Fuel supply swings remain a major driver of U.S. electricity costs, even as energy markets have calmed from recent extremes. Natural gas, which fuels the largest share of U.S. power generation, continues to heavily influence wholesale electricity prices. When fuel supplies are tight or prices spike, power costs rise in tandem – as seen during 2022’s energy crisis. Conversely, easing gas, coal, and oil prices in 2023 brought some relief, with wholesale electricity prices moderating significantly. Volatility in fuel markets – whether from global events or domestic weather – will directly shape power price stability and consumer electricity bills in the next few years.
Natural Gas Prices and Global Fuel Market Trends
Natural gas price trends are central to the power market outlook. After surging to multi-year highs in 2022 (driven by the war in Ukraine and rebounding post-pandemic demand), U.S. natural gas prices fell markedly in 2023 thanks to milder weather and strong domestic production. This drop in fuel costs was a primary reason wholesale electricity prices declined and became less volatile in 2023–24. The U.S. Energy Information Administration (EIA) forecasts only a modest uptick in gas prices over the next two years as demand growth slightly outpaces supply. Henry Hub spot prices will remain below about $3.00 per million Btu in 2025.
However, uncertainty in global fuel markets could yet disrupt this calm outlook. Europe’s pivot away from Russian pipeline gas has made it a major buyer of liquefied natural gas (LNG), tightening worldwide supply. In 2022, European natural gas benchmarks soared to record highs, illustrating how international turmoil can send fuel costs surging. While U.S. gas prices did not reach those extremes, increased LNG exports mean domestic prices are now more exposed to global demand.
A harsh winter in Europe or Asia, or supply cuts by major exporters, could lift LNG prices and, in turn, raise U.S. natural gas costs. Regionally, infrastructure constraints also amplify volatility. In New England, limited pipeline capacity in winter can cause local gas shortages and price spikes, quickly translating into surging electricity prices. Similarly, parts of California have seen gas price jumps during supply bottlenecks. Ample U.S. supply has kept prices in check recently, but a sudden weather or geopolitical shock could quickly change the picture.
Regional Power Market Challenges
Different U.S. power regions face distinct fuel supply and infrastructure challenges that will affect price volatility:
ERCOT (Texas)
Texas’s isolated grid relies heavily on in-state natural gas generation alongside growing wind and solar capacity. Demand growth and extreme weather (summer heat or winter freezes) test its fuel-supply resilience. In 2024, power prices in ERCOT were relatively low due to cheap gas and a surge of new renewable generation. But more wind and solar also mean variability – a lull in output can quickly drive up prices.
A projected rise in gas costs in 2025 could put upward pressure on ERCOT’s wholesale rates. Texas regulators are implementing market reforms to curb volatility, notably a new Performance Credit Mechanism that rewards generators for being available during tight grid conditions. These measures aim to prevent repeats of the 2021 winter crisis. Still, fuel stability (especially gas availability during extreme cold) remains a key factor for price stability in ERCOT.
CAISO (California)
California is rapidly adding renewables but still depends on natural gas-fired power and imports during peak demand (especially hot summer evenings when solar output fades). The state’s prices have swung from record highs during heat waves and droughts to lows when demand is light. An unusually cool, wet 2023 – with no significant heatwaves and plenty of hydropower – kept California’s electricity prices in check. Going forward, the grid faces tight margins as some gas plants and the Diablo Canyon nuclear plant approach retirement.
California extended Diablo Canyon’s operation to bolster reliability and delayed certain plant retirements while rapidly expanding battery storage to cover evening hours. These actions should help moderate extreme price swings. However, if an intense heatwave or poor hydro year hits in the next couple of summers, California could see renewed volatility until more infrastructure and storage are in place.
PJM (Mid-Atlantic)
The PJM region has historically enjoyed ample generation and fuel diversity, which kept prices stable. But it is now coping with a wave of planned coal and nuclear retirements that may tighten reserves. A stark example of fuel risk came during Winter Storm Elliott in December 2022: frigid temperatures drove up demand while many power plants failed to deliver. About 24% of PJM’s capacity was offline at the peak, with gas-fired units making up roughly 70% of the outages.
In response, PJM is reforming its capacity market rules to ensure generators firm up fuel supplies and perform when needed. If severe winter weather or fuel disruptions occur, PJM could still experience price spikes in the near term. Otherwise, moderate conditions and lower fuel costs have recently kept its power prices in check. The region’s challenge will be adding reliable new resources fast enough to replace retiring plants and maintain comfortable reserve margins.
ISO New England
New England’s grid is the most vulnerable to fuel supply constraints. Over half of the region’s electricity is generated from natural gas, yet its pipeline infrastructure is limited and often maxed out in winter. During cold spells, gas is diverted for heating, leaving power plants short – a scenario that has triggered severe wholesale price spikes in past winters. Indeed, winter electricity prices will continue to be volatile under these fuel and weather constraints.
The region has arranged emergency measures like importing LNG and paying generators to stockpile oil or LNG, but these stop-gaps are costly and highlight the underlying vulnerability. New England’s electricity prices will remain tightly tied to winter fuel supply and global LNG conditions until new pipelines, transmission links, or non-gas energy sources are developed (all challenging endeavors).
Southwest Power Pool (SPP)
SPP is increasingly dominated by renewable wind power, which now provides over one-third of its electricity, while coal’s share continues to decline. Natural gas remains necessary for grid balancing, but abundant regional supply stabilizes fuel prices. The main challenge is transmission congestion: as wind capacity grows, limited transfer capacity forces curtailments during high-output periods, potentially leading to localized price spikes. Despite these issues, SPP’s low-cost wind generation generally keeps wholesale prices among the nation’s lowest, and retail rates remain favorable. Consumers can expect continued price stability, with only modest increases due to gradual infrastructure investments and occasional congestion-related adjustments.
Midcontinent Independent System Operator (MISO)
MISO is undergoing a significant resource transition as aging coal plants retire and are replaced by natural gas and expanding wind power. This shift is supported by robust fuel supplies and improved coordination with gas networks, keeping generation costs in check. However, limited transmission capacity between northern and southern regions can lead to localized price volatility during peak demand periods. Overall, MISO’s wholesale electricity prices are expected to remain moderate, with incremental retail rate increases as utilities invest in grid upgrades and new capacity. For consumers, this means relatively stable bills in the near term, punctuated by occasional spikes during extreme weather events.
New York Independent System Operator (NYISO)
NYISO faces a unique challenge as it transitions toward a cleaner energy mix while relying heavily on natural gas for reliability. With over 60% of capacity being gas-fired, fuel supply constraints—especially during winter—can lead to significant price spikes. Infrastructure issues, such as limited pipeline capacity and transmission bottlenecks between upstate renewables and downstate demand centers, further stress the system. While planned renewable projects and transmission upgrades are underway, near-term reliability still depends on dual-fuel plants and emergency measures. Consequently, NYISO wholesale prices and retail rates will likely remain above the national average, with periodic volatility during extreme weather, keeping consumer bills higher.
Impacts on Consumer Electricity Bills
Volatile wholesale prices eventually flow through to consumers, affecting monthly electricity bills for households and businesses. The fuel price spikes of 2021–2022 led to significantly higher electric rates in many areas. For instance, New England and California utilities raised retail tariffs sharply in late 2022 as power procurement costs surged. New England’s average residential electricity price hit almost 29 cents per kWh in 2023 – the highest of any U.S. region – primarily driven by expensive natural gas and fuel oil. By contrast, regions with steadier fuel supplies saw more modest rate increases.
Looking ahead, the trajectory of electric bills will mirror fuel trends, albeit with some lag. U.S. residential electricity prices rose about 4.8% in 2024, in line with increases over the previous four years. Any future run-up in fuel prices or significant supply disruption will eventually translate into higher utility bills. Businesses exposed to real-time energy rates could see particularly volatile costs, whereas residential customers in regulated states might experience more minor, delayed adjustments. If the current fuel market calms, electricity bill increases should stay modest in the near term – but consumers remain exposed to the risk of price jumps if another fuel crunch or extreme weather event strikes.
Mitigating Volatility and Long-Term Outlook
A range of actions is underway to temper power price volatility and strengthen supply resilience. Grid regulators are tightening market rules to ensure reliability under stress. For example, Texas’s PCM and PJM’s new capacity accreditation reforms aim to incentivize power plants to secure fuel and be available during peak emergencies.
Investments in infrastructure are also crucial. Efforts to upgrade gas pipelines and build new transmission connections could alleviate bottlenecks and let power flow to high-demand areas, dampening price extremes. Meanwhile, the push for clean energy and storage will play a growing role in stability. Renewable sources like wind and solar are not subject to fuel price swings. As they supply more power, the influence of fossil fuel volatility on overall electricity costs will diminish. Large-scale batteries are being deployed to buffer renewable intermittency and provide a backup supply when wind or solar output lulls. Over the next 1–3 years, as more projects clear the regional queues, there will be an increase in the build-out of wind, solar, and battery projects. These additions and measures, like keeping existing nuclear plants online longer in California, should improve the supply-demand balance and reduce the frequency of price spikes.
While these efforts will take time to materialize fully, they are laying the groundwork for more predictable electricity costs. If fuel markets stay stable and planned improvements proceed, the next few years should see fewer dramatic price swings, making electricity bills more manageable.
Disclaimer:
This article’s forward-looking projections and analyses are based on current market trends, available data, and expert forecasts. They involve assumptions and inherent uncertainties, and actual future outcomes may differ materially from those projected. This article does not constitute financial or investment advice.