Opinion
No. 12–1881.
2014-01-24
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.
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.
Before , WYNN, and THACKER, Circuit Judges.
Affirmed by published opinion. Judge wrote the opinion, in which Judge WYNN and Judge THACKER joined.
, 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. See16 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 projects to spur infrastructure investment. 16 U.S.C. § 824s (c).
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.
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 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, 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.
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).
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 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.” 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.
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.
II.
A.
On July 1, 2008, VEPCO, a member of PJM Interconnection LLC (“PJM”), 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.
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).
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 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.
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. 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.
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)
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 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.
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 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 localopposition. 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 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 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 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. § 825 l(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. § 825 l(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, 103 S.Ct. 2246, 76 L.Ed.2d 437 (1983)).
IV.
NCUC makes two primary arguments on appeal. First, it argues that FERC erred by declining to grant rehearing to apply 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.
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, 67 S.Ct. 1575, 91 L.Ed. 1995 (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.
A.
Preliminary, however, we must determine whether we have jurisdiction to entertain this appeal. FERC argues that under 16 U.S.C. § 825 l(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. § 825 l, “[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 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, 75 S.Ct. 467, 99 L.Ed. 583 (1955)).
It is hardly surprising that NCUC did not argue in its September 28, 2008 rehearingpetition 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 § 825 l (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 § 825 l(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. 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 test. 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. 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.
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.
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, § 825 l(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 § 825 l(b).
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, 94 S.Ct. 2074, 40 L.Ed.2d 612 (1974)).
In reviewing that discretion, we consider the parties' reliance interests. See ARA Serv., Inc. v. NLRB, 71 F.3d 129, 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 application. Incentives Order ¶ 49. 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 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.
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 “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, 103 S.Ct. 2856, 77 L.Ed.2d 443 (1983) (quoting Burlington Truck Lines v. United States, 371 U.S. 156, 168, 83 S.Ct. 239, 9 L.Ed.2d 207 (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 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 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, 104 S.Ct. 2778, 81 L.Ed.2d 694 (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 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.
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.
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 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.