South Carolina Public Service Authority v. Federal Energy Regulatory Commission

United States Court of Appeals

FOR THE DISTRICT OF COLUMBIA CIRCUIT

Argued March 20, 2014 Decided August 15, 2014

No. 12-1232

SOUTH CAROLINA PUBLIC SERVICE AUTHORITY,

PETITIONER

v.

FEDERAL ENERGY REGULATORY COMMISSION,

RESPONDENT

ALABAMA PUBLIC SERVICE COMMISSION, ET AL.,

INTERVENORS

Consolidated with 12-1233, 12-1250, 12-1276, 12-1279,

12-1280, 12-1285, 12-1292, 12-1293, 12-1296, 12-1299,

12-1300, 12-1304, 12-1448, 12-1478

On Petitions for Review of Orders of the

Federal Energy Regulatory Commission

Harvey L. Reiter and Andrew W. Tunnell argued the causes

for petitioners and supporting intervenors South Carolina Public

Service Authority, et al. concerning Threshold Issues. With

them on the joint briefs were Ed R. Haden, Scott B. Grover,

Jonathan D. Schneider, Jonathan Peter Trotta, Kenneth G.

Jaffe, Michael E. Ward, Randall Bruce Palmer, George Scott

Morris, Luther Daniel Bentley IV, Sue Deliane Sheridan,

2

Kenneth B. Driver, William H. Weaver, John Lee Shepherd Jr.,

William Rainey Barksdale, Tamara L. Linde, Jodi L. Moskowitz,

Daniel M. Malabonga, Stephen G. Kozey, Matthew R. Dorsett,

Wendy N. Reed, Matthew J. Binette, David S. Berman, Clare E.

Kindall, Assistant Attorney General, Office of the Attorney

General for the State of Connecticut, James Bradford Ramsay,

Holly Rachel Smith, Cynthia Brown Miller, Daniel E. Frank,

and Jennifer J.K. Herbert. Dennis Lane, Samantha M. Cibula,

John A. Garner, and Glen L. Ortman entered appearances.

Randolph Lee Elliott argued the cause for petitioners and

supporting intervenors American Public Power Association, et

al. concerning Transmission Planning and Public Policy. With

him on the joint briefs were John Lee Shepherd Jr., William

Rainey Barksdale, Tamara L. Linde, Jodi L. Moskowitz, Cynthia

Brown Miller, Andrew W. Tunnell, Ed R. Haden, Scott B.

Grover, George Scott Morris, Luther Daniel Bentley, IV, Harvey

L. Reiter, Jonathan D. Schneider, Jonathan Peter Trotta, James

Bradford Ramsay, Holly Rachel Smith, Cynthia S. Bogorad, and

William S. Huang. Delia D. Patterson, Jesse S. Unkenholz,

Lyle D. Larson, and Daniel H. Silverman entered appearances.

Luther Daniel Bentley, IV argued the cause for state

petitioner and intervenors Alabama Public Service Commission,

et al. With him on the joint briefs were George Scott Morris,

Clare E. Kindall, Assistant Attorney General, Office of the

Attorney General for the State of Connecticut, James Bradford

Ramsay, Holly Rachel Smith, and Cynthia Brown Miller.

Jonathan D. Schneider argued the cause for petitioners and

supporting intervenors South Carolina Public Service Authority,

et al. concerning Cost Allocation. With him on the joint briefs

were Harvey L. Reiter, Jonathan Peter Trotta, Andrew W.

Tunnell, Ed R. Haden, Scott B. Grover, Sue Deliane Sheridan,

Randolph Lee Elliott, Elias G. Farrah, Kenneth G. Jaffe,

3

Michael E. Ward, Randall Bruce Palmer, Howard Haswell

Shafferman, Jack Nadim Semrani, George Scott Morris, Luther

Daniel Bentley, IV, Holly Rachel Smith, John Lee Shepherd, Jr.,

William Rainey Barksdale, Tamara L. Linde, and Jodi L.

Moskowitz.

John Lee Shepherd, Jr. argued the cause for petitioners and

supporting intervenors Public Service Electric and Gas

Company, et al. concerning Rights of First Refusal. With him

on the joint briefs were William Rainey Barksdale, Tamara L.

Linde, Jodi L. Moskowitz, Kenneth G. Jaffe, Michael E. Ward,

Randall Bruce Palmer, Andrew W. Tunnell, Ed R. Haden, Scott

B. Grover, Kenneth B. Driver, William H. Weaver, John

Longstreth, Donald A. Kaplan, William M. Keyser, Stephen M.

Spina, John D. McGrane, J. Daniel Skees, Edward Comer,

Henri D. Bartholomot, Gary E. Guy, Jeanne Jackson Dworetzky,

Barry S. Spector, Matthew J. Binette, N. Beth Emery, Daniel E.

Frank, Jennifer J.K. Herbert, Wendy N. Reed, David S. Berman,

Daniel M. Malabonga, Stephen G. Kozey, and Matthew R.

Dorsett.

Linda G. Stuntz, James W. Moeller, and Andrew M.

Jamieson were on the briefs for petitioners International

Transmission Company d/b/a ITC Trasmission, et al.

Randolph Lee Elliott, Jonathan D. Schneider, Harvey L.

Reiter, and Jonathan Peter Trotta were on the joint briefs for

petitioners and supporting intervenors concerning Reciprocity

Condition. Marie D. Zosa entered an appearance.

Andrew W. Tunnell, Ed R. Haden, Scott B. Grover, Harvey

L. Reiter, Jonathan D. Schneider, Jonathan Peter Trotta,

Randolph Lee Elliott, Stephen Matthew Spina, John D.

McGrane, George Scott Morris, Luther Daniel Bentley, IV, Sue

Deliane Sheridan, Kenneth G. Jaffe, Michael E. Ward, Randall

4

Bruce Palmer, Wendy N. Reed, Matthew J. Binette, David S.

Berman, Howard Haswell Shafferman, Jack Nadim Semrani,

Elias G. Farrah, John Lee Shepherd, Jr., William Rainey

Barksdale, Tamara L. Linde, Jodi L. Moskowitz, Kenneth B.

Driver, Clare E. Kindall, Assistant Attorney General, Office of

the Attorney General for the State of Connecticut, Gary E. Guy,

Jeanne Jackson Dworetzky, Barry S. Spector, Cynthia Brown

Miller, Daniel M. Malabonga, Stephen G. Kozey, and Matthew

R. Dorsett, N. Beth Emery, James Bradford Ramsay, Holly

Rachel Smith, Daniel E. Frank, and Jennifer J.K. Herbert were

on the joint brief for petitioners and supporting intervenors

concerning Statement of the Case, Statement of Facts, and

Standards of Review.

Edward H. Comer, Henri D. Bartholomot, John D.

McGrane, Stephen M. Spina, and John Daniel Skees were on the

briefs for petitioner Edison Electric Institute concerning FPA

§ 211A.

Beth G. Pacella and Lona T. Perry, Senior Attorneys, and

Robert M. Kennedy, Attorney, Federal Energy Regulatory

Commission, argued the causes for respondent. With them on

the briefs were David L. Morenoff, Acting General Counsel,

Robert H. Solomon, Solicitor, and Jennifer S. Amerkhail,

Attorney.

Michael R. Engleman argued the cause for intervenors LS

Power Transmission, LLC, et al. concerning Rights of First

Refusal. With him on the brief were Neil L. Levy and Ashley C.

Parrish. David G. Tewksbury entered an appearance.

Dimple Chaudhary, Jill Tauber, Abigail Dillen, and Gene

Grace were on the brief for intervenors Conservation Law

Foundation, et al. in support of respondents concerning

Threshold Issues, Cost Allocation, Transmission Planning and

5

Public Policy, and State Sovereignty. Hannah Chang and

Benjamin H. Longstreth entered appearances.

Randall V. Griffin, Gary E. Guy, Jodi Moskowitz, John

Longstreth, Donald A. Kaplan, and William M. Keyser were on

the brief for intervenors The Dayton Power and Light Company,

et al. concerning Scope of Cost Allocation. Megan E. Vetula

entered an appearance.

Jonathan D. Schneider, Harvey L. Reiter, Jonathan Peter

Trotta, and Randolph Lee Elliott were on the joint brief for

intervenors American Public Power Association, et al.

concerning FPA § 211A. Delia D. Patterson entered an

appearance.

Before: ROGERS, GRIFFITH and PILLARD, Circuit Judges.

PER CURIAM: 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.

§ 791a 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 their mutual transmission needs.

The Final Rule also requires each planning process to have a

method for allocating ex ante among beneficiaries the costs of

6

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 intervenors (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 their 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 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

7

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

1

Judge Rogers wrote Parts I, II.A–B, and III; Judge Griffith

wrote Parts II.C, IV, and VI; and Judge Pillard wrote Parts V and VII.

8

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 (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 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

9

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 “functional[ly] unbundl[e]” 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, 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

10

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-1(b)). Further, the Commission was instructed to

exercise its authority under the FPA “in a manner that 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

11

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 “[s]ignificant expansion of the transmission grid

will be required” to “increase reliability, reduce costly

congestion and line losses, and supply access to low-cost remote

12

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 Technical 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”

13

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 Owning 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

14

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 transmission

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.

15

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 (i.e., 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 protected by

16

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 (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. 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. “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, 133 S. Ct. 1863,

1868 (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.

2

United Gas Pipe Line Co. v. Mobile Gas Serv. Corp., 350

U.S. 332 (1956); FPC v. Sierra Pac. Power Co., 350 U.S. 348 (1956).

17

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 (1983) (internal quotation

marks omitted). The Commission’s factual findings are

conclusive if supported by substantial evidence. 16 U.S.C.

§ 825l(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 Commission’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

18

Stanley Capital Grp. Inc. v. Pub. Util. Dist. No. 1, 554 U.S. 527,

532 (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 (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

nondiscriminatory,” 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, 132 S. Ct. 1670, 1680–81 (2012); N.Y.

State Conference of Blue Cross & Blue Shield Plans v. Travelers

Ins. Co., 514 U.S. 645, 655 (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:

19

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 (1997).

In the Final Rule, the Commission identified underlying

problems with “existing 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

20

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

investigat[ing] 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

21

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 (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 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.

22

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 anti-

competitive 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 “[a]greements to coordinate transmission planning” that

require transmission providers to take on “binding” commercial

23

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 (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;

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 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. 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

24

“subject to limitations unrelated to antitrust considerations” in

order to “preserve the voluntary action of the utilities.” Id. at

373–74 (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 (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 purport 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

25

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 standard in step two of the Chevron analysis, 467

U.S. at 843, 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.

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

26

“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 “self-

evident,” 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 (2006) (quoting Jarecki v. G.D. Searle & Co., 367 U.S.

303, 307 (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

27

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 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 dispositive 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

28

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 I-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 court in Central Iowa interpreted Section 202(a) to mean that

“Congress intended coordination and interconnection

29

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 Iowa 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

(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 (1993); see also ANTONIN SCALIA &

BRYAN A. GARNER, READING LAW: THE INTERPRETATION OF

LEGAL TEXTS 167 (2012). It is neither ungrammatical nor

30

unnatural to read “and” to suggest a chronological sequence.

See DAVID CRYSTAL, THE CAMBRIDGE ENCYCLOPEDIA 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 pre-

operational 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

“[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

31

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.

32

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 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, 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. The Court’s substantial discussion of Section 201 yields

several insights into the provision’s meaning that are helpful in

resolving petitioners’ argument.

3

For example, the Florida Public Service Commission is

statutorily vested with authority to “plan[], develop[], and

main[tain] . . . a coordinated electric power grid” throughout the state.

FLA. STAT. § 366.04(5); see also Joint Br. of State Pet’rs’ 20–22

(citing state statutes related to planning).

33

First, the Commission possesses greater authority over

electricity transmission than it does over sales. See id. at 17,

19–20. 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. 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 (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.

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.

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

4

This fact distinguishes this case from Electric Power Supply

Ass’n v. FERC, 753 F.3d 216 (D.C. Cir. 2014), a case cited by

petitioners where this court struck down a Commission attempt to

regulate an aspect of retail electricity sales. Id. at 218.

34

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 (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

(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

operations”). 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.

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

35

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 requirement[s] 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

36

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 practice 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 (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).

37

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

interregional cost allocation).

Comments during the rulemaking, including comments

from the regulated industry, referred to similar problems. For

example, industry economists at The Brattle Group “identified

approximately 130 mostly conceptual and often overlapping

planned transmission projects,” with a total cost of over $180

38

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 . . . demonstrat[ing] the need for 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

39

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. ¶¶ 35–41, 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 “[t]ransmission 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

40

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 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 “confirm[ing] 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

41

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.

42

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. 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.

43

¶ 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 “significant[ly] 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

“competition 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

44

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.

45

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 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.

46

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

47

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.” IIIB AREEDA &

HOVENKAMP ¶ 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 mischaracterize 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

concluding 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 AREEDA & HOVENKAMP ¶ 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.

48

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) (citing SEC

v. Chenery Corp., 332 U.S. 194, 202–03 (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

49

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 load-

serving entities,” and that “serv[ing] 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 VI.B.

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 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

5

Under the FPA, a tariff is the mechanism through which a

regulated utility sets its rates unilaterally. See NRG Power Mktg., LLC

v. Me. Pub. Utils. Comm’n, 558 U.S. 165, 171 (2010). Rates may also

be set by agreement between utilities and power purchasers. See id.

50

from proposing transmission facilities.6 Not only would non-

incumbents 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

6

As explained in Part I, an “incumbent” transmission provider

is “an entity that develops a transmission project within its own retail

distribution service territory or footprint.” Order No. 1000 ¶225, 76

Fed. Reg. at 49,880. By contrast, a “non-incumbent” transmission

provider is either “a transmission developer that does not have a retail

distribution service territory or footprint” or “a public utility

transmission provider that proposes a transmission project outside of

its existing retail distribution territory or footprint. Id.

51

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 inefficiencies 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 non-

incumbents 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 non-

incumbents 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

52

to other parties (which the challenged orders refer to as “local

transmission facilit[ies]”). 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 (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.

53

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 practice 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

54

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 IIB

PHILLIP E. AREEDA 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.”).

55

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 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

7

For similar reasons, United States v. Pennsylvania Railroad

Co., 242 U.S. 208 (1916), which petitioners cite, does not aid their

argument. Although that opinion’s reasoning is difficult to follow,

petitioners claim that that the decision established that Section 206 is

“manifestly concerned about practices that directly relate[] to the . . .

service provided customers.” Pet’rs’ Rights of First Refusal Br. 13.

But, as already explained, because rights of first refusal are directly

tied to rates charged for electricity transmission, such rights do

directly relate to the service that is provided (i.e., the provision of

electricity transmission service).

56

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

(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

57

activities. Thus, even assuming an absolute obligation to

interpret the NGA and FPA in lockstep, there would be no

superfluity. The NGA “construction” provision 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. 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

8

Assuming that petitioners’ CAISO and superfluity arguments

were Chevron step two arguments would not aid petitioners. The

direct economic relationship between rights of first refusal and rates

forecloses any suggestion that characterizing these rights as practices

affecting rates was somehow impermissible. And, as explained,

petitioners’ superfluity argument is unpersuasive.

58

Commission’s mandate opens up opportunities for non-

incumbents, 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. § 825l(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 support[ed] 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 adverse effects

on rates” by noting that “[w]e do not think it is surprising that

there is limited evidence of exclusion of nonincumbent

transmission developers” given that rights of first refusal give

rise to a “situation that discourages [nonincumbents] from

59

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-necessary 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

60

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 “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.

61

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.

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

62

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

development 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

63

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

package of reforms designed to prevent that risk from

materializing.10

9

Petitioners’ briefing takes primary aim at this requirement,

suggesting that monitoring is unlikely to solve reliability concerns in

light of the long lead times for transmission infrastructure construction

projects and the unacceptability of short-term, stop-gap solutions (e.g.,

rolling blackouts) where needed infrastructure is not in place. But this

straw-man argument overlooks the other aspects of the Commission’s

response to reliability concerns.

10

The orders belie petitioners’ assertion that the Commission

failed to address comments raising concerns that potential state

sanctions and civil liability might result if non-incumbent delays led

to interrupted electricity service. On rehearing, the Commission

reasonably determined that because these concerns were speculative,

see Order No. 1000-A ¶ 482, 77 Fed. Reg. at 32,259, they “require[d]

no response,” see Home Box Office, Inc. v. FCC, 567 F.2d 9, 35 n.58

(D.C. Cir. 1977). The Commission did not need to promise total

immunity from any conceivable reliability-related risks to make its

decision rational.

64

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.

§ 824o(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 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

65

Connection Series, available at http://www.nerc.com/pa

/Stand/Pages/AllReliabilityStandards.aspx?jurisdiction=United

States (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.

11

In petitioners’ right of first refusal reply brief, they assert

that the orders’ mitigation requirement is new because it requires

transmission providers to submit a mitigation plan before a reliability

violation occurs. Petitioners contend that this “modifies the current

NERC enforcement process, which does not permit a mitigation plan

until a violation exists.” Pet’rs’ Rights of First Refusal Reply Br. 22.

But petitioners failed to raise this argument with sufficient

particularity in their opening brief. See Pet’rs’ Rights of First Refusal

Br. 43–47. Accordingly, we refrain from addressing it. See, e.g.,

Domtar Me. Corp., 347 F.3d at 309–10.

66

Reg. at 32,260. Accordingly, the challenged orders do not

violate Section 215’s bar against requiring construction.

In comments submitted during the rulemaking 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. § 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.

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.,

67

498 U.S. 211, 230 (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.

68

Finding no merit in any of petitioners’ right of first refusal

challenges, we deny those portions of their petitions that attack

the ban.

V.

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.

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.

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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

70

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 improvement 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

71

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

interregional 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 ¶ 523, 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 ¶¶ 586–87, 76 Fed. Reg. at 49,932–33.

72

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.

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

73

transmission projects, even if it leads to reallocating sunk costs.”

FirstEnergy Serv. Co. v. FERC, -- F.3d --, No. 12-1461, 2014

WL 3538062, at *7 (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 pre-

existing 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 pre-existing commercial

relationships of any given utility. See Gonzales, 520 U.S. at 5.

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

74

specific issue.” Chevron, 467 U.S. at 843; 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; 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. 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.

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. Comm’rs 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.”

75

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

76

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 by

contract rather than unilaterally by tariff.” Morgan Stanley, 554

U.S. at 532 (addressing the scope of the Mobile-Sierra doctrine);

see also Mobile, 350 U.S. 332; Sierra, 350 U.S. 348. 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. 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]”

77

“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

78

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 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

interregional 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

79

interregional 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 interregional 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 amount 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

80

with this unremarkable principle by comparing the costs

assessed 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.

81

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 ou

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