North Carolina Utilities Comm v. FERC
Filing
PUBLISHED AUTHORED OPINION filed. Originating case number: ER08-1207. [999283278]. [12-1881]
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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.
1207)
Argued:
December 10, 2013
Decided:
(ER08-
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,
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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.
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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
authority to grant the incentives at issue.
FERC’s
statutory
Under the Federal
Power Act, FERC exercises general jurisdiction over all rates,
terms,
and
conditions
of
interstate
service provided by public utilities.
electric
transmission
See 16 U.S.C. § 824(b).
Congress amended the FPA in 2005 by passing the Energy Policy
Act
(“EPAct”)
to
create
a
national
increasing efficiency and innovation.
energy
the
reliability
of
the
focused
on
Pub. L. 109-58, 119 Stat.
594 (2005); S. Rep. 109-78 at 1 (2005).
about
policy
In response to concerns
country’s
aging
transmission
system, § 219 of the FPA required FERC to promulgate a rule
establishing
incentive-based
rate
3
treatments
for
qualifying
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projects
to
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spur
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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.
demonstrate
Order No. 679 ¶ 42.
project.
a
nexus
Id. ¶ 48.
between
the
Second, the utility must
requested
incentive
and
the
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.
1
A utility can qualify for a
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
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rebuttable
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presumption
that
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its
infrastructure
project
will
either ensure reliability or reduce transmission congestion if
it
resulted
from
a
regional
planning
process
that
consideration of reliability and cost reduction.
included
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.”
679-A ¶ 21.
Order No. 679 ¶ 26; see also Order No.
Significantly here, a utility need not prove it
would not undertake the project without the incentive.
No. 679 ¶ 48.
Order
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
determination,
(1)
the
increase
“not
FERC
project’s
in
reliability
considers
scope
transfer
or
routine.”
all
¶
54.
relevant
measured
capability;
reduced
Id.
in
(2)
congestion
To
make
factors
dollar
this
including:
investment
or
its
impact
on
regional
costs;
and
(3)
project
specific challenges including siting risks, political pressure,
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and difficulties in securing financing.
Id. ¶ 52.
FERC also
held projects resulting from a regional planning process qualify
as
“not
routine”
reliability.
because
of
their
impact
on
regional
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
Order No. 679-A ¶ 27.
“provide
sufficient
whether
the
nexus
test
was
met.
While the utility was still required to
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).
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single application.
meet
the
nexus
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Instead, a utility would be required to
test
for
Interconnection, 133 FERC
each
individual
¶ 61,273, at ¶ 45.
would be applied “in this and future cases.”
project.
PJM
This new policy
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.
application
With this explanation in mind, we turn now to FERC’s
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.
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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
numerous
notice
other
of
VEPCO’s
parties
moved
filing
to
was
published,
intervene.
NCUC
NCUC
originally
protested the grant of incentives to six of the projects.
appeal, NCUC continues to challenge five.
and
On
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).
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adder.
We
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briefly
describe
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each
challenged
project
before
turning to the proceedings below.
1.
The
Lexington
Reconductor
(“RTEP”)
are
Tie
PJM
projects.
Project
Regional
The
RTEP
and
Idylwood-Arlington
Transmission
is
the
Expansion
product
of
a
Plan
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,
lines.
and
a
the
construction
of
new
transmission
The Garrisonville Project will result in a five mile
underground
million.
involve
transmission
line
at
an
estimated
cost
of
$120
The Pleasant View Project involves the construction of
twelve-mile
transmission
line,
two
of
which
would
constructed underground, at an estimated cost of $90 million.
9
be
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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
transformer failure.
by
significantly
reducing
the
risk
of
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)
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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.
there
If one of these transformers failed, VEPCO argued,
would
be
a
decrease
of
between
transformation capacity at each substation.
the
PJM’s
PRA
actually
determined
33%
to
66%
in
NCUC responded that
that
VEPCO’s
current
transformer network was sufficiently reliable because VEPCO had
more
than
result,
the
PJM
transformer
required
did
not
network
number
of
spare
recommend
in
its
any
planning
transformers.
upgrades
process.
As
a
to
VEPCO’s
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
multiple service areas.
a
risk
of
outages
for
customers
in
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.
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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
identified
the
the
construction
substation
construction.
nexus
in
test
be
Eastern
risks,
taken
Interconnection.
including
out
of
service
also
requirement
the
VEPCO
that
temporarily
during
VEPCO argued that the Idylwood Project met the
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
Lexington
Tie
Idylwood
Baltimore
Gas.
Lexington
Tie
and
As
and
RTEP
arguments,
Projects
projects,
Idylwood
were
FERC
Projects
12
finding
that
non-routine
concluded,
would
both
enhance
the
under
both
the
regional
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reliability.
additional
Id.
¶
arguments
100.
that
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Further,
these
FERC
projects
credited
were
VEPCO’s
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
Virginia
at
a
lower
Commission
had
cost.
NCUC
approved
pointed
entirely
out
that
the
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
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build
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underground
did
not
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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
required
deviated
coordination
necessitated
capital.
should
approach
across
significant
from
the
industry
multiple
investment
in
standard,
substations,
skilled
labor
and
and
As it had under prong one, NCUC replied that the PTRP
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
incentives.
insufficient
Id.
¶
72.
to
disqualify
Overall,
FERC
it
from
held
that
meriting
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.
¶ 1.
Id.
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
14
FERC’s
order
as
well.
In
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particular,
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it
contended
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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
after
reasons
oral
that
argument,
remain
FERC
unsatisfactorily
failed
to
issue
explained
its
Order
even
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.
be
argued
that
if
a
similar
request
FERC stated “it can
for
incentives
were
submitted to the Commission at this time, the result might be
different
in
light
of
the
Commission’s
evolving
policy
respect to application of the Order No. 679 nexus test.”
11.
with
Id. ¶
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.
regulatory
that
uncertainty
would
And, FERC feared that the
result
from
shifting
an
earlier position four years after the fact could deter reliance
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on
§
Doc: 67
219
confirm
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incentives
the
additional
grant
more
of
arguments
broadly.
VEPCO’s
raised
grounds for rehearing.
Pg: 16 of 27
Id.
incentives,
FERC
on
rehearing
proceeded
finding
failed
that
to
to
the
provide
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
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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
jurisdiction to entertain this appeal.
whether
we
have
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.
the
Under 16 U.S.C. § 825l, “[n]o objection to the order of
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.
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any, prior to court intervention.
F.2d
764,
requirement
exhaustion
773-74
(D.C.
strictly
of
based
See ASARCO, Inc. v. FERC, 777
Cir.
1985).
on
administrative
the
We
interpret
“time-honored
remedies.”
Consol.
this
doctrine
Gas
of
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
reevaluate
VEPCO’s
rehearing
incentives
petition
under
the
that
2010
FERC
should
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.”
18
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FERC, 877 F.2d 1066, 1072 (D.C. Cir. 1989) (quoting Boston Gas
Co. v. FERC, 575 F.2d 975, 978 (1st Cir. 1978)).
Gas,
for
discounted
example,
rate
FERC
initially
agreement
under
rejected
the
the
Natural
Gas
In Columbia
petitioners’
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.
directly to the D.C. Circuit.
That court held that it had
jurisdiction
to
evaluate
the
The petitioners appealed
parties’
challenge
to
FERC’s
finding of discrimination because the rehearing order did not
change
the
outcome
and
FERC
had
“not
yet
revealed”
rationale when the parties requested rehearing.
Similarly
here,
the
conclusions
of
the
its
new
Id.
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
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test. 7
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Pg: 20 of 27
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
petition. 8
rehearing
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,
agency’s sound discretion.”
in
the
first
instance,
to
the
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
reliance interests.
that
discretion,
we
consider
the
parties’
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).
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135 (4th Cir. 1995).
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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.
points
to
the
Rehearing
Order
where
FERC
stated
that
NCUC
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.”
unconnected
projects
in
the
Id. ¶ 45.
aggregate,
Instead of assessing
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.
¶ 27.
test
Order No. 679-A
And, in the 2008 Incentives Order, FERC applied the nexus
in
the
aggregate
to
the
21
eleven
projects
in
VEPCO’s
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Incentives Order ¶ 49. 9
application.
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
certainly
whether
entitled
to
grant
to
rehearing
consider
here.
the
Agencies
broader
are
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
merited
incentive
evidence.
reweigh
Proactive
Transformer
treatment
Replacement
is
not
Project
supported
by
(“PTRP”)
substantial
We consider each argument mindful that we may not
the
evidence.
We
determine
9
only
whether
FERC
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.
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“examine[d] the relevant data and articulate[d] a satisfactory
explanation
for
its
action
including
a
‘rational
between the facts found and the choice made.’”
connection
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
decisions.
would
“materially
Order No. 679-A ¶ 25.
affect”
its
investment
We disagree.
In Order No. 679-B, FERC stated that there was no size cutoff
for
projects
when
under the nexus test.
determining
Id. ¶ 18.
eligibility
for
incentives
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.
A ¶ 20.
run
Order No. 679-
FERC found that such a high “evidentiary hurdle” would
counter
to
Congress’s
directive
to
drive
money
improving the country’s aging transmission infrastructure.
into
Id.
There is therefore nothing to prevent a utility from qualifying
23
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for
Doc: 67
incentives
given
that
Filed: 01/24/2014
based
they
construction.
on
could
Pg: 24 of 27
projects
help
that
attract
are
already
financing
or
underway,
accelerate
Order No. 679 ¶ 35.
Finally, we have no trouble holding that FERC’s finding
that
both
substantial
projects
satisfy
evidence.
the
Both
nexus
the
test
Lexington
is
supported
Tie
Projects meet many of the Baltimore Gas factors.
and
by
Idylwood
They resulted
from a regional planning process, faced ongoing and significant
local opposition, and involved construction challenges based on
changeable
elevation
and
the
Incentives Order, ¶¶ 100, 106.
use
of
new
technology.
See
Therefore, we affirm.
2.
NCUC next argues that the Garrisonville and Pleasant View
Projects
fail
to
meet
the
nexus
test
because
they
“economically efficient” as required by § 219(a).
824s(b)(1).
expensive
underground
The
basis
of
this
alternative--namely,
construction--exists
contention
above
for
is
ground
both
are
16 U.S.C. §
that
a
rather
utility
not
lines.
less
than
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 costbenefit analysis, concluding that consumers would be adequately
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protected by the requirement that incentive-based rates remain
just and reasonable.
its
three-prong
Order No. 679 ¶ 59.
test
for
incentives
Instead, FERC created
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
219].”
See Chevron U.S.A., Inc. v. Natural Res. Def. Council
Inc., 467 U.S. 837, 843 (1984).
construction
of
[§
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.
the
Therefore, rather than evaluating Order No. 679 under
familiar
FERC’s
Chevron
grant
we
simply
incentives
of
test,
to
VEPCO
supported by substantial evidence.
will
for
determine
these
whether
projects
was
FERC concluded that these
projects satisfied the nexus test based on construction risks,
ongoing
local
reliability.
opposition,
and
their
Incentives Order, ¶¶ 77, 85.
impact
on
regional
We affirm.
3.
NCUC’s
granted
for
VEPCO’s Proactive Transformer Replacement Project (“PTRP”).
It
argues
that
final
challenge
FERC’s
decision
is
is
to
not
the
incentive
supported
by
substantial
evidence because FERC misunderstood the scope of the project and
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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.
of
course,
has
an
outsized
impact
That one missing word,
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
transformers.
remand
for
that
listed
each
Id. ¶ 37, n.17.
FERC
to
correct
of
the
thirty-two
targeted
Therefore, we will not require
its
error
and
reevaluate
PTRP’s
eligibility for incentive treatment under § 219. 10
NCUC’s
meaning
of
additional
challenge--that
the
PRA--asks
PJM’s
us
to
FERC
misunderstood
reweigh
the
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
however
these
findings.
This
analysis
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
change
in
discretion
its
in
declining
Rehearing
application for incentives.
Order
to
and
apply
in
the
2010
evaluating
policy
VEPCO’s
FERC’s grant of incentives to VEPCO
under § 219 is therefore
AFFIRMED.
27
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