North Carolina Utilities Commission v. Federal Energy Regulatory Commission

PUBLISHED
UNITED STATES COURT OF APPEALS
FOR THE FOURTH CIRCUIT
No. 12-1881
NORTH CAROLINA UTILITIES COMMISSION,
Petitioner,
OLD DOMINION ELECTRIC COOPERATIVE; NORTH CAROLINA ELECTRIC
MEMBERSHIP CORPORATION,
Intervenors,
v.
FEDERAL ENERGY REGULATORY COMMISSION,
Respondent,
VIRGINIA ELECTRIC AND POWER COMPANY,
Intervenor.
Appeal from the Federal Energy Regulatory Commission. (ER08-
1207)
Argued: December 10, 2013 Decided: January 24, 2014
Before DUNCAN, WYNN, and THACKER, Circuit Judges.
Affirmed by published opinion. Judge Duncan wrote the opinion,
in which Judge Wynn and Judge Thacker joined.
ARGUED: Kimberly Weaver Duffley, NORTH CAROLINA UTILITIES
COMMISSION, Raleigh, North Carolina, for Petitioner. Lona
Triplett Perry, FEDERAL ENERGY REGULATORY COMMISSION,
Washington, D.C., for Respondent. ON BRIEF: Louis S. Watson,
Jr., General Counsel, NORTH CAROLINA UTILITIES COMMISSION,
Raleigh, North Carolina, for Petitioner. David L. Morenoff,
Acting General Counsel, Robert H. Solomon, Solicitor, FEDERAL
ENERGY REGULATORY COMMISSION, Washington, D.C., for Respondent.
Michael C. Regulinski, DOMINION RESOURCES SERVICES, INC.,
Richmond, Virginia; J. Tracy Walker, IV, David Martin Connelly,
MCGUIREWOODS LLP, Richmond, Virginia, for Intervenor Virginia
Electric and Power Company.
2
DUNCAN, Circuit Judge:
The North Carolina Utilities Commission (“NCUC”) challenges
incentives granted by the Federal Energy Regulatory Commission
(“FERC”) to Virginia Electric Power Company d/b/a Dominion
Virginia Power (“VEPCO”) to encourage investment in transmission
infrastructure projects. NCUC argues that FERC violated § 219
of the Federal Power Act (“FPA”) and abused its discretion by
granting these incentives in 2008 and by denying its petition
for rehearing in 2012. Constrained by the standard of review,
we affirm.
I.
We begin with a brief description of FERC’s statutory
authority to grant the incentives at issue. Under the Federal
Power Act, FERC exercises general jurisdiction over all rates,
terms, and conditions of interstate electric transmission
service provided by public utilities. See 16 U.S.C. § 824(b).
Congress amended the FPA in 2005 by passing the Energy Policy
Act (“EPAct”) to create a national energy policy focused on
increasing efficiency and innovation. Pub. L. 109-58, 119 Stat.
594 (2005); S. Rep. 109-78 at 1 (2005). In response to concerns
about the reliability of the country’s aging transmission
system, § 219 of the FPA required FERC to promulgate a rule
establishing incentive-based rate treatments for qualifying
3
projects to spur infrastructure investment. 16 U.S.C. §
824s(c). 1
After notice and comment, FERC adopted a final rule
establishing a three-prong test for evaluating applications for
incentives under § 219. Promoting Transmission Investment
Through Pricing Reform, Order No. 679, FERC Stats. & Regs. ¶
31,222, at P 326 (2006), order on reh'g, Order No. 679-A, FERC
Stats. & Regs. ¶ 31,236 (2007), order on reh'g, Order No. 679-B,
119 FERC ¶ 61,062 (2007); codified at 18 C.F.R. § 35.35 (“Orders
No. 679, 679-A, & 679-B”). First, the utility must show that
its infrastructure project will increase reliability or reduce
congestion. Order No. 679 ¶ 42. Second, the utility must
demonstrate a nexus between the requested incentive and the
project. Id. ¶ 48. Finally, the utility must prove that its
resulting rates with the incentive remain “just and reasonable.”
Id. ¶ 59. We briefly explain each prong.
A.
The requirement of prong one--a showing of either increased
reliability or reduced congestion--is largely self-explanatory
with one proviso relevant here. A utility can qualify for a
1
The incentives take the form of basis point “adders.”
Each basis point is equivalent to a 1/100% increase in a
utility’s return on equity (ROE), meaning that, for example, a
100 basis point adder translates into a 1% rise in a utility’s
ROE.
4
rebuttable presumption that its infrastructure project will
either ensure reliability or reduce transmission congestion if
it resulted from a regional planning process that included
consideration of reliability and cost reduction. Order No. 679
¶ 58; Order No. 679-A ¶ 5.
B.
The analysis under prong two--determining whether the nexus
requirement is met--is more challenging. A utility must
demonstrate that the incentive will materially affect investment
decisions by showing that it is “tailored to [the project’s]
risks and challenges.” Order No. 679 ¶ 26; see also Order No.
679-A ¶ 21. Significantly here, a utility need not prove it
would not undertake the project without the incentive. Order
No. 679 ¶ 48. FERC determined that a but-for test would erect
too high of an “evidentiary hurdle.” Order No. 679-A ¶ 25.
FERC has further clarified the parameters of the nexus test
through adjudication. In Baltimore Gas & Electric Company, 120
FERC ¶ 61,084 (2007), FERC held that a project meets the nexus
test if it is “not routine.” Id. ¶ 54. To make this
determination, FERC considers all relevant factors including:
(1) the project’s scope measured in dollar investment or
increase in transfer capability; (2) its impact on regional
reliability or reduced congestion costs; and (3) project
specific challenges including siting risks, political pressure,
5
and difficulties in securing financing. Id. ¶ 52. FERC also
held projects resulting from a regional planning process qualify
as “not routine” because of their impact on regional
reliability. Id. ¶ 58. 2
FERC’s approach to applying the nexus test has evolved over
time. Initially, when a utility included multiple, unrelated
projects in a single application, FERC evaluated the projects in
the aggregate to determine whether the nexus test was met.
Order No. 679-A ¶ 27. While the utility was still required to
“provide sufficient explanation and support to allow the
Commission to evaluate each element of the package,” because an
incentive for one project might lower the risk of another in the
same application, FERC sought to ensure that the package of
incentives as a whole would appropriately address the utility’s
risk overall. Id.
In 2010, however, in PJM Interconnection, Inc., 133 FERC ¶
61,273 (2010), and Oklahoma Gas and Electric Company, 133 FERC ¶
61,274 (2010), FERC announced that it would no longer apply the
nexus test in the aggregate to unrelated projects presented in a
2
After FERC issued the final order in this case, it
determined that it would no longer use the Baltimore Gas
routine/non-routine analysis as a proxy for satisfying the nexus
test to applications received after November 2012. Promoting
Transmission Investment Through Pricing Reform, 141 FERC ¶
61,129 (2012).
6
single application. Instead, a utility would be required to
meet the nexus test for each individual project. PJM
Interconnection, 133 FERC ¶ 61,273, at ¶ 45. This new policy
would be applied “in this and future cases.” Id.
C.
Finally, under the third prong of the Order No. 679 test, a
utility must demonstrate that its resulting rates are “just and
reasonable” under § 219(d). This requirement clarifies that a
utility seeking a § 219 incentive remains constrained by the
requirement that its rates be “just and reasonable” under § 205
of the FPA. Order No. 679 ¶ 8. Under the FPA, a utility must
obtain approval through a rate-setting process in order to raise
its rates to incorporate an incentive. Id. ¶ 77. A utility
meets this requirement if its return on equity (ROE) with the
requested incentive falls within a “zone of reasonableness.” 3
Id. ¶ 91. With this explanation in mind, we turn now to FERC’s
application of the three prongs of Order No. 679’s test to
VEPCO’s application in its 2008 declaratory proceeding.
3
This zone is determined through the same one-step
discounted cash flow analysis (“DCF”) used in any rate
proceeding before FERC. Order No. 679 ¶ 92. The DCF compares
the utility’s ROE with those of proxy companies and accounts for
other factors, such as risk. Id.
7
II.
A.
On July 1, 2008, VEPCO, a member of PJM Interconnection LLC
(“PJM”), 4 sought incentives for eleven transmission projects with
a total estimated cost of $877 million. VEPCO requested a 125
basis point adder for a bundle of seven projects, a mix of new
construction and improvements to existing infrastructure. VEPCO
requested an additional 150 basis point adder for a bundle of
four larger-scale projects.
After notice of VEPCO’s filing was published, NCUC and
numerous other parties moved to intervene. NCUC originally
protested the grant of incentives to six of the projects. On
appeal, NCUC continues to challenge five. Four of the five
projects were part of VEPCO’s application for a 125 basis point
adder: The Lexington Tie Project, Idylwood-to-Arlington
Reconductor (“Idylwood Project”), the Garrisonville Project, and
the Pleasant View-to-Hamilton Project (“Pleasant View Project”).
The fifth, the Proactive Transformer Replacement Project
(“PTRP”), was part of VEPCO’s application for a 150 basis point
4
PJM is one of the voluntary Regional Transmission
Organizations (“RTOs”) authorized by FERC to facilitate the
transmission of electricity between owners of transmission lines
that comprise an integrated regional grid. Regional
Transmission Organizations, 65 Fed. Reg. 810, 811-12 (2000).
8
adder. We briefly describe each challenged project before
turning to the proceedings below.
1.
The Lexington Tie Project and Idylwood-Arlington
Reconductor are PJM Regional Transmission Expansion Plan
(“RTEP”) projects. The RTEP is the product of a long-term
planning process by PJM to identify areas where infrastructure
upgrades or improvements are needed to ensure compliance with
national and regional reliability standards. The Lexington Tie
Project requires the installation of upgraded line breakers at
VEPCO’s Lexington substation at an estimated cost of $6 million.
The Idylwood Project requires replacement of existing conductors
on 230 kV transmission lines with triple-circuit structures and
high-temperature/high-capacity conductors. As RTEP projects,
they enjoy a rebuttable presumption that the requirements of
prong one are met.
The Garrisonville and Pleasant View Projects are not RTEP
projects, and involve the construction of new transmission
lines. The Garrisonville Project will result in a five mile
underground transmission line at an estimated cost of $120
million. The Pleasant View Project involves the construction of
a twelve-mile transmission line, two of which would be
constructed underground, at an estimated cost of $90 million.
9
VEPCO’s Proactive Transformer Replacement Project (“PTRP”)
is also not a RTEP project. It requires the replacement of
thirty-two 500/230 kV transformers located in nine transformer
banks in seven substations at an estimated cost of $110 million.
2.
At the proceedings below, VEPCO supported its application
with twenty-four exhibits seeking to demonstrate why each of the
eleven projects merited § 219 incentives. NCUC challenged the
five projects on appeal under the first two prongs of Order
679’s test. Under prong one, NCUC disputed only the Proactive
Transformer Replacement Project (“PTRP”) arguing that it would
not increase reliability. 5 NCUC protested the grant of
incentives to each of the five projects challenged on appeal
under prong two contending that they failed to meet the nexus
requirement. We consider each challenge in turn.
a.
Under prong one, VEPCO argued that its PTRP would increase
regional reliability by significantly reducing the risk of
transformer failure. VEPCO based its application, in part, on a
5
At the initial hearing, NCUC challenged the Pleasant View
and Garrisonville Projects under prong one arguing that they
would not increase regional reliability. This argument is not
before us on appeal however because NCUC declined to raise it in
its petition for rehearing. See Mt. Lookout-Mt. Nebo Prop.
Prot. Ass’n v. FERC, 143 F.3d 165, 173 (4th Cir. 1998)
10
Probabilistic Risk Analysis (“PRA”) conducted by PJM as part of
its regional planning process. VEPCO used this data to identify
aging transformers with a higher risk of failure to target for
replacement. If one of these transformers failed, VEPCO argued,
there would be a decrease of between 33% to 66% in
transformation capacity at each substation. NCUC responded that
the PJM’s PRA actually determined that VEPCO’s current
transformer network was sufficiently reliable because VEPCO had
more than the required number of spare transformers. As a
result, PJM did not recommend any upgrades to VEPCO’s
transformer network in its planning process. NCUC argued,
therefore, that VEPCO should not be able to rely upon the PRA to
support its application for an incentive.
FERC found that VEPCO carried its prong-one burden of
proving the PTRP would increase reliability agreeing that absent
the project, there was a risk of outages for customers in
multiple service areas. Virginia Electric and Power Company,
124 FERC ¶ 61,207 (2008) (“Incentives Order”), at ¶ 37. FERC
also noted that the standard industry practice of relying on
spares can result in delays in restoring service. Id. ¶ 38.
Therefore, FERC rejected NCUC’s argument that PJM’s decision not
to include this project in its RTEP project list meant the PTRP
would not enhance reliability.
11
b.
Under prong two of the Order No. 679 test, VEPCO presented
evidence that each of its projects was non-routine under
Baltimore Gas and, therefore, met the nexus test.
i.
The Lexington Tie Project merited incentive treatment,
VEPCO contended, because it would ensure reliability along a
major interface in the Eastern Interconnection. VEPCO also
identified construction risks, including the requirement that
the substation be taken out of service temporarily during
construction. VEPCO argued that the Idylwood Project met the
nexus test because it faced significant local opposition.
Construction would take place along a heavily used portion of
the Washington & Old Dominion Trial in a densely populated area.
VEPCO’s construction permits had been denied twice and a third
application was pending. NCUC responded that, to the contrary,
these projects were routine. In NCUC’s view, VEPCO’s current
ROE was sufficient to attract investment in the Lexington Tie
and Idylwood projects as evidenced by their small scale and the
fact that they were already underway.
FERC rejected NCUC’s arguments, finding that both the
Lexington Tie and Idylwood Projects were non-routine under
Baltimore Gas. As RTEP projects, FERC concluded, both the
Lexington Tie and Idylwood Projects would enhance regional
12
reliability. Id. ¶ 100. Further, FERC credited VEPCO’s
additional arguments that these projects were non-routine
because of ongoing local opposition and construction challenges.
Id. ¶¶ 100, 110.
ii.
In contending that both the Garrisonville and Pleasant View
Projects qualified as non-routine, VEPCO pointed out that it had
agreed to construct the Garrisonville line and part of the
Pleasant View line underground in response to significant local
opposition. Underground construction raised the risk of these
projects, VEPCO argued, because of changeable elevation, tricky
soil conditions, and the required use of new technology.
NCUC responded these projects were not economically
efficient as planned because these lines could be constructed
above ground at a lower cost. NCUC pointed out that the
Virginia Commission had approved entirely above-ground
construction for the Pleasant View Line demonstrating that VEPCO
decided to build underground solely to appease local officials.
At the very least, NCUC contended, VEPCO’s wholesale customers
should not be required to subsidize the incremental cost of
underground construction.
In light of the on-going local opposition to these
projects, construction challenges, and their beneficial impact
on regional reliability, FERC concluded that VEPCO’s decision to
13
build underground did not disqualify these projects from
incentive treatment and that VEPCO satisfied the nexus test for
the full price of both projects. Id. ¶¶ 77, 85.
iii.
Finally, VEPCO argued that the PTRP was non-routine because
its proactive approach deviated from the industry standard,
required coordination across multiple substations, and
necessitated significant investment in skilled labor and
capital. As it had under prong one, NCUC replied that the PTRP
should not qualify for incentive treatment because VEPCO’s
supply of spare transformers was more than adequate.
FERC rejected NCUC’s argument in this regard as well,
concluding that the fact that this project was not included in
PJM’s RTEP was insufficient to disqualify it from meriting
incentives. Id. ¶ 72. Overall, FERC held that VEPCO’s
application satisfied the nexus requirement “both as a package
and for each individual project.” Id. ¶ 48.
FERC ultimately granted VEPCO’s application in full. Id.
¶ 1. NCUC filed a petition for rehearing on September 29, 2008.
B.
1.
In its request for rehearing, NCUC reiterated its
objections to the incentives for the five challenged projects
and identified other errors in FERC’s order as well. In
14
particular, it contended FERC misunderstood the PTRP’s scope
because it twice incorrectly stated that the project involved
the replacement of only nine, not thirty-two, transformers.
2.
For reasons that remain unsatisfactorily explained even
after oral argument, FERC failed to issue its Order Denying
Rehearing until almost four years after its initial order on May
22, 2012. Virginia Electric and Energy Company, 139 FERC ¶
61,143 (2012) (“Rehearing Order”).
In its Rehearing Order, FERC considered whether to grant
rehearing to apply the intervening 2010 policy change to the
nexus test announced in PJM and Okla. Gas. FERC stated “it can
be argued that if a similar request for incentives were
submitted to the Commission at this time, the result might be
different in light of the Commission’s evolving policy with
respect to application of the Order No. 679 nexus test.” Id. ¶
11. Nevertheless, FERC decided against rehearing on that basis
for three reasons. First, PJM and Okla. Gas expressly stated
that the change to the nexus requirement would be applied only
prospectively. Id. ¶ 11. Second, VEPCO legitimately relied on
the application of the nexus test as interpreted at the time of
the Incentives Order. Id. ¶ 12. And, FERC feared that the
regulatory uncertainty that would result from shifting an
earlier position four years after the fact could deter reliance
15
on § 219 incentives more broadly. Id. FERC proceeded to
confirm the grant of VEPCO’s incentives, finding that the
additional arguments raised on rehearing failed to provide
grounds for rehearing. On July 20, 2012, NCUC timely appealed
under 16 U.S.C. § 825l(b).
III.
We will affirm FERC’s conclusions unless they are
“arbitrary, capricious, an abuse of discretion, or otherwise not
in accordance with law, or unsupported by substantial evidence.”
Appomattox River Water Auth. v. FERC, 736 F.2d 1000, 1002 (4th
Cir. 1984); 16 U.S.C. § 825l(b). Substantial evidence is “more
than a mere scintilla, but less than a preponderance.” T-Mobile
Ne. LCC v. City Council of Newport News, Va., 674 F.3d 380, 385
(4th Cir. 2012). When we are required to review an agency’s
“complex predictions based on special expertise,” our review is
“at its most deferential.” Ohio Valley Envtl. Coal. v. Aracoma
Coal Co., 556 F.3d 177, 192 (4th Cir. 2009) (citing Balt. Gas &
Elec. Co. v. Natural Res. Def. Council, 462 U.S. 87, 103
(1983)).
IV.
NCUC makes two primary arguments on appeal. First, it
argues that FERC erred by declining to grant rehearing to apply
16
the 2010 policy change with respect to the nexus test. Second,
it contends that FERC abused its discretion by granting VEPCO
incentives based on the five challenged projects. We address
these arguments in turn. 6
A.
Preliminary, however, we must determine whether we have
jurisdiction to entertain this appeal. FERC argues that under
16 U.S.C. § 825l(b), we lack jurisdiction to consider NCUC’s
argument that FERC should have granted rehearing to apply the
2010 change to the nexus test because NCUC did not challenge its
decision in a renewed petition for rehearing before filing this
appeal. Under 16 U.S.C. § 825l, “[n]o objection to the order of
the Commission shall be considered by the court unless such
objection shall have been urged before the Commission in the
application for rehearing unless there is reasonable ground for
failure so to do.” The self-evident purpose of this requirement
is to allow FERC the opportunity to correct its own errors, if
6
NCUC also argues that FERC’s Incentives Order and
Rehearing Order both failed to adequately address its arguments
and to provide sufficient reasoning to facilitate appellate
review in violation of SEC v. Chenery, Corp., 332 U.S. 194
(1947). We agree that at times FERC erred in characterizing
NCUC’s arguments but find no evidence that FERC failed to
“address []important challenge[s] to its reasoning” as would be
required to remand here. K N Energy, Inc. v. FERC, 968 F.2d
1295, 1303 (D.C. Cir. 1992). Therefore, we find these arguments
to be without merit.
17
any, prior to court intervention. See ASARCO, Inc. v. FERC, 777
F.2d 764, 773-74 (D.C. Cir. 1985). We interpret this
requirement strictly based on the “time-honored doctrine of
exhaustion of administrative remedies.” Consol. Gas Supply
Corp. v. FERC, 611 F.2d 951, 959 (4th Cir. 1979) (quoting Fed.
Power Comm’n v. Colo. Interstate Gas Co., 348 U.S. 492, 500
(1955)).
It is hardly surprising that NCUC did not argue in its
September 28, 2008 rehearing petition that FERC should
reevaluate VEPCO’s incentives under the 2010 policy change.
Given that NCUC filed its petition two years before FERC issued
PJM and Okla. Gas, absent extraordinary prescience it could not
have done so. In any case, we find that NCUC had reasonable
grounds for failing to file a renewed petition for rehearing
under § 825l(b).
When FERC reaffirms a prior result in a rehearing order but
provides a new rationale about which the petitioner had no prior
notice, the petitioner has reasonable grounds for challenging
the FERC’s new justification on appeal without first filing a
renewed petition for rehearing. See Columbia Gas Transmission
Corp. v. FERC, 477 F.3d 739, 741-742 (D.C. Cir. 2007). To
interpret § 825l(b) otherwise would “‘permit an endless cycle of
applications of rehearing and denials,’ limited only by FERC’s
ability to think up new rationales.” So. Natural Gas Co. v.
18
FERC, 877 F.2d 1066, 1072 (D.C. Cir. 1989) (quoting Boston Gas
Co. v. FERC, 575 F.2d 975, 978 (1st Cir. 1978)). In Columbia
Gas, for example, FERC initially rejected the petitioners’
discounted rate agreement under the Natural Gas Act (“NGA”)
based on the inclusion and scope of the agreement’s section 5
waivers. 477 F.3d at 740. On rehearing, FERC affirmed its
decision but added a new reason for rejecting the agreement,
that the gas company had acted improperly by offering discounts
only to its biggest customers. Id. The petitioners appealed
directly to the D.C. Circuit. That court held that it had
jurisdiction to evaluate the parties’ challenge to FERC’s
finding of discrimination because the rehearing order did not
change the outcome and FERC had “not yet revealed” its new
rationale when the parties requested rehearing. Id.
Similarly here, the conclusions of the May 22, 2012
Rehearing Order and the August 29, 2008 Incentives Order were
identical. In both, FERC determined that VEPCO merited
incentives for each of its eleven infrastructure projects. The
only new analysis FERC provided in its Rehearing Order was its
decision not to reopen the case to apply the 2010 policy change.
NCUC had no way to anticipate that FERC would consider whether
to grant rehearing to apply its changed approach to the nexus
19
test. 7 Given that NCUC had already waited four years for a
response to its initial petition, we have little difficulty
concluding that it had reasonable grounds for failing to file a
renewed rehearing petition. 8 Having found that we have
jurisdiction to consider whether FERC erred by failing grant
rehearing to apply the 2010 policy change in this case, we now
review that decision for abuse of discretion.
B.
When an agency announces a new policy while a case is
pending, the decision regarding whether to apply that new policy
on rehearing is “committed, in the first instance, to the
agency’s sound discretion.” Nat’l Posters, Inc. v. NLRB, 720
F.2d 1358, 1364 (4th Cir. 1983) (quoting NLRB v. Food Store Emp.
Union, 417 U.S. 1, 10 n.10 (1974)).
In reviewing that discretion, we consider the parties’
reliance interests. See ARA Serv., Inc. v. NLRB, 71 F.3d 129,
7
NCUC’s lack of notice also disposes of FERC’s additional
argument that NCUC could have amended its petition to urge FERC
grant rehearing to apply its new approach to the nexus test
after the 2010 policy change was issued.
8
FERC seeks to differentiate this case from Columbia Gas by
arguing that its decision not to apply the 2010 policy change
was distinct from the merits of the case and did not represent a
new justification for VEPCO’s incentives. However, as FERC
itself argued, § 825l(b) does not differentiate between FERC’s
decision regarding what policy to apply and its assessment of
the merits of a case. We find no reason, therefore, to alter
our analysis under § 825l(b).
20
135 (4th Cir. 1995). When a new policy represents an “abrupt
change of administrative course,” the parties’ reliance on the
old standard cautions against retroactive application. Id.
NCUC contends, however, that any alleged reliance interest here
was unreasonable because PJM and Okla. Gas represent merely a
clarification of the nexus test and not a policy change. NCUC
points to the Rehearing Order where FERC stated that its
approach to the nexus test is “evolving,” Rehearing Order ¶ 11,
and to the PJM decision itself where FERC noted that it had not
uniformly applied the nexus test since issuing Order No. 679.
133 FERC ¶ 61,273, at ¶ 44. In the very next paragraph of PJM,
however, FERC explicitly stated that it was announcing a “change
[to] Commission policy with respect to application of the nexus
test to groups of projects.” Id. ¶ 45. Instead of assessing
unconnected projects in the aggregate, FERC would require a
utility to “demonstrate [a] nexus between the incentive sought
and the specific investment being made” project by project. Id.
This is a clear change in policy given that, in Order No. 679-A,
FERC stated that it would apply the nexus test in the aggregate
to projects presented in a single application. Order No. 679-A
¶ 27. And, in the 2008 Incentives Order, FERC applied the nexus
test in the aggregate to the eleven projects in VEPCO’s
21
application. Incentives Order ¶ 49. 9 Under these circumstances,
VEPCO was “entitled to rely on the consistent application of
administrative rules.” Se. Mich. Gas Co. v. FERC, 133 F.3d 34,
38 (D.C. Cir. 1998).
FERC also appropriately considered doctrinal stability when
determining whether to grant rehearing here. Agencies are
certainly entitled to consider the broader regulatory
implications of their decisions and we will not second guess
their reasonable conclusions. See id. For these reasons, we
find no error in FERC’s decision not to grant rehearing to apply
the 2010 policy change to the nexus test.
C.
We now turn to NCUC’s challenges to the merits: that the
Lexington Tie, Idylwood, Garrisonville, and Pleasant View
Projects fail the nexus requirement; and that FERC’s finding
that the Proactive Transformer Replacement Project (“PTRP”)
merited incentive treatment is not supported by substantial
evidence. We consider each argument mindful that we may not
reweigh the evidence. We determine only whether FERC
9
FERC also found that VEPCO’s application met the nexus
test for each individual project. Incentives Order ¶ 48. It is
unclear therefore whether the outcome would actually be
different had FERC opted to grant rehearing. However, because
we find that FERC’s decision was reasonable, we do not need to
determine whether any error would be harmless.
22
“examine[d] the relevant data and articulate[d] a satisfactory
explanation for its action including a ‘rational connection
between the facts found and the choice made.’” Motor Vehicle
Mfrs. Ass’n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43
(1983) (quoting Burlington Truck Lines v. United States, 371
U.S. 156, 168 (1962)).
1.
NCUC argues the Lexington Tie and Idylwood Projects fail to
meet the nexus requirement because their pre-incentive ROE was
sufficient to attract investment. In light of the small scale
of these projects and the fact that they were already underway
when the incentives issued, NCUC contends, VEPCO failed to show
that the incentives would “materially affect” its investment
decisions. Order No. 679-A ¶ 25. We disagree.
In Order No. 679-B, FERC stated that there was no size cut-
off for projects when determining eligibility for incentives
under the nexus test. Id. ¶ 18. Instead, FERC would evaluate
each project on a “case-by-case basis.” Id. Moreover, as we
have noted previously, a utility need not prove that but-for a §
219 incentive, it would not undertake a project. Order No. 679-
A ¶ 20. FERC found that such a high “evidentiary hurdle” would
run counter to Congress’s directive to drive money into
improving the country’s aging transmission infrastructure. Id.
There is therefore nothing to prevent a utility from qualifying
23
for incentives based on projects that are already underway,
given that they could help attract financing or accelerate
construction. Order No. 679 ¶ 35.
Finally, we have no trouble holding that FERC’s finding
that both projects satisfy the nexus test is supported by
substantial evidence. Both the Lexington Tie and Idylwood
Projects meet many of the Baltimore Gas factors. They resulted
from a regional planning process, faced ongoing and significant
local opposition, and involved construction challenges based on
changeable elevation and the use of new technology. See
Incentives Order, ¶¶ 100, 106. Therefore, we affirm.
2.
NCUC next argues that the Garrisonville and Pleasant View
Projects fail to meet the nexus test because they are not
“economically efficient” as required by § 219(a). 16 U.S.C. §
824s(b)(1). The basis of this contention is that a less
expensive alternative--namely, above ground rather than
underground construction--exists for both utility lines. We
find no error in FERC’s analysis.
Fatal to NCUC’s argument is the fact that neither § 219 nor
Order No. 679 require FERC to only grant incentives to the least
expensive approach to a project. To the contrary, FERC
expressly rejected a requirement that utilities provide a cost-
benefit analysis, concluding that consumers would be adequately
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protected by the requirement that incentive-based rates remain
just and reasonable. Order No. 679 ¶ 59. Instead, FERC created
its three-prong test for incentives that, in its view,
“fulfilled [Congress’s] command by . . . removing impediments to
new investment or otherwise attract that investment.” Order No.
679-A ¶ 3.
In some respects, it appears NCUC is asking us to determine
whether Order No. 679 is a “permissible construction of [§
219].” See Chevron U.S.A., Inc. v. Natural Res. Def. Council
Inc., 467 U.S. 837, 843 (1984). However, NCUC has repeatedly
claimed that it is only challenging FERC’s finding that these
projects meet the nexus test, not the reasonableness of the rule
itself. Therefore, rather than evaluating Order No. 679 under
the familiar Chevron test, we simply will determine whether
FERC’s grant of incentives to VEPCO for these projects was
supported by substantial evidence. FERC concluded that these
projects satisfied the nexus test based on construction risks,
ongoing local opposition, and their impact on regional
reliability. Incentives Order, ¶¶ 77, 85. We affirm.
3.
NCUC’s final challenge is to the incentive granted for
VEPCO’s Proactive Transformer Replacement Project (“PTRP”). It
argues that FERC’s decision is not supported by substantial
evidence because FERC misunderstood the scope of the project and
25
the meaning of the Probabilistic Risk Analysis (“PRA”) relied
upon by VEPCO in its application.
We agree with NCUC that FERC’s error in describing the PTRP
in the Incentives Order and its failure to correct its mistake
in the Rehearing Order are troubling. Twice in the Incentives
Order, FERC referred to the project as the replacement of "nine
500/230 kV transformers." Incentives Order ¶¶ 9, 68. In fact,
VEPCO proposed to replace thirty-two transformers across nine
transformer banks in seven substations. That one missing word,
of course, has an outsized impact on the project’s scope.
However, based on the record as a whole, we are persuaded that
FERC understood the nature of the PTRP. FERC quoted the correct
estimated cost of the project, $110 million, and cited to a
VEPCO exhibit that listed each of the thirty-two targeted
transformers. Id. ¶ 37, n.17. Therefore, we will not require
remand for FERC to correct its error and reevaluate PTRP’s
eligibility for incentive treatment under § 219. 10
NCUC’s additional challenge--that FERC misunderstood the
meaning of the PJM’s PRA--asks us to reweigh the evidence.
VEPCO used the PRA preformed by PJM as a starting point for its
10
FERC explained that it was quoting from VEPCO’s original
application that contained this error. However, VEPCO
subsequently corrected its application. It remains unclear why
FERC failed to do the same.
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own analysis, which FERC credited, to identify thirty-two aging
transformers to replace. FERC determined the PTRP would
increase reliability because reliance on spares can mean delays
in restoring service. Incentives Order ¶ 38. Further, FERC
concluded the PTRP satisfied the nexus test because it was an
innovative and large-scale undertaking. NCUC clearly disagrees
with these findings. This analysis however is more than
sufficient for us to affirm FERC’s finding that the PTRP met
prongs one and two of the Order No. 679 test.
V.
In sum, we hold that in this case, FERC properly exercised
its broad discretion in declining to apply the 2010 policy
change in its Rehearing Order and in evaluating VEPCO’s
application for incentives. FERC’s grant of incentives to VEPCO
under § 219 is therefore
AFFIRMED.
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