NORTH CAROLINA — A Cary-based energy consulting firm found Duke Energy’s proposed natural gas buildout could substantially increase ratepayer bills over the next decade. The study comes amid ongoing expert witness hearings, in which critics argue the company is suppressing cheaper and cleaner alternatives.
READ MORE: Critics argue Duke’s carbon plan benefits shareholders above ratepayers
Energy analytics firm EQ Research published the study — “An Analysis of Natural Gas Buildout Risks and Impacts on Residential Customers” — on Tuesday. It was released a day before Duke representatives gave their first testimony for expert witness hearings before the North Carolina Utilities Commission regarding Duke’s near-term and long-term energy plans.
According to the analysis, Duke Energy’s plans for a major increase in natural gas infrastructure could cost the residential customer $2,100 more on their power bill by 2038. The study uses Duke’s projections of a “high fuel price scenario” instead of the “base price” used in previous modeling.
“Our analysis demonstrates that there is a considerable risk to customers from natural gas volatility that is not articulated or clearly considered in Duke’s carbon plan,” EQ Research president Justin Barnes told Port City Daily.
Rates significantly increase under a high gas price forecast. The firm estimates the monthly natural gas cost for ratepayers in 2031 would be 175% higher than 2024 costs under a high price scenario. With other factors remaining the same, Duke Progress customers would pay $2,094 more for natural gas in incremental costs from 2024-2038.
The study was commissioned by the Environmental Defense Fund, which will provide expert testimony in ongoing hearings for Duke’s future energy plans, along with other renewable energy advocates. The Utilities Commission is charged with reviewing evidence put forward in the hearings before approving or rejecting Duke’s proposal at the end of the year.
“Our goal was to take the publicly available data and do a public-facing report,” EDF southeast director Will Scott told Port City Daily.
Duke is required to reach carbon neutrality by 2050 and reduce carbon dioxide emissions to 2005 levels by 2030 under H.B. 951, a 2021 state law. The company’s most recent plan proposes creating new natural gas plants to replace coal and expanding a diverse range of other resources to meet growing demand.
Duke argues its proposed carbon plan is the least-cost path to achieving H.B. 951 goals while meeting energy demands, grid reliability, and affordable rates. It’s near-term plan includes:
- Increasing natural gas production by 8,925 MW by 2023
- Increasing solar energy by 6,400 MW by 2031
- Increasing battery storage by 2,700 MW by 2034
- Creating 1,800 MW of hydrogen storage by 2034
- Adding 600 MW of advanced nuclear power by 2035
Duke estimates its plan would increase average monthly bills over $50 by 2033 and $80 by 2038.
EQ Research president Justin Barnes told Port City Daily the firm decided against predicting an overall monthly rate increase due to the complexity of contributing factors.
He emphasized the firm did not publish the study to criticize Duke’s plan, but to provide context on how Duke’s high fuel price scenario — rather than the base price used in its modeling — would increase costs for ratepayers. The 2024 cost of gas in an average monthly bill for Duke Progress customers is $16.60. Under a high-price scenario, the figure would nearly triple to $45.70 by 2031.
Barnes noted natural gas price forecasts typically predict a moderate cost increase over time but are inherently limited in their ability to consider unforeseen market shocks, such as Russia’s invasion of Ukraine.
Duke’s price forecast failed to predict rapidly rising commodity prices in 2022 that caused an 11.3% rate hike last year. Duke anticipates recovering $1.9 billion in deferred fuel costs from the 2022 price hike included in ratepayer bills by the end of 2024, according to a May SEC filing.
“The point is not to say, ‘Duke should have predicted that,’ because no one did,” he said. “But that history of volatility is something that is important to consider as a risk to consumers.”
EQ research also analyzed the long-term viability of Duke’s proposed new gas infrastructure, which would be retired by 2050 to comply with H.B. 951’s carbon emission goals. The plants have a 35-year life cycle but would only operate for approximately 20 years after coming online around 2030.
The firm estimates ratepayers would be responsible for over $8 billion in expenses for the unused infrastructure as “stranded costs.”
EQ Research also emphasized the significance of new Environmental Protection Agency rules finalized in April. It requires new large gas plants to limit production to 40% of the time.
“But regardless of whatever EPA rules are in place, Duke’s goal is to effectively be carbon neutral by 2050, right?” Barnes asked. “And they’re investing in new natural gas plants for 2029 or 2033 that have a 35-year operating life.”
PCD reached out to Duke to ask how the company would adapt to the federal regulations and if Duke has a counterargument to claims about gas price volatility and unpredictability as a major risk for increased costs. A response was not received.
In its May SEC filing, Duke noted it was reviewing the new rules and affirmed cost recovery for its proposed plants would be pursued through the normal ratemaking process. The company is suing the EPA over the rule.
Expert witness hearings
Representatives of the office of the attorney general questioned Duke Energy’s North Carolina president, Kendal Bowman, at Wednesday’s hearing about the legality of the utility’s effort to delay its carbon deadline to 2035. Bowman argued H.B. 951 allows delays to ensure affordability and reliability.
Southern Environmental Law Center senior attorney David Neal praised the attorney general’s office for focusing on Duke’s compliance with legal emission requirements.
“I was encouraged to see a line of questions from the Attorney General’s office focused on this theme of: ‘What does the law require?’” he said. “And I think there were a fair amount of probing questions for Duke’s modeling panel about some of their assumptions. So much of what happens in these modeling exercises depends so heavily on input assumptions, whether that’s the price or availability of a resource.”
The Utility Commission’s public staff — an independent agency designated to represent the public interest in matters before the commission — was among groups that submitted testimonies ahead of ongoing hearings.
Several members raised similar concerns to the EQ Research study, such as natural gas price volatility and the impact of the EPA’s new natural gas limitations on Duke’s carbon plan. The utility commission’s public staff advocated a higher proportion of solar plus storage, offshore wind, and nuclear development in the carbon plan.
The Attorney General’s office and public staff also raised concerns about Duke’s failure to fully implement federal clean energy incentives in its plan.
Utilities Commission engineer Jeff Thomas wrote that Duke factored some Inflation Reduction Act tax credits into its modeling but failed to include the $250 billion federal Energy Infrastructure Reinvestment program, which provides guaranteed federal loans to projects that replace fossil fuel infrastructure.
“We think there’s a lot of promise in the EIR program,” Neal told PCD. “And I was really happy to see the public staff pick up that mantle.”
Michelle Boswell, director of public staff’s accounting division, wrote that maximizing the Energy Infrastructure Reinvestment Program could save ratepayers over $1 billion compared to traditional utility financing. Although EIR loans would provide ratepayer benefits, Boswell noted they would lower the utility’s earnings by replacing a portion of Duke’s equity investments in infrastructure.
Duke is an investor-owned regulated state monopoly that receives a guaranteed “return on equity” — generally around 10% — for its infrastructure investments. Critics argue the regulatory arrangement incentivizes utilities to prioritize expensive infrastructure even if there are more affordable alternatives.
“When Duke builds gas plants, it can earn its return from customers on those expensive assets,” Neal told PCD last week. “But it is insulated from the impacts of potential price spikes from volatile methane gas markets, because fuel costs are passed directly on to its customers.”
Public staff was scheduled to testify at the hearings but will no longer do so after reaching a compromise with Duke earlier this month. The company agreed to review the Energy Infrastructure Reinvestment loan program and other utility staff concerns as a condition of its agreement.
Neal noted state law mandates 45% of North Carolina’s solar production be independently owned. Because it is the only resource Duke cannot solely own and charge to its rate base, the utility has a potential disincentive from maximizing solar production.
“Duke itself recognizes the value that solar brings to the system and is embracing building out more,” he said. “We think they could do even more than they’ve put on the table.”
Durham-based NC WARN — also an intervenor in the expert witness hearings — argues Duke’s prioritization of revenue streams over carbon goals has led the company to suppress rooftop solar and storage. The group issued a proposal for greater emphasis on the resource in April. It cites research including a 2014 study by investment research firm Sanford Bernstein & Co. finding rooftop solar lowers electricity prices by reducing peak demand.
NC WARN is involved in an ongoing lawsuit against Duke over the state’s net-metering policy, which gives rooftop solar users credits for contributions to the grid. The Utilities Commission approved Duke’s request to lower credits last year.
In a February SEC filing, Duke admitted expanding distributed energy — such as rooftop solar and storage — could threaten revenue:
“Federal and state regulations, laws, commercialization and reduction of costs and other efforts designed to promote and expand the use of EE (efficient energy) measures and distributed generation technologies, such as private solar and battery storage, in Duke Energy service territories could reduce recovery of fixed costs in Duke Energy service territories or result in customers leaving the electric distribution system and an increase in customer energy net-metering, which allows customers with private solar to receive bill credits for surplus power up to the full retail credit amount.”
Tips or comments? Email journalist Peter Castagno at peter@localdailymedia.com.
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