the non-public utility was a member). And Order No. 890 explicitly determined that comparable service for reciprocity purposes includes compliance with the transmission planning reforms instituted by Order No. 890. See Order No. 890 ¶ 441, 72 Fed.Reg. 12,321; Order No. 890-A ¶214, Preventing Undue Discrimination and Preference in Transmission Service, 73 Fed.Reg. 2984, 3008-09 (2008) (stating on rehearing that a non-public utility with reciprocity obligations that does not adopt a planning process that complies with Order No. 890 may be at risk of being denied open access transmission services by public utilities); see also NPRM ¶ 10, 75 Fed.Reg. at 37,886. The Final Rule’s reciprocity condition was not the radical swerve the Joint Petitioners decry.

The Final Rule did change the requirements for public utilities — by requiring both transmission planning and cost allocation — and in so doing altered what constitute comparable terms for non-public *95 utilities that choose to seek Commission-jurisdictional transmission service. See Order No. 1000-A ¶776, 77 Fed.Reg. at 32,301 (“Order No. 1000 applied the reciprocity provisions of Order Nos. 888 and 890 to provide that ... a public utility transmission provider [may] refuse to offer open access transmission service to any non-public utility transmission provider that does not provide comparable reciprocal transmission service insofar as it is capable of doing so, including regional planning and cost allocation.”). Even if we were to view the Commission’s alteration of what constitutes comparable service under the pro forma OATT as a change in course, however, the agency acknowledged that it was altering the content of the reciprocal obligations. See, e.g., id. And the Commission provided an adequate justification for that change-namely, that non-public utilities that take service from public utilities will benefit greatly from the reforms announced in the Final Rule, because “a well-planned grid is more reliable and provides more available, less congested paths for the transmission of electric power in interstate commerce.” Id. ¶ 778, 77 Fed.Reg. 32,301.

In sum, the Commission’s adoption of the reciprocity condition in the Final Rule fully complied with the requirement that an agency “display awareness that it is changing position^]” and “show that there are good reasons for the new policy.” FCC v. Fox Television Stations, Inc., 556 U.S. 502, 515, 129 S.Ct. 1800, 173 L.Ed.2d 738 (2009).

C.

Petitioner Edison, by contrast, takes the position that the Commission has authority under Section 211A of the FPA to mandate that non-public utilities comply with the Final Rule, including its regional planning and cost allocation requirements, and that the agency acted arbitrarily and capriciously in failing to so mandate. We reject that contention as well.

In Edison’s view, “[w]ithout a mandate to participate, nonpublie utility transmission providers will receive the[] benefits [of transmission planning and new facilities] without being assessed commensurate costs.” Initial Br. of Pet’r Concerning FPA § 211A at 5 (“Edison Br.”). Edison argues that “[t]he record demonstrates” that non-public utility transmission providers will not in fact voluntarily participate in transmission planning or cost allocation. Id. at 7. In support, Edison cites comments by non-public utilities to the effect that they are committed to participating in the planning and cost allocation processes but cannot commit to being bound by the building expansion programs that may result because those programs have not yet been determined. Id. According to Edison, the Commission must therefore mandate the participation of nonpublic utilities under Section 211 A of the FPA, and its failure to do so was arbitrary and capricious.

Section 211A(b) of the FPA provides in relevant part:

[T]he Commission may, by rule or order, require an unregulated transmitting utility to provide transmission services—

(1) at rates that are comparable to those that the unregulated transmitting utility charges itself; and

(2) on terms and conditions (not relating to rates) that are comparable to those under which the unregulated transmitting utility provides transmission services to itself and that are not unduly discriminatory or preferential.

16 U.S.C. § 824j — 1(b).

Congress’ use of the word “may” in Section 211A plainly permits, but does not mandate, the Commission to require a *96 nonpublic utility to provide transmission service on given terms. See, e.g., Wagner v. FEC, 717 F.3d 1007, 1012 (D.C.Cir.2018); McCreary v. Offner, 172 F.3d 76, 83 (D.C.Cir.1999). As such, the statute does not require the Commission to go as far as Edison urges.

The Commission, moreover, adequately explained that its past successful experience with voluntary participation under Order No. 890 led to its decision to take a conditional incentive-based approach to reciprocity in planning and cost allocation, at least at this juncture. Order No. 1000 ¶ 815, 76 Fed.Reg. at 49,960. The Commission thus articulated a satisfactory explanation for its predictive judgment that non-public utilities are likely to participate voluntarily, and we owe that judgment deference. “ ‘[I]t is within the scope of the agency’s expertise to make ... a prediction about the market it regulates, and a reasonable prediction deserves our deference notwithstanding that there might also be another reasonable view.’ ” Constellation Energy Commodities Grp., Inc. v. FERC, 457 F.3d 14, 24 (D.C.Cir.2006) (ellipses in original) (quoting Envtl. Action, Inc. v. FERC, 939 F.2d 1057, 1064 (D.C.Cir.1991)).

The evidence that Edison cites for the proposition that nonpublic utilities will not participate does not “flatly contradict[ ]” the Commission’s conclusion. Edison Br. 7. Edison points to comments from nonpublic utilities expressing concerns about mandatory cost allocation, but those comments do not contravene the Commission’s judgment that such utilities are likely to participate in planning and cost allocation when it is a condition of access to public transmission service.

Nor was the Commission’s approach arbitrary and capricious because it “creates undue discrimination” between public and non-public utilities. Edison Br. 10. Edison complains the Rule foists the costs of new facilities on regulated public utilities while giving non-public utilities a free ride. The Commission was under no statutory obligation to regulate nonpublic utilities, and it provided a reasoned basis for choosing a conditional approach, grounded in a prediction that non-public utilities would in fact participate, and leaving for another day whether to require non-public utilities’ participation pursuant to its Section 211 A authority. Order No. 1000 ¶ 815, 76 Fed. Reg. at 49,960.

The Commission’s decision to adopt a reciprocity condition embracing voluntary and incentive-based participation by nonpublic utilities was accordingly neither arbitrary nor capricious. We therefore need not reach whether the Commission has authority under Section 211A to mandate the participation of non-public utilities.

Edison additionally contends that the Commission acted arbitrarily and capriciously by failing to respond adequately to its arguments to the Commission on rehearing. That contention, too, is without merit. Following the Commission’s announcement in the Notice of Proposed Rulemaking that it planned to use a voluntary approach, a number of commenters raised materially identical arguments to those Edison raised in its request for rehearing. Compare Order No. 1000 ¶ 812, 76 Fed.Reg. at 49,960 (summarizing comments asserting that the Commission has authority to require non-public utilities’ participation under Section 211A and that its failure to do so “will result in an inequitable burden for jurisdictional utilities and their customers”) and id. ¶¶ 815, 817-18, 821, 76 Fed.Reg. at 49,960-61 (responding to those concerns), with Order No. 1000-A ¶¶ 767-70, 77 Fed.Reg. at 32,299-300 (summarizing Edison’s comment that the Commission “erred by relying on non-public utility transmission providers to volun *97 tarily participate in regional transmission planning and cost allocation processes” instead of exercising its authority under Section 211A). “While an agency must consider and explain its rejection of ‘reasonably obvious alternative[s],’ it need not ... respond to every comment made. Rather, an agency must consider only ‘significant and viable’ and ‘obvious’ alternatives.” Nat’l Shooting Sports Found., Inc. v. Jones, 716 F.3d 200, 215 (D.C.Cir.2013) (brackets in original) (citations omitted). The Commission adequately addressed the commenters’ concerns that voluntary participation by non-public utilities would undermine the Commission’s objectives and sufficiently explained its reasons for declining, at that time, to require non-public utility compliance under Section 211 A.

For these reasons, we reject the challenges to the reciprocity condition.

Accordingly, we deny the petitions for review.