US coal markets quiet as winter weather roils natural gas markets

Sufficient inventories and low seaborne demand combined to limit movement of US coal prices during January, even as Winter Storm Fern drove high gas heating and electricity demand in the second half of the month.

Firm natural gas prices are expected to support increased coal generation via gas-to-coal switching, driving stable or growing coal production through 2027. After 2027, the US coal market is forecast to face pressure from the expansion of zero-carbon electricity incentivized in part by broad-based tax credits. Overall, the S&P Global Market Indicative Power Forecast projects 36.5 gigawatts of coal plant retirements by 2035, despite recent orders to keep coal plants operating.

Coal plant generation share through 2035 is forecast to decline slowly, from 18.3% of total generation in 2026 to 8.4%. The phaseout of tax credits for solar and wind generation is forecast to slow their growth, allowing coal plants to run more after 2030 than previously forecast. The greatest production uplift will occur in the Powder River Basin (PRB), followed by the Illinois Basin (ILB), as reduced growth in wind and solar generation mainly affects the generation mix in the Midcontinental US.

➤ After rallying to close 2025, US coal prices held mostly flat in January, restrained by high inventories and low demand in the first two weeks of the year.

➤ The S&P Global Market Indicative Power Forecast anticipates 36.5 GW of coal plant retirements by 2035, down slightly from prior forecasts amid market pressure to retain existing generation. Market pressure is attributed to several factors, including high natural gas prices, high demand growth, delays in deploying new gas generation and slower growth of green generation.

➤ The production outlook varies by region, with the Powder River Basin and Illinois Basin expecting stable to slightly growing production through 2027, while Appalachian coal production is forecast to decline, due to falling domestic demand and limited export growth.

Coal prices were mixed during January, with domestic coal benchmarks mostly unchanged. CAPP region export benchmarks shed $1.00/short ton to $81.00/st (1.2%); NYMEX CAPP added 50 cents/st (0.6%) to $80.50/short ton; and NAPP Pittsburgh Seam 13,000 British thermal units/pound gained $2.50/st to $64.50/st (4.0%). Illinois Basin 11,500 mid-sulfur held at $51.75/st, while the NYMEX Powder River Basin benchmark held at $15.00/st.

Persistent cold weather, including heavy snow and ice, settled across the Eastern US during January, as the reach of Winter Storm Fern extended to states on the Gulf Coast. Natural gas prices soared with heating demand. Henry Hub spot gas prices opened January at a seasonal $4.00/MMBtu and declined to a mid-month low of $2.87/MMBtu before surging to a daily high of $30.72/MMBtu during the final week and closing the month at $10.25/MMBtu. Spot prices averaged $7.55/MMBtu for the month. Storage withdrawals were steady through mid-January ahead of the storm, with working gas at 3,065 billion cubic feet as of Jan. 16 — 177 Bcf above the five-year average and 141 Bcf above the same week of 2025.

The regional gas markets of the upper Midwest and Northeast US, with high gas-heating loads, saw prices rise to substantial premiums above Henry Hub. Chicago Gate averaged $10.21/MMBtu, a $2.66/MMBtu premium to Henry Hub. TCO Pool also moved to a premium of 84 cents/MMBtu for a monthly average of $9.39/MMBtu, while TETCO M3 went to a premium of $10.23/MMBtu for a monthly average of $17.78/MMBtu. With the Western US largely unaffected by the storm, SoCal Border averaged $3.13/MMBtu during the month, $4.42/MMBtu below Henry Hub.

The US Energy Information Administration estimated October 2025 coal stockpiles at 109 million st, growing nearly 4 million st from September. Growing inventories during the fourth quarter of 2025 likely provided a supply cushion for coal plants called on during the January storm.

Current forward pricing for PRB coal has been flat and stable, reflecting sufficient inventories at power plants and mining capacity to increase production as needed against firmer natural gas prices. After 2027, lower natural gas prices and declining coal demand are forecast to restrain price growth.

Bituminous coal prices are primarily influenced by export markets, with today's prices making domestic coal generation generally less competitive against Northeast natural gas. Firmer eastern natural gas prices nevertheless boosted domestic demand through the summer, even as seaborne coal demand declined by an estimated 7.7% from 2024 due to reduced demand from India and China.

Pricing benchmarks exceeding $65/st suggest sustainable returns for eastern bituminous coal, with Atlantic Basin export above that threshold and coal competing in Pacific Basin export markets generally below it. After declining in 2024, bituminous coal demand for electric generation is expected to remain stable through 2027 on higher electricity demand and more supportive natural gas prices. Declines in steam coal demand are expected to resume after 2027, and overall Eastern US coal demand is forecast to decline 47 million st in 2025–30.

Outlook for US coal production, demand

For the four weeks ending Jan. 24, coal shipments averaged 9.6 million st, 1.7% below 2025 levels. This continues the fourth-quarter 2025 trend of elevated inventories, keeping shipments in line with the prior year's levels, with only modest demand uplift. Shipments ended 2025 at an aggregate 535 million st, implying an overall inventory drawdown from year-end 2025 between 5-10 million st.

The chart below compares the current production forecast with recent history. We forecast increased coal demand against higher natural gas prices through 2027 with annual tonnage at 550 million st. Beginning in 2028, relative normalization of coal and gas pricing and growth in green generation is forecast to pressure coal generation lower. The overall coal market, including domestic demand and exports, is forecast to decline by 140 million st between 2026 and 2031.

Production outlook — Powder River Basin

Production reports of the Mine Safety and Health Administration (MSHA) through the third quarter of 2025 indicate production of 172.2 million st, an annualized rate of 229.6 million st. Production is now forecast at 230 million st in 2025, with higher inventories potentially constraining fourth-quarter production. Production is forecast to grow through 2027 against higher natural gas prices. By 2030, S&P Global Energy projects that coal retirements in the Midwest and expansion of wind generation in PRB's core markets will gradually shrink the coal demand to 204 million st, declining further to 177 million st through 2035.

Production outlook — Illinois Basin

MSHA's 2025 September quarter production reports indicate production of 50.6 million st, or an annualized rate of 67.5 million st. We forecast production will grow from 68 million st in 2025 to an annual 75 million st through 2027, after which the expansion of wind generation and announced coal retirements are forecast to erode ILB coal demand. Coal production in the ILB is forecast to fall to 65 million st by 2030, declining further to 50 million st by 2035.

Production outlook — Appalachian basins

MSHA's production reports for the year's third quarter indicate year-to-date production at 118.8 million st, or an annualized rate of 158.4 million st. Appalachian coal demand tends to be more sensitive to global seaborne markets than to domestic natural gas prices, unlike the PRB or the ILB, which are forecast for improved demand against natural gas generation. Therefore, gains in Appalachian coal will be more limited. We forecast 2025 production at 159 million st, just 0.6% higher than 2024. As remaining domestic demand erodes after 2027, with only modest offsets from export growth, Appalachian production is forecast to fall to 112 million st by 2030.

Further information

Market indicative coal forecasts by S&P Global Energy represent forward curves for spot-traded instruments, analogous to a strip of contracts. The shorter tenors — current year and prompt year, plus additional years, if available — are driven by the observed/assessed marker prices. The longer tenors — typically forecast years three to 20 for physically assessed markers — are driven by fundamental estimates of cash costs of production, accepted returns to capital, regional productive capacity, and forecast supply and demand. For the long-tenured portion of the curve, S&P Global Energy forecasts prices for specific coal markers and defines the remaining markers via historical spreads.

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