Power Industry Outlook: High Electricity Prices Persist, Elections Add Uncertainty to Clean Energy Plans

The past year has been challenging for electric power companies:Stock performance lagged behind the broader market，Supply chain issues increased costs and timelines for renewable energy projects，Electricity prices continued their three-year upward trend. What will the industry face in 2024?

In a January 9 outlook, BofA Global Research analysts described the outlook for power companies and the clean energy industry as an "unusual level of volatility and opportunity."

With less than 10 months until the U.S. presidential election, the vote could significantly impact energy policy, the implementation of clean energy tax credits, and federal loan guarantees. Interest rates may have stabilized but remain at 15-year highs, which experts say will increase refinancing and debt service risks for renewable developers. Market observers say rising electricity demand and falling natural gas prices send mixed signals for consumer bills.

Investment in new technologies will grow, but not evenly. Experts believe near-term expectations for hydrogen may be too high, while investment in virtual power plants could expand rapidly. BofA says solar deployment may stabilize after years of supply chain constraints and tariff uncertainty, and batteries as an asset class could reach "critical mass."

Electricity prices will remain high

According to the U.S. Energy Information Administration (EIA), the average residential electricity price in 2023 was $0.1588 per kilowatt-hour, up rapidly from $0.1372 per kilowatt-hour in 2021. Prior to that, electricity prices had remained relatively stable for years.

EIA expects U.S. retail electricity prices to decline slightly in 2024, averaging $0.1573 per kilowatt-hour, before rising to $0.1611 per kilowatt-hour in 2025. The forecast is based largely on falling natural gas prices, which EIA expects to remain near $3 per million British thermal units through 2025, when liquefied natural gas exports begin to increase.

In its short-term outlook, EIA said this level "should keep wholesale electricity prices below or near last year's levels in most regions."

However, regional differences are significant: EIA forecasts wholesale electricity prices will rise this year in New York and New England.

Moody's Investors Service said in December it was maintaining its stable outlook for unregulated power companies and the generation industry, "based on our expectations of higher electricity prices." Growth in electricity demand from data centers, industrial activity, and weather will be factors "driving forward prices higher in most markets."

Moody's noted in its 2024 outlook that the Electric Reliability Council of Texas (ERCOT) market "is an exception," where "peak prices will decline as solar generation is expected to grow rapidly over the next three to five years."

But both EIA and Moody's said Texas could see price spikes under constrained market conditions.

Moody's Vice President Toby Shea said that in California and the West, "generation shortfalls could keep prices high in some areas, even if natural gas prices remain low."

Moody's analyst Jillian Cardona said the firm expects natural gas prices this year to range between $2.50 and $3.50 per million British thermal units, a significant drop from prices near $9 per million British thermal units in 2022.

Cardona said Henry Hub spot prices closed 2023 at about $2.50 per million British thermal units, "which is quite favorable for regulated utilities' credit. We don't think they will have difficulty with excess fuel costs." Moody's maintains a stable outlook for the regulated utility sector.

But Paul Cicio, president and CEO of the Industrial Energy Consumers of America, said that while natural gas as the marginal fuel often determines electricity prices, it is not the only factor.

"We have entered an acceleration period where electricity price inflation will persist for decades," he said, blaming increased transmission capital investment made without competitive bidding.

The Federal Energy Regulatory Commission (FERC) has proposed new transmission planning and cost allocation rules, but Cicio said the rule "does not require competitive bidding for transmission projects; it avoids it. Without competition, monopoly incumbent utilities have no incentive to reduce costs when building new transmission projects."

Mark Dyson, managing director of RMI's Carbon-Free Electricity program, said the impact of competitive bidding is "complicated." But "if you build the right transmission lines—for example, those that help unlock low-cost wind and solar resources that otherwise couldn't be delivered to market—that would actually lower future electricity prices."

He added, however, that the lines built in recent years have not been of that type.

"The lines we've built over the past five years have been more regional, not necessarily optimized around bringing low-cost resources to market, but more justified on reliability grounds," Dyson said.

Electricity demand rises in 2024, flat the following year

Experts say electrification in transportation and buildings is beginning to add to utility loads, but so far, new demand has appeared mainly at the local level. Observers say weather and economic growth will drive U.S. electricity demand higher in 2024.

EIA expectsU.S. electricity demand to grow 2.6% in 2024, driven mainly by weather, and to remain stable in 2025.

"U.S. economic growth could also drive commercial and industrial demand higher, including new demand from data centers across the country," Moody's said.

RMI reviewed utility integrated resource plans (IRPs) in December to quantify the potential demand impact of the Inflation Reduction Act (IRA). The act, passed in 2022, directs tens of billions of federal dollars to clean energy and electrification.

Dyson said about half of U.S. utilities submit IRPs. RMI's analysis shows that in January 2021, these companies expected demand to grow 6.5% by 2035. Since the IRA's passage,the expected demand growth by 2035 has exceeded 16%。

"Demand growth forecasts are steadily rising. The U.S. experienced 15 years of flat demand; that is no longer the case," Dyson said.

Industry must contend with higher interest rates

Debt analysts say that while interest rates have stabilized, they remain high and will pose challenges for some industry segments.

For unregulated utilities and clean energy developers, "significantly higher debt costs have increased debt service costs and refinancing risks. For new renewable projects, higher debt costs raise the levelized cost of electricity," Moody's said.

High capital costs and rising inflation "have threatened the viability of some planned renewable projects," Moody's said in its December 2024 industry outlook,"especially offshore wind."”。

In the regulated sector, Cardona said the impact is greater on utility holding companies than on operating companies, because operating companies' interest costs are typically passed through to customers.

"The biggest risk is for holding companies with significant debt maturing in the next year that needs to be refinanced, and any exposure to floating-rate debt. Interest rates could come down. The Fed seems to hint at possible rate cuts in early 2024. But that remains to be seen," she said.

What impact will the election have?

Republican caucuses and primaries have just begun, but former President Donald Trump has promised to end the "Green New Deal atrocities" on day one if re-elected.Green New Deal atrocitiesObservers say the election poses some risk to clean energy incentives funded through the Inflation Reduction Act, including tax credits and Department of Energy loan guarantees.

"If Biden administration agencies fail to complete their work on carbon emissions (actual emission limits and disclosures), hydrogen, electric vehicles, and other policy goals, a Republican administration could halt or reverse many elements," BofA analysts wrote.

The biggest risk is "related to changes in administrative interpretation of the IRA, rather than the tax credits themselves," they wrote.

BofA analysts also said they look forward to the completion of the Department of Energy's clean energy federal subsidy program in 2024. "Watch for substantial progress on initial awards early in the year," they said. "We believe conditional loan approvals need to be finalized by the end of the 2024 calendar year."

"There is talk about repealing or modifying the IRA if Republicans take power, but we don't know exactly what they would do. So it's hard to say what the impact would be. The IRA benefits utilities across the country. So it's not a blue-versus-red issue. They all benefit," Moody's Shea said.

The U.S. Treasury and Internal Revenue Service (IRS) issued proposed regulations in December definingthe standards hydrogen producers must meetto qualify for the IRA's 45V clean hydrogen production tax credit.

The proposed rule is one of a series of rules the IRS and Treasury have issued on how to qualify for various IRA clean energy and electric vehicle tax credits.

Alex Piper, senior associate for RMI's U.S. program, said the Biden administration faces pressure to finalize the rule quickly.The comment period ends February 26, and even if the rule is finalized, "a future administration different from this one certainly has other ways... to impede progress."

Investment in new technologies: hydrogen and virtual power plants

2024 will be a year of investment in new technologies, but some will start with stronger momentum than others.

"Despite the IRA's passage, we see a subdued hydrogen outlook for 2024," BofA said. "We emphasize that this is about expectations—after the IRS issued fairly strict implementation rules, expectations around hydrogen in the 'green new economy' appear clearly too high."

"Overall, we expect 2024 to be a 'year of reset' in expectations, as hydrogen companies had anticipated greater flexibility on emissions hourly matching and other issues," BofA said.

Under the proposed rule, hydrogen producers mustuse renewable or zero-emission electricity from facilities that began operation no more than three years before the hydrogen facility's construction. The electricity must also come from the same geographic region as the hydrogen production facility and, starting in 2028, comply with hourly matching rules.

Piper said he doesn't expect to see large electrolyzer projects deployed this year, "but we could see announcements and investment decisions around hydrogen and industrial decarbonization."

New offtake agreements for clean hydrogen that can decarbonize steel, fertilizer, and aviation fuel, he said, "are large investment decisions and utility business trends that I think will start to show up in the second half of this year and next year."

Dyson also said he expects increased investment in virtual power plants because they "address many of the pressing issues U.S. utilities now face... We see declining reliability and rising costs. Done well, virtual power plants can help address both challenges."

The U.S. Department of Energy concluded in September that significantly expanding U.S. virtual power plant capacity couldsave about $10 billion in grid costs annually. Current domestic virtual power plant capacity is 30 to 60 gigawatts, depending on how resources are defined.

Dyson also said he expects more "clean repowering" projects,clean repoweringwhich deploy renewables at former fossil fuel plant sites already connected to the grid. RMI research released January 16 shows a national repowering potential of 250 gigawatts.

"This will be a trend this year. More and more utilities will take advantage of this opportunity because of the IRA economics and the grid's technical ability to absorb new renewables at existing interconnection points," he said.