US PUBLIC POWER ELECTRIC UTILITY 2026 RISK OUTLOOK STABLE

December 18, 2025|AGVP Advisory

US PUBLIC POWER ELECTRIC UTILITY 2026 CREDIT AND RISK OUTLOOK STABLE; AGVP CAUTIONS THAT STABILITY DEPENDS ON SOUND COST RECOVERY DECISIONS AND STRATEGIC PLANNING

AGVP Advisory believes the outlook for public power electric utilities in 2026 is stable but will be dependent on the decisions made by management on cost recovery, financial policies and absorption of new demand growth. This is amidst developing concerns about affordability and the risks of the unsettled federal approach to tariffs and the clean energy transition. These factors weigh heavily on the 2026 outlook.

In particular, the current federal administration policies present challenges that could not be planned for. It depends on where one is positioned how the change in direction will immediately impact the financial position of utilities. For example, as was pointed out in the outlook for 2025, the lifting of more restrictive regulations on fossil fuels will provide time to comply with existing regulations and room to manage the new growth being caused by data center development. But this may also slow the pace of transition to less carbon emissions. Utilities serving communities opposed to the use of natural gas or coal-fired generation or concerned about their future role, in favor of cleaner energy, may now be faced with indecision about the next generation source to meet forecasted demand if reliability can’t be assured.

The potential of an outsized risk for the sector also remains the potential federal pullback from extreme weather recovery financial support and the weather patterns that develop during the year.

Red flag risks in the 2026 outlook persist and must be successfully managed including the pressures of new demand growth, regulatory risk, cybersecurity risk and extreme weather risks and insuring transmission grid stability.

KEY TRENDS IN THE PUBLIC POWER ELECTRIC UTILITY SECTOR

Following are several leading trends into 2026 affecting public power electric utilities:

* Most public power electric utilities continued to maintain progress in 2025 on their decarbonization pledges and planning their transition to cleaner energy. While progress on decarbonization plans took place in 2025, the outlook for 2026 is cautioned based on the role the federal and state governments play in regulatory policy, federal judicial decisions and financial incentive policies. For example, the federal government’s halt of offshore-wind development was a major change in direction and a future return to an offshore wind plan is at this point questionable. Another significant shift was the Supreme Court ruling that only Congress can provide authority for EPA to regulate greenhouse gas emissions. While clean energy plans of many utilities remain popular, how the federal government’s current position on climate policy complicates further advancements.

* Energy Information Administration data confirms the competitive advantage for the largest 25 US public power electric utilities. Also, the American Public Power Association (APPA) estimates there has been a consistent average 10% plus competitive difference between public power electric utilities and investor-owned utilities. But even public power utilities have seen an increase in rates to account for new investment to meet demand and power supply costs which will be a pressure in 2026. How utility governance responds to rate increase requests could be a determining factor in credit position in 2026.

*AGVP estimates 2025 financial metrics for public power electric utilities were stable including debt service coverage and debt leverage ratios and liquidity. This after the effects of commodity price volatility and pandemic impacts in 2020-2022. The outlook for 2026 indicates a continuation of the stable trend if short-term risks are managed and longer-term planning is sound.

*New capital investment partly funded by debt is expected by numerous public power utilities for T&D and renewable energy generation which will affect leverage burden. Moderating interest rates in 2026 could be a positive financial factor for public power electric utilities. The new revenue bond debt will however be affected by the inflationary pressures, new tariff costs on generation equipment and possibly the narrowing of the time frame when new generation is needed due to the projected demand growth taking place. Significant new debt leverage could be a negative pressure on ratings in 2026, particularly if more intensive capital investment takes place such as for new natural gas generation facilities, battery storage or nuclear investment.

*Like in 2025, fuel diversity, along with transmission reliability, will remain fundamental strengths in 2026 as important public power management objectives , as extreme weather continues to potentially threaten operations. Intermittency of renewable energy still will become even a greater issue as renewable energy production expands. Overall, public power electric utilities have maintained sound reliability performance metrics including the most recent EIA reported SAIDI index, at 1.27 hours versus the private sector ratio of 2.29 hours.

*Limited new transmission was built in US in 2021-2025, but FERC controversial order 1920 still is expected to identify and encourage new transmission. FERC Order 1920 establishes implementation of long-term planning with 5-year cycles; use of scenario planning and requires grid enhancing technology planning and use. Each U.S. region has significant new investment planned.

*For some municipal electric utilities, fiscal stress on the city government could affect the utility as new pressure builds on increasing the utility transfer to the city’s General Fund. There are expectations that the city budgets are being increasingly stressed as Covid-related subsidies ended and federal budget deficits have resulted in cutbacks to states.

* Further evaluation of the municipalization of electric service may take place as customers assert investor-owned utilities are slowing the pace to cleaner energy. San Diego, California, Tucson, Arizona, Ann Arbor, Michigan, and Rochester, New York, for example, are expected to remain engaged in their efforts, as are California cities formation of community choice aggregators (CCA). But the political and financial strength of incumbent utilities will remain a constraint on progress on changing the electric business model at the local level.

Most consultant studies on the subject recommend cities not to proceed, but the studies in AGVP Advisory’s view, misrepresent many of the attributes of a municipal electric utility.

*Concerns about electricity transmission reliability and the narrowing of choices of fuel for generation in the future has prompted a sooner than previously expected resurgence in plans for new nuclear generation construction including small modular nuclear reactors. See

AOBSERVATIONS on PUBLIC POWER AND FINANCING OF NEW NUCLEAR GENERATION.pdf

(SMRs) and a larger unit project that uses lessons learned from Vogtle could move ahead faster. Some public power electric utilities will participate in the financing possibly through joint municipal action power agencies. The advanced SMR are eligible for federal production tax credits if started before 2033 and if sited at an existing coal-fired generation site, there is an additional 10% credit. For example, Energy Northwest is participating in a project in the Pacific Northwest and the Tennessee Valley Authority and Ontario Power Generation(OPG) , have joined in development of the GE Hitachi small modular reactor technology.

Recently, NPPD, OPPD, GRDA and LES have launched a joint effort, the Great Plains New Nuclear Consortium, explore the feasibility and development of deploying between 1,000 and 2,000 megawatts of new nuclear technology— including Small Modular Reactors (SMRs)—within Nebraska to serve the needs of the four utilities in the Southwest Power Pool market footprint.

*Most of the energy storage that has been developed is 4-hour storage and below which does not meet the needs of grid stability in the face of significant new intermittent generation. There is 23 GW of short-duration storage now in operation, with most of it being pumped storage. Estimates are to get to net zero by 2050, 225 to 460 GW of long-duration storage will be needed. The regulatory commitment is present at both federal and state levels to encourage the scaling and better economics of long-duration storage but the advancement in technology to extend storage to 8 hours is still not there.

Some of the leading candidates of new clean capacity besides new nuclear include:

Geo-thermal-The heat and energy captured by geothermal systems would provide renewable energy and nearly zero emissions. Capturing geothermal production, while it has vast potential, is complicated. A major new development project by FERVO Energy scheduled to be commercial in 2026 established its first power sales agreement with Shell.

Green Hydrogen– Intermountain Power Project (IPP) is the first gas turbine in the world being built to run on 100% carbon free green hydrogen. Built at the site of Utah’s largest coal-fired power plant, one of the two units is operational whereby 30% of fuel will be green hydrogen and 70% natural gas and by 2045, 100% green hydrogen. Significant IRA incentives were awarded to the project. Whether projects such as the IPP project are compromised by a federal pullback on clean energy incentives is uncertain. The two-unit IPP coal fired units were closed in 2025 which resulted in Los Angeles becoming 100% coal-free. Utah did pass state legislation to sell the closed units to a third-party for reopening.

Carbon capture on gas plants- Unless the economics of carbon capture improves, federal support could wane in favor of letting the market determine its success. Also, the federal government’s dismantling of the EPA’s regulations on greenhouse gas emissions in 2025 could become permanent in 2026, which reduces the compliance value of carbon capture initiatives.

RED FLAG RISKS TO STABLE CREDIT AND RISK OUTLOOK for 2026

There are several red flag risks that will be challenging for public power electric utilities in 2026:

*The transmission grid, particularly in California, cannot fully handle the growing demand from the electrification of the transportation and building sectors and federal and state policy mandates, and threatened by extreme weather, subjecting the grid to reliability issues with potential for public safety impacts. The same issues will be faced elsewhere in the U.S. in 2026. Furthermore, the immense computational power needed for generative AI and the significant new investment in US manufacturing facilities and data centers and EV charging will continue to present new challenges to demand management. Substantial focus will be public power electric utilities incorporating advancements in strengthening grid resilience.

*Cyber security risks remain present and public power management remains focused on mitigation, but new threats continue to create uncertainty. More training of staff and refined incident response plans remain a critical step for public power electric utilities, particularly for smaller entities.

*Solar roof top and plug-and-play solar devices and other distributive generation programs could upend utility revenue certainty should customers not be required to fully support a utility’s systemwide financial requirements. Cost of service studies, use of AI, and implementation of automatic meter reading (AMR) will continue to expand in 2026 to try to better manage customer revenue.

*In 2026, public power electric utilities will continue to be more responsible for the reliability of the transportation sector in their service area as electric vehicle adoption expands. An existing public power electric utility strength is strong electric system reliability performance, but taking on EVs will test local utility demand management. Bidirectional EV battery charging may be a possibility to ease serving demand but initially it will complicate residential supply-demand management.

*Natural gas volatility remains a risk particularly as natural gas maintains its dominance in most US regions and is critical as that electric capacity now balances renewable energy intermittency. Current EIA forecasts show at the hub a 2026 price of $4.00\MMBtu, up from $3.10/MMBtu in 2025.

*Federal action to disband Environmental, Social and Governance reporting (ESG) requirements, SEC climate disclosure requirements and future US Supreme Court rulings on carbon regulation continue to change the regulatory landscape and further adoption of clean energy plans. The US Supreme Court significantly limited EPA’s authority over carbon regulation concluding any action requires Congress approval for broad economic mandates.

* Not preparing for the extreme weather risk is a risk, but preparation is a cost that will pressure budgets in 2026 for some utilities. The lingering question is “who is next? “regarding unpredictable extreme weather. A winter blizzard in Orlando affecting power generation? An unexpected 500-year flood in Omaha? Or will there be a cold wave in Phoenix in July? Utility planning for climate change extreme weather will continue to be a heightened planning activity and a budget pressure. The role FEMA will play in the recovery from adverse impacts of extreme weather remains uncertain. Also, the extent that impacts from extreme weather increase, insurance costs and liability claims against utilities may result.

CONCLUSION

Public power electric utilities, due to their inherent strengths such as local governance and lower cost structure, should maintain their stable financial position in 2026. As the US electric industry transitions to cleaner energy and adopts new innovations in technology, there are potential risks that if not managed could present long-term challenges. For example, the temptation to encourage new data center development with inadequate downside protection is a potential risk.

But a longer-term perspective is that the electric industry goes through periods of uncertainty and outsized risks. Strong public power utility management and leadership going forward will continue to make a difference.

Dan Aschenbach

AGVP Advisory at [email protected]

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