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Texas and its electricity market are in the news again, this time centered on the political fallout of Winter Storm Uri. A host of controversial energy policy bills are making their way through the Texas legislature, headlined by SB6, a $18 billion out-of-market directive to build natural gas power plants. The debate about the Texas electric grid and Texas state policy should not be mistaken as merely a local issue. Instead, it represents the leading edge of a political problem that will play out across the United States in the years to come. The heart of the problem is power grid reliability and how to pay for it.
If all is well, power grid politics recede from public focus; the grid operates seamlessly, and the lights simply always work. Unfortunately, failures of the power grid are increasingly common. The most visible example was the partial collapse of ERCOT, the Texas power market, in February 2021 during Winter Storm Uri. Large-scale load shedding was required to prevent a total system failure that would have shut power off across the state for far longer. Even with these measures, 69 percent of Texans reported losing power, almost half of Texans lost water service, and the cost to the state has been assessed at $80–130 billion.
Texas is not alone. In the summer of 2020, CAISO, California’s grid operator, initiated rolling blackouts to preserve system stability amid a severe two-day heatwave. The summer of 2022 witnessed a 10-day heatwave in which CAISO only very narrowly avoided blackouts; a mass text sent via the governor’s office calling for voluntary load reduction made the difference. In December 2022, Winter Storm Elliot brought extreme cold and tested power grid operators across the United States, causing two failures. Duke Energy initiated rolling blackouts affecting 500,000 customers over two days in North Carolina and South Carolina. The Tennessee Valley Authority (TVA) was likewise forced to initiate two sets of rolling blackouts amid the storm.
These headline-making events should not be written off as aberrations. Instead, they are confirmation of the increasing risk which grid operators are clearly communicating in public reporting. A brief stroll through these studies is illuminating.
The New England grid operator, ISONE, finds that decarbonization scenarios pose serious risks to resource adequacy: “with high electrification and more aggressive retirements of the existing flexible fleet, operating reserves may become deficient, and at times completely depleted. Modeling showed that by large margins, available resources were repeatedly unable to match their aggregate output to system demand.” This long-term risk is consistent with a near-term winter reliability risk, described recently by a Federal Energy Regulatory Commission (FERC) commissioner as “basically crossing our fingers and hoping.”
New York’s 2022 Reliability Needs Assessment states that “the reliability of the New York City area faces the greatest risk due to limited generation and transmission to serve forecasted demand,” adding that “the New York City grid as planned has limited transmission security margin in 2025 and approaches zero in ten years.”
Moving south into PJM, the power market covering 13 states from New Jersey to Illinois, a 2023 report details a series of trends which “present increasing reliability risks during the transition,” primarily centered around the fact that “retirements are at risk of outpacing the construction of new resources.” Lest the future be discounted, Winter Storm Elliot brought PJM to the brink of load-shedding, with a senior official describing the risk of rolling blackouts as “very real” in a situation update during the storm.
Heading west into MISO, a power market covering states from Louisiana to Minnesota, a 2022 “Regional Resource Assessment” study found “a continued near-term capacity risk, highlighting the immediate importance of coordinated resource planning and additional investment.”
Capacity adequacy is the central issue identified by these studies. In other words, is the pool of generation assets sufficient to meet electricity demand at any given moment amid any given set of circumstances? Grid operator’s answer to this fundamental question is increasingly uncertain. Too often, they are left scraping the bottom of the barrel of generation resources and are required to shift to controlled load shedding to maintain balance.
This state of affairs is at least a decade in the making. Across the United States, large numbers of coal, nuclear, and aging natural gas fired generators have been retired. In their place, the United States has deployed wind, solar, and combined-cycle natural gas generation. Today, the Inflation Reduction Act (IRA) and Biden administration policies accelerate aspects of this trend. Wind and solar deployment have been assured by rich and long-term production and investment tax credits in the IRA. Developers across the country are piling into interconnection queues to bring these resources onto the grid. Meanwhile, the Biden administration has directed the Environmental Protection Agency to overhaul coal emissions and pollution standards. These new, tighter regulations are expected to add significant costs to coal power production in the United States and drive an accelerated wave of plant retirements.
In some cases, the IRA has reversed trends. In the pre-IRA years, many nuclear power plants retired ahead of schedule due to poor economic conditions, and many more were preparing for such a fate. The new Nuclear Production Tax Credit contained in the IRA ensures the commercial viability of existing nuclear power plants and has halted the trend of nuclear plant closure. However, the pathway to new nuclear generation in the United States remains cloudy.
The net result of these trends is two overlapping energy transitions. A long-term transition toward carbon-free generation is underway and gathering steam, but a more immediate transition, from coal to gas, is far closer to completion. This leaves U.S. power grids increasingly reliant on natural gas generation. Looking ahead, modeling teams unanimously foresee a continued role for natural gas-fired generation as a key balancing resource.
Natural gas generation has a claim on reliability because, unlike intermittent wind and solar, it is a dispatchable resource. Unfortunately, it has also proven to be a significant liability in winter conditions. In winter storms Elliot and Uri, natural gas generation saw very high rates of unavailability in PJM and ERCOT, respectively. FERC has identified clear improvements to weatherization that would reduce these outages. This indicates that there is room to squeeze far more reliability out of existing natural gas plants. Investment into the pipeline network, both in terms of weatherization and expansion, would also help alleviate fuel availability issues that drive many outages.
However, these changes require investment and some type of cost-recovery mechanism. The U.S. power sector—regulators, industry, policymakers, and ratepayers—faces a paradox. How can it invest in a resource that is absolutely critical to grid reliability over the near and medium term, and yet that is also temporary and something to be transitioned away from? Too little investment will lead to serious grid-reliability risks. Too much investment unnecessarily delays the transition to clean energy and undermines environmental goals.
The politics of SB6 in Texas sit squarely within the context of this tricky problem. The SB6 approach resolves the stranded asset risk by implementing an out-of-market transaction; 10 plants are to be built, with guaranteed returns, paid for by ratepayers. This is a blunt policy instrument to a delicate problem. In bypassing all market mechanisms, it voids any competitive pressure to build or operate efficiently. It also reflects a “stab in the air” approach to right-sizing investment, given that it has no connection to price signals. Perhaps most flagrantly, it represents billions of dollars not invested where the need has been most clearly identified: winterization of plants and the pipeline network. This is a path that leads toward more noncompetitive government intervention in power markets, increased costs for ratepayers, and misallocation of capital which is crucially needed in so many other parts of the power grid.
An alternative approach would rely on well-designed price signals. This could take the form of a capacity market, a model in place in many other markets, which pays generators in advance to be available at times when the grid is most under strain. Revenues from this could be designed to cover costs associated with winterization investments. This would incent and guide needed investment but do so competitively from within a market construct. Getting this design right will not be without its own issues. In PJM, a fight is brewing over capacity market penalties charged to generators who failed to run during Winter Storm Uri. Despite this, PJM has fast-tracked an overhaul of the market to ensure it addresses the capacity adequacy problems it sees on the horizon.
Regardless of the challenges faced by PJM and other capacity market models, a move away from markets is in direct conflict with the undeniable benefits that competitive and transparent markets have delivered across the United States. Perhaps the best evidence of these benefits is a race toward markets in the Western interconnect, one of the last regions in the United States where organized power markets do not yet reign. The Texas power market has been accurately described as “a postcard from the future” of U.S. electricity—this applies equally to the political battles over its future. In Texas and across the United States, policymakers should aim to evolve the design of power markets to meet the challenges ahead rather than undercut them.
Cy McGeady is an associate fellow with the Energy Security and Climate Change Program at the Center for Strategic and International Studies in Washington, D.C.
