For years, following the natural gas market was often enough to understand where electricity prices were headed. Since natural gas-fired generation frequently establishes the marginal cost of electricity, wholesale power markets across the country generally moved in the same direction. When gas prices rallied, power prices usually followed. When gas prices declined, wholesale electricity prices generally moved lower as well.
That relationship still exists, but it is becoming less predictive than it once was.
Over the past year, national natural gas fundamentals have generally become more favorable for buyers. Production remains robust, storage inventories are healthy, and near-term LNG feedgas demand has softened due to seasonal maintenance and export outages. While today's market remains well supplied, forward natural gas prices continue to increase in future years as expanding LNG export capacity is expected to strengthen long-term demand. Not all regional power markets, however, are reflecting that same longer-term outlook.
What changed?
Electricity markets are becoming far more regional. Natural gas still establishes the foundation for wholesale power prices, but each regional grid now layers its own mix of reliability costs, infrastructure investments, policy initiatives, and local supply-demand dynamics on top of that common fuel price. The result is one national natural gas market supporting several regional electricity markets that are increasingly behaving in different ways.
The Growing Importance of Non-Energy Costs
Energy itself, the electrons flowing into your home or business, are no longer the only significant component of wholesale electricity pricing.
When suppliers build a fixed-price electricity contract, they must account for a growing list of non-energy cost components that vary considerably by region. Capacity obligations, transmission investments, congestion, ancillary services, renewable integration, and other reliability-related costs have become much more significant over the past decade. In many markets, these costs are growing faster than the commodity itself.
Increasingly, wholesale electricity prices are being determined less by the cost of producing the next megawatt-hour and more by the cost of ensuring that megawatt-hour can be delivered reliably when and where it is needed.
That means two regions exposed to the same Henry Hub natural gas price can produce very different electricity prices because suppliers are managing entirely different risk profiles.
A Tour of Today’s Power Markets
ERCOT: Growth is the Story
Texas continues to experience some of the fastest electricity demand growth in the country. Population growth, industrial expansion, electrification, and hyperscale data centers are all pushing long-term load forecasts higher. At the same time, ERCOT continues adding record amounts of wind, solar, and battery storage, often reducing wholesale electricity prices during periods of strong renewable output while helping moderate price volatility during the evening ramp.
Natural gas infrastructure is changing as well. New pipeline expansions are allowing more Permian gas to reach premium downstream markets, strengthening West Texas basis and gradually reducing ERCOT's historical advantage of exceptionally inexpensive local fuel. While improving natural gas fundamentals have pressured near-term forward prices lower, continued load growth and evolving regional gas dynamics continue supporting longer-term contracts.
Unlike most eastern markets, ERCOT does not operate a centralized capacity market, giving it a cost structure that looks very different from PJM or ISO New England.
PJM: Reliability Comes at a Price
PJM's biggest challenge is maintaining reliability as electricity demand accelerates.
Rapid data center development, increasing electrification, and the retirement of dispatchable generation have significantly increased the value of reliable capacity. Recent capacity auctions have reflected that reality, producing some of the highest capacity prices the market has seen.
At the same time, billions of dollars are being invested in transmission upgrades to accommodate changing generation patterns and growing demand. Those investments improve long-term reliability but also become part of the total cost suppliers must recover when pricing retail electricity. Aging infrastructure and changing power flows are also increasing congestion costs across portions of the PJM footprint, creating wider pricing differences between locations than many buyers have historically experienced.
While natural gas continues to drive wholesale energy prices, capacity, transmission, and congestion have become increasingly important drivers of total electricity costs.
NYISO: Infrastructure and Policy Shape the Market
New York occupies something of a middle ground.
The state continues investing heavily in transmission, energy storage, and other clean energy initiatives while maintaining reliability in one of the nation's largest urban load centers. The Champlain Hudson Power Express (CHPE) now delivers up to 1,250 MW of Canadian hydroelectric power directly into New York City, increasing supply into the constrained downstate region. While CHPE does not eliminate New York's structural challenges, it improves supply diversity, helps ease transmission congestion, and should gradually reduce some of the localized price pressures that have historically characterized downstate electricity markets.
Source: NYSERDA
New York also maintains some exposure to geopolitical developments. While the state relies far less on imported LNG than New England, downstate pipeline constraints, dual-fuel generation units, and winter reliability concerns mean that stronger global LNG or oil prices can still contribute to higher winter risk premiums, particularly during periods of heightened international uncertainty.
ISO New England: Where Global Markets Meet Local Reliability
No U.S. electricity market is more closely tied to global energy markets than ISO New England.
Limited natural gas pipeline capacity means the region continues relying on imported LNG and oil-fired generation during periods of extreme winter demand. As a result, geopolitical events that influence global LNG prices, oil markets, or international shipping can affect New England electricity forwards even when domestic natural gas fundamentals remain relatively favorable.
At the same time, projects such as the New England Clean Energy Connect (NECEC) transmission line are expanding access to Canadian hydroelectric generation, helping diversify the region's resource mix. However, offshore wind, once expected to become a cornerstone of New England's long-term supply strategy, has encountered rising construction costs, supply chain challenges, permitting delays, and higher financing costs. Those headwinds have reinforced the region's continued dependence on natural gas while extending the timeline for its energy transition.
Those global influences are layered on top of local infrastructure constraints, creating one of the country's most unique electricity markets. While summer weather certainly matters, winter fuel security often has the greatest influence on long-term pricing.
MISO: Managing the Energy Transition
Across the Midwest, MISO continues navigating one of the nation's largest generation transitions. Coal-fired power plants that historically supplied dependable, around-the-clock electricity are steadily retiring, while renewable generation and battery storage continue expanding. Replacing dispatchable coal generation with more weather-dependent resources requires substantial transmission investment, additional operating reserves, and increasingly complex reliability planning.
As renewable penetration grows, transmission expansion, congestion management, and seasonal reliability planning are becoming larger components of electricity pricing. Like several other regions, MISO is gradually shifting a larger share of wholesale electricity costs away from fuel and toward maintaining grid reliability.
CAISO: A Different Kind of Reliability
While Texas leads the nation in total renewable electricity generation, California remains a primary laboratory for grid decarbonization, battery integration, and utility modernization. Massive volumes of solar generation have fundamentally altered California's daily pricing patterns, driving midday wholesale prices to zero or below while the nation's largest battery fleet helps manage the steep evening ramp following sunset.
California is also expanding regional market coordination through the Western Energy Imbalance Market (WEIM) and the forthcoming Extended Day-Ahead Market (EDAM). By allowing utilities across the West to share generation over a larger geographic footprint, these markets aim to reduce congestion, improve renewable integration, and make better use of existing transmission infrastructure.
At the same time, heavy investments in wildfire mitigation, transmission upgrades, and grid modernization continue contributing to one of the country's highest-cost electricity markets. California demonstrates that building a cleaner grid introduces its own set of operational challenges and infrastructure costs.
What Should Energy Buyers Watch?
For commercial energy buyers, understanding regional market dynamics has become just as important as monitoring natural gas.
Beyond Henry Hub, buyers should also pay close attention to:
- Capacity market changes
- Data center growth and large-load connections
- Transmission expansion projects
- Renewable and battery deployment
- Pipeline additions and regional basis trends
- Congestion and ancillary service costs
- State regulatory and policy changes
- Geopolitical events that may affect LNG and oil markets, particularly in the Northeast
These factors now play a much larger role in determining how each regional electricity market responds to changes in natural gas prices.
Natural gas remains the single largest driver of wholesale electricity prices across much of the United States, but it no longer tells the entire story.
Every regional grid is solving a different set of challenges. Some are managing explosive load growth, others are investing in transmission, integrating renewable resources, reforming capacity markets, or addressing winter fuel security. Those decisions create regional risk premiums that often influence electricity prices independent of the underlying commodity.
The result is a market where one national natural gas price supports several distinct regional electricity markets, each with its own drivers, risks, and opportunities. For energy buyers, understanding those regional differences has become essential to developing a sound procurement strategy. Looking only at natural gas may explain where the market starts, but understanding your local grid is increasingly what explains where your electricity price ends.
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