US domestic coal producers cited cost pressures and low demand as key factors weighing on earnings during the first quarter of 2026. While Asia-Pacific demand for coking and thermal coal could help narrow the gap, energy markets remain unsettled even as the Hormuz crisis eases. Elevated stockpiles following the spring shoulder season — the period of reduced electricity demand between winter heating and summer cooling — further pressured US coal prices throughout June.

Federal policy actions — including delayed coal plant retirements and funding for coal plant refurbishment and unit additions — have underpinned a more stable demand and regulatory environment for coal. Firmer natural gas prices in 2025 supported coal generation through gas-to-coal switching, the primary competitive dynamic between the two largest sources of US electricity, yet high coal stockpiles are forecast to constrain production through 2027. Beyond 2027, the US coal market faces renewed pressure from the expansion of solar and wind generation in regions where economics and state policies are supportive.

Over the longer term, the S&P Global Market Indicative Power Forecast projects coal plant retirements and reduced utilization. By 2035, 36.1 GW of coal-fired capacity is forecast to retire, with coal's share of total generation declining to 8.7% from 17.1% in 2027.

Price Declines Across Benchmarks

Coal benchmark prices fell during June amid high stockpiles and steady natural gas prices. Export benchmark prices led the declines: CAPP region export benchmarks settled at $82.00/short ton, down $4.00/st (4.7%); NYMEX CAPP fell to $80.00/st, also declining $4.00/st; and NAPP Pittsburgh Seam 13,000 British thermal units per pound held flat at $71.00/st. Domestic benchmarks also softened, with Illinois Basin 11,500 mid-sulfur dropping 75 cents/st to $55.25/st (1.3%), while the NYMEX Powder River Basin benchmark shed 50 cents/st to $14.70/st (3.3%).

Natural Gas Market Trends

Global crude oil and natural gas prices declined in June as the Hormuz crisis eased, but US natural gas prices remained largely unaffected, following normal seasonal trends. Henry Hub spot prices opened June at $3.04/million Btu and rose throughout the month on warm weather to close at $3.33/MMBtu, averaging $3.15/MMBtu for the month. Seasonal storage injections continued, with working gas at 2,835 billion cubic feet as of June 19 — 152 Bcf above the five-year average and 49 Bcf above the same week in 2025.

With gas availability holding steady, regional market discounts followed suit. Chicago Gate averaged $2.73/MMBtu, a $0.42/MMBtu discount to Henry Hub. TCO Pool's discount was $0.73/MMBtu for a monthly average of $2.42/MMBtu, while TETCO M3 moved to a $0.76/MMBtu discount for a monthly average of $2.39/MMBtu. In the Western US, SoCal Border again posted a nationwide low of $2.04/MMBtu during June, $1.11/MMBtu below Henry Hub.

Coal Stockpiles and Inventory Buildup

The US Energy Information Administration (EIA) estimated March 2026 coal stockpiles at 111 million st, 6 million st higher than February levels. This inventory growth serves as a lagging indicator of surplus coal carried over from the spring shoulder season. Elevated stockpiles effectively reduce the need for utilities to purchase additional coal, dampening near-term demand even as summer cooling loads begin to lift electricity consumption.

Regional Coal Price Outlook

Current forward pricing for Powder River Basin (PRB) coal has been flat and stable, reflecting sufficient power-plant inventories and mining capacity to absorb demand changes. 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 current prices making domestic coal generation generally less competitive against Northeast natural gas. The disruption in international energy markets has elevated export coal prices, likely through 2027. As natural gas prices normalize after 2027, coal prices are projected to ease.

Pricing benchmarks exceeding $70/st suggest sustainable returns for eastern bituminous coal, with Atlantic Basin export coal above that threshold and coal competing in Pacific Basin export markets generally closer to it. Bituminous coal demand for electric generation is expected to remain stable through 2027, supported by higher electricity demand and favorable natural gas prices. Declines in steam coal demand are expected to resume after 2027, with overall Eastern US coal demand forecast to decline by 50 million st during 2025–30.

US Coal Production and Demand Outlook

For the four weeks ending June 20, coal shipments averaged 9.5 million st, 8.3% below the same period in 2025. Relatively low shipments indicate that high inventories are constraining production even as summer demand begins to pick up.

Where overall production growth was previously forecast for 2026, S&P Global Energy now forecasts a modest year-over-year decline to 522 million st. Similar coal production is expected in 2027, with higher natural gas prices offset by robust inventories. Beginning in 2028, growth in green generation is forecast to pressure coal generation lower. The overall coal market — comprising domestic demand and exports — is forecast to decline by 109 million st between 2026 and 2031, a contraction driven by the combined effects of renewable capacity additions, plant retirements, and gradually normalizing natural gas prices.

Powder River Basin

MSHA production reports for the first quarter of 2026 indicate year-to-date production of 57.0 million st, an annualized rate of 228.0 million st. Production for 2026 is now forecast at 228 million st, slightly below 2025. Production is expected to remain elevated through 2028 against higher natural gas prices. S&P Global Energy projects that coal retirements in the Midwest and the expansion of wind generation in PRB's core markets will gradually reduce coal demand to 204 million st by 2030, declining further to 184 million st by 2035.

Illinois Basin

MSHA's first-quarter 2026 production reports indicate year-to-date output of 15.9 million st, an annualized rate of 63.6 million st. Production is forecast to grow modestly from 66 million st in 2026 to 68 million st through 2028, after which the expansion of wind generation and announced coal retirements are expected to erode ILB coal demand. Coal production in the ILB is forecast to fall to 64 million st by 2030 and further to 56 million st by 2035.

Appalachian Basins

MSHA's first-quarter 2026 production reports indicate year-to-date output of 39.2 million st, an annualized rate of 156.8 million st. Appalachian coal demand tends to be more sensitive to global seaborne markets than to domestic natural gas prices, compared with PRB or ILB. Consequently, the demand increase relative to natural gas generation expected to benefit PRB and ILB will be much more limited for Appalachian producers. Modest declines from 2025 levels are forecast through 2027. 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.

Forecast Methodology

Market Indicative coal forecasts by S&P Global Energy represent forward curves for spot-traded instruments, analogous to a strip of contracts. Shorter tenors — the current year and prompt year, plus additional years where available — are driven by observed or assessed marker prices. Longer tenors — typically forecast years three through 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 remaining markers via historical spreads.

Source: Platts / S&P Global Commodity Insights