Virginia stakeholder group hears primer on how utility rates are set and which costs are recovered through riders

The Performance Based Regulation Stakeholder Group heard an overview of how the State Corporation Commission sets electric utility rates in Virginia and how a growing share of costs is recovered through rate adjustment clauses during a virtual meeting on Dec. 12, 2024.

The presentation from Kim Pate, director of utility accounting and finance at the State Corporation Commission, described three primary rate proceedings: the fuel-factor and other rate adjustment clauses (dollar‑for‑dollar trackers), periodic adjustments to base rates that recover the utility’s remaining costs, and biennial earnings reviews. "The commission is an economic regulator. So that means we're setting the rates," Pate said while outlining the statutory framework in Article IX of the Virginia Constitution and Title 56 of the Virginia Code that governs public service companies.

The nut graf: The group convened to inform a study of performance‑based regulation. Understanding how costs are allocated today—especially the growth of riders that are trued up annually—frames stakeholder discussion about whether multiyear rate plans, decoupling, or other PBR tools would better align utility incentives with state energy and affordability goals.

Key facts presented - Kim Pate said fuel and many other "racks" (rate adjustment clauses) are dollar‑for‑dollar recovery mechanisms; most include a profit margin except the fuel factor, which does not. Pate said the typical residential Dominion Energy Virginia bill (1,000 kWh) was about $140 and that Dominion had proposed increases that would raise a typical bill to approximately $149 if approved. - The Commission uses an earnings test looking at historic earnings; sharing mechanisms return excess earnings to customers. For Dominion, Pate described sharing bands that return 85% of earnings above the authorized return up to a set threshold and 100% above that higher threshold. - Dominion has a large near‑term capital plan: in investor materials the company identified about $35 billion of capital expenditures over the next five years for transmission, distribution, solar, storage, nuclear and grid transformation. - Pate and later presenters emphasized that the alternatives in law differ for Dominion (a "phase 2" utility under the code) and Appalachian Power Company (APCo). APCo’s current average bill was cited at about $172 (moving toward $174), and APCo’s recovery through trackers was shown at roughly 52% versus 48% through base rates; Dominion’s mix was presented as roughly 50/50.

How the ROE and earnings sharing work now Joe Reed, counsel presenting for Dominion Energy Virginia, summarized statutory features that already tie some utility compensation to performance. The commission sets an authorized return on equity (ROE) and, by statute, can adjust ROE up or down based on performance metrics. Reed said the 2023 legislation narrowed the ROE adjustment band and required the commission to develop criteria for adjustments. He also summarized the current earnings‑sharing test: when base earnings exceed the authorized return, most available excess earnings flow back to customers under the statutory formula.

Timing and forward rates Pate explained the biannual cadence for filing: Dominion typically files on odd years and APCo on even years; filings look back at two historic test years and set forward rates for two prospective rate years (Dominion’s filings set two forward periods, APCo’s approach differs). Reed and Pate noted that some elements of the 2007 alternative regulation framework remain in place but were modified in later laws (notably the 2018 Grid Transformation and Security Act and the Virginia Clean Economy Act).

What this means for stakeholders Stakeholders at the meeting said knowing which costs are recovered through trackers versus base rates is crucial to judging whether the current model aligns utility incentives with state policy goals such as decarbonization or affordability. The presenters left open technical questions—such as whether further adjustments to riders, multiyear rate plans, or explicit decoupling should be proposed—but described the existing statutory tools stakeholders should consider.

Ending Participants agreed to submit written comments and continue the stakeholder process into January, when comparative PBR experiences from other jurisdictions will be presented and the group will revisit its workplan.