STATE OF NORTH CAROLINA ex rel. NORTH CAROLINA UTILITIES COMMISSION, and DUKE ENERGY PROGRESS, LLC, Applicant v. CAROLINA INDUSTRIAL GROUP FOR FAIR UTILITY RATES II and HAYWOOD ELECTRIC MEMBERSHIP CORPORATION, Intervenors, and ATTORNEY GENERAL JOSHUA H. STEIN, Intervenor; STATE OF NORTH CAROLINA ex rel. NORTH CAROLINA UTILITIES COMMISSION, and DUKE ENERGY CAROLINA, LLC, Applicant v. CAROLINA INDUSTRIAL GROUP FOR FAIR UTILITY RATES III, BLUE RIDGE ELECTRIC MEMBERSHIP CORPORATION, HAYWOOD ELECTRIC MEMBERSHIP CORPORATION, PIEDMONT ELECTRIC MEMBERSHIP CORPORATION, RUTHERFORD ELECTRIC MEMBERSHIP CORPORATION, and ATTORNEY GENERAL JOSHUA H. STEIN, Intervenors.
Nos. 75A24-1 and 139A24-1
IN THE SUPREME COURT OF NORTH CAROLINA
Filed 22 May 2026
Heard in the Supreme Court on 13 February 2025
ALLEN, Justice.
Troutman Pepper Hamilton Sanders LLP, by Kiran H. Mehta, Jack E. Jirak, Christopher G. Browning, Jr., and Molly McIntosh Jagannathan for Duke Energy Carolinas, LLC and Duke Energy Progress, LLC, applicant-appellees.
Public Staff—NCUC, by Lucy E. Edmondson, Chief Counsel, and Jennifer T. Harrod, Nadia J. Luhr, William S.F. Freeman, William E.H. Creech, Thomas J. Felling, and Anne M. Keyworth, intervenor-appellee.
Brooks, Pierce, McLendon, Humphrey & Leonard, L.L.P., by Marcus W. Trathen, Matthew B. Tynan, Amanda S. Hawkins, and Christopher B. Dodd, for Carolina Utility Customers Association, Inc., cross-intervenor-appellant.
Jeff Jackson, Attorney General, by Derrick C. Mertz and Tirrill Moore, Special Deputy Attorneys General.
ALLEN, Justice.
In this appeal we consider the lawfulness of final orders issued by the North Carolina Utilities Commission granting rate increases for Duke Energy Progress, LLC (DEP) and Duke Energy Carolinas, LLC (DEC), both of which are wholly owned subsidiaries of Duke Energy Corporation.1 The orders approve performance-based regulation (PBR) pursuant to
The Attorney General and other intervenors appealed the Commission‘s final orders to this Court. The intervenors point to several alleged errors by the Commission, many of which concern its interpretations of provisions in
I. Background
The Public Utilities Act—Chapter 62 of the General Statutes—authorizes and requires the Commission to regulate investor-owned companies that sell electricity or other designated utility services to the public. See
Section 62-133 of the General Statutes spells out the procedures that have
In October 2021, the General Assembly enacted
On 6 October 2022, DEP filed a general rate case application with the Commission that included a request for PBR regulation. DEC did the same on 19 January 2023. The Commission responded by initiating a general ratemaking case for each application. From March to May 2023, the Commission held an evidentiary
The Attorney General and the Public Staff3 intervened by right in both ratemaking cases. See
On 18 August 2023, the Commission issued its final order in the DEP case (the DEP Order). In the DEP Order, the Commission approved DEP‘s proposed MYRP, albeit with modifications. Ten days later, on 28 August 2023, the Commission concluded DEC‘s evidentiary hearing. On 15 December 2023, the Commission issued its final order in the DEC case (the DEC Order), wherein it approved a modified version of DEC‘s proposed MYRP.
Pursuant to
II. Standard of Review
“Subsection 62-79(a) of the North Carolina General Statutes sets forth the standard for Commission orders against which they will be analyzed on appeal.” State ex rel. Utils. Comm‘n v. Cooper, 367 N.C. 644, 647 (2014) (cleaned up). It provides:
(a) All final orders and decisions of the Commission shall be sufficient in detail to enable the court on appeal to determine the controverted questions presented in the proceedings and shall include:
- (1) Findings and conclusions and the reasons or bases therefor upon all the material issues of fact, law, or discretion presented in the record, and
- (2) The appropriate rule, order, sanction, relief or statement of denial thereof.
In an appeal from a final order of the Commission, subsection 62-94(b) authorizes this Court to
affirm or reverse the decision of the Commission, declare
the decision null and void, or remand the case for further proceedings; or [we] may reverse or modify the decision if the substantial rights of the appellants have been prejudiced because the Commission‘s findings, inferences, conclusions, or decisions are any of the following:
- (1) In violation of constitutional provisions.
- (2) In excess of statutory authority or jurisdiction of the Commission.
- (3) Made upon unlawful proceedings.
- (4) Affected by other errors of law.
- (5) Unsupported by competent, material, and substantial evidence in view of the entire record as submitted.
- (6) Arbitrary or capricious.
In reviewing a decision by the Commission, this Court must “review the whole record or the portions of it that are cited by any party” and take “due account . . . of the rule of prejudicial error.”
On appeal “the rates fixed or any rule, finding, determination, or order made
III. Analysis
A. Interclass Subsidization
The Commission approved a 10% reduction in interclass subsidies for DEP and DEC (the Utilities). CIGFUR appeals the Commission‘s decision in both cases, while CUCA appeals the Commission‘s decision in the DEC case only.
Although the PBR Statute authorizes the Commission to implement PBR ratemaking, it circumscribes that authority in important ways. Specifically, subsection (b) of the PBR Statute requires the Commission to (1) adhere to the cost causation principle and (2) minimize interclass subsidies.
The Utilities sort their customers into classes based on which rate schedules the customers use. For instance, those customers purchasing power on one of the
The Utilities’ residential customers have long benefited from significant interclass subsidies largely paid by commercial and industrial customers. To combat interclass subsidization, each of the Utilities utilizes a “cost of service study” (COSS) to align costs with its customer classes. The COSS results provide only a starting point, and the Utilities consider other factors before finalizing their rate requests, such as the need to prevent the “rate shock” that a sharp increase in electricity bills could cause some customers.
Here, the Utilities ultimately proposed a 10% reduction in interclass subsidies, which was less than the COSS recommendations. Citing the “concept of gradualism,” the Commission approved a 10% reduction in both cases. Gradualism recognizes that, when customers have set expectations in light of an interclass subsidy, eliminating the subsidy entirely in a single rate case could harm those customers whose rates increase drastically. The better approach, according to gradualism, is to eliminate the subsidy in stages by adjusting rates incrementally over several ratemaking cases.
Section (b) of the PBR Statute reads:
In addition to the method for fixing base rates established under [N.C.G.S. §] 62-133, the Commission is authorized to approve performance-based regulation upon application of an electric public utility pursuant to the process and requirements of this section, so long as the Commission allocates the electric public utility‘s total revenue requirement among customer classes based upon the cost causation principle, including the use of minimum system methodology by an electric public utility for the purpose of allocating distribution costs between customer classes, and interclass subsidization of ratepayers is minimized to the greatest extent practicable by the conclusion of the MYRP period.
Additionally, subsection (d) of the PBR Statute prohibits the Commission from approving a PBR application unless it finds that the utility‘s proposal “would result in just and reasonable rates, is in the public interest, and is consistent with the criteria established in this section and rules adopted thereunder.”
- a. Assures that no customer or class of customers is unreasonably harmed and that the rates are fair both to the electric public utility and to the customer.
- b. Reasonably assures the continuation of safe and reliable electric service.
- c. Will not unreasonably prejudice any class of electric customers and result in sudden substantial rate increases or “rate shock” to customers.
According to CIGFUR, subsection (b) of the PBR Statute outlines a two-step process for the Commission‘s approval of a PBR application. The Commission may approve a PBR application only “so long as” it complies with cost causation and reduces subsidies to the greatest extent practicable. Thus, under CIGFUR‘s interpretation of subsection (b), the Commission‘s first step is to determine whether the plan satisfies these dual requirements. If it does, the Commission proceeds to step two, where it approves the application “pursuant to the process and requirements of [N.C.G.S. § 62-133.16].” It is not until step two, CIGFUR argues, that the Commission must consider the factors listed in subsection (d), such as the risk of rate shock to customers.
“When construing a statute, a court‘s principal goal is to accomplish the legislative intent. The court must begin with an examination of the relevant statutory language.” N.C. Dep‘t of Revenue v. Philip Morris USA, Inc., 388 N.C. 181, 187 (2025). “If the statute‘s plain language is clear and unambiguous,” the court “applies the statute as written and does not engage in further statutory construction.” N.C. Farm
We agree with CIGFUR that the words “so long as” in subsection (b) of the PBR Statute introduce two conditions that must be satisfied before the Commission may approve a PBR application, namely, allocation of the utility‘s revenue requirement based on the cost causation principle and minimization of interclass subsidies “to the greatest extent practicable.” We disagree, though, with CIGFUR‘s contention that the text of the PBR Statute supports its two-step approach.
CIGFUR would have a stronger argument if the General Assembly had used the word “possible” instead of “practicable” in subsection (b). It may well have been “possible” for the Commission to have eliminated interclass subsidization entirely among the Utilities’ customers by authorizing a subsidy reduction of 100%.
But “possible” and “practicable” are not exactly synonymous. “Practicable” is a narrower term. It refers to a subset of “possible” outcomes. Specifically, it refers to those possible outcomes that are ”reasonably capable of being accomplished” or ”feasible in a particular situation.” Practicable, Black‘s Law Dictionary (12th ed. 2024) (emphases added). As we recently explained when interpreting the legislature‘s use of the term “practicable” in the judicial dissolution statute for limited liability companies,
By using the term “practicable” in subsection (b), the General Assembly required the Commission to make judgments about the appropriateness of proposed interclass subsidy reductions. Read carefully, other language in subsection (b) also indicates that the legislature expected such reductions to occur incrementally. Subsection (b) requires interclass subsidization to be ”minimized to the greatest extent practicable by the conclusion of the MYRP period.”
Yet subsection (b) does not identify the factors that should—or must—inform the Commission‘s practicability analysis. Subsection (d) fills this obvious gap, at least partially. Certainly, if a proposed interclass subsidy reduction would “unreasonably prejudice any class of electric customers and result in sudden substantial rate increases or ‘rate shock’ to customers,”
Subsection (b) requires the Commission to determine at what point further increases in the subsidy reduction would present an unreasonable risk of rate shock. That is what the Commission did in the DEP and DEC Orders. Hence, it is CIGFUR—not the Commission—that has misconstrued subsection (b).
CIGFUR further argues that the Commission failed to adhere to the cost causation principle. Based on its understanding of that principle, CIGFUR maintains that large general service customers should experience a rate decrease over the course of the MYRP. Because that will not happen, CIGFUR reasons that the Commission‘s order must violate the cost causation principle.
This argument is a non sequitur. The Utilities filed their PBR applications seeking to increase the rates paid by their customers. Application of the cost causation principle might mean that large general service customers will bear a smaller portion of the rate increase than they otherwise would, but it by no means guarantees that their rates will go down.
CIGFUR and CUCA also maintain that the evidence before the Commission was insufficient to show that no subsidy reduction greater than 10% was “practicable.” CIGFUR notes that expert witnesses for DEP and DEC testified that the 10% reduction “help[s] reduce interclass subsidies to better align each rate class to the average rate of return” while at the same time “balanc[ing] the rate increases . . . so that no rate class receives a disproportionate increase.” Neither witness
CUCA observes that DEC proposed subsidy reductions of 25% in previous ratemaking cases but that in the present DEC case the Utility‘s expert witness testified that 25% was too high because it would trigger a 10% rate increase for DEC‘s lighting customers. CUCA argues that, even if the witness‘s testimony supports the Commission‘s decision not to impose a uniform 25% subsidy reduction, the Commission failed to analyze whether a uniform reduction between 10% and 25% was practicable. Moreover, according to CUCA, the Commission failed to evaluate whether a nonuniform reduction might protect DEC‘s lighting customers. CUCA believes that the Commission should have made such inquiries before deciding that a 10% subsidy reduction would satisfy subsection (b) of the PBR Statute.
As discussed above, the Commission‘s task under subsection (b) is to balance increased subsidy reductions against other important factors. Performing this task requires the Commission to apply its technical knowledge and expertise in utility ratemaking. For this reason, a reviewing court will not disturb the Commission‘s finding that a particular subsidy reduction is the highest practicable based on the factors set out in the PBR Statute if the finding rests upon “competent, material and substantial evidence.” VEPCO, 381 N.C. at 515 (quoting State ex rel. Utils. Comm‘n v. Cooper, 367 N.C. 444, 448 (2014)).
On much the same grounds, the Commission concluded in the DEC Order that a 10% uniform subsidy reduction was “consistent with the PBR Statute” because it “help[ed] move toward eventual rate parity and minimize interclass subsidization . . . while considering and incorporating other important factors,” including the risk of “disproportionate [rate] increases” and rate shock. The Commission further determined that “it [was] reasonable and equitable to apply the same basic rate
In both final orders, the Commission expressly rejected CIGFUR‘s proposed 25% subsidy reduction. The Commission acknowledged CIGFUR‘s concerns regarding the persistence of interclass subsidies that burden general service customers but noted that reducing interclass subsidies is “not the only issue that a utility must consider when designing rates.” In the end, the Commission concluded that “other important factors,” such as the need to protect against unreasonable rate increases, supported a lower subsidy reduction.
We hold that in each case the Commission‘s approval of a 10% subsidy
CIGFUR also insists that, for the Commission to approve the 10% reduction, it needed evidence establishing that uniform reductions higher than 10% but lower than 25% were not practicable. CUCA similarly argues that the Commission should have considered in the DEC case whether any nonuniform subsidy reductions that applied a lower reduction rate to DEC‘s lighting customers than to other customer classes were practicable. According to appellants, the Commission‘s failure to consider any alternative subsidy reductions other than CIGFUR‘s proposed 25% uniform rate means that the Commission‘s decisions were not supported by
We disagree. The Commission made its decision in each case after hearing expert testimony that a 10% uniform reduction would reduce interclass subsidies to the greatest extent practicable. The Commission was entitled to rely on this evidence if it deemed it credible. See State ex rel. Utils. Comm‘n v. Gen. Tel. Co. of the Se., 281 N.C. 318, 360–61 (1972) (“It is . . . the prerogative of the [Utilities] Commission to determine the credibility of evidence . . . .“). Having determined that the experts’ testimony was credible and entitled to “significant weight,” the Commission was not obligated to second-guess the testimony and cast about for other evidence on the off chance that it might support a subsidy reduction that no party had requested.
Finally, CIGFUR argues that the Commission erred in failing to explain adequately why it approved a 25% subsidy reduction rate in prior ratemaking cases filed by DEP and DEC but not in the present cases. CIGFUR claims that it argued to the Commission in both of the present cases that subsection (b) of the PBR Statute required the Utilities to continue seeking a subsidy reduction rate of at least 25%. According to CIGFUR, the Commission acted arbitrarily and capriciously by not adequately summarizing CIGFUR‘s argument in the DEP and DEC Orders.
The Public Utilities Act requires the Commission‘s final orders to be “sufficient in detail to enable the court on appeal to determine the controverted questions presented in the proceedings.”
CIGFUR cites Conservation Council for the proposition that
The Commission correctly evaluated whether the Utilities’ PBR applications minimized interclass subsidization to the greatest extent practicable by the
B. Electric Vehicle Charging
The Commission approved excluding revenue generated by residential electric vehicle (EV) charging from the Utilities’ decoupling mechanisms. The Attorney General appeals this decision in both cases.7
PBR applications must include a decoupling rate-making mechanism.
As part of PBR ratemaking, the utility estimates how much power its residential customers will consume and calculates a per-customer revenue target consistent with the utility‘s overall revenue requirement. If residential customers purchase more power than anticipated, the utility may be overfunded. If they purchase less power than expected, the utility risks being underfunded.
The decoupling mechanism employs an annual rider to neutralize the impact that fluctuating residential power purchases might otherwise have on a utility‘s revenue.
By eliminating the financial incentive that utilities would otherwise have to
The electric public utility may exclude rate schedules or riders for electric vehicle charging, including EV charging during off-peak periods on time-of-use rates, from the decoupling mechanism to preserve the electric public utility‘s incentive to encourage electric vehicle adoption.
In other words, the legislature wants electric public utilities to promote the use of EVs, so the PBR Statute allows them to exclude revenue that falls within the EV exclusion from the decoupling mechanism. Consequently, the decoupling mechanism does not require a utility to refund revenue covered by the EV exclusion, even if the utility exceeded its per-customer revenue target.
The Utilities proposed to exclude from their respective decoupling mechanisms revenue gained from incremental residential EV charging.9 Yet rather than develop rate schedules or riders specifically for EV charging, the Utilities proposed to estimate their revenue attributable to EV charging under existing residential schedules.
In both cases, the Attorney General opposed the proposed EV exclusion,
In his briefing to this Court, the Attorney General contends that the Commission exceeded its authority under the PBR Statute by permitting the Utilities to exclude estimated EV revenues from the decoupling mechanism. According to the Attorney General, the plain language of the PBR Statute restricts the EV exclusion‘s applicability to rate schedules or riders adopted for EV charging. Based on his reading of the PBR Statute‘s EV exclusion, the Attorney General insists that the Commission should not have allowed the Utilities to exclude EV charging revenue because DEP and DEC do not have any rate schedules, rates, riders, or rider programs for, or specific to, EV charging.
The Attorney General misreads the PBR Statute. As quoted above, the PBR Statute‘s EV exclusion permits an electric public utility to exclude from the decoupling mechanism rate schedules or riders for [EV] charging, including EV charging during off-peak periods on time-of-use rates.
On its face, this provision does not condition the exclusion of incremental EV charging revenues on a utility‘s adoption of new rate schedules or riders particular to EVs. If anything, the plain language of the provision cuts the other way. As the Utilities point out in their joint brief to this Court, the PBR Statute expressly references time-of-use (TOU) rates as one of the possible types of rate schedules for
Additionally, the Attorney General attacks as unreasonable the Utilities’ formula for calculating the EV exclusion. Consistent with a stipulation reached by the Utilities, CIGFUR, and the Public Staff, this formula comprised three major steps. First, using data from the North Carolina Department of Motor Vehicles (DMV), each Utility would determine the number of incremental residential EVs in its service territory.11 Second, each Utility would multiply that number by the estimated monthly per-customer kilowatt hours attributable to EV charging.12 (The Utilities agreed to replace estimated per-customer EV usage with actual EV usage data in subsequent decoupling proceedings.) Third, each Utility would arrive at its total EV charging revenue by applying the appropriate rate to the number of kilowatt
The Attorney General takes issue with all three steps of the EV exclusion formula. To begin with, he describes the DMV data relied on by the Utilities as speculative and imprecise. Although the data indicated the number of EVs registered in each North Carolina county, the Utilities had no way of knowing how many of those EVs were residential, as opposed to commercial or industrial. Nor did the data reveal which, if any, of the EVs were owned by individuals residing in parts of the county served by electric membership cooperatives or other electric utilities.
The Attorney General also criticizes the Utilities’ estimate of monthly per-EV charging consumption as speculative and imprecise. He notes that the Utilities based their estimate on the results of DEP‘s Make-Ready Credit Program, a relatively new pilot program involving roughly 1.3% of all EVs then registered in North Carolina. According to the Attorney General, no evidence in the record provides grounds for believing that the customers in the pilot program were representative of EV owners statewide.
Furthermore, the Attorney General denies the existence of any evidence in the record supporting which non-EV-specific rate schedule constituted the most accurate substitute for [the Utilities‘] failure to offer a residential EV charging-specific rate schedule. He asserts that the Utilities’ initial proposal averaged certain off-peak rate schedule rates, which did not measure only for EV charging. On the other hand, [t]he Public Staff advocated using the general residential flat service rate. The
The Attorney General emphasizes that the Utilities bear the burden of establishing the reasonableness of requested rate increases. Given his critique of their EV exclusion formula, the Attorney General insists that the reasonableness of [the Utilities‘] estimated costs was sufficiently challenged but the Commission did not meet its obligation to test the same. The Attorney General cites State ex rel. Utilities Commission v. Stein, 375 N.C. 870 (2020), as authority for the Commission‘s duty to test the formula‘s reasonableness.
While recognizing that North Carolina utilities have the burden of proving that the costs upon which their rates are based are reasonable and prudent, this Court explained in Stein that the reasonableness and prudence of those costs is presumed unless the Commission or an intervenor adduces sufficient evidence to cast doubt upon their reasonableness or prudence, at which point the burden to make an affirmative showing of the reasonableness of the costs in question shifts to the utility. Id. at 908 (cleaned up). To meet this evidentiary threshold,
an intervenor must offer affirmative evidence tending to show that the expenses that the utility seeks to recover are exorbitant, unnecessary, wasteful, extravagant, or incurred in abuse of discretion or in bad faith or that such expenses exceed either the cost of the same or similar goods or services on the open market or the cost similar utilities pay to their affiliated utilities for the same or similar goods or services.
Even if we assume that these principles from Stein govern the Attorney General‘s challenge to the Utilities’ EV exclusion formula, the Attorney General has clearly failed to adduce evidence sufficient to satisfy the evidentiary standard articulated in Stein. True, the EV exclusion formula produced an estimate and not an exact accounting of EV charging purchases, but this fact alone does not render the formula exorbitant, unnecessary, wasteful, extravagant, an abuse of discretion, or an act of bad faith. Id. Likewise, the Attorney General has not shown that EV charging calculations under the formula exceed[ed] either the cost of [EV charging] on the open market or the cost similar utilities pa[id] to their affiliated utilities for the same. Id. (cleaned up).
In any event, the Commission had ample evidence before it of the EV formula‘s reasonableness. As remarked above, the formula incorporated the terms of a stipulation agreed to by the Utilities, CIGFUR, and the Public Staff. Although the Attorney General was not a party thereto,
a stipulation entered into by less than all of the parties as to any facts or issues in a contested case proceeding under chapter 62 should be accorded full consideration and weighed by the Commission with all other evidence presented by any of the parties in the proceeding. The Commission must consider the nonunanimous stipulation along with all the evidence presented and any other facts the Commission finds relevant to the fair and just determination of the proceeding. The Commission may even adopt the recommendations or provisions of the nonunanimous stipulation as long as the Commission sets forth its reasoning and makes its own independent conclusion supported by substantial evidence on the record that the proposal is just and reasonable to all parties in light of all the evidence presented.
The DEP and DEC Orders demonstrate convincingly that the Commission did not simply take the EV stipulation at face value. It also weighed extensive witness testimony regarding the mechanics and soundness of the EV exclusion. In its order approving DEC‘s PBR application, for example, the Commission noted the following:
DEC witnesses [Laura] Bateman[, Vice President of Carolinas Rates and Regulatory Strategy,] and [Phillip] Stillman[, Managing Director of Load Forecasting and Corporate Strategic Regulatory Initiatives,] explained the agreement to exclude all residential EV sales from the decoupling mechanism resolves contested issues between the parties and provides a process for DEC to work with the Public Staff to develop tariffs and programs to estimate and update revenue associated with EV sales. Witnesses Bateman and Stillman explained that the tracking metric to report beneficial electrification from incremental load of EVs from estimated incremental load from EVs is consistent with
N.C.G.S. § 62-133.16(c)(2) ‘s provision to encourage EVs by excluding EV charging from thedecoupling mechanism. . . . They assert that the residential EV tracking metric will provide important data about an area with material policy interest. . . . Witnesses Bateman and Stillman concluded that the conditions associated with tracking and estimating DEC‘s proposal to exclude incremental residential EV sales from the decoupling mechanism are reasonable and will result in a transparent process for updating EV revenue estimates before the Commission. In [the] supplemental direct testimony [of Melissa B. Abernathy, Director of Rates and Regulatory Planning for DEC], she further explained that the [EV exclusion] Stipulation (also approved in the [DEP Order]) agreed and clarified that DEC and DEP will obtain data that will help them to better estimate revenue associated with incremental residential EVs. Witness Abernathy explained that the agreed upon method entails using data from the Department of Transportation to derive the number of residential EVs in DEC‘s service territory and then applying the flat residential tariff rate to the average monthly EV usage amount to derive the amount of residential EV sales to exclude from the decoupling mechanism. Finally, witness Abernathy stated that pursuant to the [EV exclusion] Stipulation, within 90 days of a Commission order in this proceeding, DEC will file tariffs or programs, and further using the data from those tariffs and programs, will refine the analytics to update the number of EVs and the usage assigned to each vehicle.
(Cleaned up.)
After considering the available evidence, the Commission concluded that DEC‘s proposal to exclude EV sales from the decoupling mechanism . . . , as modified by the [EV exclusion] Stipulation, is reasonable and should be approved. In reaching this conclusion, the Commission gave
substantial weight to the testimony of the DEC witnesses who explained that [the] residential EV sales section of the [EV exclusion] Stipulation is consistent with the spirit and
intent of N.C.G.S. § 62-133.16(c)(2) to encourage EV sales and who explained the process that will be utilized to arrive at an estimate of EV sales that addresses the objections of the Public Staff to DEC‘s initial proposal.
The Commission is responsible for determining the weight and credibility to be afforded to the testimony of any witness, including any expert opinion testimony. Stein, 375 N.C. at 900. Such determinations are entitled to great deference because the Commission‘s members possess an expertise in utility ratemaking that makes them uniquely qualified to decide the issues that are presented for their consideration. Id. Here, the Commission acted well within its discretion in deciding what weight to assign to the testimony of various witnesses in the DEP and DEC cases.
The Commission correctly interpreted the PBR Statute‘s exclusion for EV charging, and competent, material, and substantial evidence supported its approval of the Utilities’ EV exclusion formula. It therefore did not err in approving the exclusion of EV charging revenues from the Utilities’ decoupling mechanisms.
C. Future Capital Projects
In its PBR application, DEC identified certain capital spending projects that it planned to implement during the MYRP period.14 DEC later reduced its cost estimates for those projects in response to concerns raised by the Public Staff. The Commission eventually approved the inclusion of those revised cost estimates in the
The Commission fixes the rates charged by an electric public utility at levels that will enable the utility to meet its revenue requirement. An electric public utility‘s revenue requirement is that amount of money it is allowed to recoup to (1) cover the costs it incurs in providing power to its customers and (2) provide the utility with a reasonable profit.
This Court has previously described the steps used to calculate a utility‘s revenue requirement:
The clear wording of
N.C.G.S. § 62-133(b) requires the Commission to determine the utility‘s rate base (RB) (the reasonable cost of its property used and useful in service to the public, less accumulated depreciation plus reasonable cost of construction work in progress), its reasonable operating expenses (OE), and a fair rate of return on the company‘s capital investment (RR). These three components are then combined in a formula expressed as follows: (RB X RR) + OE = Revenue Requirements. Operating expenses generally include costs for fuel, wages and salaries, and maintenance, as well as annual depreciation charges and taxes. The rate of return is a percentage multiplier applied to the rate base to produce the amount of money the Commission concludes should be earned by the utility, over and above its reasonable operating expenses.
State ex rel. Utils. Comm‘n v. Pub. Staff N.C. Utils. Comm‘n, 333 N.C. 195, 201 (1993) (cleaned up).
The PBR Statute mandates the use of data from the twelve-month test period in PBR ratemaking.
In its appeal to this Court, CUCA objects to the Commission‘s approval of six capital spending projects in DEC‘s MYRP:
- the Hardening & Resilience: Public Interference Program for (a) identifying parts of DEC‘s distribution infrastructure vulnerable to outages from vehicles striking utility poles and (b) implementing custom solutions to decrease outage risk;
- the Infrastructure Integrity Program for identifying and replacing damaged, outdated, or obsolete equipment in DEC‘s distribution infrastructure (such as capacitors, regulators, and reclosers) that could cause outages;
- the Transmission Cathodic Protection Program for identifying and remedying corrosion on DEC‘s transmission towers;
- the Targeted Wood Pole Upgrade Program for identifying wood transmission poles nearing the end of their lifespans and replacing them with steel poles;
- the Distribution Hazard Tree Removal Program for identifying and cutting down dying or structurally unsound trees growing outside DEC‘s rights of way that threaten DEC‘s distribution lines; and
- the Transmission Hazard Tree Removal Program for identifying and cutting down dying or structurally unsound trees growing outside DEC‘s
rights of way that threaten DEC‘s transmission lines.
CUCA argues that the Commission should not have approved these six programs because they do not qualify as a known and measurable set of capital investments . . . associated with a set of discrete and identifiable capital spending projects to be placed in service during the first rate year.16
To illustrate its point, CUCA focuses on what it perceives as a fatal shortcoming in the Distribution Hazard Tree Removal Program. According to CUCA, [t]here were no particular trees expected to be removed nor any particular locations identified where tree removal was expected to be needed. CUCA directs our attention to the testimony of a DEC witness, who admitted that he could not point to any specific or identifiable trees that [DEC] is going to be removing as part of the
The Commission construes the phrase known and measurable differently, and not just in the context of electric public utilities. The phrase also appears in
The Commission‘s rule on PBR applications reflects this same interpretation of known and measurable.17 Under Commission Rule R1-17B(d), an electric public utility‘s PBR application must contain
- The reason for each capital spending project;
- The scope of each capital spending project;
- The timing of each capital spending project, including projected in-service month and year for each capital spending project;
- The depreciation life of each capital spending project by year;
- Changes expected in the depreciable life of each capital spending project for two years after the conclusion of the MYRP; and
- The impacts on (a) operating expenses (including operations and maintenance, depreciation, and taxes other than income expenses), and (b) the itemized rate base, related to the construction, and placement into service, of the capital spending projects for each Rate Year of the MYRP.
This Court does not defer to an administrative agency‘s statutory interpretations, but we will consider and respect [the agency‘s] reasoning. Savage v. N.C. Dep‘t of Transp., 388 N.C. 196, 202 (2025). Like the Commission, we do not interpret the phrase known and measurable in
A closer look at the testimony regarding the Distribution Hazard Tree Removal Program shows both the reasonableness of the Commission‘s approach and the unreasonableness of CUCA‘s. While admitting that DEC had not designated the particular trees that would be removed as part of the program, the same witness quoted by CUCA explained that the program, just like [e]very kind of project in MYRP, was a forward-looking project based on estimates and estimated scopes. He further observed:
The only thing different in the MYRP and the projects we‘ve submitted is the forward-looking ratemaking mechanism that‘s associated with those. We have significant experience doing this exact type of work with estimating what it takes to do the work, what the scopes will be that we will find, what it takes to engineer it, what it takes to execute it and the cost associated. And the only thing that‘s different about hazard tree here or any other project that‘s listed here is that we submit it as part of a forward-looking ratemaking plan. The work is no different than what we‘ve been doing for years.
This testimony aligns with DEC‘s explanation to this Court of how it arrived at the cost estimates for its proposed MYRP projects: The cost estimates were informed by substantial experience and historical data from completing substantially similar projects in the past. Such past experience provides further confidence in the
Simply put, DEC estimated the cost of its Distribution Hazard Tree Removal Program based on what its experience and data indicated that it would have to spend on removing hazardous trees during the MYRP period. Though unavoidably imperfect, this approach also strikes us as rational under the circumstances. On the other hand, it does not seem rational to demand—as CUCA apparently would—that DEC identify in advance every tree that it expects to cut down over the course of the MYRP.
CUCA offers another objection to DEC‘s proposed Distribution Hazard Tree Removal Program and Transmission Hazard Tree Removal Program. It argues that these two programs do not qualify as MYRP capital projects because [t]hey are not capital investments’ or capital spending’ programs and do not result in any capital being placed in service.’ CUCA points out that DEC must follow accounting rules promulgated by the Federal Energy Regulatory Commission (FERC). As construed by CUCA, those rules require accounting for tree trimming in connection with transmission and distribution lines as [a] maintenance expense—not capital—unless the tree trimming is associated with initial construction. CUCA notes that FERC‘s Division of Audits, Office of Enforcement, has explicitly rejected the suggestion that hazard tree removal for trees outside of utility rights-of-way . . . should be capitalized. Thus, [t]he Commission‘s decision to allow DEC to include hazard tree
The Attorney General likewise challenges the Commission’s decision to allow the inclusion of DEC’s hazardous tree removal programs in the MYRP. In his brief to this Court, the Attorney General highlights the requirement in
We do not discern legal error in the Commission’s assumption that an electric public utility’s spending on hazardous tree removal may qualify as a capital spending project for MYRP purposes. It seems obvious that, if properly planned and executed, a program to remove—not merely prune—dying or structurally unsound trees that threaten power lines can substantially prolong the life of those lines. By cutting down such trees, a utility can permanently eliminate serious risks to its ability to provide its customers with uninterrupted service. Here, DEC’s hazardous tree removal programs would protect power lines that currently carry electricity to DEC’s customers; those lines thus constitute property “used and useful” even under the Attorney General’s definition of the term.
Lastly, the record evidence establishes that the Commission rested its decision to approve DEC’s hazardous tree removal programs on competent, material, and substantial evidence. DEC witness Nicholas G. Speros, Director of Accounting for Duke Energy Business Services, LLC, testified that hazardous tree removal is a “narrow category of vegetation management that is capitalized” because it provides a long-term benefit to customers and is not annually recurring. He explained that, “[w]hen a danger tree is removed, a sustained, long term reliability enhancement is provided for that line[:] the benefit of that tree no longer being able to result in an outage is experienced for years to come.”
Similarly, Public Staff witness Tommy Williamson, an engineer with the Public Staff’s Energy Division, furnished extensive information about how DEC identifies hazardous trees and about the scope of its hazardous tree removal programs. For instance, Mr. Williamson testified that, “[d]uring the 2014 through 2022 timeframe, [DEC] removed approximately 301,978 hazard trees that were a
The Commission did not err in approving the capital spending projects challenged by CUCA and the Attorney General. We thus affirm the Commission’s order to the extent that it allowed DEC to include those projects in its MYRP.
D. Fuel Cost Allocation
The DEP Order prohibits DEP from continuing to use the equal percentage fuel cost allocation method in fuel rider proceedings governed by
The Commission sets the base fuel rates for an electric public utility in a general rate case. Thereafter, the utility is entitled
to charge an increment or decrement as a rider to its rates for changes in the cost of fuel and fuel‑related costs used in providing its North Carolina customers with electricity from the cost of fuel and fuel‑related costs established in the . . . utility’s previous general rate case on the basis of cost per kilowatt hour.
Section 62-133.2 defines “cost of fuel and fuel-related costs” to include discrete types of credits and debits, such as “[t]he cost of fuel burned,” “[t]he cost of [chemicals] consumed in reducing or treating emissions,” energy sales by the utility to other companies, and certain costs associated with energy purchases from other companies.
Before authorizing a fuel rider, the Commission conducts a hearing at which it receives evidence from the utility, the Public Staff, intervenors, and the public.
Although it describes how the Commission should go about determining the cost adjustment for a fuel rider,
Starting in 2008, the Commission began utilizing the “equal percentage methodology” to allocate DEP’s annual fuel-cost adjustments, and in 2012 the Commission began using this same methodology for DEC’s fuel riders.19 The equal percentage methodology adjusts each customer class’s share of the total fuel and fuel related costs by the same percentage. Using data from the test period, the utility
In these cases, DEP and DEC proposed to continue using the equal percentage methodology in their fuel cost allocations. The Public Staff opposed this, arguing that the equal percentage methodology causes rate “distortion” that unfairly benefits large industrial customers. Due to factors other than the cost of fuel, industrial customers pay lower average rates per kilowatt hour than customers in other classes. Thus, the percentage of the Utilities’ total revenue contributed by industrial customers is lower than the percentage of the Utilities’ fuel costs attributable to those same customers. As a result, when fuel prices increase, other customer classes shoulder a disproportionate share of the costs.
Given this misalignment between consumption and cost allocation, the Public Staff asked the Commission to eliminate the equal percentage methodology from the Utilities’ rate schemes. Public Staff witness Jay Lucas, Manager of the Electric Section, Operations and Planning in the Energy Division of the Public Staff, acknowledged that the Public Staff had supported the adoption of equal percentage
Additionally, Mr. Lucas asserted that the equal percentage methodology failed to comply with the PBR Statute’s “cost causation principle.” As noted in section III.A of this opinion,
CIGFUR’s expert witnesses supported the Utilities’ continued use of the equal percentage methodology, arguing that it had served ratepayers well and that it “levelize[d]” over time any harsh effects on customers. The CIGFUR experts also maintained that the costs recoverable in the fuel rider include certain “capital costs” that are wholly distinct from the cost of fuel. In their view, the recoverability of these non-fuel costs provides additional justification for the equal percentage methodology. Furthermore, in the DEC case, the CIGFUR expert claimed that
The Commission agreed to cease using the equal percentage methodology for
Based on all the evidence in this proceeding, the Commission concludes that use of the equal percentage method of allocating fuel and fuel related costs does not follow the cost causation principle. In reaching this conclusion, the Commission gave substantial weight to the testimony of the Public Staff regarding the cost causation principle set forth in
N.C.G.S. § 62-133.16 , as well as their demonstration of the distortion that can be created by equal percentage fuel adjustments.
Accordingly, the Commission declared that the equal percentage methodology would no longer be employed in DEP’s fuel rider proceedings.
The Commission offered a more thorough explanation of its reasoning in the DEC Order, stating that it gave “substantial weight to the testimony of [the Public Staff’s witness] . . . that the distortion created by the equal percentage fuel adjustment allocation methodology shifts fuel costs away from industrial customers and onto other customer classes.” Although the Commission appeared to accept CIGFUR’s contention that the PBR Statute’s cost causation principle does not apply to the fuel rider, it nonetheless concluded that
[T]he purpose and intent of
N.C.G.S. § 62-133.16(g) is to make clear that [section 62-133.16 ] does not “limit or abrogate the existing rate-making authority of the Commission.” It is not, as CIGFUR would have the Commission interpret, to limit the Commission’s authority related to our analyses of appropriate cost allocation methodologies. The Commission has existing authority underN.C.G.S. § 62-133.2(f) , the statute that governs thefuel rider proceeding, to determine the appropriate cost allocation methodology of fuel rates in a rate case. Therefore, the Commission is acting within its authority by applying cost-causation principles to fuel costs and determining the appropriate cost allocation methodology within this general rate case.20
(Cleaned up). In light of its decision to apply the cost causation principle, the Commission directed DEC “to discontinue use of the equal percentage fuel adjustment methodology [in] its next fuel rider proceeding.”
The Commission also devoted space in both final orders to another issue involving the fuel rider. While the Public Staff opposed the Utilities’ use of the equal percentage methodology, it supported the use of “voltage differentiated rates.” Voltage differentiation adjusts an allocation of fuel costs to reflect the reality that delivering electricity at high voltages is more efficient than delivering it at lower voltages. Put another way, less fuel is consumed in generating and delivering a single kilowatt hour of energy for an industrial customer taking its power at a high voltage than in doing the same for a low-voltage customer. By the time of the evidentiary hearings, DEP had already adopted voltage differentiation in its fuel rider proceedings, and the Public Staff proposed that DEP continue using the mechanism. DEC had not yet adopted voltage differentiation, but it agreed by stipulation with the Public Staff to use voltage differentiation in its 2024 fuel rider proceeding.
On appeal to this Court, CIGFUR argues that the Commission erroneously “rejected the equal-percentage approach and approved a voltage-differentiated method for recovering fuel and fuel-related costs.”21 According to CIGFUR, the Commission’s decision in both cases rested on its incorrect assumption that the PBR Statute’s cost causation principle extends to fuel rider proceedings. CIGFUR alleges that the Commission “gave ‘substantial weight’ to Public Staff witness Jay Lucas’s testimony, in which he argued that [
“When an order or judgment appealed from was entered under a misapprehension of the applicable law, an appellate court may remand for application of the correct legal standards.” N.C. Dep’t of Env’t & Nat. Res. v. Carroll, 358 N.C. 649, 664 (2004) (cleaned up). No such action is warranted here.
Contrary to CIGFUR’s assertions, the DEP and DEC Orders and the record evidence do not prove that the Commission based its decision to abandon the equal percentage methodology on the mistaken belief that the PBR Statute required it to
Moreover, in its subsequent order denying CIGFUR’s motion for reconsideration in the DEP case, the Commission expressly rejected CIGFUR’s claim that any mischaracterization of the law by Mr. Lucas had significantly influenced its decision:
For CIGFUR to imply that the Commission relied solely on Public Staff witness Lucas’ testimony in which he misstated the statutory language, or that the witness’s human error negates all the other evidence of record on which the Commission’s conclusion was based, is patently inconsistent with the [DEP] Order and strains credulity. The record as a whole includes ample evidence, including from witness Lucas himself in his direct prefiled testimony, upon which the Commission based its decision and cited in the [DEP] Order. Moreover, the [DEP] Order notes that the
Commission afforded substantial weight to the testimony of the Public Staff regarding the cost causation principle set forth in N.C.G.S. § 62-133.16 , as well as their demonstration of the distortion that can be created by equal percentage fuel adjustments. . . . The Commission never indicated that it gave that substantial weight to the witness’s inaccurate recitations of the statutory language.
CIGFUR’s argument fares no better with respect to the DEC Order. As in the DEP case, the Commission gave substantial weight to testimony by Mr. Lucas.22 However, it emphasized his statements concerning the unfairness of the equal percentage methodology, especially his testimony that the equal percentage methodology distorts fuel rates by “shift[ing] fuel costs away from industrial customers and onto other customer classes.” The Commission also deemed “credible” his opinion that the equal percentage methodology should be discontinued because of its rate-distorting effects. The Commission did not state that the PBR Statute required it to apply the cost causation principle to fuel riders. On the contrary, it plainly indicated that the decision to do so was one that it had the discretion to make pursuant to
CIGFUR further argues that the Commission’s abandonment of the equal percentage methodology was arbitrary and capricious because it went against the
The “unrebutted evidence” in question consists of testimony by CIGFUR’s expert witnesses. In the DEP case, CIGFUR’s expert stated in his pre-filed testimony that the equal percentage methodology should be maintained because the fuel rider has grown over time to include expenses less directly tied to the cost of fuel and more appropriately termed “capital costs“:
Many years ago, the fuel adjustment only involved cost recovery for fuel costs. Over time other costs have been included which are basically capital costs. For example, renewable costs, such as purchased power from solar or other renewable energy facilities, are not fuel expenses.
The expert testified that, “[t]o the extent these costs are included in the annual fuel adjustment,” DEP should continue to use the equal percentage methodology. He pointed out that DEP’s large general service customers continue to subsidize other customer classes, a fact he viewed as “strong evidence that the [equal percentage] methodology results in just, reasonable rates, is not causing an undue cost shift over time, and should be continued.” In other words, since on the whole DEP’s industrial customers subsidize residential customers, it is only fair that residential customers should continue subsidizing industrial customers in the fuel cost allocation.
Capacity costs associated with solar purchases and other costs such as chemical costs and transmission costs are now included in the fuel rider. These costs have no heat content and are not fuel costs. There is no showing that these costs vary by kilowatt-hour of electricity consumed.
CIGFUR’s expert argued that DEC should continue utilizing the equal percentage methodology so long as capacity costs make their way into the fuel rider, “since those costs will continue to grow as DEC retires its coal generating capacity and replaces it with solar and other generating resources with zero or reduced carbon emissions.”
Adverting to the existing interclass subsidy benefitting DEC’s residential customers, CIGFUR’s witness stated that eliminating the equal percentage
The record belies CIGFUR’s assertion that the testimony of its expert witnesses went unrebutted. The rebuttal evidence in each case came in the form of testimony by Mr. Lucas.
On cross examination in the DEP case, Mr. Lucas admitted that the fuel rider covered some “capital costs” that “are not incurred based on the cost of fuel to produce a kilowatt hour of energy,” but he asserted that such capital costs made up only a “small component” of the rider. Mr. Lucas also explained that the fuel costs DEC incurred in purchasing energy from renewable generation facilities were not fixed costs as CIGFUR maintained:
[O]ne thing about solar facilities, you can’t just say, “We’re going to pay you a capacity payment because it’s a 5 megawatt solar facility.” Its output is variable. It’s not dependent on capacity. And this is true for all renewable energy facilities. The[y] are all paid for kilowatt hours. They get paid more during peak demand for those kilowatt hours, and that sort of acts like a capacity payment.
(Cleaned up).
Put differently, DEP did not make fixed capacity payments to renewable generation facilities that it then recouped in the fuel rider. Rather, DEP purchased power from these facilities on a per-unit basis, with that per-unit cost increasing
[I]f a solar panel system is not putting out energy, [it is] not getting paid. It’s not a fixed cost. It’s not like if a solar panel system breaks for a whole year, [it can] come back in and say, “Well, I should get fixed cost anyway, because it cost me to run this solar panel system.” If [it doesn’t] make kilowatt hours, [it doesn’t] get paid.
At the DEC evidentiary hearing, Mr. Lucas testified that, while the fuel rider covered some “capital costs,” these were not fixed. When asked by CIGFUR’s attorney whether it was “[his] testimony that everything recovered through the fuel rider . . . var[ies] by kilowatt hours consumed,” Mr. Lucas responded, “Yes.”
“It is not this Court’s duty to evaluate the accuracy of complex statistical models, conflicting methodologies, and the opposing expert opinions drawn therefrom. This, instead, is the duty of the Commission which has the special knowledge, experience and training best suited to make such determinations.” State ex rel. Utils. Comm’n v. Carolina Util. Customers Ass’n, Inc., 323 N.C. 238, 251 (1988) (cleaned up). The Commission properly performed its duty in these cases when confronted by dueling experts from CIGFUR and the Public Staff. Having reviewed their testimony, the Commission gave substantial weight to that of Mr. Lucas and made his testimony a basis for its decision to abandon the equal percentage methodology. CIGFUR’s assertion that unrebutted evidence supported the continued use of that methodology—and thus that the Commission acted arbitrarily and
The Commission’s decision to cease using the equal percentage methodology in fuel rider proceedings conducted pursuant to
E. Transmission Cost Allocation Stipulation
The DEP and DEC Orders approve the Transmission Cost Allocation (TCA) Stipulation approved by DEP, DEC, and the Public Staff. CIGFUR challenges that approval in its appeal to this Court.
DEP and DEC pool their energy production under the terms of their Joint Dispatch Agreement (JDA) to satisfy the power demands of their respective customers. Approved by FERC in 2012, the JDA enables each Utility to meet
In 2021 the General Assembly enacted H.B. 951, authorizing PBR ratemaking and directing the Commission to develop a state-wide Carbon Plan.25 In 2022, following an evidentiary hearing, the Commission issued a joint Carbon Plan for DEP and DEC, which outlined a multiyear program for reducing carbon dioxide emissions from the Utilities’ power generating facilities. See Order Adopting Initial Carbon Plan and Providing Direction for Future Planning, Docket No. E-100, Sub 179, at 135 (Dec. 30, 2022). Therein, the Commission expressed concern that the JDA’s payment mechanism failed to compensate DEP fully for its energy transfers to DEC. Id. at 135.
Primarily covering the eastern half of North Carolina, DEP’s service region is a more attractive location for solar generation facilities than DEC’s service region, which lies to the west. For this reason, the Carbon Plan placed a disproportionate burden on DEP to increase the number of renewable energy generation facilities in its service region. Id. at 126. Likewise, the Carbon Plan required DEP to build
At the evidentiary hearing to consider the Carbon Plan, an expert witness for the Public Staff observed that historically DEP’s customers have paid higher rates than DEC’s customers. Id. He voiced concern that DEP’s new infrastructure projects would cause the rate disparity between DEP and DEC to grow even more, causing DEP’s customers to absorb a disproportionate share of the costs incurred to achieve statewide compliance with the Carbon Plan. Id. In response to this concern, the Commission directed the Utilities to “take reasonable steps to mitigate further exacerbation of the rate disparity between DEC and DEP attributable to the Carbon Plan.” Id. at 128. It further instructed the Utilities to address the growing rate disparity in their next general ratemaking cases. Id. at 135.
Acting on the Commission’s instruction, the Utilities agreed to shift a portion of DEP’s revenue requirement to DEC. The Utilities and the Public Staff memorialized this agreement on 27 April 2023 by executing the TCA Stipulation. Under the TCA Stipulation, DEP’s revenue requirement was reduced by roughly $20 million, and DEC’s revenue requirement was increased by the same amount.26
On 27 April 2023, the Utilities and the Public Staff filed the TCA Stipulation in both of the instant ratemaking cases. No party opposed the TCA Stipulation during the DEP or DEC evidentiary hearings, nor did any party raise objections to it in post-hearing briefing. The Commission approved the TCA Stipulation in both cases, concluding that it “establishe[d] a reasonable method to align costs with cost causation principles.”
CIGFUR did not appeal the Commission‘s approval of the TCA Stipulation in the DEP case. In its notice of appeal in the DEC case, CIGFUR alleged for the first time that the Commission lacked authority under both
CIGFUR failed to preserve its argument that the Commission exceeded its statutory authority by approving the TCA Stipulation. Hence, the merits of its appeal on this issue are not properly before this Court.
In an appeal from a final order of the Commission, this Court must “review the record and the issues raised in accordance with the rules of appellate procedure[.]”
Rule 10(a)(1) of the Rules of Appellate Procedure generally requires parties to preserve issues for appeal by “present[ing] to the trial court a timely request, objection, or motion, stating the specific grounds for the ruling the party desire[s] the court to make if the specific grounds were not apparent from the context.”27
In its reply brief, CIGFUR insists that it twice disputed the legality of the TCA Stipulation before the Commission in the DEC case. The first instance noted by CIGFUR occurred during a cross-examination of two Public Staff witnesses by CIGFUR‘s counsel. We quote the relevant portion of the cross-examination in full:
Q: [C]an you point me to any statutory authority supporting the adjustment agreed to in th[e] [TCA] [S]tipulation?
A: [Witness 1] These adjustments recommended by [Public Staff] witness Metz so effect would be—if you want the detail, because it was just statutory, they are not affect, our legal team may be the source—
A: [Witness 2] Neither of us are attorneys so—
A: [Witness 1] Yeah.
A: [Witness 2] —as far as what statute it relates to, I would have to look to my attorneys on that.
Q: Thank you. Can you point me to any precedent for such an adjustment that has been agreed to by this stipulation?
A: [Witness 2] Not from the stand today, no.
This brief exchange hardly satisfies Rule 10(a)(1). CIGFUR‘s counsel asked two questions about the legal basis for the TCA Stipulation and then dropped the subject.
CIGFUR also points to the post-hearing brief that it filed with the Commission in response to DEC‘s proposed final order. But CIGFUR did not dispute the lawfulness of the TCA Stipulation in that brief. CIGFUR appears to have in mind the brief‘s introduction, where it stated that its “silence on any issue in its [b]rief should not be interpreted as . . . waiving any position it took throughout the course of th[e] proceeding.” Since CIGFUR did not take a position on the TCA Stipulation during the DEC proceeding, this sentence did nothing to put the issue on the Commission‘s radar.28
By failing to satisfy the requirements of Rule 10(a)(1), CIGFUR waived its argument that the Commission lacked statutory authority to approve the TCA Stipulation. Thus, the issue “is not properly preserved for our review.” Willowmere Cmty. Ass‘n, Inc. v. City of Charlotte, 370 N.C. 553, 561 n.7 (2018).
CIGFUR did not raise its due process challenge to the Commission. Ordinarily, a party may not raise a constitutional issue for the first time on appeal. See State v. Wiley, 355 N.C. 592, 615 (2002) (“It is well settled that an error, even one of constitutional magnitude, that [the party] does not bring to the trial court‘s attention is waived and will not be considered on appeal.“). This Court has carved out an exception to this prohibition, however, for at least some constitutional challenges in direct appeals from the decisions of administrative agencies to this Court or the Court of Appeals. “When an appeal lies directly to the Appellate Division from an administrative tribunal, in the absence of any statutory provision to the contrary, . . . a constitutional challenge may be raised for the first time in the Appellate Division . . . .” In re Redmond, 369 N.C. 490, 497 (2017). This exception recognizes that in many cases it would be pointless to require parties to bring
In Redmond—unlike here—the constitutionality of a statute was at stake. Yet even if CIGFUR did not have to raise its due process challenge to the Commission, we must still conclude that CIGFUR failed to preserve the issue for our review. Section 62-90 reads in pertinent part:
Any party to a proceeding before the Commission may appeal from any final order or decision of the Commission within 30 days after the entry of the final order or decision, or within an additional time fixed by the Commission, not to exceed 30 additional days, and by order made within 30 days, if the party aggrieved by the decision or order files with the Commission a notice of appeal that sets forth specifically the ground or grounds on which the aggrieved party considers the decision or order to be unlawful, unjust, unreasonable, or unwarranted and that includes the errors alleged to have been committed by the Commission.
Section 62-94 spells out the consequences of failing to identify the specific grounds for an appeal from a final order or decision of the Commission: “The appellant shall not be permitted to rely upon any grounds for relief on appeal that were not set forth specifically in the appellant‘s notice of appeal . . . .”
The notices of appeal filed by CIGFUR in the DEP and DEC cases do not allege that the Commission‘s approval of the TCA Stipulation violated due process. Indeed, CIGFUR‘s notice of appeal in the DEP case omits any reference to the TCA
None of CIGFUR‘s challenges to the Commission‘s approval of the TCA Stipulation have been preserved for appellate review. Accordingly, those challenges do not provide a basis for vacating the DEP and DEC Orders.
F. Return on Equity
The DEP Order authorized a 9.8% return on equity (ROE) for DEP, while the DEC Order approved a 10.1% ROE for DEC. The Attorney General and CUCA appeal the Commission‘s ROE determination in the DEC case.
Section 62-133 directs the Commission to fix a rate of return in a general ratemaking case that
will enable the public utility by sound management to produce a fair return for its shareholders, considering changing economic conditions and other factors . . . as they then exist, to maintain its facilities and services in accordance with the reasonable requirements of its customers in the territory covered by its franchise, and to compete in the market for capital funds on terms that are reasonable and that are fair to its customers and to its existing investors.
In the DEP case, DEP‘s ROE expert Dr. Roger Morin, Professor of Finance for Regulated Industry at the Center for the Study of Regulated Industry at Georgia State University, recommended an ROE of 10.4%.30 This constituted a 0.8 percentage-point increase from DEP‘s previous ROE of 9.6%. According to Dr. Morin, 10.4% was the “minimum amount needed” to comply with DEP‘s constitutional rights.31 He maintained that “declining demand growth, rising operating costs, rising capital costs, [and industry-wide] lower allowed returns” had all led investors to view electric public utilities more negatively, making it difficult for DEP to raise capital. Dr. Morin‘s ROE recommendation included recovery of estimated flotation costs, which are one-time costs such as accounting and legal expenses associated with issuing new equities.
Several of the intervenors’ expert witnesses conducted their own ROE analyses
In his rebuttal testimony, Dr. Morin criticized the methodologies used by the intervenors to arrive at their ROE recommendations. He argued that, given the rise in interest rates and inflation since DEP‘s last ratemaking case, it was unreasonable for the other experts to propose ROEs lower than DEP‘s then current rate of 9.6%. Dr. Morin defended his inclusion of flotation costs in his recommended ROE and rejected the other experts’ opinion that approval of DEP‘s MYRP justified a downward adjustment to the ROE.
In a split decision, the Commission awarded DEP an ROE of 9.8%. In reaching this conclusion, the Commission majority observed that its task was to calculate a “zone of reasonableness” for the ROE. That range would be bounded on the low end
The majority acknowledged its obligation under State ex rel. Utilities Commission v. Cooper (Cooper I), 366 N.C. 484 (2013), “to inform its selection of [an ROE] within [the range of reasonableness]” by addressing “the impact of changing economic conditions on customers.” Consistent with its understanding of Cooper I, the majority declared that it must “exercise its subjective judgment so as to balance two competing [ROE]-related factors—the economic conditions facing DEP‘s customers and DEP‘s need to attract equity financing on reasonable terms in order to continue providing safe and reliable service.”
Regarding the first factor, the majority observed that Dr. Morin “provided detailed data concerning changing economic conditions in North Carolina, as well as nationally,” and that these data were already accounted for in Dr. Morin‘s recommended ROE. Nonetheless, the majority adopted an ROE closer to the low end of the zone of reasonableness. In selecting 9.8%, the majority remarked that, while
Turning to the second factor, the majority concluded that increasing DEP‘s ROE from 9.6% to 9.8% would sufficiently “allow DEP to compete in the market for equity capital, providing a fair return on investment to its investor-owners.” The majority noted DEP‘s need to respond to “macroeconomic, geopolitical, extreme weather, public health, and other exogenous events beyond [its] control.” The majority also observed that DEP faced new operating risks arising from its obligation under the Carbon Plan to transition to greater renewable power generation. In sum, and “taking into account changing economic conditions and their impact on customers,” the majority exercised its “independent judgment and discretion” to conclude that its approved ROE of 9.8% would “allow DEP to . . . provid[e] a fair return on investment” and “result in the lowest rates constitutionally permissible.”
Three of the seven commissioners dissented because they thought the majority‘s chosen ROE was too low.34 The three dissenters would have approved an ROE of 10%, the upper limit of the zone of reasonableness. They expressed concern that the 9.8% ROE approved by the majority would increase costs for consumers over
No party appealed the Commission‘s decision to approve a 9.8% ROE in the DEP Order. The Commission‘s membership changed, though, between the issuance of the DEP Order and the DEC Order. Two of the four commissioners in the DEP majority left the Commission, which made the DEP dissenters the majority in the DEC case.
Dr. Morin testified as an expert witness for DEC. His testimony at the DEC hearing largely resembled his testimony at the DEP hearing. As in the DEP case, he recommended an ROE of 10.4%, which included flotation costs. When asked on cross-examination whether he was aware of any “substantive difference[s]” between DEC and DEP that could justify assigning them different ROEs, Dr. Morin said he was not. He also admitted that bond rating agencies had initially reacted favorably to the 9.8% ROE approved by the Commission in the DEC case. Toward the end of his cross-examination, when asked what he thought about giving DEC an ROE of 10.2%: Dr. Morin responded, “It‘s in my range, but the upper portion of the range. So I wouldn‘t . . . violently object to that.”
As in the DEP case, the intervenors’ expert witnesses recommended lower ROEs than Dr. Morin, though they uniformly recommended higher ROEs than the ones they had proposed in the DEP case. Instead of 9.45%, the Public Staff‘s expert recommended 9.55%. CUCA‘s expert recommended 9.40%, not 9.25%. Despite having
In his rebuttal testimony, Dr. Morin remarked that the other proposed ROEs for DEC were lower than DEC‘s then-current ROE of 9.6% even though interest rates had risen since DEC‘s last general ratemaking case.35 He also observed that in recent months the average ROE authorized for a vertically integrated electric utility in the United States such as DEC was 9.73%, significantly higher than the intervenors’ recommendations.
In another split decision, but this time with the DEP dissenters in the majority, the Commission approved an ROE of 10.1% for DEC. Drawing once more on the parties’ independent analyses, the majority determined the zone of reasonableness to be 9.99% to 10.37%. The majority, “in its discretion,” then selected 10.1%, concluding that substantial evidence supported this ROE. As in the DEP case, the Commission
The Commission again incorporated the customer interest analysis required by Cooper I into its ROE determination, copying the customer interest analysis in the DEP Order nearly verbatim. The majority observed that Dr. Morin‘s testimony took customer interests into account and “provided detailed data concerning changing economic conditions in North Carolina, as well as nationally.” As it had in the DEP case, the majority judged that, while “some [customers] will struggle to pay the increased rates,” the majority‘s chosen ROE did not pose a serious risk of “undue hardship” to consumers, due partly to DEC‘s assistance programs for low-income residential customers.
The Commission‘s analysis of DEC‘s interests tracked the examination of DEP‘s interest in the DEP Order. The Commission concluded that “macroeconomic, geopolitical, extreme weather, public health, and other exogenous events beyond DEC‘s control” necessitated increasing DEC‘s ROE, as did DEC‘s new obligations under the Carbon Plan. Echoing the DEP Order, the Commission stated that the 10.1% ROE approved for DEC would “result in the lowest rates constitutionally permissible.”
On appeal the Attorney General and CUCA contend that DEP and DEC presented “substantially similar evidence” on their respective risk profiles, and thus it was arbitrary and capricious for the Commission to approve a higher ROE for DEC than it did for DEP. The Attorney General separately challenges the Commission‘s
1. DEC‘s Higher ROE
The Attorney General covers essentially the same ground as CUCA and then some, so we will focus on the Attorney General‘s ROE arguments. In claiming that the Commission arbitrarily and capriciously approved a higher ROE for DEC than for DEP, the Attorney General maintains that the evidence before the Commission in the DEC case was “substantially similar” to evidence presented in the DEP case, including evidence on risk profiles, credit ratings, planned capital projects, and proxy groups.36 The Attorney General also notes that Dr. Morin served as an expert witness for both DEP and DEC and that in each case he recommended an ROE of 10.4% (adjusted to include flotation costs). In fact, much of Dr. Morin‘s pre-filed testimony at the DEP evidentiary hearing was, by his own admission, “substantially identical” to his pre-filed testimony at the DEC hearing. Dr. Morin used identical economic models, for example, and argued that the same set of financial risks—“declining demand growth, rising operating costs, rising capital costs, . . . [and] lower allowed returns“—threatened both Utilities. When asked at the DEC hearing whether there was any “substantive difference” between DEP and DEC that would justify different ROEs, Dr. Morin said he was “not . . . aware of any difference that would warrant a
According to the Attorney General, the Commission “use[d] . . . the exact same methodologies and inputs to arrive at a fundamentally different result for a utility with an identical risk profile.” This, says the Attorney General, was arbitrary and capricious decision-making. While the Attorney General admits that the Commission need not “always reach precisely the same ROE for utilities that come before it at the same time,” he argues that, where the material evidence presented by the utilities is the same, “the Commission must treat identical facts alike unless there is evidence and good reason not to.”
The Utilities maintain that the Attorney General‘s argument is foreclosed by this Court‘s VEPCO decision. We do not think VEPCO controls because here the Commission did not fail to explain why it took different positions in rate cases involving comparable facts. When read together, the DEP and DEC Orders unambiguously explain why the Commission approved a different ROE for DEC. Consequently, the Attorney General would not prevail even if this Court had ruled in VEPCO that the Commission must spell out its reasoning when it takes different positions in ratemaking cases involving comparable evidence.
In their dissent to the DEP Order, the three dissenting commissioners set out in significant detail the reasons for their belief that the Commission should have approved a higher ROE—10.0%—for DEP. For instance, they expressed concern that some of the models that expert witnesses had used to measure the cost of equity were
When the dissenting commissioners in the DEP case became the majority in the DEC case shortly thereafter, they confronted ROE evidence that was—to adopt the Attorney General‘s characterization—“substantially similar” to the ROE evidence they had just analyzed extensively in their DEP dissent. Not bound by the outcome in the DEP case, they cast votes in the DEC case in line with the views they had expressed in that dissent less than four months earlier. We see nothing arbitrary or capricious in their conduct. Moreover, it would border on silly for this Court to reverse their decision merely because the DEC Order does not repeat the arguments laid out
Our dissenting colleagues argue that the Commission erred as a matter of law by not picking the lowest ROE within its zone of reasonableness for the DEC case. According to them, “[w]hen presented with a range of reasonable options, the Commission lacks ‘discretion’ to randomly select a number in that range. Instead, it must select the lowest possible rate consistent with due process.”
This argument fundamentally misapprehends the zone of reasonableness. The zone does not represent—as our dissenting colleagues seem to believe—a determination by the Commission that any number within the zone will do. Rather, in delimiting a zone of reasonableness, the Commission narrows the range within which it will search for the lowest, constitutionally permissible rate, much as soldiers use bracketing to close in on artillery targets.
The Commission‘s ROE analysis in the DEC proceeding confirms our understanding. After identifying the zone‘s parameters in that case, the Commission went on to conclude, “taking into account changing economic conditions and their impact on customers, that the approved [10.1% ROE rate] will result in the lowest rates constitutionally permissible in th[e] [DEC] proceeding.”
Undoubtedly, the Commission‘s ROE decision involved the exercise of discretion. Such rate-setting determinations always “require[ ] the exercise of subjective judgment.” State ex rel. Utils. Comm‘n v. Public Staff-North Carolina Utils. Comm‘n, 323 N.C. 481, 490 (1988). The necessity of subjective judgment becomes
The Attorney General further asserts that evidence presented at the DEC hearing affirmatively contradicted the Commission‘s award of a higher ROE for DEC. Dr. Morin testified that “the bond rating agencies ha[d] . . . reacted favorably” following the Commission‘s approval of a 9.8% ROE for DEP. Such “real-world reactions” to DEP‘s ROE, says the Attorney General, were “perhaps the best evidence that a 9.8% (or lower) ROE was more than fair to existing investors.” Dr. Morin also testified that he wouldn‘t “violently object” to a 10.2% ROE because it was within the
Although Dr. Morin did say in his DEC testimony that he would not “violently object” to an ROE of 10.2%, the fact remains that he recommended an ROE of 10.4%, a number higher than the 10.1% ROE approved by the Commission. The Attorney General‘s argument therefore lacks merit.39
Following the Attorney General‘s lead, our dissenting colleagues argue that Dr. Morin‘s testimony, “taken as a whole, fails to support an award higher than 9.8%.” Like the Attorney General, they seize upon Dr. Morin‘s admission that bond markets reacted favorably to the 9.8% ROE approved by the Commission in the DEP proceeding. But this short-term reaction does little—if anything—to undermine Dr. Morin‘s ROE recommendation in the DEC case, which rested to a significant degree on long-term financial considerations. Specifically, Dr. Morin tied his ROE recommendation to an uptick in the 30-year U.S. treasury bond yield (3% to 4%),
common stocks are very long-term instruments more akin to very long-term bonds rather than to short-term Treasury bills or intermediate-term Treasury notes. . . . The expected common stock return is based on very long-term cash flows, regardless of an individual‘s holding period. Moreover, utility asset investments generally have very long-term useful lives and should correspondingly be matched with very long-term maturity financing instruments.
Even if one disagrees with Dr. Morin‘s recommendation, his testimony unquestionably provided more than a scintilla of competent and material evidence supporting the Commission‘s ROE decision in the DEC proceeding. See State ex rel. Utils. Comm‘n v. Carolina Util. Customers Ass‘n, 348 N.C. 452, 460 (1998) (“Substantial evidence is defined as more than a scintilla or a permissible inference. It means such relevant evidence as a reasonable mind might accept as adequate to support a conclusion.” (cleaned up)).
While our dissenting colleagues accuse us of “burying [our] heads, ostrich-like in the sand, as to the actual evidence below,” the real difference between their position and ours is that we are unwilling to usurp the role of the Commission and reweigh the evidence. This Court may not “disturb an order of the Commission merely because [we] would have given [the evidence] a different weight.” State ex rel. Utils. Comm‘n v. Duke Power Co., 285 N.C. 377, 390 (1974) (cleaned up). If the Commission followed the law and based its decision on competent, material, and substantial evidence, we must uphold its determination, regardless of whether we would prefer a different outcome. To do otherwise would be to appropriate power that does not
2. Customer Interest Analysis
The Attorney General separately asks us to vacate the Commission‘s decision to approve a 10.1% ROE in the DEC case because the Commission “failed to properly consider the impact that its . . . determination would have on DEC ratepayers.” The Attorney General‘s argument depends heavily on Cooper I.
While conceding that the DEC Order references the need to protect DEC‘s customers from excessive rates, the Attorney General insists that it gives only “scant attention” to the interests of DEC‘s customers and focuses almost exclusively on DEC‘s need for an ROE high enough to attract investors. He also points out that the customer interest analysis in the DEC Order tracks the DEP Order‘s analysis “verbatim.” The Attorney General regards this “parroting” as another sign that the Commission “failed to acknowledge or consider the unique circumstances facing [DEC‘s] customers.”
In Cooper I, this Court construed
We find the Attorney General‘s arguments unpersuasive. For starters, his criticism that the DEC Order copies the DEP Order verbatim rings hollow. In arguing that the Commission impermissibly failed to explain its decision to approve a higher ROE for DEC than for DEP, the Attorney General insisted that the evidence in the two cases is “substantially similar.” Given this similarity, it is hardly surprising that the Commission would analyze customer interests in both cases in much the same terms.
More importantly, the DEC Order demonstrates conclusively that the Commission duly evaluated customer interests when setting DEC‘s ROE. Contrary to the Attorney General‘s allegation that the Commission gave them “scant attention,” the Commission devoted considerable attention to customer interests, carefully evaluating and weighing the relevant evidence. To prove the point, we quote the Commission‘s customer interest analysis at length:
Cooper I Factors and Ultimate Conclusion Regarding Cost of Equity Capital
Regarding the obligation in accord with the holding in Cooper I to inform its determination of a[n] [ROE rate] within that range, the Commission must address the impact of changing economic conditions on customers.
In this case, all parties had the opportunity to present the Commission with evidence concerning changing economic conditions as they affect customers. The testimony of DEC witness Morin and Public Staff witness [Christopher C.] Walters, an associate with Brubaker & Associates, Inc., addresses changing economic conditions at
some length. Witness Morin provided detailed data concerning changing economic conditions in North Carolina, as well as nationally, and concluded that the North Carolina-specific conditions are “highly correlated” with conditions in the broader national economy. As such, witness Morin testified that changing economic conditions, both nationally and specific to North Carolina, are reflected in his [ROE rate] estimates. Public Staff witness Walters generally agreed with DEC witness Morin that as of the time of the filing of his testimony, economic conditions had improved in North Carolina. As the Commission has noted, customer impact due to changing economic conditions is embedded in [ROE] expert witness analyses. Witness Morin‘s analysis, which the Commission credits and to which the Commission gives weight, also indicates that even though the North Carolina and U.S. economies have contracted, economic conditions in North Carolina continue to be highly correlated to conditions nationally, and, therefore, continue to be reflected in the analyses used to determine the [ROE rate].
The Commission concludes that based upon the evidence presented in this case, the econometric data relied upon by [ROE rate] expert witnesses captures the effects and impacts of changing economic conditions upon customers and the Commission concludes that based on the evidence presented in this case, it does.
With changing economic conditions in mind, the Commission concluded that an ROE of 10.1% “will not cause undue hardship to customers even though some will struggle to pay the increased rate.” The Commission also highlighted programs to assist those DEC customers most affected by the increased rate:
Indeed, affordability, especially for low-income customers, was a special focus of DEC and the intervening parties to this proceeding. As noted above, the Commission established the [Low-Income Affordability Collaborative (LIAC)] in its April 16, 2021 Order in the 2019 Rate Case
and tasked the LIAC with addressing affordability issues for low-income residential customers. The efforts of the LIAC are apparent in this case and include the Affordability Stipulation as previously discussed in this Order.40 The provisions in the Affordability Stipulation, which include[ ] the development of the [Customer Assistance Program (CAP)] pilot, directly benefit customers with the least ability to pay in the current economic environment. In addition, as previously discussed in this Order, through the Payment Navigator program proposed in this proceeding, DEC will work closely with customers in need of assistance with managing bills and will connect those customers with sources of support and funding, based on the unique situation of the customer. While these programs will not ease the burden that electricity rates will place on certain of DEC‘s customers, the Commission expects these programs to provide a meaningful level of support to eligible customers. The Commission takes these facts into account in approving the 10.1% [ROE].
The Commission exhorted DEC to continue working to provide financial relief to its customers:
[T]he Commission also concludes, based on the evidence of record, that efforts to address energy burden and support for customers needing assistance with their bills are continuing to evolve. The LIAC allowed DEC and its stakeholders to generate data that illustrates the depth and breadth of the challenge in North Carolina. Work must continue to reach these customers and provide meaningful support both in terms of assisting customers to use energy more efficiently so that bills are reduced and in terms of providing support to those customers when they are in need of bill assistance. The Commission recognizes the difficulties attendant to solving for these issues but
emphasizes that the utility must continue to work with community partners and the LIAC in this work. As has been previously expressed by this Commission, the electric utilities must pursue every opportunity presented by federal funding made available by the IRA and other federal legislation to support customers in need. The Commission has confidence that DEC, the Public Staff and stakeholders will identify such opportunities for customers and will develop programs that take advantage of every federal dollar that is available for customer support.
The Commission also took into account the potential financial benefits to customers from an ROE that allows DEC to compete for capital on reasonable terms:
The need to invest significant sums to serve its customers requires DEC to maintain its creditworthiness in order to compete for large sums of capital on reasonable terms. In addition, as recent years have demonstrated, macroeconomic, geopolitical, extreme weather, public health, and other exogenous events beyond DEC‘s control may necessitate and indeed have necessitated the need for DEC to access and invest significant sums during atypical and volatile market conditions. The Commission takes note of [the testimony of] DEC witness [Karl W.] Newlin[, Senior Vice President of Corporate Development and Treasurer of Duke Energy Business Services, LLC,] . . . that particularly in light of DEC‘s present credit metrics, [ROE rate] is one predicate . . . to the level of creditworthiness necessary to efficiently access the capital markets on reasonable terms during all market cycles, including periods of high volatility, which access ultimately lowers borrowing costs passed through to customers during such time. Witness Newlin testified that high credit quality will benefit customers. Witness Newlin explained that if the credit profile of DEC is weakened, customers might pay less in rates in the short-term, but DEC would face higher debt borrowing costs in the long-term that will be passed through to customers. Witness Newlin testified that “it would be risky to do that . . . because I can see — you know, mathematically, you might get some near-term savings, but longer term, I believe it‘d be greater cost to customers.”
(Cleaned up).
Having examined the evidence, the Commission explained that it was “mindful of the burden” higher electricity rates pose to consumers but that it “must balance the burden against DEC‘s being in a position to access capital: (1) on reasonable terms, and (2) in moments when DEC most needs capital in order to provide reliable service.” The Commission concluded that an ROE of 10.1% “appropriately balances the benefits received by DEC‘s customers from DEC‘s provision of safe, adequate, and reliable electric service in support of the well-being of the people, businesses, institutions, and economy of North Carolina . . . with the difficulties that some of DEC‘s customers will experience in paying DEC‘s adjusted rate.”
Viewed objectively, the customer interest portion of the DEC Order demonstrates that the Commission took Cooper I seriously and duly considered customer interests before it approved DEC‘s ROE. Although the Attorney General finds fault with the Commission‘s analysis, “[i]t is not this Court‘s duty to evaluate the accuracy of complex statistical models, conflicting methodologies, and the opposing expert opinions drawn therefrom.” Carolina Util. Customers Ass‘n, 323 N.C. at 251. The General Assembly has assigned that responsibility to the Commission, and the record indicates that the Commission fulfilled its obligation during its ROE deliberations in the DEC case.
Neither the Attorney General nor CUCA has shown that the Commission‘s ROE determination in the DEC case was “affected by error of law” or unsupported by
IV. Conclusion
Our careful review of appellants’ arguments discloses no grounds for reversing or vacating the final orders entered by the Commission in the DEP and DEC cases. Accordingly, we affirm those orders.
AFFIRMED.
STATE EX REL. UTILS. COMM‘N V. CAROLINA INDUS. GRP. FOR FAIR UTIL. RATES II
Earls, J., concurring in part and dissenting in part
The majority affirms the Utilities Commission‘s decision to award a rate increase to Duke Energy Carolinas and Duke Energy Progress. Specifically, the Commission awarded Duke Energy Carolinas a higher rate of return on common equity than it had received in the past—higher even than the Commission awarded Duke Energy Progress only three and one-half months earlier. Because the majority affirms these decisions, Duke Energy will charge consumers in the western part of the state more than consumers in the eastern part of the state for identical electrical services. I dissent from the majority‘s decision to approve this disparate treatment. In my view, the Commission‘s decision in the Duke Energy Carolinas rate case is quite plainly unlawful and arbitrary.
Before diving into the weeds of the particular legal challenge here, it is useful to start with a fifty-thousand-foot view of this Court‘s role, especially regarding North Carolina‘s new framework of performance-based regulation of public utilities. Under the old system, each time a utility wanted to increase rates, it would have to file a new application with the Commission. Under the new system, certain public utilities can apply once to increase rates over three years.
Yet today, the majority blanketly rejects nine distinct challenges to the Commission‘s orders in two such ratemaking cases.1 In doing so, the majority appears to transform appropriate deference to the Commission‘s technical expertise into an exercise in largely taking the Commission at its word. Our critical review requires more. Ratepayers across North Carolina deserve more.
I would not so sweepingly affirm the Utilities Commission. Instead, I would vacate the Duke Energy Carolinas award of a 10.1% rate of return on common equity as well as reverse the Commission‘s decision to treat hazard tree removal as a capital expense. As to the return on common equity, I conclude that the Commission‘s order
The majority concludes that this decision is permissible because the Commission‘s composition changed between the two rate orders. The Commission majority‘s award in the Carolinas case was consistent with the dissent‘s view in the Progress case, it reasons—implying that Duke Energy Progress should have been able to charge its consumers more, too.
As to the hazard tree removal program, the Commission acted in excess of its statutory authority by awarding rate base treatment to the routine vegetation management practice of removing hazard trees. I fail to see why routinely trimming trees is an operating expense while routinely cutting trees down on property adjacent to Duke Energy‘s facilities is a capital one. Because Chapter 62 limits rate base treatment to only those qualifying “capital investments” and “property used and useful” during the rate period, the Commission acted in excess of its authority by allowing Duke Energy Carolinas a return on these costs.
As to the remaining challenges, I respectfully concur.
I. Rate of Return on Common Equity
It bears emphasizing that public utility regulations must robustly protect the consuming public. That is a core purpose of a regulated public utility.
A public utility company is granted a “legal monopoly upon a service vital to the economic well being and the domestic life of the people of a large territory.” State ex rel. Utils. Comm‘n v. Gen. Tel. Co. of the Se., 281 N.C. 318, 335 (1972). Because “[a]n uncontrolled legal monopoly in an essential service leads, normally and naturally, to poor service and exorbitant charges,” id., the state must check the utility‘s worst impulses which would otherwise threaten harm to consumers, other business industries, and the state writ large. The Public Utilities Act thus tasks the Utilities Commission with protecting the public interest by carefully setting the rates that public utilities can charge to customers.
To that end, the Utilities Commission must set rates high enough that utilities can ensure reliable service to customers, including by paying shareholders for the cost of accessing necessary capital, but low enough to be fair to consumers.
As the majority notes, one step in the process of setting rates is for the Commission to determine the utility‘s overall rate of return, or the percentage the utility will earn on certain of its capital investments. See majority supra Section III.C; State ex rel. Utils. Comm‘n v. Thornburg, 325 N.C. 463, 467 n.2 (1989). One of the most important components of that overall rate of return is the rate of return on common equity.
Because the rate of return on common equity is a matter of expectations of investors in this particular type of equity, among the most important evidence is the
Accurately calculating the proper rate of return on common equity is “extremely important” because “it is the most expensive form of capital accumulation” and is “ultimately borne by the ratepayer.” State ex rel. Utils. Comm‘n v. Pub. Staff (Public Staff I), 322 N.C. 689, 697–98 (1988). Each increase in the rate of return on common equity triggers substantial costs for consumers. See State ex rel. Utils. Comm‘n v. Cooper (Cooper I), 366 N.C. 484, 485 n.1 (2013) (“The higher the [return on equity], the higher the resulting rates that customers will pay to the utility.“).
In light of these factors, the Commission has limited discretion to set rates, including the rate of return on common equity. The Commission must “fix rates as low as may be reasonably consistent with the requirements of the Due Process Clause of the Fourteenth Amendment to the Constitution . . . [and] those of the State Constitution, Art. I, § 19.” State ex rel. Utils. Comm‘n v. Duke Power Co., 285 N.C. 377, 388 (1974) (emphasis added); see also id. (noting that the federal and state constitutional requirements are “the same in this respect“); State ex rel. Utils. Comm‘n v. Pub. Staff (Public Staff II), 323 N.C. 481, 490 (1988) (observing that case law on the overall rate of return applies to the rate of return on common equity and that rates must be “as low as may be reasonably consistent with” due process (cleaned up)).
These requirements mean that, when presented with a range of reasonable options for a return on common equity, the Commission‘s compass must always point downward. Rates must be set at the “lowest possible cost to the using public for quality service” while assuring “sufficient shareholder investment in utilities.” Id. at 494 (quoting State ex rel. Utils. Comm‘n v. Carolina Util. Customers Ass‘n (CUCA I), 348 N.C. 452, 458 (1998)). Ultimately, “[w]hat constitutes a fair rate of return on common equity is a conclusion of law that must be predicated on adequate factual findings.” CUCA I, 348 N.C. at 462 (citing Public Staff I, 322 N.C. at 693).
In turn, our Court is responsible for directly reviewing whether the Commission complied with these legal obligations. See
B. Challenges to the Duke Energy Carolinas Return on Common Equity
Here, the Utilities Commission awarded Duke Energy Carolinas (Carolinas) a return on common equity of 10.1% merely three and one-half months after it awarded Duke Energy Progress (Progress) a return on common equity of 9.8%. No one disputes that the two utilities are materially identical. Yet this decision means that, according to one estimate, North Carolinians in the central and western parts of the state will pay over $129 million more than others in the central and eastern parts of the state—millions more for the same services from the soon-to-be same company.4
1. The Award Is Unsupported by Substantial Evidence
The Commission‘s conclusion that a 10.1% return on common equity was the lowest possible rate consistent with due process is unsupported by “substantial evidence in the record as a whole” and must be set aside. Public Staff III, 331 N.C. at 222. As the Commission‘s order acknowledged, the only expert witness whose return on common equity recommendation supported a 10.1% award was Duke Energy‘s own Dr. Roger Morin. Every other expert witness recommended an award below 10%—indeed even below 9.8%.5 Thus Dr. Morin was the sole expert upon whose testimony the Commission could have based its decision. But his testimony, taken as a whole, fails to support an award higher than 9.8%.
Dr. Morin was Duke Energy‘s rate of return expert in both the Progress and the Carolinas rate cases. He was also the only one of Duke Energy‘s return on equity
After Dr. Morin‘s initial testimony in the Carolinas case, the Commission announced that it would award Progress a 9.8% return on common equity. Dr. Morin was then questioned about how that development affected his recommendations for Carolinas. After all, the cost of equity capital for one public utility depends in part on the comparable returns of peer public utilities.8 How the market received Duke
In light of the Commission‘s award of 9.8% to Duke Energy Progress, Dr. Morin acknowledged that 9.8% for Duke Energy Carolinas was “reasonable.” Indeed, he conceded that this figure was at the “bottom of [his recommended] range.” He further conceded that “bond rating agencies . . . reacted favorably” to Progress‘s 9.8% award. He again affirmed that he was not “aware of any [substantive] difference that would warrant a difference in allowed [return on equity]” between the two public utilities.
Thus, the testimony of the only expert who supported a rate of 10.1% or higher added that 9.8% was also reasonable and that Duke Energy Carolinas and Duke Energy Progress were entitled to the same return. Indeed, his conclusion that 9.8% was reasonable was bolstered by early indications that the market too thought this figure was reasonable and that concerns voiced by the dissenters in Duke Energy Progress about the utility‘s possible downgrading did not materialize. The Commission in Carolinas found no facts to support that the two companies exhibited different risk profiles warranting a greater return on common equity for one of them.
of the public equal to that generally being made at the same time and in the same general part of the country on investments in other business undertakings which are attended by corresponding risks and uncertainties; but it has no constitutional right to profits such as are realized or anticipated in highly profitable enterprises or speculative ventures.” (emphasis added)); Phillips, Regulation of Public Utilities 381 (noting that the public utility rate of return on equity must be high enough to, in part, “provide a return on common equity that is commensurate with returns on investments in other enterprises of corresponding risk“).
Instead, after identifying its own “zone of reasonableness of 9.99% to 10.37%” based on various averages of witness testimony, “the Commission in its discretion” selected a number in the “approximate midpoint of this range.” This is an error of law. See Public Staff I, 322 N.C. at 693. When presented with a range of reasonable options, the Commission lacks “discretion” to randomly select a number in that range. Instead, it must select the lowest possible rate consistent with due process. See Duke Power, 285 N.C. at 388; Cooper I, 366 N.C. at 494. If it does not select the lowest possible rate consistent with due process, it must provide reasons why it is departing from that figure—reasons that (1) comport with legal requirements governing the return on common equity and the Commission‘s mandates under
The majority waves away this evidence (or lack thereof). It concludes simply that “the fact remains that [Duke Energy‘s witness] originally recommended an ROE of 10.4%, a number higher than the 10.1% ROE approved by the Commission.” See majority supra Section III.F.1. But our job here is not to ask whether any evidence supported the Commission‘s conclusion. Rather, we must assure ourselves that there is “such relevant evidence as a reasonable mind might accept as adequate to support a conclusion.” Cooper III, 367 N.C. at 648. Reasonable minds surely do not focus
Speaking of the actual evidence below, not only did the Commission fail to provide reasons for departing from the lowest reasonable rate, but its higher award was unsupported in light of the ample record evidence showing the harmful likely impact of the proposed rate increase on customers. The Commission heard testimony that “[n]early 20 percent of North Carolina residents were unable to pay their electric bills at least once in 2021.” For the “90,000 workers in this state [who make] at or below the minimum wage,” a rate increase would pose a serious hardship, “just pil[ing] onto housing costs that have gone out of control.” Consumers reported that they would have difficulty affording a higher rate, especially those who are living on fixed or low incomes, and that they are concerned about inflation and the general state of the economy. Others expressed alarm that a company “which reported a $2.56 billion profit last year” had grounds to demand more revenue from ratepayers, particularly in light of “ongoing economic challenges caused by the pandemic.”
Testimony illuminated the disproportionate burdens imposed by new rate increases. Seniors and others on fixed or low incomes “do not receive sufficient annual income increases to cover the financial burden of potentially[ ]approved requested
In personal terms, consumers told the Commission that their utility bills are “very stressful” and that the “rate increase hike is just going to be even more detrimental.” A rate increase could pose the risk of having insufficient funds to “meet[ ] other essential needs like food and medicine” or not allowing a child to participate on a sports team. Increasing rates would place “an undue burden on those who are already struggling financially” and force the too “many North Carolinians who already have to make tough decisions [to choose] between paying utility bills or other basic necessities.” Testimony reflected that those individuals and others “simply [can]not afford a rate increase.”
In light of this evidence, the Commission‘s decision to depart from the lowest recommended “reasonable” rate and to instead award a return thirty basis points higher than that—without offering any reasons consistent with
In a tacit acknowledgement that the evidence before the Commission in this case does not support its ultimate award, Duke Energy offered post hoc justifications. Specifically, Duke argued, and the majority agrees, that the Commission‘s change in composition justified its larger return on common equity award in Carolinas. As the majority puts it, the Commission acted reasonably because the new commissioners “cast votes in the [Carolinas] case in line with views they had expressed in that dissent [in Progress] less than four months earlier.” See majority supra Section III.F.1.
To start, this observation about the change in the Commission‘s composition is beside the point. The Commission‘s rate order never cited its change in composition as the reason it adopted a different position on the rate of return on common equity. There is no discussion about the different membership of the Commission‘s decision-making panel or explanation of how that different composition changed the underlying inquiry as to the legal conclusion regarding the lowest possible rate of return consistent with due process.
As a general matter, judicial review of agency actions is limited to those “grounds invoked by the [Commission]” when it took the challenged action. Godfrey v. Zoning Bd. of Adjustment, 317 N.C. 51, 63–64 (1986) (cleaned up). This Court should not affirm an agency‘s decision because we can conceive of a legal basis to
Second, while the majority concludes that “it would border on silly for this Court to reverse [the Commission‘s] decision merely because the [Carolinas] Order does not repeat the arguments made in the [Progress] dissent,” see majority supra Section III.F.1, that conclusion ignores the reality that some of the reasoning in the Progress dissent did not and could not justify the Carolinas return on common equity order. Namely, the evidence of how the bond rating agencies reacted to the Progress order undermined the Progress dissenters’ reasoning and thus could not apply to the Carolinas order. The dissenting commissioners in the Duke Energy Progress case were specifically concerned that the market would not react well to the 9.8% award. The primary dissent in the Progress rate order feared that a return on equity lower than 10.0% could result in a “downgrade” in creditworthiness specifically from credit rating agencies like Moody‘s. The favorable reaction by bond rating agencies to the Progress award was thus contemporaneous evidence that the earlier dissenters’ concerns were misplaced. The reasoning from the earlier order‘s dissent could not be uncritically copied over to the later order in light of this new information. Put simply,
Third, the majority gestures to changed economic conditions that developed in the three and one-half month interim between the Progress award and the Carolinas award. See majority supra Section III.F. Duke argued, and the majority apparently agrees, that the higher return on equity in Carolinas was supported because all expert witnesses raised their recommendations in the later rate order in light of changed economic conditions. Under the actual facts of this case, though, this argument is without merit. The Commission never acknowledged the earlier 9.8% Progress award and tied its greater award to Carolinas to different economic conditions, so this cannot be grounds to affirm the Commission‘s decision. See Godfrey, 317 N.C. at 63–64. Moreover, no expert‘s recommended increase accounted for the full variation between the Commission‘s two rate orders.
Looking at the witness testimony, all experts increased their recommendations by ten to twenty basis points at most. The difference in the Commission‘s ultimate award to Carolinas was thirty basis points. We do not improperly override the Commission‘s expertise by merely observing that its math does not add up. Our responsibility to review the Utilities Commission‘s action demands more than simply concluding that “the witness‘s numbers got bigger, so the Commission‘s bigger number was justified.”
| Party – Witness | Progress | Carolinas | Difference |
|---|---|---|---|
| Duke Energy Progress/Carolinas – Morin | 10.4%9 | 10.4% | 0 pts |
| Public Staff – Walters10 | 9.45% | 9.55% | 10 pts |
| CUCA – O‘Donnell (Progress) and LaConte (Carolinas) | 9.25% | 9.40% | 15 pts |
| NCJC et al. – Ellis | 6.00% | 6.15% | 15 pts |
| Commission Award | 9.8% | 10.1% | 30 pts |
It bears emphasizing that shifts in “economic conditions” were the only factual basis Duke Energy itself was aware of that would justify a different cost of equity capital for Carolinas than for Progress. When pressed about the grounds for awarding a different return to Carolinas than for Progress, a Duke Energy executive responded as follows:
[Question from attorney for Public Staff:] [W]e know that this Commission ordered a 9.8 ROE in the DEP case, and DEP covers, let‘s say, Wake County, for example. So, when DEC is asking for a 10.4, 60 more basis points [than its current award], when we go to Graham County and people say why is – why am I paying 60 basis points more than
people in Wake County, what answer do I give? [Answer from Duke Energy executive Laura Bateman:] I think from the Company‘s perspective we requested the same ROE in both – both – for both utilities and, obviously, there is slightly different timing of the cases, slightly different contents to the cases, but I think primarily the timing would have an impact or could have an impact.
So Duke Energy itself cannot explain to Graham County consumers why they must pay more than Wake County consumers for the same services. How the Commission still determined that such disparate treatment was justified is a mystery. The majority does not explain or identify the substantial evidence it believes supports this disparate treatment. In my view, it cannot, because the Commission‘s conclusion here is unsupported and unlawful.
Furthermore, according to Duke Energy‘s own evidence, economic changes in the intervening three months should not account for a substantially different return on equity between these two arms of Duke Energy. Dr. Morin conceded that “day-to-day fluctuations in interest rates and current spot circumstances” should not be reflected in the “allowed rate of return,” in that the rate of return on common equity is “to remain in effect typically for the next several years.” So again, the only witness whose recommendation supported an award of 10.1% also thought short-term economic shifts (maybe over three months) should not bear heavily in the Commission‘s award. Short-term changes cannot account for the 10.1% award, and this further bolsters that the award itself is unsupported and must be set aside. See
2. The Award is Arbitrary and Capricious
I also dissent from the majority‘s conclusion that the Commission‘s return on equity award to Carolinas was not arbitrary or capricious.
“Decisions are arbitrary and capricious when, among other things, they indicate a lack of fair and careful consideration or fail to display a reasoned judgment.” State ex rel. Utils. Comm‘n v. Thornburg, 314 N.C. 509, 515 (1985). Here, the Commission‘s analysis shows a lack of careful consideration and reasoned judgment because it affirmatively relied on the Progress rate order sometimes and other times acted like the Progress rate order did not exist, apparently without any good or consistent reason for doing so.
Specifically, throughout its Carolinas order, the Commission used its Progress rate order as a point of comparison. That included multiple times in its very analysis of the return on common equity. E.g., Order Accepting Stipulations, Granting Partial Rate Increase, Requiring Public Notice, and Modifying Lincoln CT CPCN Conditions, In re Application of Duke Energy Carolinas, LLC for Approval to Construct a 402 MW Natural Gas-Fired Combustion Turbine Electric Generating Facility in Lincoln County & for Adjustment of Rates and Charges Applicable to Electric Service in North Carolina and Performance Based Regulation, Docket Nos. E-7, SUB 1134 & 1276, slip op. at 199 (N.C.U.C. Dec. 15, 2023) (“The Commission notes also that it rejected
Yet despite finding the Duke Energy Progress award a probative baseline for some parts of the rate of return on common equity analysis, the Commission strangely omitted any reference to its earlier choice to award Progress a 9.8% return on common equity.
This selective omission is further suspect because the Commission carefully analyzed returns on common equity for peer utilities. The Commission looked at the range of “currently authorized rates of return on common equity for vertically integrated electric utilities in the United States,” including the overall average of
Nevertheless, the Commission inexplicably refused to look at the most recent version of the same data: Progress‘s 2023 North Carolina return. So even as the Commission insisted that the Carolinas award must be sensitive to the fact that the utility “is in competition for equity capital with other utilities,” it blatantly ignored what was arguably the best comparable indication of the market for this kind of equity capital. Such selectivity is clearly arbitrary.
Notably too, the Commission discounted some witnesses’ return on common equity recommendations where the award would have been “below any rate of return on equity ever approved by this Commission for [Duke Energy Carolinas].” The Commission credited Dr. Morin‘s testimony that Carolinas’ last return was 9.6% and his testimony that the cost of equity capital was at least as great as that figure. So the Commission apparently relied on historical precedent where it justified a higher return but ignored historical precedent when that evidence counseled in favor of a lower one. Again, seemingly random selectivity shows “a lack of fair and careful consideration” and dooms the Commission‘s reasoning as arbitrary and capricious. Thornburg, 314 N.C. at 515.
Our holding in Virginia Electric & Power Co. is consistent with this conclusion. There we held that the Commission validly exercised its discretion to consider “other material facts” under
3. The Award Fails to Account for Consumer Interests
Finally, the majority concludes that “the customer interest portion of the [Carolinas] Order demonstrates that the Commission took Cooper I seriously and duly considered customer interests before it approved [Carolinas‘] [return on equity].” See majority supra Section III.F.2. The majority quotes the Commission‘s conclusions at length, including its determination that the 10.1% rate of return “will not cause undue hardship to customers even though some will struggle to pay the increased rate,” and that Duke Energy Carolinas has some supplementary programs to help customers “with the least ability to pay,” aided by funding from the federal Inflation Reduction Act. See id. The majority apparently reaches this conclusion even as it agrees with the Attorney General that the Carolinas order‘s customer interest analysis was a near verbatim copy of the Progress order.
Contrary to the majority, I find it difficult to conclude that the Commission adequately took account of customer interests in the Carolinas rate order where the Commission‘s analysis was substantively the same as in the Progress order yet the
II. Rate Base Treatment to Hazardous Tree Removal
Although less consequential, I also dissent from the majority‘s decision to affirm the Utilities Commission‘s treatment of a hazard tree removal program as a capital expense. In my view, this kind of vegetation management practice is indistinguishable from other routine vegetation management practices that are properly classified as operating expenses. It does not meet the statutory criteria for a capital expense eligible for return. I would vacate this part of the Commission‘s decision too and remand for removal of this project from the rate base and for recalculation of Duke Energy Carolinas’ operating expenses to account for this change.
Public utilities have a significant financial incentive to classify their expenses as “capital” rather than “operating” because only capital expenses earn a return for the utility. Thornburg, 325 N.C. at 475. Capital expenses are distinct from “operating expenses” under traditional ratemaking and performance-based regulation.
The Attorney General and the Carolina Utility Customers Association challenge the Commission‘s order for improperly allowing Carolinas’ hazard tree removal program to be treated as a capital project. They allege that this decision was in excess of the Commission‘s statutory authority because the program is quintessentially an operating program to manage vegetation growth and maintain the utility‘s provision of services. See
The record showed that Duke Energy Carolinas’ hazard tree removal program is one aspect of its overall vegetation management program. This overall program has been routine, or “cycl[ical]” since after 2013. Other parts of Carolinas’ vegetation management program are classified as operating expenses, according to the Commission. Trimming trees along existing property lines, for example, is routine
Within this vegetation management program, the hazard tree program manages trees “which lie[ ] outside [Duke Energy Carolinas‘] rights-of-way.” The program identifies and removes “structurally unsound, dying, diseased, leaning or otherwise defective trees that could strike electrical lines or equipment” from beyond Carolinas’ existing property. This routine maintenance of existing corridors is distinct from Carolinas’ efforts to clear trees to construct a new right-of-way or building. The costs of clearing trees for a new right-of-way are statutorily classified as eligible for rate base treatment.
This type of routine tree management is a classic operating expense not eligible for rate base treatment. See operating expense, Black‘s Law Dictionary (12th ed. 2024) (“An expense incurred in running a business and producing output.“). Just as the costs associated with trimming trees are operating expenses, so are the costs associated with routinely cutting them down. Federal regulators have concluded the
Nor is it “property used and useful.” Id.
Notably, the Commission offered no reasons why it classified costs associated with maintaining trees on the right-of-way as operating while those off the right-of-way are capital. Why does the tree being on someone else‘s property transform this operating expense into a capital one? The Commission did not say nor does any evidence in the record appear to provide an explanation.
The majority gestures to the “permanent” or long-term benefit of cutting down these trees that helps the company maintain services. See majority supra Section III.C. But whether something is permanent is not a useful standard for whether an item is a capital or operating expense. Surely any routine efforts to maintain reliable service for a business whose main asset is physical property has a long-term benefit. Of course, routinely maintaining physical equipment redounds to a long-term
In any event, it is curious to me that anything associated with vegetation management could in fact be “permanent.” Presumably Duke Energy is not in the habit of constructing power lines next to hazardous trees. The issue is simply that vegetation grows. Saplings become trees, and trees can eventually become “hazardous.” Public utilities may not categorize operating expenses as capital ones on the mistaken premise that some kinds of vegetation will somehow remain static.
III. Electric Vehicle Charging Decoupling and Interclass Subsidy Reduction
As to the other issues on appeal, I concur with the majority‘s analysis and write separately to underscore narrow points.
Regarding the majority‘s interpretation of incremental electric vehicle charging to be exempt from the decoupling mechanism, I concur with the majority that the clear legislative intent here was to “preserve the electric public utility‘s incentive to encourage electric vehicle adoption.” See majority supra Section III.B &
As the majority notes, here Duke Energy stipulated in both rate orders that it would work with the Public Staff and industry representatives to develop and file electric vehicle tariffs and programs to obtain accurate estimates of revenue from electric vehicle charging usage. The record also indicated that Duke Energy operates public-facing programs that educate consumers about costs and opportunities associated with electric vehicle adoption, including the Make-Ready Credit Program, through which Duke Energy “will defray part of the cost of installing the infrastructure necessary to charge [electric vehicles].” See majority supra Section III.C n.11. This stipulation and record evidence supports that procedures have been agreed upon that will position Duke Energy to continue incentivizing electric vehicle adoption in order to have the benefit of excluding these revenues from the decoupling mechanism, consistent with legislative intent.
Second, on the Commission‘s approval of the 10% reduction in interclass subsidies for Duke Energy in both rate orders, I agree with the Majority‘s explanation of why the Commission did not err here, particularly as it relates to the scope of the word “practicable” in the context of this statute and the interrelation of subsections
By statute, the public utility has the burden of proof to show that a proposed rate change “is just and reasonable.” Id.
Because we generally assume the legislature knows the law and legislates in reference to it, see C Invs. 2, LLC v. Auger, 383 N.C. 1, 13 (2022), I would expect similar burden-shifting principles to apply in this context and under the new performance-based regulation framework unless the legislature indicates otherwise.
As the majority explains, the Carolina Industrial Group for Fair Utility Rates II proposed a 25% uniform interclass subsidy reduction, which the Commission rejected as impracticable and likely to cause severe rate shock. See majority supra
IV. Conclusion
I dissent in part from the majority‘s decision to affirm the return on common equity award, which I conclude unlawfully fails to give weight to the considerable consumer interests at stake and is the result of arbitrary and capricious reasoning and conclusions that are unsupported by substantial evidence in the record and inadequately took account of customer interests. I also dissent from the Commission‘s decision to award rate base treatment to Duke Energy Carolinas’ routine vegetation management practice of removing hazard trees. As to the Majority‘s other conclusions, I respectfully concur.
Justice RIGGS joins in this dissenting opinion.
Notes
In broad terms, the legislation instructed the Commission to “take all reasonable steps to achieve a seventy percent (70%) reduction in emissions of carbon dioxide (CO2) emitted in the State from electric generating facilities owned or operated by electric public utilities from 2005 levels by the year 2030 and carbon neutrality by the year 2050.” Id. § 1, 2021 N.C. Sess. Laws at 739. In 2025, the General Assembly amended the legislation, striking the requirement to achieve a 70% reduction in CO2 emissions by 2030. An Act to Eliminate the Interim Date for Carbon Reduction by Certain Electric Public Utilities, to Allow an Alternative Cost Recovery Mechanism for the Financing Costs of Construction Work in Progress for Baseload Electric Generating Facilities, to Modify the Statutes Governing Cost
Recovery for Fuel-Related Charges and Performance-Based Ratemaking, and to Codify a Provision Authorizing Securitization of Costs for Retirement of Coal-Fired Generating Units, S.L. 2025-78, § 1, https://www.ncleg.gov/EnactedLegislation/SessionLaws/PDF/2025-2026/SL2025-78.pdf. That includes a requested rate increase that succeeds this one. Liz McLaughlin, Duke Energy seeks rate hike as customers push back on rising bills, WRAL https://www.wral.com/news/local/duke-energy-residential-rate-hike-public-hearing-march 2026 (Apr. 2, 2026, 2:19 PM). Notably, Duke Energy Carolinas appears to give shareholders a higher return on common equity than is allowed by the Commission, depending on the underlying metric. Duke Energy Carolinas recently reported achieving a rate of return on common equity of 11.1%, or 150 basis points above the return on common equity authorized in its 2019 Rate Case (9.6%). Letter from Jack E. Jirak, Deputy General Counsel for Duke Energy Corporation, to A. Shonta Dunston, Chief Clerk, North Carolina Utilities Commission, Re: 2025 Quarter 4 E.S.-1 Report (filed on 2 March 2026 in Docket No. M-1, Sub 12DEC), starw1.ncuc.gov/NCUC/ViewFile.aspx?Id=c7f6bb18-5c0a-4664-ab05-92cfa2cee017 (last visited May 11, 2026).In deciding to defend the DEP and DEC Orders, the Public Staff may have been influenced by its success in persuading the Utilities to accept several pro-consumer modifications to their applications. For instance, the Utilities agreed to exclude from their revenue requirements, among other things, incentive pay related to earnings per share and total shareholder return for the top levels of Company leadership, 50% of the benefits associated with the five Duke Energy executives with the highest amounts of compensation, and the credit card payment fees for nonresidential customers. DEC further agreed to reduce [its] projected MYRP capital by $351 million on a system basis. We do not know to what extent the Public Staff‘s pro-consumer agreements with the Utilities would survive if the Attorney General were to prevail on appeal.
Dr. Morin recommended 10.4% in both his Carolinas and Progress testimony. Notably, the president of Duke Energy Progress and Duke Energy Carolinas, Kendal C. Bowman, referred to the two companies as one—“our Carolinas utilities“—and described risks to company operations specific to North Carolina generally.