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, 
2

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.
3

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 
4

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.
5

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, 
6

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).
7

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.
8

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).
9

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.
10

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)
11

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.
12

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 
13

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 
14

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 
15

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 
16

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 
17

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.
18

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. 
19

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 
20

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).
21

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 
22

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.
23

“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 cutoff 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 
24

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 costbenefit analysis, concluding that consumers would be adequately 
25

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 
26

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.
27

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.