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.
69
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 out in the Rule, the bulk of planning occurs within
regions. The Commission adopted region-based planning for
interregional facilities on the basis that doing so would give
stakeholders “the opportunity to participate fully in the
consideration of interregional transmission facilities” and that
“stakeholder participation in the various regional transmission
planning processes will enhance the effectiveness of
interregional transmission coordination.” Order No. 1000 ¶ 465,
76 Fed. Reg. at 49,916–17. This was neither arbitrary nor
82
capricious. The Commission reasonably concluded that
requiring neighboring regions to share regional plans and jointly
evaluate potential interregional facilities was complementary to,
rather than redundant with, regional planning.
We therefore reject the challenges to the cost allocation
reforms.
VI.
Public Policy Requirement. Petitioners raise three
challenges to the orders’ requirement that regions establish
procedures that account for the impact federal, state, and local
laws and regulations (i.e., public policy requirements) will have
on transmission systems. None is persuasive. According to the
Commission, this mandate responds to a recent proliferation of
laws and regulations affecting the power grid. For example, the
Commission expects that many States will require construction
of new transmission infrastructure to integrate sources of
renewable energy, such as wind farms, into the grid and that
new federal environmental regulations will shape utilities’
decisions about when to retire old coal-based generators. Plans
that fail to account for such laws and regulations, the
Commission reasoned, would not adequately reflect future
needs. See Order No. 1000-A ¶¶ 205–06, 336, 77 Fed. Reg. at
32,217–18, 32,236.
The orders allow regions to address in a flexible manner the
impact such public policy requirements will have on
transmission. Rather than mandating any particular outcome,
the challenged orders require transmission providers to establish
procedures to address the effects of public policy on the
electricity grid. See Order No. 1000 ¶¶ 109, 111, 206–10, 76
Fed. Reg. at 49,861–62, 49,877–78; Order No. 1000-A ¶¶ 209,
318–21, 77 Fed. Reg. at 32,218, 32,234. A utility must
83
“describe these procedures in sufficient detail in its OATT such
that the process for stakeholders to provide input and offer
transmission proposals regarding transmission needs they
believe are driven by public policy requirements in the regional
transmission planning process is transparent to all interested
stakeholders.” NorthWestern Corp., 143 F.E.R.C. ¶ 61,056 at ¶
84 (2013). Plans are not required to take every need into
account, see Order No. 1000-A ¶¶ 320–21, 77 Fed. Reg. at
32,234; instead, regions must only create procedures to
“identify, out of the larger set of potential transmission needs
driven by public policy requirements that may be proposed,
those transmission needs for which transmission solutions will
be evaluated in the . . . regional transmission planning process.”
NorthWestern Corp., 143 F.E.R.C. ¶ 61056 at ¶ 85.
A.
Petitioners assert that the Commission lacks statutory
authority to promote the public welfare. See NAACP v. FPC,
425 U.S. 662, 669–70 (1976) (noting that the FPA did not grant
the Commission “a broad license to promote the general public
welfare”). It is difficult to understand petitioners’ precise
argument, but they seem to argue that the Commission can only
exercise authority to promote goals specified in the FPA and that
the public policy mandate cannot be justified with respect to any
of those goals. This argument misunderstands the nature of the
mandate. It does not promote any particular public policy or
even the public welfare generally. The mandate simply
recognizes that state and federal policies might affect the
transmission market and directs transmission providers to
consider that impact in their planning decisions. In this regard,
the requirement is no different from other facets of the planning
process. The providers assess what transmission capacity is
required to fulfill a variety of needs (such as reliability of the
grid, geographic expansion, and now public policy
requirements) and then plan how to develop that capacity. See
84
Order No. 1000 ¶¶ 11, 21, 76 Fed. Reg. at 49,846, 49,848. This
fits comfortably within the Commission’s authority under
Section 206. Unlike the employment discrimination by power
companies that the Court held was beyond the Commission’s
jurisdiction in NAACP, the public policy mandate bears directly
on the provision of transmission service. Petitioners’ argument
that the orders seek to unlawfully promote the general welfare
is misplaced.
B.
Petitioners next argue that the orders’ public policy mandate
violates Section 217(b)(4) of the FPA, which states that the
Commission “shall exercise [its authority] under this chapter in
a manner that facilitates the planning and expansion of
transmission facilities to meet the reasonable needs of load-
serving entities to satisfy [their] service obligations.” 16 U.S.C.
§ 824q(b)(4).12 Petitioners argue that by failing to require
regions to specifically consider the needs of load-serving
entities, the Commission unlawfully demoted those needs in
violation of the plain meaning of Section 217(b)(4).
This contention, however, misses the mark. Section
217(b)(4) creates a requirement for the Commission, not for
utilities. It requires that the Commission act in such a way to
facilitate “the planning and expansion of transmission facilities
to meet the reasonable needs of load-serving entities to satisfy
[their] service obligations.” This section would only be violated
if the Commission exercised its authority in a manner that was
at odds with the needs of load-serving entities. Here, however,
the Commission did no such thing. The ability of load-serving
entities to meet their service obligations depends on their ability
12
A “load-serving entity” is a utility with an obligation
created under law or contract to provide electricity service to end-use
customers or to a distribution utility. 16 U.S.C. § 824q(a)(2)–(3).
85
to deliver power when it is needed. A failure to meet those
obligations occurs when the utility must engage in practices
such as rolling blackouts because of insufficient transmission
capacity. Thus, Section 217(b)(4) requires the Commission to
facilitate the planning of a reliable grid, which is exactly what
the Commission has done in the challenged orders. The orders
seek to ensure that adequate transmission capacity is built to
allow load-serving entities to meet their service obligations. See
Order 1000 ¶¶ 44–46, 76 Fed. Reg. at 49,851; Order 1000-A
¶¶ 170, 173, 77 Fed. Reg. at 32,213. The Commission has
therefore “facilitate[d]” the planning of a more reliable grid and
thus complied with the dictates of Section 217(b)(4).
Petitioners also appear to make a separate argument that the
Commission acted arbitrarily and capriciously by abandoning
without explanation a previous interpretation of Section
217(b)(4). According to petitioners, the Commission previously
held that Section 217(b)(4) requires a categorical preference for
load-serving entities, which it failed to incorporate into the
challenged orders. They cite Order No. 681, in which the
Commission concluded that Section 217(b)(4) creates a “general
‘due’ preference for load serving entities to obtain long-term
firm transmission service.” See Long-Term Firm Transmission
Rights in Organized Electricity Markets, F.E.R.C. Stats. & Regs.
¶ 31,226, at ¶ 320, 71 Fed. Reg. 43,564, 43,597 (2006). But we
defer to the Commission’s reasonable interpretation of Order
No. 681, see Indiana Util. Regulatory Comm’n v. FERC, 668
F.3d 735, 740 (D.C. Cir. 2012), and the Commission explains in
the challenged orders that Order No. 681 did not establish that
Section 217(b)(4) creates a preference for load-serving entities
in the “broader context of planning new transmission capacity.”
Order 1000-A ¶ 171, 77 Fed. Reg. at 32,213 (emphasis added).
Instead, the Commission says, Order No. 681 established a
preference for load-serving entities only with regard to existing
capacity. Id. This interpretation is reasonable. So limited,
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Order No. 681 is not inconsistent with Order No. 1000 regarding
the meaning of Section 217(b)(4). See Order 1000-A ¶¶ 171–72,
77 Fed. Reg. at 32,213.
C.
Petitioners also argue that the orders’ public policy mandate
is too vague, complaining that transmission providers will have
great difficulty discerning exactly what the orders require of
them. Their chief concern is that the Commission did not
provide guidance on how regions should weigh and reconcile
competing public policy requirements.
But petitioners’ attack is once again based on a
misunderstanding of the orders. The orders merely require
regions to establish processes for identifying and evaluating
public policies that might affect transmission needs. See Order
No. 1000 ¶¶ 205–11, 214–16, 76 Fed. Reg. at 49,877–79; Order
No. 1000-A ¶¶ 318, 327–29, 332–33, 77 Fed. Reg. at 32,234–36.
The regions are free to choose their own manner of determining
how best to identify and accommodate these policies. Our
precedent makes clear that the Commission’s choice to afford
regions such broad discretion does not render its mandate
impermissibly vague. See Am. Exp.-Isbrandtsen Lines, Inc. v.
Fed. Mar. Comm’n, 389 F.2d 962, 967 (D.C. Cir. 1968). In
American Export, the petitioners argued that an agency order
directing them to modify certain parts of their tariffs was void
for vagueness because it left “unanswered such questions as:
What will be the measure of damages and what sort of tribunal
will fix them? What is an unusual delay? Who shall have the
burden of proof of causation?” Id. “Despite these questions,”
however, the court found “no legitimate basis for complaint
about the order’s indefiniteness.” Id. Instead, the court
suggested that the “petitioners should welcome the leeway and
flexibility the Commission has given them in framing a . . . rule.
Any vagueness in the Commission’s order should make
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compliance with it that much easier. . . . It hardly behooves
them to complain that they have been left too many options in
undertaking this task.” Id. Likewise, here, allowing regional
flexibility does not make the mandate impermissibly vague.
Utilities must come up with a procedure for evaluating needs
driven by public policy, just as they evaluate needs driven by
economic and reliability concerns. The details of the procedure,
and how the utilities consider or weigh different needs, are left
to their discretion.
To show that the public policy mandate has sown confusion,
petitioners point to tariffs rejected by the Commission for failure
to comply with this requirement. But the Commission found no
fault in the adequacy of the utilities’ procedures; the
Commission rejected the tariffs because they failed to include,
in certain respects, any procedures at all. See, e.g., S. Carolina
Elec. & Gas Co., 143 F.E.R.C. ¶ 61,058 at ¶ 119 (2013) (“While
SCE&G states in its transmittal letter that proposed transmission
solutions to address transmission needs driven by public policy
requirements will be evaluated in the same open and
nondiscriminatory manner as other proposed regional
transmission solutions for purposes of cost allocation, such
information is not set forth in its tariff.” (footnote omitted));
NorthWestern Corp., 143 F.E.R.C. ¶ 61,056 at ¶ 84
(“NorthWestern has not established actual procedures in its
OATT to identify at the regional level those transmission needs
driven by public policy requirements for which potential
transmission solutions will be evaluated. For example, it is not
clear in NorthWestern’s OATT when and how stakeholders can
propose transmission needs driven by public policy
requirements for potential evaluation in the . . . regional
transmission planning process.”). Rejection of tariffs that
utterly fail to establish the procedures required by the public
policy mandate tells us nothing about whether the mandate is
impermissibly vague.
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We find all of the challenges to the public policy mandate
to be without merit and thus uphold the mandate.
VII.
Reciprocity. Petitioners raise two challenges to the Final
Rule’s reciprocity condition. The reciprocity principle,
instituted by the Commission in the Final Rule and two prior
orders, requires non-public utility transmission providers that
choose to access a public utility’s transmission lines to provide
in exchange “reciprocal” transmission service, that is, service
provided on comparable terms. See Order No. 1000 ¶¶ 818–19,
76 Fed. Reg. at 49,961; Order No. 890 ¶¶ 162–192, 72 Fed. Reg.
at 12,290–94; Order No. 888 at pp. 31,690–92, 61 Fed. Reg. at
21,541–42. The Final Rule includes as part of the reciprocity
condition that non-public utilities must participate in
transmission planning and cost allocation in exchange for open
access. Order No. 1000 ¶¶ 818–19, 76 Fed. Reg. at 49,961.
Two groups of petitioners attack the Rule’s reciprocity
condition on nearly opposite grounds. The Joint Petitioners
argue that the Commission changed course from past practice
without reasoned explanation by expanding the previous
reciprocity condition to include planning and cost allocation
requirements. The Edison Electric Institute (“Edison”), by
contrast, contends that the Commission did not go far enough.
Edison claims that the Commission acted arbitrarily and
capriciously by allowing non-public utilities to participate
voluntarily in the planning and cost allocation requirements of
the orders, whereas Edison contends their participation should
be mandatory. In particular, Edison asserts that the Commission
should have invoked its power under Section 211A of the FPA
to require non-public utility participation. Both contentions
miss the mark.
89
The reciprocity condition before us is fundamentally the
same as that contained in two prior Commission orders, Order
Nos. 888 and 890. None requires non-public utilities to take any
particular action. But all require such utilities, if they choose to
take transmission service from a public utility, to provide
reciprocal transmission service on comparable terms. The
current orders simply apply that principle to transmission
planning and cost allocation, such that any utility drawing from
a public utility’s transmission lines must participate in planning
and cost allocation processes. The Commission provided a
reasoned and adequate basis for doing so, and was not arbitrary
or capricious in deciding to stop at a conditional rather than a
categorical requirement for non-public utilities. Section 211A
does not require the Commission to mandate non-public utility
participation in planning and cost allocation, and the
Commission reasonably declined invoke its Section 211A
authority to adopt such a mandate in favor of the order’s
incremental and incentive-based approach.
A.
The Commission first established the reciprocity condition
in Order No. 888 as part of its “ambitious program of market-
based reforms.” Morgan Stanley, 554 U.S. at 535. As
previously discussed, Order No. 888 required each transmission
provider to file a pro forma OATT offering transmission service
to all customers on an equal basis. In efforts to further open
access to transmission services, the Commission established
that, when non-public utilities use the open public lines, they are
subject to the same conditions as public utilities. See Order No.
888 at p. 31,760, 61 Fed. Reg. at 21,613 (stating that “[a]ny
public utility that offers non-discriminatory open access
transmission for the benefit of customers should be able to
obtain the same non-discriminatory access in return”). That
reciprocity condition, which is carried forward in Order Nos.
890 and 1000, appears in section 6 of the pro forma OATT and
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authorizes public utilities to refuse to offer non-public utilities
access unless the non-public utilities reciprocate by “agree[ing]
to provide comparable transmission service to” the transmission-
providing public utilities “on similar terms and conditions.” Id.
app. D Pro Forma OATT § 6, 61 Fed. Reg. at 21,710; see also
Order No. 890 ¶ 163, 72 Fed. Reg. at 12,290.
Non-public utilities are not subject to Section 206 of the
FPA, and so are not directly governed by Order No. 1000 and its
planning and cost allocation requirements. By conditioning
non-public utilities’ access to the open systems of public utilities
on the former’s adherence to the planning and cost allocation
requirements, however, the Final Rule encourages non-public
utilities to participate in planning and cost allocation. See Order
No. 1000-A ¶ 773, 77 Fed. Reg. at 32,301 (“[T]hose [including
non-public utilities] that ‘take advantage of open access,
including improved transmission planning and cost allocation,
should be expected to follow the same requirements as public
utility transmission providers.’” (quoting Order No. 1000 ¶ 818,
76 Fed. Reg. at 49,961)).
In proposing that reciprocity condition, the Commission
explained that, under Order No. 890, both public and non-public
utilities had collaborated in a number of regional transmission
planning processes. Encouraged by that collaboration, the
Commission employed that voluntary and incentive-based
approach in the orders now under review. NPRM ¶ 43, 75 Fed.
Reg. at 37,890; see also Order No. 1000 ¶ 815, 76 Fed. Reg. at
49,960. The Commission concluded that it was not “necessary
at this time to invoke [the] authority under FPA section 211A,
which allows [the Commission] to require non-public utility
transmission providers to provide transmission services on a
comparable and not unduly discriminatory or preferential basis.”
NPRM ¶ 43, 75 Fed. Reg. at 37,890; see also Order No. 1000
¶ 815, 76 Fed. Reg. at 49,960. Instead, it chose to wait to
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“exercise its authority under FPA section 211A on a case-by-
case basis” if it “finds on the appropriate record that non-public
utility transmission providers are not participating in the
regional transmission planning and cost allocation processes.”
NPRM ¶ 43, 75 Fed. Reg. at 37,890; see also Order No. 1000 ¶
815, 76 Fed. Reg. at 49,960.
In justifying the revised reciprocity condition, the
Commission explained that:
[N]on-public utility transmission providers will benefit
greatly from the improved transmission planning and
cost allocation processes required for public utility
transmission providers because a well-planned grid is
more reliable and provides more available, less
congested paths for the transmission of electric power
in interstate commerce. Those that take advantage of
open access, including improved transmission planning
and cost allocation, should be expected to follow the
same requirements as public utility transmission
providers.
Order No. 1000 ¶ 818, 76 Fed. Reg. at 49,961.
In Order No. 1000-A, the Commission denied rehearing on
Order No. 1000’s reciprocity requirement, again emphasizing
that the reciprocity requirement it adopted was unchanged from
that in Order Nos. 888 and 890. Order No. 1000-A ¶¶ 754, 771,
77 Fed. Reg. at 32,297–98, 32,300.
B.
The Joint Petitioners challenge the reciprocity condition,
urging that the Commission expanded it beyond prior orders,
without reasoned explanation, by including within it the
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planning and cost allocation requirements. We reject this
contention.
The requirement of reciprocity in the Final Rule is the same
as in the prior orders. The Final Rule changes the condition
only by altering the substantive requirements of the pro forma
OATT, centrally by requiring public utilities to engage in
transmission planning and cost allocation. As noted above, it
does not require non-public utilities to take any action unless
they choose to obtain transmission service from a public utility.
Order No. 1000 ¶ 819, 76 Fed. Reg. at 49,961.
The Joint Petitioners contend that the previous orders
limited a non-public utility’s reciprocity obligation to the public
utility that provided it with transmission access, and that the
orders here impermissibly alter that scope without reasoned
basis. The Joint Petitioners misconstrue the prior orders as
limiting reciprocity to two utilities—a non-public utility and the
public utility from which it takes transmission. The prior orders
were not as narrowly bilateral as the Joint Petitioners assert.
Instead, Order No. 890 required non-public utilities that were
either members of, or took transmission service from, a power
pool, Regional Transmission Group (“RTG”), RTO, ISO, or
other such group to provide in return comparable services to all
members of such groups. Order No. 890 app. C Pro Forma
OATT § 6, 72 Fed. Reg. at 12,509; see also Order No. 888 app.
D Pro Forma OATT § 6, 61 Fed. Reg. at 21,710; id. at p.
31,760, 61 Fed. Reg. at 21,613 (Order No. 888’s reciprocity
condition required reciprocal transmission to any power pool or
RTG of which the non-public utility was a member). And Order
No. 890 explicitly determined that comparable service for
reciprocity purposes includes compliance with the transmission
planning reforms instituted by Order No. 890. See Order No.
890 ¶ 441, 72 Fed. Reg. 12,321; Order No. 890-A ¶ 214,
Preventing Undue Discrimination and Preference in
93
Transmission Service, 73 Fed. Reg. 2984, 3008–09 (2008)
(stating on rehearing that a non-public utility with reciprocity
obligations that does not adopt a planning process that complies
with Order No. 890 may be at risk of being denied open access
transmission services by public utilities); see also NPRM ¶ 10,
75 Fed. Reg. at 37,886. The Final Rule’s reciprocity condition
was not the radical swerve the Joint Petitioners decry.
The Final Rule did change the requirements for public
utilities—by requiring both transmission planning and cost
allocation—and in so doing altered what constitute comparable
terms for non-public utilities that choose to seek Commission-
jurisdictional transmission service. See Order No. 1000-A ¶
776, 77 Fed. Reg. at 32,301 (“Order No. 1000 applied the
reciprocity provisions of Order Nos. 888 and 890 to provide that
. . . a public utility transmission provider [may] refuse to offer
open access transmission service to any non-public utility
transmission provider that does not provide comparable
reciprocal transmission service insofar as it is capable of doing
so, including regional planning and cost allocation.”). Even if
we were to view the Commission’s alteration of what constitutes
comparable service under the pro forma OATT as a change in
course, however, the agency acknowledged that it was altering
the content of the reciprocal obligations. See, e.g., id. And the
Commission provided an adequate justification for that
change—namely, that non-public utilities that take service from
public utilities will benefit greatly from the reforms announced
in the Final Rule, because “a well-planned grid is more reliable
and provides more available, less congested paths for the
transmission of electric power in interstate commerce.” Id.
¶ 778, 77 Fed. Reg. 32,301.
In sum, the Commission’s adoption of the reciprocity
condition in the Final Rule fully complied with the requirement
that an agency “display awareness that it is changing
94
position[s]” and “show that there are good reasons for the new
policy.” FCC v. Fox Television Stations, Inc., 556 U.S. 502, 515
(2009).
C.
Petitioner Edison, by contrast, takes the position that the
Commission has authority under Section 211A of the FPA to
mandate that non-public utilities comply with the Final Rule,
including its regional planning and cost allocation requirements,
and that the agency acted arbitrarily and capriciously in failing
to so mandate. We reject that contention as well.
In Edison’s view, “[w]ithout a mandate to participate, non-
public utility transmission providers will receive the[] benefits
[of transmission planning and new facilities] without being
assessed commensurate costs.” Initial Br. of Pet’r Concerning
FPA § 211A at 5 (“Edison Br.”). Edison argues that “[t]he
record demonstrates” that non-public utility transmission
providers will not in fact voluntarily participate in transmission
planning or cost allocation. Id. at 7. In support, Edison cites
comments by non-public utilities to the effect that they are
committed to participating in the planning and cost allocation
processes but cannot commit to being bound by the building
expansion programs that may result because those programs
have not yet been determined. Id. According to Edison, the
Commission must therefore mandate the participation of non-
public utilities under Section 211A of the FPA, and its failure to
do so was arbitrary and capricious.
Section 211A(b) of the FPA provides in relevant part:
[T]he Commission may, by rule or order, require an
unregulated transmitting utility to provide transmission
services—
(1) at rates that are comparable to those that the
unregulated transmitting utility charges itself; and
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(2) on terms and conditions (not relating to rates) that
are comparable to those under which the unregulated
transmitting utility provides transmission services to
itself and that are not unduly discriminatory or
preferential.
16 U.S.C. § 824j-1(b).
Congress’ use of the word “may” in Section 211A plainly
permits, but does not mandate, the Commission to require a non-
public utility to provide transmission service on given terms.
See, e.g., Wagner v. FEC, 717 F.3d 1007, 1012 (D.C. Cir. 2013);
McCreary v. Offner, 172 F.3d 76, 83 (D.C. Cir. 1999). As such,
the statute does not require the Commission to go as far as
Edison urges.
The Commission, moreover, adequately explained that its
past successful experience with voluntary participation under
Order No. 890 led to its decision to take a conditional incentive-
based approach to reciprocity in planning and cost allocation, at
least at this juncture. Order No. 1000 ¶ 815, 76 Fed. Reg. at
49,960. The Commission thus articulated a satisfactory
explanation for its predictive judgment that non-public utilities
are likely to participate voluntarily, and we owe that judgment
deference. “‘[I]t is within the scope of the agency’s expertise to
make . . . a prediction about the market it regulates, and a
reasonable prediction deserves our deference notwithstanding
that there might also be another reasonable view.’”
Constellation Energy Commodities Grp., Inc. v. FERC, 457 F.3d
14, 24 (D.C. Cir. 2006) (ellipses in original) (quoting Envtl.
Action, Inc. v. FERC, 939 F.2d 1057, 1064 (D.C. Cir. 1991)).
The evidence that Edison cites for the proposition that non-
public utilities will not participate does not “flatly contradict[]”
the Commission’s conclusion. Edison Br. 7. Edison points to
comments from non-public utilities expressing concerns about
mandatory cost allocation, but those comments do not
96
contravene the Commission’s judgment that such utilities are
likely to participate in planning and cost allocation when it is a
condition of access to public transmission service.
Nor was the Commission’s approach arbitrary and
capricious because it “creates undue discrimination” between
public and non-public utilities. Edison Br. 10. Edison
complains the Rule foists the costs of new facilities on regulated
public utilities while giving non-public utilities a free ride. The
Commission was under no statutory obligation to regulate non-
public utilities, and it provided a reasoned basis for choosing a
conditional approach, grounded in a prediction that non-public
utilities would in fact participate, and leaving for another day
whether to require non-public utilities’ participation pursuant to
its Section 211A authority. Order No. 1000 ¶ 815, 76 Fed. Reg.
at 49,960.
The Commission’s decision to adopt a reciprocity condition
embracing voluntary and incentive-based participation by non-
public utilities was accordingly neither arbitrary nor capricious.
We therefore need not reach whether the Commission has
authority under Section 211A to mandate the participation of
non-public utilities.
Edison additionally contends that the Commission acted
arbitrarily and capriciously by failing to respond adequately to
its arguments to the Commission on rehearing. That contention,
too, is without merit. Following the Commission’s
announcement in the Notice of Proposed Rulemaking that it
planned to use a voluntary approach, a number of commenters
raised materially identical arguments to those Edison raised in
its request for rehearing. Compare Order No. 1000 ¶ 812, 76
Fed. Reg. at 49,960 (summarizing comments asserting that the
Commission has authority to require non-public utilities’
participation under Section 211A and that its failure to do so
“will result in an inequitable burden for jurisdictional utilities
97
and their customers”) and id. ¶¶ 815, 817–18, 821, 76 Fed. Reg.
at 49,960–61 (responding to those concerns), with Order No.
1000-A ¶¶ 767–70, 77 Fed. Reg. at 32,299–300 (summarizing
Edison’s comment that the Commission “erred by relying on
non-public utility transmission providers to voluntarily
participate in regional transmission planning and cost allocation
processes” instead of exercising its authority under Section
211A). “While an agency must consider and explain its
rejection of ‘reasonably obvious alternative[s],’ it need not . . .
respond to every comment made. Rather, an agency must
consider only ‘significant and viable’ and ‘obvious’
alternatives.” Nat’l Shooting Sports Found., Inc. v. Jones, 716
F.3d 200, 215 (D.C. Cir. 2013) (brackets in original) (citations
omitted). The Commission adequately addressed the
commenters’ concerns that voluntary participation by non-public
utilities would undermine the Commission’s objectives and
sufficiently explained its reasons for declining, at that time, to
require non-public utility compliance under Section 211A.
For these reasons, we reject the challenges to the reciprocity
condition.
Accordingly, we deny the petitions for review.