Devising a robust power supply strategy for municipal utilities and electric cooperatives has always been challenging. A power supply strategy is a utility's long-term plan to affordably and reliably secure enough electricity to meet the needs of customers. This is typically accomplished through a mix of contracts, wholesale market purchases, and owning and operating generation.

Confidently developing power supply strategies requires public power leaders to assess and mitigate complex risks—from fuel price fluctuations to regulatory changes. Today, that challenge is intensifying.

The reasons for the complexity will be familiar: rapid and unprecedented load growth due to the proliferation of data centers, widespread electrification, and domestic manufacturing at a time when many power plants are retiring, taking desperately needed capacity with them. Here's how the trade group American Public Power Association (APPA) summed up the challenge:

Many factors, including federal policies, overly burdensome permitting processes, increased reliance on natural gas for electricity generation, and supply chain constraints, are resulting in the premature retirement of existing generation resources at a faster rate than they can be replaced by new generation with equivalent reliability attributes.

APPA declared. "This has created challenges for public power utilities as they work to maintain current reliability and meet growing demand."

There is a growing gap between the capacity needed to meet electricity demand and the available supply of reliable and dispatchable new resources. The North American Electric Reliability Corporation (NERC) has been sounding the alarm about shrinking reserve margins in multiple regions across the U.S., including PJM, where the nation's largest wholesale market operator expects 20 gigawatts of thermal generation to retire by 2030 and where capacity auction prices have skyrocketed in recent years.

The Public Power Difference

It's true that investor-owned utilities (IOUs) must also contend with rapid load growth and the cost, permitting, policy, and supply chain obstacles slowing and challenging the quick addition of needed capacity. But it's also important to understand the significant differences between IOUs and public power utilities:

• Fundamentally different missions: IOUs are owned by investors who expect a return. And the way IOUs earn a return is by investing in new power plants, transmission lines, and other power system infrastructure. Municipal utilities and electric cooperatives do not exist to make money for investors. Instead, both exist to provide reliable and affordable energy to their members and the citizens they serve.
   
• Different mission, different motivation: Public power utility leaders focus intensely on keeping rates low. There's no incentive to overbuild if it means higher rates for cooperative members or citizens who can vote them out. This can encourage extending asset life rather than making large new investments.
   
• Greater agility: While IOUs spend years navigating public utility commission approvals, well-informed cooperative boards can approve major decisions in months—assuming staff keeps them educated about technology and market developments.

Grasping these fundamental differences matters because they should inform how public power utilities evaluate risk in their power supply strategies. For instance, electric cooperatives and municipal utilities may be tempted to extend the life of existing assets, wait for technology costs to come down, and avoid being the first to deploy new technologies. But in a world where capacity is retiring quickly, demand is spiking, and supply chain lead times stretch for years, that risk calculus may be dangerously backwards.

The Five Essential Questions

Here are the five questions you should be asking to understand whether your power supply strategy meets the unique challenges of today, and tomorrow. 

Question 1: Does your capacity strategy solve the right problem?

The capacity crisis in PJM includes the impending retirement of 20 gigawatts of thermal generation by 2030 and the explosion of capacity auction prices from as low as about $39 per megawatt-day in recent years to nearly $330 per megawatt-day in this past summer’s auction. It's hard to imagine a stronger sign of the desperate need for dispatchable resources.

The power sector has a capacity problem, not an energy problem. The two terms are related, but distinct. Energy is the total amount of electricity consumed or produced and is measured in megawatt-hours, or MWh. Capacity, on the other hand, describes the ability to generate electricity when it's needed and is measured in megawatts (MW). The value of capacity is in the certainty that those megawatts will be available precisely when needed.

The grid has plenty of energy. For example, between 2014 and 2024, the U.S. added over 100 gigawatts of utility-scale solar, according to the U.S. Energy Information Administration. These additions are welcome, but they don't solve the capacity problem—solar can't deliver power on a cold winter's night when it's needed most. Traditional pillars of a public power utility's power supply strategy—like building a new combined-cycle natural gas plant—face major obstacles: according to S&P Global, it can take until 2032 to obtain a turbine. 

Waiting for these traditional supply chains introduces the risk that load growth and generation retirements will cause grid reliability problems. The bottom line: Adding capacity is obligatory. The question is whether it's more responsible to wait for supply chains to ramp up or to investigate solutions that can be deployed faster.

Question 2: Are you pricing in the cost of delivery? 

Basis risk refers to the potential cost difference between where electricity is generated or purchased and where it's ultimately delivered. For example, wind generated in western Kansas produces abundant energy where few people live. But that electricity commands a lower price at the point of generation than what customers who need the electrons transported long distances must pay—a spread driven by transmission congestion. For public power utilities, this risk matters because congestion and long transmission distances can sharply increase costs. When power must move across overloaded lines or through volatile regional markets, what once looked like a stable, contracted price can quickly escalate. Locally sited generation—especially projects that can be permitted and built quickly—can help hedge against these costs. 

Question 3: Does your strategy anticipate inevitable regulatory changes?

Public power utilities have always had to consider regulatory risk in their power supply strategies. For example, utilities scrambled to comply with NOx and mercury emissions standards by retrofitting their coal plants. Public power utilities in some states, like Colorado, must now consider the more fundamental question of whether fossil fuel plants will be permitted to operate in 15 or 20 years. 

Natural gas combined-cycle power plants typically have 30-year lifespans. Public power utilities focused on affordability need to decide whether contracting with or building an asset that may not be in operation—or will require expensive retrofits to continue operating—in the future is the right use of customer dollars. One way to mitigate regulatory risk is to prioritize assets that can run on multiple fuels—natural gas today, then hydrogen or renewable natural gas when those fuels become more available and affordable.

The power sector has a capacity problem, not an energy problem.

Question 4: Can you withstand the next storm?

Hurricanes, wildfires, winter storms, and other events are especially threatening to public power utilities because they lack the balance sheet and ability to socialize losses that IOUs have. In the aftermath of Winter Storm Uri in 2021, Brazos Electric Power Cooperative in Texas filed for bankruptcy after ERCOT billed Brazos nearly $2 billion for electricity purchased during the storm. A power supply strategy must acknowledge the reality of extreme weather events and take steps to enhance resiliency. Distributed and fuel-flexible generation located near load both reduces the risk of outages during a storm and the possibility that breakdowns of the transmission system or disrupted fuel supplies will become financially catastrophic.

Question 5: What is the risk of inaction today?

Perhaps the biggest risk public power utilities face is the risk of doing nothing. Supply chain challenges make traditional playbooks for adding capacity anytime soon unrealistic. But does that mean load growth will cease? Will the threat of extreme weather decrease? Is regulatory certainty coming soon? 

Risk management is central to public power utilities' mission to deliver affordable, reliable electricity. But the strategies that worked when capacity was abundant and load was flat—like extending asset life, waiting for costs to decline, and avoiding early adoption of emerging technologies—may now carry more risk than they mitigate. Understanding this changed risk landscape, and the tools available to navigate it, is essential for constructing a resilient power supply strategy.

An honest assessment of these five questions may not provide clear-cut answers that apply to all public power utilities in all cases. But what is clear is that the power supply strategies that have delivered affordable and reliable electricity for decades need to evolve. Leaders who proactively answer these questions today will position themselves to serve members and citizens well long into the future.