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

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

customers.

“When construing a statute, a court’s principal goal is to accomplish the

legislative intent. The court must begin with an examination of the relevant statutory

language.” N.C. Dep’t of Revenue v. Philip Morris USA, Inc., 388 N.C. 181, 187 (2025).

“If the statute’s plain language is clear and unambiguous,” the court “applies the

statute as written and does not engage in further statutory construction.” N.C. Farm

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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.

N.C.G.S. § 62-133.16(c)(2).

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)

(cleaned up).

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)

(cleaned up).

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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.

(Cleaned up).

Put differently, DEP did not make fixed capacity payments to renewable

generation facilities that it then recouped in the fuel rider. Rather, DEP purchased

power from these facilities on a per-unit basis, with that per-unit cost increasing

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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 met

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