State ex rel. N.C. Utils. Comm'n v. Carolina Indus. Grp. for Fair Util. Rates III

• Court: Supreme Court of North Carolina
• Decided: May 22, 2026
• Docket: 139A24
• Status: Published
• Author: Justice Trey Allen

Opinion

IN THE SUPREME COURT OF NORTH CAROLINA

Nos. 75A24-1 and 139A24-1

Filed 22 May 2026

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.

Consolidated appeals as of right pursuant to N.C.G.S. §§ 62-90, 7A-29(b) from

final orders of the North Carolina Utilities Commission entered on 18 August 2023

in Docket No. E-2, Sub 1300 and on 15 December 2023 in Docket Nos. E-7, Sub 1134

and 1276. Heard in the Supreme Court on 13 February 2025.

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. STATE EX REL. UTILS. COMM’N V. CAROLINA INDUS. GRP. FOR FAIR UTIL. RATES II

Opinion of the Court

Ward and Smith, P.A., by Christopher S. Edwards, Alex C. Dale, and Alexandra E. Ferri, and Bailey & Dixon, LLP, by Christina D. Cress, for Carolina Industrial Group for Fair Utility Rates II, Carolina Industrial Group for Fair Utility Rates III, Blue Ridge Electric Membership Corp., Piedmont Electric Membership Corp., Rutherford Electric Membership Corp., and Haywood Electric Membership Corp., intervenor-appellants.

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 N.C.G.S. § 62-133.16, a statute enacted by the General

1 Duke Energy Corporation announced in August 2025 that it would seek approval

from regulators to merge DEP and DEC to “streamlin[e] operations and significantly reduc[e] costs for customers.” Combining Duke Energy Carolinas and Duke Energy Progress projected to save customers over $1B in future costs, Duke Energy News Ctr. (Aug. 14, 2025), https://news.duke-energy.com/releases/combining-duke-energy-carolinas-and-duke-energy- progress-projected-to-save-customers-over-1b-in-future-costs. The Federal Energy Regulatory Commission approved the merger on 30 January 2026. Duke Energy reaches agreement with South Carolina customer groups and others on proposed combination of Duke Energy Carolinas, Duke Energy Progress, Duke Energy News Ctr. (Mar. 10, 2026), https://news.duke-energy.com/releases/duke-energy-reaches-agreement-with-south- carolina-customer-groups-and-others-on-proposed-combination-of-duke-energy-carolinas- duke-energy-progress. The Commission as well as South Carolina’s utility regulator, the Public Service Commission of South Carolina, must still approve the merger before it may go into effect next year. Id.

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Assembly in 2021 that provides electric public utilities in North Carolina with an

alternative to traditional ratemaking.

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 N.C.G.S. § 62-

133.16. Because the Commission construed the law correctly and made sufficient

findings of fact supported by competent, material, and substantial evidence in view

of the entire record, we affirm.

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 N.C.G.S. § 62-3(23) (2025)

(defining “public utility” for purposes of Chapter 62 of the General Statutes); N.C.G.S.

§ 62-31 (2025) (“The Commission shall have and exercise full power and authority to

administer and enforce the provisions of [the Act], and to make and enforce

reasonable and necessary rules and regulations to that end.”). In particular, the Act

directs the Commission to “make, fix, establish or allow just and reasonable rates for

all public utilities subject to its jurisdiction.” N.C.G.S. § 62-130(a) (2025); see also

N.C.G.S. § 62-32(a) (2025) (granting the Commission “general supervision over the

rates charged and service rendered by all public utilities in this State”).

Section 62-133 of the General Statutes spells out the procedures that have

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traditionally governed the fixing of utility rates in general rate cases. N.C.G.S.

§ 62-133 (2025). The General Assembly enacted N.C.G.S. § 62-133 to achieve the

“twin goals” of “assuring sufficient shareholder investment in utilities while

simultaneously maintaining the lowest possible cost to the using public for quality

service.” State ex rel. Utils. Comm’n v. Carolina Util. Customers Ass’n, Inc., 348 N.C.

452, 458 (1998). These twin goals must be understood in the context of the Act’s

“primary purpose,” which “is to assure the public of adequate service at a reasonable

charge,” not “guarantee to the stockholders of a public utility constant growth in the

value of and in the dividend yield from their investment.” State ex rel. Utils. Comm’n

v. Gen. Tel. Co. of the Se., 285 N.C. 671, 680 (1974).

In October 2021, the General Assembly enacted N.C.G.S. § 62-133.16 (the PBR

Statute) as one of a package of measures aimed at reducing the carbon emissions of

electric public utilities.2 The PBR Statute provides an alternative to traditional

2 An Act to Authorize the Utilities Commission to (I) Take All Reasonable Steps to

Achieve a Seventy Percent Reduction in Emissions of Carbon Dioxide from Electric Public Utilities from 2005 Levels by the Year 2030 and Carbon Neutrality by the Year 2050, (II) Authorize Performance-Based Regulation of Electric Public Utilities, (III) Proceed with Rulemaking on Securitization of Certain Costs and Other Matters, and (IV) Allow Potential Modification of Certain Existing Power Purchase Agreements with Eligible Small Power Producers, S.L. 2021-165, § 4(a)–(c), 2021 N.C. Sess. Laws 738, 741–46. 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

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ratemaking that differs from it in significant respects. In traditional ratemaking, for

example, a public utility may not impose a general rate increase without filing a new

general rate application with the Commission. The PBR Statute allows the

Commission to approve a “multiyear rate plan” (MYRP) that remains in effect for up

to three years and includes preapproved rate increases for years two and three.

N.C.G.S. § 62-133.16(c)(1)(a), (f) (2025). The public electric utility’s base rates for the

first year of the MYRP are fixed in accordance with N.C.G.S. § 62-133, whereas the

rate increases for the MYRP’s second and third years are based on certain cost

projections, such as “projected incremental Commission-authorized capital

investments that will be used and useful during the rate year.” N.C.G.S. § 62-

133.16(c)(1)(a). Thus, an approved MYRP enables an electric public utility to fund

Commission-authorized investments “without the need . . . to file a subsequent

general rate application pursuant to [N.C.G.S. §] 62‑133.” Id. § 62-133.16(a)(5), (c)

(2025).

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

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.

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hearing in the DEP case. In June 2023, following the conclusion of the DEP hearing,

the Commission began its evidentiary hearing in the DEC case.

The Attorney General and the Public Staff3 intervened by right in both

ratemaking cases. See N.C.G.S. § 62-15(d)(3) (2025); N.C.G.S. § 62-20 (2023)

(repealed 2024). The Commission permitted other groups to intervene, including the

Carolina Industrial Group for Fair Utility Rates (CIGFUR), the Carolina Utility

Customers Association (CUCA), and multiple electric membership corporations

(EMCs).4 The intervenors actively participated in the evidentiary hearings, offering

expert testimony and making recommendations to the Commission.

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 N.C.G.S. §§ 7A-29(b) and 62-90(d) (2025), a party may appeal the

3 The Public Staff is a statutorily created consumer advocate that represents the public in the Commission’s rate cases. See N.C.G.S. § 62-15(b) (2025). 4 CIGFUR and CUCA are associations comprising business or industrial customers of

DEP or DEC. “CIGFUR” refers to more than one entity. The members of CIGFUR II are customers of DEP, whereas those of CIGFUR III are customers of DEC. CIGFUR II appealed the Commission’s final order in the DEP case; CIGFUR III appealed the final order in the DEC case. In the interest of readability, and because they filed a joint brief, we will simply use the term “CIGFUR” when we mean either CIGFUR II or III.

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Commission’s final order in a general rate case directly to this Court. The Attorney

General, CIGFUR, and Haywood EMC appealed the DEP Order. They also appealed

the DEC Order, as did CUCA, Blue Ridge EMC, Piedmont EMC, and Rutherford

EMC. In their appeals, the intervenors assert that the Commission made numerous

errors, some of which involve alleged misinterpretations of the PBR Statute.5 We

address each alleged error in turn.

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.

N.C.G.S. § 62-79(a) (2025).

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

5 CIGFUR and the EMCs filed a consolidated brief and reply brief with this Court. For

clarity’s sake, we refer to those documents as CIGFUR’s briefs in this opinion.

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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.

N.C.G.S. § 62-94(b) (2025).

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.” Id. § 62-94(b). If the Commission correctly followed the

law in setting rates, and competent, material, and substantial evidence supports its

decision, this Court will not reverse that decision “merely because we would have

reached a different conclusion upon the evidence.” State ex rel. Utils. Comm’n v.

Morgan, 277 N.C. 255, 267 (1970). “The Commission’s conclusions of law are,

however, subject to de novo review for legal error on appeal.” State ex rel. Utils.

Comm’n v. Va. Elec. & Power Co. (VEPCO), 381 N.C. 499, 515 (2022).

On appeal “the rates fixed or any rule, finding, determination, or order made

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by the Commission under . . . Chapter [62] is prima facie just and reasonable.”

N.C.G.S. § 62-94(b). Consequently, “[t]he burden is on the appellant to demonstrate

an error of law in the proceedings.” State ex rel. Utils. Comm’n v. Piedmont Nat. Gas

Co., 346 N.C. 558, 573 (1977).

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. N.C.G.S. § 62-133.16(b)

(2025). The cost causation principle “means establishment of a causal link between a

specific customer class, how that class uses the electric system, and costs incurred by

the electric public utility for the provision of electric service.” Id. § 62-133.16(a)(1)

(2025). Interclass subsidization occurs when one category of an electric public utility’s

customers pays more than its share of the utility’s cost to produce power for all

customers.

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

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“residential” schedules fall into the “residential customer class.” Commercial and

industrial customers typically fall under one of the “general service” schedules. The

Utilities subdivide their general service customers into classes based on how much

power the customers demand: small general service, medium general service, and

large general service. The Utilities also categorize customers based on the type of

energy they use. For example, customers operating large outdoor light fixtures take

service under one of the “lighting” schedules.

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.

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At the hearings in both cases, expert witnesses for CIGFUR recommended that

the Commission approve a subsidy reduction of at least 25%. According to these

witnesses, the Utilities’ large commercial and industrial customers were paying

subsidies in the tens of millions of dollars. While acknowledging CIGFUR’s

“legitimate concern” about the ongoing interclass subsidy, the Commission concluded

that other factors weighed against CIGFUR’s recommendation. On appeal CIGFUR

and CUCA argue that the Commission erred in making this determination.

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.

N.C.G.S. § 62-133.16(b) (emphases added).

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.” N.C.G.S. § 62-

133.16(d)(1) (2025). In assessing whether the proposal meets this standard, the

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Commission “shall consider” whether the PBR application:

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.

Id. (emphasis added).

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

“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

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Bureau Mut. Ins. Co. v. Hebert, 385 N.C. 705, 711 (2024).

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, N.C.G.S. § 57D-6-02(2)(i), “ ‘practicable’ is synonymous with ‘feasible[,]’

. . . [and] [s]omething may be possible but not feasible without extra time or resources

in a certain circumstance. By that same logic, ‘not practicable’ is synonymous with

‘unfeasible’ and does not mean ‘impossible.’ ” James H.Q. Davis Tr. v. JHD Props.,

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LLC, 387 N.C. 19, 26 (2025).

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.” N.C.G.S. § 62-133.16(b)

(2025) (emphases added). In using the term “minimized” rather than “eliminated,”

the legislature left the door open for some level of continued interclass subsidization

after the MYRP period ends.

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,” N.C.G.S. § 62-133.16(d)(1)(c), the Commission

might justifiably regard the reduction as neither “reasonably capable of being

accomplished” nor “feasible,” Practicable, Black’s Law Dictionary (12th ed. 2024)

(emphases added). Similarly, the Commission might rationally deem a proposed

reduction impracticable if it would “unreasonably harm[ ]” a utility’s “customer or

class of customers.” N.C.G.S. § 62-133.16(d)(1)(a). In short, the PBR Statute makes

reasonableness and fairness the touchstones of the Commission’s “practicable”

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analysis under subsection (b).

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

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testified that 10% was the highest “practicable” subsidy reduction, so CIGFUR

contends that it was error for the Commission to conclude as much based on the

limited testimony.

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)).

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In the DEP Order, the Commission ultimately concluded that a 10% uniform

subsidy reduction was acceptable under subsection (b) because it “move[d] towards

eventual rate parity/minimization of interclass subsidization while, at the same time,

balancing the other requirements of the PBR Statute including that no class of

customer is unreasonably harmed or faces a sudden and substantial increase in rates

resulting in rate shock.” In reaching its conclusion, the Commission placed

“significant weight” on the testimony of DEP’s expert witness who proposed the 10%

reduction. According to the Commission, the witness “appropriately considered

[ ]competing priorities[ ] such as cost causation, rate shock, and gradualism.” In her

testimony, the expert acknowledged that DEP had proposed and received subsidy

reductions of 25% in some earlier rate cases. She explained, though, that a 25%

reduction in the present case would have produced unreasonable rate increases for

the residential and lighting customer classes. She also noted that DEP and DEC were

using a different COSS methodology than the one they had employed in previous

ratemaking cases.

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

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design and revenue requirement allocation approach in [DEC’s] case as was approved

and implemented” in DEP’s case. The Commission placed “significant weight” on the

testimony of DEC’s expert witness and that of the Public Staff’s expert witness, both

of whom recommended a 10% reduction.6 Like DEP’s expert witness, DEC’s expert

conceded that residential customers benefitted from interclass subsidies and that the

Commission had approved 25% subsidy reductions in other cases. Echoing DEP’s

expert witness, however, DEC’s expert argued against a 25% reduction, citing DEC’s

adoption of a new COSS methodology and the unreasonable cost increases for DEC’s

lighting customers that would result from a uniform 25% subsidy reduction.

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

6 The Public Staff’s expert recommended a uniform 10% reduction in his initial testimony but later filed supplemental testimony advocating for a different approach. CIGFUR unconvincingly argues it was prejudiced by this. In fact, the Commission gave “little to no weight” to the supplemental testimony. Accordingly, CIGFUR cannot show prejudice. See N.C.G.S. § 62-94(c) (providing that in appeals from the Commission’s decisions “due account shall be taken of the rule of prejudicial error”).

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reduction was supported by “competent, material and substantial evidence in view of

the entire record as submitted.” N.C.G.S. § 62-94(b)(5). See generally 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)). During her cross-examination, DEP’s expert

witness explained that, given the need to avoid unreasonable rate increases, 10% was

the greatest subsidy reduction practicable. Similarly, DEC’s expert witness explained

that, even before the passage of the PBR Statute, DEC had consistently sought to

“reduce interclass cross subsidization as quickly as [it] c[ould] within each case” and

that DEC had done the same in the present case. These expert opinions explained

why a 25% reduction was unwarranted and provided a legally sufficient basis for the

Commission’s decision to approve a reduction rate of 10% in each case.

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

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competent, material, and substantial evidence.

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.” N.C.G.S. § 62-79(a). The orders must include

“[f]indings and conclusions and the reasons or bases therefor upon all the material

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issues of fact, law, or discretion presented in the record.” Id. § 62-79(a)(1). In State ex

rel. Utilities Commission v. Conservation Council of North Carolina, 312 N.C. 59

(1984), we analyzed whether the Commission’s findings were adequate under

N.C.G.S. § 62-79(a)(1) to support its decision to include roughly $145 million in an

electric utility’s rate base for construction work then in progress. Conservation

Council, 312 N.C. at 61. We held that, although the Commission’s “scant findings and

conclusions barely pass[ed] muster[,] . . . [t]he Commission’s summary of the

appellant’s argument and its rejection of the same [were] sufficient to enable the

reviewing court to ascertain the controverted questions presented in the proceeding.”

Id. at 62. In our view, “[t]hat [was] all that [N.C.]G.S. § 62-79(a) require[d].” Id.

CIGFUR cites Conservation Council for the proposition that

N.C.G.S. § 62-79(a)(1) required the Commission to summarize CIGFUR’s argument

that historic practice called for a subsidy reduction rate of at least 25% in the present

cases. But CIGFUR did not squarely present that argument in the evidence that it

calls to our attention. Merely pointing out—as CIGFUR’s expert witnesses

undoubtedly did—that the Utilities had requested 25% subsidy reductions in prior

cases is not the same thing as asserting that the Commission would violate subsection

(b) of the PBR Statute if it approved lower reductions in the DEP or DEC proceeding.

We do not read Conservation Council to demand responses to implied arguments.

The Commission correctly evaluated whether the Utilities’ PBR applications

minimized interclass subsidization “to the greatest extent practicable by the

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conclusion of the MYRP period.” N.C.G.S. § 62-133.16(b). Moreover, competent,

material, and substantial evidence supported the Commission’s approval of a 10%

uniform subsidy reduction in the DEP and DEC Orders. We therefore reject the

challenges to the Commission’s decisions regarding interclass subsidization.

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.”

Id. § 62-133.16(c) (2025). In the absence of such a mechanism, electric public utilities

might be inclined to encourage greater energy consumption with a view towards

7 Unlike the Attorney General, the Public Staff apparently saw no basis for appealing

the Commission’s EV exclusion decision or any other final decision made by the Commission in the DEP and DEC Orders. On the contrary, the Public Staff filed a brief with this Court defending those orders against some of the challenges mounted by CIGFUR. It seems odd to have the Attorney General on one side attacking the validity of the orders and the Public Staff on the other side arguing in favor of their legality, especially since Chapter 62 designates the Public Staff as the consuming public’s representative in Commission proceedings. See N.C.G.S. § 62-15(d)(3) (directing the Public Staff to “[i]ntervene on behalf of the using and consuming public, in all Commission proceedings affecting the rates or service of any public utility”). 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.

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increasing their revenue. A decoupling mechanism attempts to eliminate this

incentive by “break[ing] the link between an electric public utility’s revenue and the

level of consumption of electricity on a per customer basis by its residential

customers.”8 Id. § 62-133.16(a)(2) (2025).

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. Id. § 62-133.16(c)(1)(b). The rider can be used to return excess revenue to

customers if the utility exceeded its per-customer revenue target or to collect

additional funds from customers if the utility fell short of that target. See

id. § 62-133.16(c)(1)(c)(3) (directing the Commission to establish a proceeding

“[w]ithin 60 days of the conclusion of each rate year” to “[e]valuate the decoupling

rate‑making mechanism, and refund or collect, as applicable, a corresponding amount

from residential customers through the rider established by the Commission”).

By eliminating the financial incentive that utilities would otherwise have to

8 The decoupling mechanism in the PBR Statute applies to residential customers only.

N.C.G.S. § 62-133.16(c)(2).

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encourage their customers to consume more electricity, the decoupling mechanism

advances the General Assembly’s goal of reducing energy consumption. It is subject

to an exception for EV charging, however.

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,

9 Because it applied to incremental EV revenues, the Utilities’ EV exclusion encompassed only those EVs purchased by residential customers after the decoupling mechanism took effect. It did not encompass EVs registered to residential customers before the decoupling mechanism’s implementation.

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arguing that it was not in the public interest and that the Utilities’ formula for

estimating EV sales was unacceptably imprecise. The Commission nonetheless

approved an EV exclusion for each Utility.

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.” Id. (emphasis added).

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

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EV charging,” even though “[r]esidential TOU rates are not solely dedicated to EV

charging.” We agree with the Utilities that, “[b]y explicitly including TOU rates, the

General Assembly made clear that it is not necessary that rate schedules and riders

must be exclusively for EVs.”10

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

10 Since we hold that the plain language of the PBR Statute’s EV exclusion defeats the

Attorney General’s argument, we need not go further. It is worth noting, though, that the Attorney General’s cramped reading of the statutory language seems inconsistent with the General Assembly’s goal of incentivizing electric public utilities “to encourage electric vehicle adoption.” N.C.G.S. § 62-133.16(c)(2). 11 Originally, the Utilities proposed using data from the Electric Power Research

Institute (EPRI) to determine the total number of EVs in each service territory. When the Attorney General objected to the EPRI data, the Utilities agreed to rely on DMV data instead. 12 That estimate was 180 kilowatt hours in the first year of the MYRP. This number

was calculated using data from DEP’s and DEC’s Make-Ready Credit Program. Through this program, DEP and DEC will defray part of the cost of installing the infrastructure necessary to charge EVs. The initial status report of the Make-Ready Credit Program indicated that an average monthly EV consumption is 180 kilowatt hours.

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hours yielded by step two.

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

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Attorney General maintains that “neither proposed rate schedule was a

demonstrably accurate substitute for the creation of a rate schedule (or metering)

specifically for EV charging.”

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.

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Id. (cleaned up). Once an intervenor satisfies this evidentiary standard, “the

Commission has the obligation to test the reasonableness of such expenses.”13 Id.

(cleaned up).

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,

13 “In addition, ‘[i]f there is an absence of data and information from which either the

propriety of incurring the expense or the reasonableness of the cost can readily be determined, the Commission may require the utility to prove their propriety and reasonableness by affirmative evidence.’ ” Stein, 375 N.C. at 908 (quoting State ex rel. Utils. Comm’n v. Intervenor Residents of Bent Creek/Mt. Carmel Subdivisions, 305 N.C. 62, 75 (1982)).

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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.

State ex rel. Utils. Comm’n v. Carolina Util. Customers Ass’n, 348 N.C. 452, 466 (1998)

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 the

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decoupling 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

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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

DEP did the same, but no one appealed the portion of the Commission’s order 14

approving DEP’s capital spending projects.

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MYRP. The Commission’s decision prompted both the Attorney General and CUCA

to appeal.

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. N.C.G.S. § 62-133(b); see also State ex rel. Utils. Comm’n v.

Thornburg, 325 N.C. 463, 467 n.2 (1989) (explaining the ratemaking formula in

N.C.G.S. § 62-133).

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)

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In a traditional general rate case under N.C.G.S. § 62-133, the Commission in

determining a utility’s rate base must “[a]scertain the reasonable original cost . . . of

the public utility’s property used and useful . . . in providing the service rendered to

the public within the State.” N.C.G.S. § 62-133(b)(1). The Commission calculates the

original cost of the utility’s property based on a historical “test period,” which

“consist[s] of 12 months’ historical operating experience prior to the date the [new]

rates are proposed to become effective.”15 N.C.G.S. § 62-133(c); see generally State ex

rel. Utils. Comm’n v. Carolina Util. Customers Ass’n, Inc., 314 N.C. 171, 185 (1985)

(explaining that under N.C.G.S. § 62-133 “the utility’s rates are based upon a historic

twelve[-]month test period”).

The PBR Statute mandates the use of data from the twelve-month test period

in PBR ratemaking. N.C.G.S. § 62-133.16(c)(1)(a). Unlike N.C.G.S. § 62-133, the PBR

Statute also allows an electric public utility to recover through its base rates the

“costs associated with 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” of the MYRP. Id. Additionally, “changes in base

rates in the second and third rate years of the MYRP” are permissible “based on

projected incremental Commission-authorized capital investments that will be used

15 The inputs to the utility’s revenue requirement may be modified in light of “actual

changes in costs, revenues or the cost of the . . . utility’s property . . . based upon circumstances and events occurring [after the test period ends and] up to the time the [rate- making] hearing is closed.” N.C.G.S. § 62-133(c).

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and useful during the rate year.” Id.

In its appeal to this Court, CUCA objects to the Commission’s approval of six

capital spending projects in DEC’s MYRP:

(1) 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;

(2) 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;

(3) the Transmission Cathodic Protection Program for identifying and

remedying corrosion on DEC’s transmission towers;

(4) the Targeted Wood Pole Upgrade Program for identifying wood

transmission poles nearing the end of their lifespans and replacing them

with steel poles;

(5) 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

(6) the Transmission Hazard Tree Removal Program for identifying and

cutting down dying or structurally unsound trees growing outside DEC’s

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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 Id. According to CUCA,

“[i]f there were a theme among these proposed programs, it would be that they are

categories of spending that DEC’s witnesses expected [DEC] might incur although

DEC does not know how, when, or where.” CUCA asserts that the programs are

“exactly the opposite of ‘known and measurable’ and ‘discrete and identifiable’ capital

spending projects” since each of them “involved continuous proposed spending on as-

yet-undetermined activities in as-yet-undetermined locations.”

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

16 CUCA also states that the challenged programs failed the standard for inclusion in

DEC’s second-year and third-year rate bases—that they be “projected incremental . . . capital investments that will be used and useful during the rate year.” N.C.G.S. § 62-133.16(c)(1)(a). Yet CUCA does not explain why the programs fall short of this standard. CUCA has therefore abandoned the argument under Rule 28(b)(6) of the North Carolina Rules of Appellate Procedure, which provides that “[i]ssues not presented in a party’s brief, or in support of which no reason or argument is stated, will be taken as abandoned.”

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[MYRP].”

The Commission construes the phrase “known and measurable” differently,

and not just in the context of electric public utilities. The phrase also appears in

N.C.G.S. § 62-133.1B. That statute establishes multiyear ratemaking for water and

sewer utilities and allows the Commission to “authorize[ ] annual rate changes for a

three-year period based on reasonably known and measurable capital investments.”

N.C.G.S. § 62-133.1B(a) (2025). In its order adopting Commission Rule R1-17A, which

implements N.C.G.S. § 62-133.1B, the Commission “acknowledge[d] that at the time

the [MYRP] is proposed by the utility in its general rate case application there will

not be actual cost data available pertaining to the ‘reasonably known and measurable

capital investments’ for the Public Staff to review and analyze.” Order Adopting

Commission Rule R1-17A, Docket No. W-100, Sub 63, at 11 (Jan. 7, 2022). The

Commission reasoned that a utility could still satisfy the “known and measurable”

standard by “provid[ing] to the Public Staff and the Commission, among other things,

‘a detailed description, including the reason for and scope of each proposed capital

investment project.’ ” Id. (quoting 4 N.C. Admin. Code 11.R1-17A (2024)).

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

17 The PBR Statute directs the Commission to adopt rules that include, among other

things, “[t]he specific procedures and requirements that an electric public utility shall meet when requesting approval of a PBR application.” N.C.G.S. § 62-133.16(j)(1) (2025).

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[p]rojected costs, including [allowance for funds used during construction], if applicable, and related workpapers associated with the discrete and identifiable capital spending projects to be placed into service for each Rate Year of the MYRP, including: i. The reason for each capital spending project; ii. The scope of each capital spending project; iii. The timing of each capital spending project, including projected in-service month and year for each capital spending project; iv. The depreciation life of each capital spending project by year; v. Changes expected in the depreciable life of each capital spending project for two years after the conclusion of the MYRP; and vi. 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.

4 N.C. Admin. Code 11.R1-17B(d)(2)(j) (2024) (amended 2025).

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 N.C.G.S. § 62-133.16(c)(1)(a) to

mandate the extreme specificity demanded by CUCA. CUCA’s overly strict approach

would require utilities to provide an unreasonable—if not impossible—level of detail

for projected capital investments. In contrast, the Commission’s interpretation of

“known and measurable” recognizes that the phrase concerns future projects. Viewed

in this light, the information requirements of Rule R1-17B(d) seem reasonably

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designed to furnish the Commission with the information it needs to analyze whether

the cost estimates for a proposed MYRP are “associated with a known and measurable

set of capital investments . . . associated with a set of discrete and identifiable capital

spending projects.” N.C.G.S. § 62-133.16(c)(1)(a).

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

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cost and schedule estimates provided, further confirming the known and measurable

nature of these MYRP [p]rojects.”

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

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removal in the [MYRP]—and thereby to capitalize and earn a return on this recurring

expense—is legally erroneous[ ] . . . and . . . should be reversed.”

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

subsection 62-133.16(c)(1)(a) that projected capital investments involve property that

“will be used and useful during the rate year.” N.C.G.S. § 62-133.16(c)(1)(a). He

asserts that “[t]here was no evidence offered that would allow the Commission to

conclude that . . . expenses [for the hazardous tree removal programs] were for

property used and useful.” According to the Attorney General, a utility’s facilities and

equipment are “used and useful” if they have been “completed, placed into service

during the time for which recovery is sought, and [are] currently used to provide

electric service to customers.” The hazardous tree removal programs were mere

“[m]aintenance work” that did not “increase [DEC’s] existing property’s value or

substantially prolong its useful life.” Hence, they may not be classified as capital

spending projects under N.C.G.S. § 62-133.16(c)(1)(a).18

18 The Attorney General further claims that the Commission arbitrarily and capriciously deviated from its past practice by approving the inclusion of the hazardous tree removal programs among the capital projects in DEC’s MYRP. He notes that the Commission categorized the costs of DEC’s hazardous tree removal as operating expenses in two recent rate cases. The Attorney General cannot show that the Commission acted arbitrarily and capriciously because—as explained in this section of our opinion—the Commission had sound reasons for treating the programs as capital spending projects and competent, material, and substantial evidence supported its decision. See generally State ex rel. Comm’r of Ins. v. N.C.

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We disagree with the Attorney General and CUCA. “The burden of showing

the impropriety of rates established by the Commission lies with the party alleging

such error. The rate order of the Commission will be affirmed if upon consideration

of the whole record we find that the Commission’s decision is not affected by error of

law and the facts found by the Commission are supported by competent, material and

substantial evidence . . . .” State ex rel. Utils. Comm’n v. Duke Power Co., 305 N.C. 1,

10 (1982) (cleaned up).

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.

Rate Bureau, 300 N.C. 381, 420 (1980) (“Agency decisions have been found arbitrary and capricious . . . when . . . they fail to indicate any course of reasoning and the exercise of judgment . . . .” (cleaned up)), overruled on other grounds, In re Redmond, 369 N.C. 490 (2017). Moreover, DEC denies that the Commission has a uniform practice of classifying the costs of hazardous tree removal programs as operating expenses. It points to evidence in the record indicating that DEC has been capitalizing hazardous tree removal costs for at least a decade.

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CUCA’s invocation of FERC’s accounting rules also falls flat. In deciding

whether to approve a capital spending project in a utility’s MYRP, the Commission

must be guided by the text of the PBR Statute, which makes no reference to FERC.

It may well be that some project costs that must be classified as maintenance

expenses under FERC’s accounting rules nonetheless qualify as “capital investments

. . . associated with a set of discrete and identifiable capital spending projects to be

placed in service during the first rate year” of an MYRP. N.C.G.S. § 62-133.16(c)(1)(a).

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

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threat to its distribution system, for an average of 33,353 trees per year.” The

combined testimony of Mr. Speros and Mr. Williamson provides more than a scintilla

of competent and material evidence supporting the Commission’s findings.

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 N.C.G.S. § 62-133.2.

The DEC Order imposes the same restriction on DEC. CIGFUR appeals both

decisions.

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.

N.C.G.S. § 62-133.2(a) (2025).

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.

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Id. § 62-133.2(a1)(1), (3)–(4) (2025). For an expense to be recoverable through the fuel

rider, it must fit within the statutory definition. See id. § 62-133.2(d) (2025).

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.

N.C.G.S. § 62-133.2(d). Subsection 62-133.2(c) lists information that the utility must

submit to the Commission for purposes of the hearing. Id. § 62-133.2(c) (2025). In

making its decision on the fuel rider, the Commission must consider that information

along with “all other competent evidence that may assist the Commission in reaching

its decision.” Id. § 62-133.2(d). The Commission then selects an adjustment rate

based on “the experienced over-recovery or under-recovery of reasonable costs of fuel

and fuel-related costs” that the utility “prudently incurred.” Id. (“The Commission

shall allow only that portion, if any, of a requested cost of fuel and fuel-related costs

adjustment that is based on adjusted and reasonable cost of fuel and fuel-related costs

prudently incurred under efficient management and economic operations.”). The

utility bears the burden of proving that the cost of fuel and fuel-related costs incurred

were reasonable and prudent. Id.

Although it describes how the Commission should go about determining the

cost adjustment for a fuel rider, section 62-133.2 does not directly address how the

Commission should allocate the cost adjustment among the utility’s customer classes.

Thus, it is left to the Commission to approve a cost allocation methodology.

Subsection (f) of N.C.G.S. § 62-133.2 does specify that nothing in the statute

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“relieve[s] the Commission from its duty to consider the reasonableness of the cost of

fuel and fuel-related costs in a general rate case and to set rates reflecting reasonable

cost of fuel and fuel-related costs pursuant to [N.C.G.S. §] 62-133.” Id. § 62-133.2(f)

(2025). Relying on this provision, the Commission has made it a practice in general

rate cases to adopt the fuel cost allocation methodology that will apply in a utility’s

subsequent fuel rider proceedings. See 4 N.C. Admin. Code 11.R8-55(d)(1) (2024)

(“Cost of fuel and fuel-related costs [in a fuel rider proceeding] will be preliminarily

established utilizing the methods and procedures approved in the utility’s last

general rate case . . . .”).

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

19 Until 2008, subsection 62-133.2(a) required the fuel rider’s increment or decrement

to be “uniform” across the electric utility’s customer classes. N.C.G.S. § 62-133.2(a) (2005). By an act passed in 2007, the General Assembly eliminated the uniformity requirement, thereby affording the Commission greater flexibility in selecting a fuel cost allocation methodology. An Act to: (1) Promote the Development of Renewable Energy and Energy Efficiency in the State Through Implementation of a Renewable Energy and Energy Efficiency Portfolio Standard (REPS), (2) Allow Recovery of Certain Nonfuel Utility Costs Through the Fuel Charge Adjustment Procedure, (3) Provide for Ongoing Review of Construction Costs and for Recovery of Costs in Rates in a General Rate Case, (4) Adjust the Public Utility and Electric Membership Corporation Regulatory Fees, (5) Provide for the Phaseout of the Tax on the Sale of Energy to North Carolina Farmers and Manufacturers, and (6) Allow a Tax Credit to Contributors to 501(c)(3) Organizations for Renewable Energy Property, S.L. 2007-397, § 5, 2007 N.C. Sess. Laws 1184, 1194–97.

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determines what percentage of its total revenue comes from a customer class,

calculates the identical percentage of its increase in fuel costs, and then assigns that

portion to the customer class. For example, if the utility needs an additional $300

million to cover fuel costs for the previous year and the utility’s residential customers

contributed 40% of the utility’s actual revenue for that year, the utility will recover

$120 million—or 40% of $300 million—of the fuel costs from its residential customers

through the fuel rider.

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

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methodology by DEP and DEC in 2008 to assist industrial customers financially

during the Great Recession; however, he testified that the methodology had outlived

its usefulness to the detriment of the Utilities’ other customer classes.

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, subsection (b) of the PBR Statute allows the Commission to approve

PBR applications only if they “allocate[ ] the electric public utility’s total revenue

requirement among customer classes based upon the cost causation principle.”

N.C.G.S. § 62-133.16(b).

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 subsection (g) of the

PBR Statute exempts fuel riders from the cost causation principle. See id. § 62-

133.16(g) (2025) (clarifying that ratemaking mechanisms in a PBR plan “operate

independently . . . from riders or other cost recovery mechanisms otherwise allowed

by law, unless otherwise incorporated into [the] plan”).

The Commission agreed to cease using the equal percentage methodology for

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reasons set out succinctly in the DEP Order:

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 subsection (f) of N.C.G.S. § 62-133.2

granted it independent authority to approve an allocation methodology consistent

with that principle:

[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 under N.C.G.S. § 62-133.2(f), the statute that governs the

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fuel 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.

20 In the DEC Order, the Commission also considered and rejected CIGFUR’s argument that, in discontinuing use of the equal percentage methodology, the Commission was engaging in impermissible single-issue ratemaking.

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The Commission did not issue any direction in the DEP Order regarding

voltage differentiation. In contrast, the Commission approved the parties’ voltage

differentiation stipulation in the DEC Order.

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 [subsection (b) of the PBR Statute] required the

Commission to adhere to the cost[ ]causation principle.” CIGFUR urges us to “vacate

the Commission’s order and allow it to apply the correct legal standard.”

“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

21 In its principal brief, CIGFUR mistakenly characterizes voltage differentiation as

an alternative method of fuel-cost allocation. In fact, it is merely a mechanism operating within a larger allocation methodology.

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apply the cost causation principle to fuel riders. As quoted above, the DEP Order

indicates that “the Commission gave substantial weight to the testimony of the Public

Staff regarding the [PBR Statute’s] cost causation principle . . . , as well as their

demonstration of the distortion that can be created by equal percentage fuel

adjustments.” At first glance, this statement might seem to indicate that the

Commission was significantly influenced by Mr. Lucas’s purported misstatement of

the law. Yet Mr. Lucas’s testimony on the cost causation principle went beyond mere

legal considerations. Mr. Lucas also testified about the relative fairness and

unfairness of the equal percentage methodology and the cost causation principle. In

particular, he described the cost causation principle as more equitable because it ties

fuel rates more closely to consumption, whereas the equal percentage methodology

“benefit[s] some customer classes at the expense of others.”

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

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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 N.C.G.S. § 62-133.2(f). It follows from what we have said so far that we

see no merit in CIGFUR’s contention that the Commission acted under a

misapprehension of law.

CIGFUR further argues that the Commission’s abandonment of the equal

percentage methodology was arbitrary and capricious because it went against the

22 Notably, Mr. Lucas clarified in his testimony during the DEC evidentiary hearing

that he had misspoken during the DEP evidentiary hearing concerning the PBR Statute.

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evidence before the Commission. CIGFUR claims to have presented “unrebutted

evidence” demonstrating that the Commission’s methodological switch would

increase—not decrease—interclass subsidies. CIGFUR asks us to vacate the orders

because the Commission, when faced with evidence contradicting its conclusions,

ignored that evidence and “failed to explain why its decision[s] w[ere] correct.”

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.

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CIGFUR’s expert witness in the DEC case was similarly concerned about the

“capital costs” portion of the fuel rider, as well as the ongoing subsidization of

residential customers by other customer classes. He went further than CIGFUR’s

witness in the DEP case by predicting that “recovery of capital costs through the fuel

[rider] will likely increase in the future” due to measures adopted under the state’s

Carbon Plan. Categorizing these capital costs as capacity costs, 23 he explained that

they do not vary based on energy consumption:

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

23 Capacity costs are those incurred by an electric public utility in ensuring that it has

access to enough energy to meet periods of peak demand. For instance, by making a one-time capacity payment to an energy generator, the utility buys the right to reserve a portion of the generator’s total energy output at some point in time. In this way, capacity costs are often fixed costs for the utility, whereas energy purchases vary with how much power the utility draws.

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methodology immediately would “exacerbate the worsening affordability challenges

affecting industrial customers.” He suggested that the Commission should “provide

rate mitigation for industrial customers” by “continuing the current cost allocation

methodology for fuel and fuel-related costs.”

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.

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

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during periods of peak demand. Hence, DEP’s cost to procure power from renewable

generators varied depending on customers’ consumption. Mr. Lucas added:

[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

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capriciously—ignores the evidentiary record.24

The Commission’s decision to cease using the equal percentage methodology in

fuel rider proceedings conducted pursuant to N.C.G.S. § 62-133.2 “is not affected by

error of law and the facts found by the Commission are supported by competent,

material and substantial evidence.” Duke Power Co., 305 N.C. at 10. We therefore

reject CIGFUR’s challenges to the Commission’s decision.

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

24 Similarly, CIGFUR’s argument that the Commission failed to adequately explain

its decision lacks merit. CIGFUR claims that the Commission’s failure to respond to its argument concerning the effect that the voltage differentiated methodology would have on interclass subsidization renders its decision arbitrary and capricious. Yet it is not necessary for the Commission to “comment upon every single fact or item of evidence presented by the parties” in order to comply with N.C.G.S. § 62-79(a). VEPCO, 381 N.C. 499, 520 (2022) (cleaned up). “[T]he Commission’s summary of the appellant’s argument and its rejection of the same is sufficient” if it “enable[s] the reviewing court to ascertain the controverted questions presented in the proceeding.” Id. at 521 (cleaned up). Here, the Commission summarized CIGFUR’s argument and witness-testimony in both cases before providing its conclusion. The mere fact it did not recite one point advanced by CIGFUR does not signal that its decision was either arbitrary or capricious; it suggests that the Commission did not find the point compelling. The Commission said as much in the DEC Order: “The Commission has given due consideration to the arguments proffered by CIGFUR in its post-hearing brief and finds them to be without merit.”

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customer demand more efficiently than it could on its own. During periods of peak

demand, DEC can draw on DEP’s excess power instead of building additional

generation facilities, and DEP can draw on DEC’s excess power during its own peak

demand periods.

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

25 See An Act to Authorize the Utilities Commission to (I) Take All Reasonable Steps

to Achieve a Seventy Percent Reduction in Emissions of Carbon Dioxide from Electric Public Utilities from 2005 Levels by the Year 2030 and Carbon Neutrality by the Year 2050, (II) Authorize Performance-Based Regulation of Electric Public Utilities, (III) Proceed with Rulemaking on Securitization of Certain Costs and Other Matters, and (IV) Allow Potential Modification of Certain Existing Power Purchase Agreements with Eligible Small Power Producers, S.L. 2021-165, § 1, 2021 N.C. Sess. Laws 738, 739–40.

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extensive new transmission infrastructure to link its new renewable facilities to its

own network and that of DEC. Id.

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

26 The parties to the TCA Stipulation agreed to calculate the precise amount of the

adjustment by multiplying the net power transfers from DEP to DEC under the JDA in 2022 by DEP’s non-firm transmission rate in Duke Energy’s Joint Open Access Transmission Tariff (Joint OATT). Since 1996, FERC has required electric public utilities owning interstate transmission infrastructure to file “open access non-discriminatory transmission tariffs.” See Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities, 61 Fed. Reg. 21540, 21541 (May 10, 1996) (to be codified at 18

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The revenue adjustment was to become effective in October 2023 and continue until

DEP and DEC either merged or implemented new rates following their next general

rate cases.

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 N.C.G.S. § 62-133 and the

PBR Statute to approve the TCA Stipulation. According to CIGFUR, the TCA

Stipulation essentially compels DEC’s customers to subsidize part of DEP’s revenue

requirement based on the Commission’s belief that the JDA is unfair to DEP’s

customers. CIGFUR maintains that neither N.C.G.S. § 62-133 nor the PBR Statute

authorizes the Commission, “in separate proceedings, to distort two separate utilities’

C.F.R. pts. 35, 385). Those tariffs set the rates and terms under which electric utilities transmit energy wholesale, both the energy the utility itself produces and that produced by third parties. See id. Duke’s Joint OATT sets the open access transmission rates for both DEP and DEC. See Joint Open Access Transmission Tariff of Duke Energy Carolinas, LLC, Duke Energy Florida, LLC, and Duke Energy Progress, LLC, https://www.ferc.duke- energy.com/Tariffs/Joint_OATT.pdf.

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revenue requirements to achieve a policy outcome.” Despite not having raised the

issue in its DEP appeal, CIGFUR asks this Court to vacate the Commission’s

approval of the TCA Stipulation in both the DEP Order and the DEC Order.

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[.]”

N.C.G.S. § 62‑94(a) (2025); see also N.C. R. App. P. 1(b) (declaring that the North

Carolina Rules of Appellate Procedure “govern procedure . . . in direct appeals from

administrative tribunals to the appellate division”).

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

N.C. R. App. P. 10(a)(1). The purpose of Rule 10(a)(1) is “to require a party to call the

[trial] court’s attention to a matter upon which he or she wants a ruling before he or

27 Although the first sentence in Rule 10(a)(1) uses the term “trial court,” and the

Commission is not a court, the rule’s third sentence employs the broader term “trial tribunal.” N.C. R. App. P. 10(a)(1). The Rules of Appellate Procedure explicitly define “trial tribunal” to encompass “any administrative agencies, boards, or commissions from which appeals lie directly to the appellate division.” N.C. R. App. P. 1(d). Thus, the preservation requirements of Rule 10(a)(1) apply to direct appeals from the Commission to this Court.

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she can assign error to the matter on appeal.” State v. Canady, 330 N.C. 398, 401

(1991). Without this rule, “a party could allow evidence to be introduced or other

things to happen during a trial as a matter of trial strategy and then assign error to

them if the strategy does not work.” Id. at 401–02.

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.

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CIGFUR’s counsel did not argue that the TCA Stipulation was unlawful, much less

ask the Commission to do anything about it. More precisely, CIGFUR’s counsel did

not present the Commission with “a timely request, objection, or motion, stating the

specific grounds for the ruling” CIGFUR wanted the Commission to make. N.C. R.

App. P. 10(a)(1).

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).

28 CIGFUR further claims that the Utilities waived their waiver argument by failing

to cite any authority for it. In support of its position, CIGFUR relies on a single nonbinding case in which a federal circuit court said that “[a] waiver argument . . . can be waived by the party it would help.” United States v. Morgan, 384 F.3d 439, 443 (7th Cir. 2004). To the best of our knowledge, this Court has never adopted that principle with respect to Rule 10(a)(1), and we decline to do so here.

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In its principal brief to this Court, CIGFUR also contends that “the way the

Commission approved the [TCA Stipulation] denied [DEC’s] customers, like

CIGFUR[’s] . . . members, due process.” After the Commission approved the TCA

Stipulation in the DEP proceeding, CIGFUR insists, it had no choice but to do the

same in the DEC case: “The process that the Commission afforded to [DEC’s]

customers was not fair[ ] because the hearing’s outcome was predetermined.” To the

extent that the outcome in the DEC case was predetermined, CIGFUR asserts that

it violated procedural due process, which “requires the opportunity to be heard at a

fair hearing without a predetermined outcome.”

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

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constitutional challenges in administrative proceedings because administrative

agencies typically “ha[ve] no authority to decide constitutional questions.” Id. at 496.

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.

N.C.G.S. § 62-90(a) (2025) (emphasis added).

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 . . . .” N.C.G.S. § 62-94(c) (2025).

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

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Stipulation.29 CIGFUR’s notice of appeal in the DEC proceeding alleges that the

Commission exceeded its ratemaking authority under N.C.G.S. § 62-133 and the PBR

Statute, but it nowhere asserts that the Commission’s action constituted a denial of

due process. Section 62-94 therefore bars CIGFUR from pursuing its due process

claim on appeal.

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.

N.C.G.S. § 62-133(b)(4).

29 The same is true of the notice of appeal filed by Haywood EMC in the DEP case.

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A utility’s ROE “is one of the components used in determining a company’s

overall rate of return.” State ex rel. Utils. Comm’n v. Cooper (Cooper II), 367 N.C. 430,

432 (2014). “The ROE represents the return that a utility is allowed to earn on its

capital investment by charging rates to its customers. As a result, a higher ROE

impacts profits for shareholders and costs to consumers.” Id.

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

30 Dr. Morin initially recommended an ROE of 10.2% but later increased his recommendation due to rising interest rates. 31 “[T]he [l]egislature intended for the Commission to fix rates as low as may be

reasonably consistent with the requirements of the Due Process Clause of the Fourteenth Amendment to the Constitution of the United States.” State ex rel. Utils. Comm’n v. Duke Power Co., 285 N.C. 377, 388 (1974).

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and proposed different ROEs to the Commission. The Public Staff’s expert witness

proposed an ROE of 9.45%, while CUCA’s expert recommended 9.25%. Two other

intervenors—the United States Government and the North Carolina Justice Center

(NCJC)—recommended ROEs of 9.3% and 6.0%, respectively.32 CUCA, the Public

Staff, and the federal government argued that, if the Commission approved DEP’s

PBR application and allowed it to increase rates incrementally under the MYRP, the

ROE should be even lower; CUCA proposed 9.0%, and the Public Staff suggested

9.25%. The intervenors’ expert witnesses also opposed allowing DEP to recover

estimated flotation costs through its ROE.

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

32 CIGFUR and another intervenor, the Commercial Group, also recommended ROEs.

The Commission placed little weight on these recommendations because, unlike the other intervenors, neither CIGFUR nor the Commercial Group conducted its own ROE analysis.

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by the “investor interest against confiscation” and the need to protect DEP’s access to

capital and on the high end by the “consumer interest against excessive and

unreasonable charges for service.” Relying on the results of the parties’ respective

ROE analyses,33 the majority determined the zone of reasonableness to be 9.75% to

10%. In settling on this range, the majority concluded that (1) DEP should not be

permitted to recover estimated flotation costs through the ROE and (2) the

Commission’s approval of DEP’s MYRP did not justify a downward adjustment.

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

33 The Commission discounted NCJC’s recommended ROE of 6.0% as an outlier.

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“some [customers] will struggle to pay the increased rates,” an ROE of 9.8% did not

pose a serious risk of “undue hardship” to consumers, partly because DEP was

simultaneously developing programs to help its low-income residential customers pay

their bills.

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

34 A fourth commission member agreed with the majority’s ROE determination but

dissented from the decision to approve DEP’s proposed EV exclusion from the decoupling mechanism.

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the long term by impairing DEP’s ability to compete for capital on the most

reasonable terms available.

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

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recommended 6.00% in the DEP case, NCJC’s expert testified that 6.15% would be

appropriate for DEC. In his DEC testimony, the Public Staff’s expert explained that

he recommended a higher ROE for DEC than he had for DEP, not because he saw

any difference in risk between the Utilities, but because of changing conditions in

capital markets. The intervenors’ experts again urged the Commission to exclude

estimated flotation costs from the ROE and apply a downward adjustment if it

approved the MYRP.

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

35 Specifically, Dr. Morin observed that the yield on the thirty-year Treasury bond was

2.16% when the Commission approved a 9.6% ROE for DEP in 2021; however, at the time of Dr. Morin’s rebuttal testimony analysis in the DEC case, the yield on thirty-year treasury bond had risen to 4.02%.

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excluded flotation costs and did not apply a downward adjustment for DEC’s MYRP.

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

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customer interest analysis in the DEC case, arguing that the Commission failed to

consider adequately the effects of DEC’s ROE increase on customers.

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

36 The proxy group is a collection of utilities with comparable properties to the subject

utility that provides the inputs for the economic models used to calculate an ROE.

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difference in allowed ROE.”

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

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“inconsistent with the current capital market environment and bias[ed] downward

the range of reasonableness.”37 Describing ROE as a “critical component of

creditworthiness,” the dissenters worried that an ROE of less than 10% would impair

DEP’s ability to compete for capital “on the most reasonable terms available.” They

regarded this point as important because, inter alia, “DEP faces substantial capital

needs over the next several years to comply with environmental requirements, to

replace and upgrade aging infrastructure, to construct or acquire new generation

resources, to upgrade the transmission system, and to satisfy its debt maturities.”

The dissenters argued that higher borrowing costs for DEP would eventually lead to

increased costs for its customers.

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

37 The dissenting Commissioners were especially critical of the expert witnesses’ Discounted Cash Flow models. Such models “estimate[ ] the ROE as the sum of expected dividend yield and expected rate of dividend growth.” Cooper II, 367 N.C. at 434.

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in their DEP dissent.

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

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clear when one considers the mountain of evidence—much of it highly technical—

that the Commission examined and weighed before it approved an ROE of 10.1% for

DEC. This evidence included an array of mathematical models produced by expert

witnesses using various methodologies.38 Despite relying on many of the same

methodologies, the experts recommended different ROEs for reasons the Commission

discussed at length in the more than forty single-spaced pages that the DEC Order

dedicates to the Commission’s ROE decision. At the end of the day, the Commission

had to set DEC’s ROE rate based on voluminous, complex, and sometimes

contradictory evidence. In performing this task, it had no choice but to exercise

discretion.

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

38 As Dr. Morin testified, the experts used multiple methodologies because “[n]o one

single method provides the necessary level of precision for determining a fair return.” In addition to the Discounted Cash Flow methodology, multiple experts also employed the Capital Asset Pricing Model and Risk Premium methodologies. As Dr. Morin informed the Commission, “all of [these methodologies] are market-based methodologies designed to estimate the return required by investors on the common equity capital committed to DEC.”

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range of what he considered reasonable. The Attorney General describes this

testimony as Dr. Morin “recalibrat[ing] his recommendation,” essentially adopting a

10.0% ROE when one removes flotation costs. Because no other expert recommended

an ROE greater than 10.0%, the Attorney General claims that the Commission’s

award of 10.1% was not supported by any expert recommendation.

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%),

39 CUCA also challenges as arbitrary the use of a particular ROE methodology by the

Commission in its calculation of the reasonable range of ROE estimates. Specifically, CUCA takes issue with how the Commission averaged various expert witnesses’ proposed ROEs in calculating what it determined to be the zone of reasonableness. We are unconvinced and, in any event, CUCA has not shown that it was prejudiced by the Commission’s methodology. See N.C.G.S. § 62-94(c) (“[D]ue account shall be taken of the rule of prejudicial error.”).

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explaining that

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

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belong to us and transform this institution into something other than an appellate

court.

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 N.C.G.S. § 62-133 to require the Commission

to “take customer interests into account when making an ROE determination.”

Cooper I, 366 N.C. at 495. To satisfy the statute, “the Commission must make findings

of fact regarding the impact of changing economic conditions on customers when

determining the proper ROE for a public utility.” Id. In so doing, the Commission

must “treat consumer interests fairly—not indirectly or as mere afterthoughts.” State

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ex rel. Utils. Comm’n v. Cooper, 367 N.C. 741, 745 (2015) (cleaned up).

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

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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

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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

40 In the Affordability Stipulation, DEP and DEC agreed to make $16 million in shareholder financial contributions to programs supporting their low-income customers. DEP and DEC also agreed to report their monthly residential payments ratio, which ostensibly indicates how many customers are unable to pay their power bills.

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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.”

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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

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“competent, material and substantial evidence.” Duke Power, 305 N.C. at 10. We thus

lack any legal basis on which to overturn that determination.

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.

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Earls, J., concurring in part and dissenting in part

Justice EARLS 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. N.C.G.S. § 62-133.16(a)(5), (c)

(2025). Each such rate order is now of even greater consequence: It represents the

Commission’s one-time decision on what North Carolinians will pay for essential

services for multiple years, and the Commission can effectively pre-approve rate

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hikes for all customers. This Court will typically have only one chance to review such

orders on direct appeal. Id. §§ 7A-29(b), 62-90 (2025). Because the stakes are higher

and chances for review fewer, this Court must exercise utmost diligence when

determining the Commission’s compliance with its legal obligations in these

proceedings.

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

1 Those nine challenges are, by my count: (1) whether the Commission’s decision to

award Duke Energy Carolinas a 10.1% return on common equity was arbitrary, capricious, unlawful, or unsupported by substantial evidence; (2) whether the Commission adequately accounted for consumer interests in the Duke Energy Carolinas return on common equity award; (3) whether the Transmission Cost Allocation stipulation in the Duke Energy Carolinas order was permissible; (4) whether the Commission erred by admitting supplemental testimony by the Public Staff; (5) whether the Commission erred by adopting a 10% interclass subsidy reduction; (6) whether the Commission erred by abandoning the equal percentage method of allocating increased fuel costs in fuel rider proceedings; (7) whether the Commission erred by excluding incremental electric vehicle revenues from the residential decoupling mechanism; (8) whether the Commission erred by treating hazardous tree removal as a capital expense; and (9) whether the Commission erred by treating transmission and distribution projects as eligible for rate base treatment.

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fails to follow the law’s mandate that attention be given to the consumers’ interests.

The record is replete with evidence that rising energy costs are hurting North

Carolina consumers. Yet Duke Energy seeks to increase rates even while it posts

record profits.2 Here, even though Duke Energy Carolinas and Duke Energy Progress

have the same capital risk profile, have previously been awarded the same rates of

return, and soon may even be the same company, the Commission authorized Duke

Energy Carolinas to give shareholders a thirty basis point higher rate of return on

common equity than that awarded to Duke Energy Progress.3

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.

2 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). 3 A “basis point” is “[o]ne-hundredth of 1%; .01%.” Basis point, Black’s Law Dictionary

(12th ed. 2024).

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It is true that the Utilities Commission’s composition has recently changed, in

part because of recent acts by the legislature that are still undergoing judicial review.

See Stein v. Hall, No. COA 25-745, slip op. at 19–24 (N.C. App. Jan. 7, 2026), appeal

and filed and disc. rev. pending, No. 53P26. But this change in composition is not a

valid or rational basis for awarding a higher return on common equity to Duke Energy

Carolinas. Namely, the Commission does not have discretion to randomly select a

rate of return on common equity. The Commission is required to award a rate that

poses the lowest possible cost to the using public for quality service while being

sufficient to maintain shareholder investment. The Commission’s failure to award

the lowest reasonable return, or to find facts and state reasons consistent with

Chapter 62 for deviating from that baseline, is legal error.

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

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A. First Principles

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. N.C.G.S. §§ 62-1, -2(a)–(b) (2025). In

this way, regulation by the Commission substitutes for traditional market

competition to control costs. See Frank W. Hanft, Control of Electric Rates in North

Carolina, 12 N.C. L. Rev. 289, 290 (1934). The Commission is trusted to carry out

North Carolina’s public policy to fairly regulate public utilities and “promote

adequate, reliable and economical utility service to all of the citizens and residents of

the State.” N.C.G.S. § 62-2(a)(1), (3).

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. Id. § 62-

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133(b)(4) (2023); State ex rel. Utils. Comm’n v. Thornburg, 316 N.C. 238, 242 (1986).

Above all, the “primary purpose [of this regulatory scheme] is not to guarantee to the

stockholders of a public utility constant growth in the value of and in the dividend

yield from their investment.” State ex rel. Utils. Comm’n v. Gen. Tel. Co. of the Se.,

285 N.C. 671, 680 (1974) (emphasis added). Rather, the statutes exist “to assure the

public of adequate service at a reasonable charge.” Id.

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. N.C.G.S. § 62-133(b). Specifically, that figure represents what “a

utility [must] earn to induce investors to hold and to continue to buy common stock.”

Charles F. Phillips, Jr., The Regulation of Public Utilities 394 (3d ed. 1993)

[hereinafter Phillips, Regulation of Public Utilities]. This is not a question of investor

expectations generally. Rather, it captures the expectations of those investors seeking

the type of “minimal risk of loss of principal” attendant to investing in a fully

regulated public utility. Gen. Tel., 281 N.C. at 338. Return on common equity in this

context is synonymous with the cost of equity capital for a public utility specifically.

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

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rate of return for similar utilities: the “return[ ] on investment[ ] in other enterprises

having corresponding risks.” Fed. Power Comm’n v. Hope Nat. Gas Co., 320 U.S. 591,

603 (1944). Regulators must look to comparable returns, or those “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.” Bluefield Water Works & Improvement Co. v. Pub. Serv. Comm’n, 262

U.S. 679, 692 (1923). Because the utility has “no constitutional right to profits such

as are realized or anticipated in highly profitable enterprises or speculative

ventures,” id. at 692–93, the high-water mark for a public utility’s return on common

equity is that which is “commensurate with returns on investments in other

enterprises of corresponding risk.” Phillips, Regulation of Public Utilities 381. Simply

put, because the rate of return on common equity for one utility is closely tied to the

returns being awarded to comparable entities, regulators must take account of those

comparable returns.

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.”).

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Indeed here, a single basis point alone is worth millions of dollars. For a typical

residential customer receiving 1000-kilowatt hours of service who had a $123 energy

bill, roughly $24 of that amount would go to paying the return on common equity––

i.e., shareholders––according to one estimate. As Duke Energy’s own expert witness

agreed, shifts in the rate of return on common equity cause “real-world impacts on

people’s bills.” If the rate of return on common equity is set higher than the cost of

capital, the Commission will, in effect, unlawfully transfer wealth from ordinary

consumers to Duke Energy’s shareholders—essentially exploiting captured

customers for shareholders’ gain. See Phillips, Regulation of Public Utilities 375, 387–

88.

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)).

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In addition to adhering to this baseline, the Commission must also directly

consider consumer interests. It is required to evaluate “the impact of changing

economic conditions on customers” when making a return on equity determination.

Cooper I, 366 N.C. at 495.

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 N.C.G.S. §§ 7A-29(b), 62-90

(2023). Although the Commission has authority and expertise to determine which

rates are reasonable, CUCA I, 348 N.C. at 462, this Court is obligated to critically

review “the evidentiary underpinning for the Commission’s findings and whether the

findings support its conclusion regarding this figure.” State ex rel. Utils. Comm’n v.

Pub. Staff (Public Staff III), 331 N.C. 215, 223 (1992). We must set aside an order

fixing a return on common equity when the decision is “not supported by adequate

findings of material facts,” Public Staff I, 322 N.C. at 693, not supported by

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“substantial evidence in the record as a whole,” Public Staff III, 331 N.C. at 222, or

arbitrary or capricious, N.C.G.S. § 62-94(b)(6) (2025). Substantial evidence is “more

than a scintilla” of evidence; it means “such relevant evidence as a reasonable mind

might accept as adequate to support a conclusion.” State ex rel. Utils. Comm’n v.

Cooper (Cooper III), 367 N.C. 644, 648 (2014) (quoting CUCA I, 348 N.C. at 460). We

must also reverse the Commission for errors of law. N.C.G.S. § 62-94(b)(4) (directing

that the reviewing “court shall decide all relevant questions of law” and “may reverse

or modify” a decision “[a]ffected by other errors of law”). We review the Commission’s

conclusions of law de novo. E.g., State ex rel. Utils. Comm’n v. Va. Elec. & Power Co.,

381 N.C. 499, 515 (2022).

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

4 One estimate by the Public Staff calculated that a one-basis-point “impact on the

consolidated revenue requirement” is in the range of $4.3 million per year, for “three years,” or $129 million over three years for a thirty-basis point increase. As the majority notes, Duke Energy Progress and Duke Energy Carolinas are in the midst of a “complex merger” that they hope will be final “at the end of 2026.”

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The Attorney General, on behalf of the using and consuming public, see

N.C.G.S. § 62-20 (2023), and Duke Energy Carolinas’ customers objected to this

decision. They advanced three distinct challenges: they argued that the Commission’s

award of a 10.1% return on common equity was arbitrary or capricious, unsupported

by substantial evidence in the whole record, and inconsistent with Cooper I’s

requirement to take account of customer interests. See id. § 62-94(b)(4)–(6) (2023). I

agree and would vacate on these bases.

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

5 Two of those witnesses further recommended twenty-basis-point downward adjustments in the rate of return if multiyear rate plans were approved, as they were here.

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witnesses who conducted his own quantitative analysis.6 Dr. Morin concluded that

Duke Energy Progress and Duke Energy Carolinas were entitled to the same return

on common equity, in part because of their materially identical risk profiles and

similar other inputs.7 Other witnesses corroborated that both Progress and Carolinas

had the same long-term Moody’s Investors Service (Moody’s) credit rating of A2. For

Carolinas, Dr. Morin calculated that a return between 9.8% and 10.9%, including

flotation costs—which may not be awarded to Carolinas under this Court’s precedent,

see Public Staff I, 322 N.C. at 696–701—would be reasonable in both cases. He

ultimately recommended the midpoint of that range: 10.4% including improper

flotation costs, or 10.2% excluding them.

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

6 Duke Energy Carolinas also offered testimony from rebuttal witness James M. Coyne, but Mr. Coyne did not conduct an independent rate of return on common equity analysis. 7 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. 8 E.g., Fed. Power Comm’n v. Hope Nat. Gas Co., 320 U.S. 591, 603 (1944) (“[T]he

return to the equity owner should be commensurate with returns on investments in other enterprises having corresponding risks.”); Bluefield Water Works & Improvement Co. v. Pub. Serv. Comm’n, 262 U.S. 679, 692–93 (1923) (“A public utility is entitled to such rates as will permit it to earn a return on the value of the property which it employs for the convenience

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Energy Progress’s award was thus some of the best comparable evidence of investors’

likely expectations for Duke Energy Carolinas.

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”).

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It also offered no specific reasons for rejecting Dr. Morin’s testimony that 9.8% was

the lowest rate within the range of reasonableness.

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 Chapter 62, and (2)

are factually supported by substantial evidence. See Gen. Tel. Co., 285 N.C. at 680.

The Commission failed to do so here.

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

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myopically on an initial, top-line recommendation to support a particular conclusion,

irrespective of intervening evidentiary developments and underlying assumptions.

Summary approval of the Commission’s determination here amounts to little more

than the majority burying its head ostrich-like in the sand as to the actual evidence

below.

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

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rate hikes” and have experienced a profound burden from ongoing requests for rate

increases that “never seem to stop.” The Commission heard testimony that Hispanic

households, as well as Black and Native American households, spend a larger share

of their income on energy bills, putting them at a higher risk of utility shutoffs should

rates go up. Multiple witnesses expressed concern that Duke’s initially proposed rate

increase would raise the average customer’s bill more than $240 a year by 2026,

requiring thirty-three more hours of work for someone being paid at the minimum

wage.

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 Chapter 62 for doing

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so—is affected with legal error and unsupported by the record, and therefore must be

set aside.

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

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support it; to do so would be to abandon the critical review called for in our statutes

and precedent, e.g., Public Staff III, 331 N.C. at 222–23; N.C.G.S. § 62-94(b), in favor

of a hyper-deferential hypothetical rational basis review. For the majority now to rely

on reasons to affirm the Commission’s decision that were not stated in the

Commission’s decision contradicts basic principles of judicial review of agency

actions.

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,

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it is no justification that “[the Commissioners] cast votes in the [Carolinas] case in

line with the views they had expressed in that dissent [in Progress] less than four

months earlier.” When intervening evidence undermined those views.

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.”

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Party – Witness Progress Carolinas Difference Duke Energy 10.4%9 10.4% 0 pts Progress/Carolinas – Morin Public Staff – 9.45% 9.55% 10 pts Walters10 CUCA – O’Donnell 9.25% 9.40% 15 pts (Progress) and LaConte (Carolinas) 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

9 Dr. Morin originally recommended a 10.2% return on common equity in his first

Progress direct testimony, and he later updated his recommendation in each case to 10.4% based on an “increase in forecast interest rates.” So Dr. Morin still recommended the companies receive the same return on common equity award, but he calculated that the interest rate changes required a more modest increase of twenty basis points—still less than the Commission’s thirty. Dr. Morin’s 10.4% figure includes flotation costs, which are omitted from other witnesses’ testimony. 10 Mr. Walters and Mr. O’Donnell recommended a downward adjustment in the rate

of return on common equity if Duke Energy’s multiyear rate plan was approved. The chart shows the witnesses’ recommended figures without those downward adjustments, which the Commission rejected in both cases despite approving the multiyear rate plan for Carolinas and Progress.

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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

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Public Staff III, 331 N.C. at 226 (setting aside Duke’s rate of return on common equity

where “the Commission went beyond the boundaries established by the evidence”).

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

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downward adjustment [of the return on common equity in light of North Carolina’s

adoption of performance-based regulation] only a few months ago in the [Duke

Energy Progress] Rate Case . . . .”); id. at 203 (rejecting reliance on “the sustainable

growth methodology” and the “Multi-Stage DCF” methodology, “just as [another

witness] himself accorded [those methods] no weight in the [Duke Energy Progress]

Rate Case”); id. at 206 (“The Commission rejected these [additional calculations of]

beta measures in the [Duke Energy Progress] rate case and does so again here.”

(cleaned up)); id. at 213 (“Based on similar evidence, the Commission declined to allow

recovery of flotation costs in the [Duke Energy Progress] rate case. The Commission

similarly declines to allow recovery of flotation costs in this case.” (emphasis added));

id. at 214 (“Accordingly, as [the Commission] did based on virtually identical evidence

in the [Duke Energy Progress] Rate Case, the Commission rejects the downward

adjustment theory.” (emphasis added)).

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

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“9.73% so far in 2023.” It specifically considered comparable rates across the

southeast, including Duke Energy Progress’s rate of return on common equity from

2023 in South Carolina as well as its rate of return from 2021 in North Carolina.11

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.

11Specifically, the Commission analyzed data showing an “Authorized [Return on Equity] Comparison of Peer Utilities in the Southeast since 2020,” which featured Progress’s 2021 North Carolina rate as well as Progress’s 2023 South Carolina rate (9.60%).

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To be clear, this is not a case in which a party complains that the Commission

only “sparse[ly]” addressed relevant evidence. Conservation Council, 312 N.C. at 62.

The Progress rate order’s return on common equity award was essential data even

under the Commission’s own criteria and analysis. Yet the Commission inexplicably

disregarded “the actual experience of a utility in the attraction of capital” in

estimating a materially identical utility’s ability to attract capital. Gen. Tel., 281 N.C.

at 371. Its conspicuous failure to account for that relevant data, which contradicted

its ultimate outcome, shows “a lack of fair and careful consideration” and reasoned

decision making. Thornburg, 314 N.C. at 515. The Commission is not bound by stare

decisis. Va. Elec. & Power, 381 N.C. at 524. Even so, it is not permitted to willfully

disregard evidence obviously relevant to the inquiry at hand—particularly when

doing so renders its resulting rate order internally inconsistent.

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 N.C.G.S. § 62-133(d), that its findings were “supported by

competent, substantial evidence,” that its conclusions “were adequately explained in

its order,” and that the Commission’s order accurately reflected “North Carolina

ratemaking law as set out in prior decisions from this Court.” Va. Elec. & Power, 381

N.C. at 526 (cleaned up). That case has little relevance here, where the return on

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common equity portion of the Commission’s order was not adequately supported or

reasoned and evinces errors of law.12

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

12 The majority’s related statement that the Attorney General’s challenge fails even

under the reasoning of the dissent in Virginia Electric is hard to follow. If the dissenters there would have held that the Commission “needed to explain why it departed from its reasoning in two cases that were decided less than two years prior, had materially similar facts, and were brought to the Commission’s attention,” State ex rel. Utils. Comm’n v. Va. Elec. & Power Co., 381 N.C. at 530 (Barringer, J., dissenting), surely the same is true with identical circumstances occurring less than four months apart.

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former was thirty basis points higher. The Commission apparently employed the

exact same analysis to reach different results. By analogy, the Commission

determined that 1+1 = 2 in the first order and 1+1 = 3 in the second. This does not,

in my view, show that the Commission took its obligations to customers “seriously”

and “duly considered” their interests. I would vacate and remand.

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. N.C.G.S.

§ 62-133(b)(1), (3) (2023) (distinguishing “property used and useful” from “reasonable

operating expenses” and affording rate base treatment to the former only); id. § 62-

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133.16(c)(1)(a) (2023) (distinguishing “capital investments” from “operating benefits,

including operation and maintenance savings”). So while classifying an expense as

“capital” or “operating” can be an accounting question, in this case it is also a question

of statutory interpretation. The Commission only has that power delegated to it by

statute, Gen. Tel., 281 N.C. at 336, and the statutes govern when the Commission can

award a return to certain capital expenses. N.C.G.S. §§ 62-133, -133.16 (2023).

Statutory interpretation is a question of law reviewed de novo. See Va. Elec. & Power,

381 N.C. at 515.

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 N.C.G.S. § 62-94(b)(2) (2023). I agree and would

hold that the Commission does not have statutory authority to award a return on this

operating program estimated to cost $71.6 million.

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

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maintenance and classified as an operating expense. Similarly, “herbicide

management” and “post outage vegetation management” are routine maintenance

and thus are operating expenses not entitled to a return.

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. N.C.G.S. § 62-133(b)(1a), (4), (4a) (2023) (allowing a return for

some newly purchased rights-of-way and costs related to new construction in

progress). In contrast, hazard tree removal maintains existing rights-of-way and is

“performed in conjunction with normal trimming cycles.”

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

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same.13 Thus, the latter is not a “capital investment” eligible for rate base treatment.

N.C.G.S. § 62-133.16(c)(1)(a).

Nor is it “property used and useful.” Id. §§ 62-133(b)(1), -133.16(c)(1)(a).

Cutting down trees on someone else’s property is hardly usefully using your own

property under the ordinary meaning of those words.

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

13 The director of the Office of Enforcement for the Federal Energy Regulatory Commission confirmed that “[u]nder the Commission’s accounting regulations,” “costs to trim trees, remove trees, prune, and clear brush specifically to ensure the reliability of the transmission system by preventing vegetation-caused failures” are “maintenance expense[s].” Letter from Norman C. Bay, Director, Office of Enforcement, Federal Energy Regulatory Commission, to Harvey L. Wagner, Vice President, American Transmission Systems, Inc. 16–17 (Apr. 24, 2013) (Docket No. FA11-8-000) (accession number 20130424- 3026), https://elibrary.ferc.gov/eLibrary/search (last visited Sept. 25, 2025).

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benefit—but cleaning equipment or periodically changing the oil for an expensive

machine, for example, are classic operating expenses, not capital ones. Such a broad

interpretation of a “capital investment” would allow public utilities to impermissibly

aggrandize their returns. And Chapter 62’s particularly phrased language—“capital

investments, net of operating benefits, associated with a set of discrete and

identifiable capital spending projects to be placed in service during the first rate year

. . . [and] used and useful during [subsequent] rate years”—is not so expansive. See

N.C.G.S § 62-133.16(c)(1)(a).

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 &

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n.9. I also agree with the Attorney General that this language must mean that the

public utility cannot simply sit back and take no action at all while reaping the benefit

of new electric vehicle adoption. The statute clearly contemplates that the utilities

will act “to encourage electric vehicle adoption” in order to take advantage of this

exclusion opportunity. See N.C.G.S. § 62-133.16(c)(2) (2025).

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

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(b) and (d). See majority supra Section III.A; N.C.G.S. § 62-133.16(b), (d) (2025). In

my view, the Carolina Utility Customers Association’s argument that the

Commission erred by approving the 10% reduction without having established that

uniform reductions between 10% and 25% were not practicable is particularly

unpersuasive in light of the long-standing burden-shifting framework that applies in

utilities cases.

By statute, the public utility has the burden of proof to show that a proposed

rate change “is just and reasonable.” Id. § 62-134(c) (2025). Nonetheless, “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.” State ex rel. Utils.

Comm’n v. Stein, 375 N.C. 870, 908 (2020) (citing State ex rel. Utils. Comm’n v.

Intervenor Residents of Bent Creek/Mt. Carmel Subdivisions, 305 N.C. 62, 76 (1982)).

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

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Section III.A. The Commission instead adopted a 10% reduction as practicable after

hearing evidence to that effect. See id. Absent some quantum of affirmative evidence

that a percentage reduction between 10% and 25% was the appropriate rate to

“minimize[ ]” interclass subsidies “to the greatest extent practicable,” neither the

Commission nor Duke Energy had the affirmative responsibility to prove a negative–

–i.e., that some unspecified other percent reduction would not also work.

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.

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