The price of fossil fuels – oil, gasoline, and methane gas – is a hot topic as the US is once again involved in conflict in the Middle East. Southeastern utilities are simultaneously doubling down on one of these fuels – methane gas – for electricity generation, so price risk to ratepayers should also be top of mind for regulators. But international conflict isn’t the only thing that affects the price of methane or fossil gas (often deceptively called natural gas). Methane gas prices are influenced by a myriad of issues, foreign and domestic, that converge uniquely at every moment. This makes predicting prices very difficult beyond the general expectation that they will rise, so a methane gas price influence “primer” might be helpful.
First, it is important to remember that the price that an electric utility pays for methane gas to burn in power plants is passed straight through to ratepayers. Utility shareholders do not share in any of the gas price risk. The cost of the gas flows straight to bills via a mechanism called a “fuel rider.” This creates a moral hazard and a commitment by our utilities to ever-escalating electricity bills.
Second, there are shorter-term influences (weather, storage, associated gas, force majeure) and there are longer-term influences (domestic competition from other utilities, LNG export terminals, and data centers, as well as producer consolidation, basin egress, and Tier 1 depletion). The key takeaway is that shorter-term influences will bounce methane gas prices up and down, but the longer-term influences only send prices upward over time. This puts electric utility customers at risk in the short run because when a utility hedges against price increases, its customers lose out on short-term price decreases; and in the long run, the only price direction is up.
Shorter-Term Influences
Weather
Generally speaking, extreme cold or hot weather raises prices and mild weather lowers them. Gas prices can spike during summer weather events, such as hurricanes that disrupt supply and pipeline operations in the Gulf of Mexico region, and they can spike during winter weather events, such as Winter Storm Elliott in 2022 and the prolonged cold snap and Winter Storm Fern in late January of 2026. Winter events disrupt supply for several reasons. Wellheads can freeze (a significant problem during both Winter Storm Uri in Texas in 2021 and Winter Storm Elliott on the East Coast in December of 2022). Methane gas has small amounts of water vapor that can freeze in the pipelines and in the production and compression equipment. This reduces the amount of gas that can be supplied to the pipelines during a timeframe when demand for power burn is at a peak. Reduced supply and increased demand results in high prices. And while gas producers and pipeline operators have improved weatherization of equipment, it is impossible to completely eliminate this risk. During the January 2026 demand spike associated with Winter Storm Fern, gas prices still shot up, even higher than during Winter Storm Uri despite far fewer freeze-off constraints, as illustrated below. LNG export capacity demand (discussed below) grew between Uri and Fern, from 9.7 Bcf per day in 2021 to 15 Bcf per day in 2025, increasing price pressures on methane gas molecules during Fern.
Storage
Methane gas is stored in large salt caverns along the Gulf Coast and also in compressed liquid form in above-ground storage tanks (called LNG storage). Salt dome storage has much greater capacity than the above-ground tanks and is therefore the larger influence on market prices. Storage data is tracked and reported by the US Energy Information Agency (EIA). (Above-ground LNG storage is used to address supply and price issues on a more site-specific or regional basis.) Gas is stored when supply is plentiful (and less expensive) and it is withdrawn when demand on the system is higher, such as during winter cold snaps and summer heat waves (so weather and storage can be interdependent). Storage supplements what can be produced in the field at any given time. East Daley Analytics recently posted an article, “Storage Deficits Are the New Reality, Putting a Strain on Gas,” explaining how Winter Storm Fern impacted storage drawdowns and price spikes, noting “The massive drawdown since late January reflects the toll of spiraling heating demand and lost production from wellhead freeze-offs.” In contrast, the EIA reported in its latest Short Term Outlook “Prices in the early part of our forecast are lower because of milder-than-forecast temperatures in February that left more natural gas in storage than we expected.”
In the East Daley graph below, historical storage deficits are on the left side, historical storage surpluses are on the right side, and the Henry Hub price is on the vertical axis. Henry Hub is a large, interconnected pipeline distribution area in Louisiana that is frequently used as a transparent market reference price. In this graph, the relationship between EIA storage data and the Henry Hub gas price is clear.
Associated Gas
The methane gas in some basins is what is called “associated gas.” It exists along with oil (in contrast, when methane gas is found without oil or other petroleum liquids, it is called “dry” gas). When both oil and methane gas prices are too low to be economic to capture and move this gas, rigs are idled. High oil prices, on the other hand, can result in increased methane gas supply to the market, but some very productive basins such as the Permian do not yet have enough pipeline capacity to move the associated gas quickly to market. When oil prices are high, the gas is produced regardless of the ability to move it, and this sometimes causes negative prices in that region as producers must pay to have the gas taken away (or they flare it). The EIA expects the high oil prices caused by the conflict in the Middle East and the closure of the Strait of Hormuz to result in more associated gas entering the market, having a short-term downward pressure on prices. This is a shorter-term influence because 1) more take-away pipelines are nearing completion and 2) the low gas prices are attracting in-basin power generation for data centers (discussed below).
Force Majeure
Force majeure refers to an event that forces a major part of the gas supply system to go offline and that has a significant impact on supply. Wellhead and compressor station outages are common causes of force majeure events, as are unexpected maintenance shutdowns and accidents such as leaks that require a section of a pipeline to shut down . These events will cause price spikes in the markets that are downstream from them if they force pipeline customers (such as gas plants and local gas companies) to scramble to replace their contracted capacity on that pipeline during the event. A large force majeure event on a major pipeline such as Transco could cause significant price disruption depending upon how long it lasted. These events are posted on the impacted pipeline’s electronic information bulletin board. One recent example of an event on Transco in Pennsylvania occurred in December of 2025, during which west-to-east flows faced cuts of 30% to 40% with impacted shippers being required to take “operational actions” during the event.
Long-Term Influences
Domestic Competition
Utilities
Utilities that rely on natural gas for a significant portion of their generation portfolio are increasingly competing with 1) each other, 2) LNG export demand, 3) data centers. How domestic supply keeps up with this speculative demand pull remains to be seen and is therefore a risk. Duke is proposing to add 9,648 MW of new gas plants by 2033; in addition to contracts with existing gas plants, Georgia Power is planning to construct 4,991 MW by 2031, Dominion Energy South Carolina and Santee Cooper are proposing to build a 2,200 MW combined cycle power plant by mid-2033, and Santee Cooper is proposing to add an additional 1,296 MW by 2036. There are also plans to build new gas generation in Florida, Alabama, and Mississippi, and various electric cooperatives and merchant power plant companies such as Southern Power Company plan to add generation. If the demand materializes enough to justify operating all of these plants at a high capacity factor, then Southeastern utilities will be competing against each other for gas molecules to burn.
Liquefied Natural Gas (LNG) Exports
The utilities will also be competing with LNG export facilities for molecules (but the LNG facilities will chill and liquify the gas molecules for export to other countries). This is particularly relevant for the Southeastern utilities because they are geographically closest to the Gulf and East Coast LNG export facilities and are therefore in more direct competition for molecules that originate in the Appalachian Basin and in the Gulf region basins. Due to strong worldwide demand for LNG (and the plentiful supply in the US), significant expansion of LNG export capacity is planned (see the graph from the Institute for Energy Economics and Financial Analysis, below), ensuring that competition for molecules will only intensify, pushing prices up. This may also cause short-term price spikes during extreme winter weather events to reach ever higher, as discussed in the Weather section above.
LNG exports create additional upward price risk because the price that exporters can command for LNG cargoes is significantly higher than the price to produce the gas in the US (and higher than domestic hub prices). We covered this price differential in more detail in our paper Southeast Electric Bills Are Paying for a Highway to Export Gas. The difference between what an international buyer is willing to pay less what it costs to produce and ship an MMBtu of gas is called “netback,” and the higher the netback, the more upward pressure will be placed on US fossil gas molecule prices. A recent snapshot of the netback spread for the forward curve is shown below (and this snapshot is prior to US military actions in Iran).
The trading markets referenced above are Japan/Korea or JPN/KOR, the United Kingdom or GBP, and the general European benchmark or TTF. LNG export is clearly profitable. And like the US, there are storage facilities worldwide that are filled with US gas when prices drop and that are drawn down when prices rise or there are demand peaks. Increased worldwide reliance on US LNG also subjects domestic methane gas prices to significant volatility when world events affect this relationship (Ukraine, tariffs, the possibility of removal of sanctions on Russian gas, etc).
Data Centers
Extremely large data center campuses, planned to be built with on-site gas generation, are a brand new direct competitor for gas molecules, and data centers have very deep pockets. They can generally afford to pay what is necessary in order to get up and running as fast as possible (this is often called “speed to compute”). The opportunity is so potentially lucrative that some gas pipelines and producers, such as Willians and Chevron, are getting directly into the business of supplying not just gas, but power, to large data center campuses.
Williams, parent of Transco Pipe Line LLC, is building a total 400MW data center, called Project Socrates, in New Albany, Ohio, for Meta. It is expected to be online by the end of 2026. Chevron, a gas producer in the Permian Basin, is expected to make a final investment decision soon on a 5,000 MW data center in West Texas. That project is targeting a 2027 in-service date. Vertically integrated producer EQT, the largest producer in the Appalachian Basin, landed a contract to supply up to 665,000 MMBtu directly to a data center developer in Pennsylvania for a 4,400 MW gas plant. These projects are being built “in basin” and leverage the infrastructure and relationship advantages that these companies have, and they can be up and running (and consuming molecules) faster than data centers that must wait for utility infrastructure to catch up. Data center campuses become direct consumers of methane gas molecules and therefore direct competitors.
Producer Consolidation
Mergers and acquisitions between methane gas producers have the potential to drive up prices as competition is reduced. This is already evident in the Appalachian Basin where EQT is the dominant producer. EQT, which just acquired Olympus for $1.8 billion in 2025, has so much market power that it can constrain production when gas prices dip too low, effectively driving prices back up into comfortable profitability (the company calls it “strategic curtailment”).
In October 2024, two of the top producers in the Appalachian Basin, Chesapeake Energy and Southwestern Energy, merged to form a new company called Expand Energy, which is now the second biggest producer in the Appalachian Basin after EQT. In the Permian Basin, producer Devon Energy has announced plans to acquire Coterra Energy for $21 billion, a deal that would create “one of the largest shale producers in the world.”
Oil Price Intelligence reported that gas consolidation deals in the US amounted to $30 billion in January-September 2025, higher than 2024’s $22.5 billion total. If the Devon/Coterra deal goes through, 2026 will likely dwarf last year.
All of this amounts to pricing power. As competition among producers diminishes, those producers increasingly have the ability to set the price of a commodity that Southeastern utilities are becoming increasingly dependent upon. In an environment with significant competition among producers, an increase in demand should create some upward pressure on prices and incentivise increased supply, creating pricing stability, all things equal. But when production becomes consolidated into the hands of a few, the free market model no longer works, and captive utility customers pay the price.
Basin Egress
Utility and pipeline witnesses often state that more pipelines will lower prices by increasing access to supply. This was a dominant narrative justifying EQT’s Mountain Valley Pipeline Mainline and Southgate projects – that increasing access to Appalachian Basin gas will lower prices. The fact is that the opposite is true. Increasing pipeline egress from basins actually raises prices by increasing access to more valuable markets such as LNG export and the competing utilities and data centers in the Southeast.
The perfect real-time example of this is the Permian Basin and the “associated gas” mentioned above. The Permian has historically had an abundance of oil and liquids pipeline egress leading to processing and markets, but the associated gas had almost no value because it had no pipeline gathering and egress pipelines. No market access means no value, and the gas was flared. As pipelines are now being built to move Permian associated gas to processing and markets, the pricing at the Waha Hub is expected to rise. Likewise, Mountain Valley Pipeline, which flows into Transco, increases access of Appalachian Basin molecules to Gulf LNG export markets and Southeastern utility demand competition.
Tier 1 Depletion
Shale gas basins are loosely rated by quality, and Tier 1 basins are the highest quality and the most productive. Tier 1 basins are the “easy” (and therefore “cheap”) gas. As Tier 1 basins are depleted, methane gas will become harder to recover and more expensive. Natural Gas Intelligence’s Patrick Rau, senior vice president of strategy and analysis, explained it succinctly:
“The expected increase in demand, especially via data centers and LNG, will continue to deplete U.S. gas reserves, especially the Tier 1 acreage. All else being equal, that will require producers to move to higher cost locations to compensate, which they will not do unless prices warrant it.”
Technology does continue to improve and adapt to challenging geological conditions, but at some point, extracting methane gas will become more difficult and more expensive. Producers are already noting that continued expansion of drilling will necessitate the manufacture of new equipment, which further adds to the cost of future methane gas extraction.
Nowhere to Go But Up
There is a saying in the gas markets analysis business: “Future prices are no indication of future prices.” Analysts readily acknowledge the complexity of forecasting the price of methane gas molecules at any given future point in time. The only verifiable direction is up, due to the influences listed above. Methane gas is a fuel. It is subject to the limits of physics, and once it is extracted, transported, and burned, it is gone forever. To keep methane gas plants running, we must go find, extract, and transport more methane gas molecules that are 1) a finite commodity and 2) becoming increasingly elusive.
Any utility executive who testifies before a regulatory body with assurances that gas supply will respond to price signals to meet demand to keep prices steady is simply wrong. Demand pressures are building, and competition for molecules includes players with far deeper pockets than utility ratepayers, and this will place upward pressure on prices. Increasing competition for molecules will also make the short-term spikes even higher. The gas exploration and production industry is consolidating, giving the suppliers more pricing power to push prices and profits up.
But our Southeastern utilities are choosing to double down on gas. Their shareholders have no skin in the game, no risk. Ratepayers – electricity bill payers – shoulder the entirety of the risk. This is occurring at a time when 1) renewables and battery storage are still getting cheaper while gas construction costs skyrocket, 2) technology is making demand-side and distributed resources even easier to coordinate as a dispatchable resource, 3) multi-day dispatchable energy storage is ready and being deployed in other parts of the country, 4) better transmission interconnections can help us share resources efficiently with neighbors near and far, and 5) the sun and wind are still free.
The sun and the wind will always be free.
