Expand Energy grew output 3.9% to 7.48 Bcfe/d in Q2 2026, but lower gas prices and a much smaller paper gain on hedges cut GAAP net income 46% to $522M ($2.19/share), while adjusted EPS rose to $1.33 and it repaid $1.3B of debt.
Revenue
$3.0B
-19.8% YoY
Net income
$522M
-46.1% YoY
Diluted EPS
$2.19
-45.5% YoY
Operating margin
22.3%
Overview
Expand Energy (formerly Chesapeake Energy) is the largest independent natural gas producer in the US. In the second quarter of 2026 it produced more gas than a year earlier, but US gas prices were lower, and its GAAP (official accounting) profit fell by almost half to $522 million, or $2.19 per diluted share. That drop overstates the change in the business. Most of it comes from a smaller paper gain on the company's price hedges, explained below. Stripping out those accounting swings, the company's own adjusted net income rose to $317 million from $265 million.
Production averaged 7.48 Bcfe/d, up 3.9% from a year earlier. (Bcfe/d means billion cubic feet equivalent per day, with oil and gas liquids converted into their gas-equivalent energy.) Hedges that paid out in cash lifted the gas price the company actually received to almost exactly the Henry Hub benchmark. The company used cash on hand to repay about $1.3 billion of bonds, bought back stock, and after the quarter agreed to buy the gas marketer Twin Eagle for about $1.25 billion.
Key metrics
Metric
Q2 2026
Q2 2025
YoY Change
Total revenues and other
$2,960M
$3,690M
-19.8%
Natural gas, oil and NGL sales
$1,830M
$2,021M
-9.5%
Income from operations
$661M
$1,269M
-47.9%
Operating margin
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*Adjusted EPS, adjusted net income, adjusted EBITDAX, free cash flow and net debt come from the company's Q2 2026 earnings release (8-K Exhibit 99.1, July 28, 2026), not the 10-Q. "Total revenues and other" includes derivative gains ($449M vs. $877M), so it is not the same as sales of gas. Operating margin here is income from operations divided by total revenues and other.
Takeaway: The 46% drop in GAAP profit is almost entirely an accounting effect. A year ago the company booked an $842M unrealized (paper) gain on its hedges. This quarter that gain was only $153M. Underneath, the business did slightly better: adjusted EBITDAX was $1,183M vs. $1,176M, and adjusted EPS rose 21%. Cash hedge payouts of about $0.48/Mcf made up almost all of the fall in gas prices. What actually got worse is cost per unit: getting gas to market now costs more for each unit produced.
Why hedges swing the profit line
Expand locks in future selling prices for much of its gas through derivatives, mainly "collars" that set a floor and a ceiling on the price. In the income statement these show up in two ways:
Realized gains or losses are the cash the hedges actually paid out on gas sold this quarter. In Q2 2026, natural gas hedges paid out $304M (vs. $34M a year earlier), because Henry Hub fell below the company's floor prices.
Unrealized gains or losses come from re-valuing the hedges still open, based on where futures prices sit on the last day of the quarter. No cash moves. The figure rises when forward gas prices fall and drops when they rise. Natural gas unrealized gains were $122M this quarter vs. $825M in Q2 2025.
Across all commodities, total derivative gains were $449M vs. $877M. That $428M gap in pre-tax income is roughly equal to the whole $446M drop in net income. The company's adjusted figures remove the unrealized piece. They also remove a $37M gain from repaying bonds early (an accounting gain from writing off the bonds' unamortized premium, not a cash gain) and $68M of non-cash "contract amortization." Year to date, the swing works in the other direction: in H1 2025 the hedges showed a $137M net loss, so H1 2026 GAAP net income of $1,681M is more than double H1 2025's $719M.
Production by basin
Basin
Q2 2026 (MMcfe/d)
Q2 2025 (MMcfe/d)
Change
Q2 2026 gas price before hedges
Q2 2025 gas price before hedges
Haynesville (Louisiana/Texas)
3,187
2,978
+7.0%
$2.62/Mcf
$3.12/Mcf
Northeast Appalachia (Pennsylvania)
2,625
2,662
-1.4%
$2.15/Mcf
$2.65/Mcf
Southwest Appalachia (West Virginia/Ohio)
1,670
1,562
+6.9%
$2.47/Mcf
$3.11/Mcf
Total
7,482
7,202
+3.9%
$2.42/Mcf
$2.93/Mcf
Growth came from Haynesville and Southwest Appalachia. Haynesville matters most for export demand: its gas sells closer to Gulf Coast buyers, and in Q2 it earned the highest per-Mcf gas price of the three basins. Northeast Appalachia gas sold at a $0.75/Mcf discount to Henry Hub, the widest gap of the three, because Pennsylvania gas has limited pipeline routes to market. Southwest Appalachia is the only basin that also produces oil (14 MBbl/d) and natural gas liquids (NGL, 83 MBbl/d). Higher prices for both helped its all-in price reach $3.64/Mcfe.
The 10-Q splits the $191M decline in gas, oil and NGL sales into -$262M from prices (lower gas prices, partly offset by higher oil and NGL prices) and +$71M from higher volumes from new wells. During the quarter the company ran an average of 12 rigs, drilled 55 wells and brought 48 wells into production (release).
Per-unit costs are creeping up
Cost ($ per Mcfe)
Q2 2026
Q2 2025
Production (lease operating)
$0.25
$0.23
Gathering, processing and transportation (GP&T)
$0.93
$0.86
Severance and ad valorem taxes
$0.09
$0.08
General and administrative
$0.07
$0.06
Depreciation, depletion and amortization (DD&A)
$1.06
$1.17
GP&T, the fees paid to move and process gas through pipelines, is by far the largest cash cost. It rose $71M to $634M. The 10-Q attributes the increase to higher volumes, annual fee escalators, and the NG3 pipeline in Haynesville, which started operating on October 1, 2025. Production expenses rose because of higher saltwater disposal and well-repair (workover) costs in Haynesville. Taken together, the four cash cost lines above went from $1.23 to $1.34 per Mcfe. With gas selling at $2.42 before hedges, that increase takes a real share of the margin. The one cost that fell was DD&A, the accounting charge that spreads the cost of wells over the gas they produce. It dropped to $1.06 from $1.17 because higher prices used in the reserve estimates lowered the depletion rate.
Marketing (buying and reselling third-party gas) made a net $32M, vs. a $3M loss a year earlier. The company credits "optimization efforts" and higher marketed volumes. This is the business the Twin Eagle deal is meant to grow.
Cash flow, debt and shareholder returns
Cash item
Q2 2026
Q2 2025
H1 2026
H1 2025
Operating cash flow
$1,096M
$1,322M
$3,498M
$2,418M
Cash capital expenditures
$753M
$657M
$1,460M
$1,220M
Free cash flow (non-GAAP, release)
$343M
$665M
$2,038M
$1,198M
Q2 free cash flow (operating cash flow minus capital spending) roughly halved. Operating cash flow fell because of lower prices and a $45M working-capital outflow, compared with a $321M inflow a year ago. Capex also rose: the 10-Q points to more drilling in both Appalachia regions and more spending on new leases. Over the first half, free cash flow still reached $2.0B, helped by high winter prices during Winter Storm Fern that pushed the H1 realized gas price before hedges to $3.67/Mcf.
Debt: In April the company redeemed $847M of 6.75% notes and $440M of 5.875% notes, both due 2029, using cash on hand. Principal debt fell to $3,738M from $5,025M at year-end. Net debt (debt minus cash, release) is $3,075M, about 0.5x trailing adjusted EBITDAX of $5,658M. Quarterly interest expense fell to $43M from $60M. Fitch upgraded the notes to BBB on May 6, 2026. The company had $4.2B of liquidity and nothing drawn on its $3.5B credit facility.
Buybacks: 6.4M shares were repurchased in H1 for $601M including excise tax (10-Q). The release puts Q2 buybacks at about $530M and year-to-date buybacks through July 24 at $849M, about 4% of shares. On July 24 the board added $1.0B to the authorization, bringing the total to $2.0B.
Dividend: The base dividend stays at $0.575 per quarter ($2.30 a year). H1 dividends cost $279M, the same as last year.
LNG and data-center demand
The 10-Q says mild weather and strong supply held down US gas prices in H1 2026. It names three structural sources of new demand expected to tighten the market: new LNG (liquefied natural gas) export capacity, industrial onshoring, and "the rapid expansion of AI-powered data centers." The filing gives no volume of Expand's gas contracted to data centers, so the company's direct exposure to that demand cannot be measured from this report. It does disclose one concrete LNG link. In April, Expand signed a 20-year agreement with Delfin FLNG 1 to buy about 1.15 million tonnes per year of LNG, priced off Henry Hub, starting in 2031. The fixed parts of that contract are estimated at about $2.9B over its life. Earlier agreements with Delfin and Gunvor were terminated. The Twin Eagle acquisition (about $1.25B, to be funded with cash and credit-facility borrowings, expected to close in Q3 2026) adds marketing and logistics that management says extend its access to demand markets "from coast to coast."
Outlook
Guidance was unchanged: 7.4–7.6 Bcfe/d of production, $2.75–$2.95B of capital spending, 11–12 rigs, and 205–235 wells brought online in 2026. H1 production of 7,459 MMcfe/d and H1 cash capex of $1.46B put the company on track for both. Hedges put a price floor under more than 65% of expected gas volumes through the end of 2026. That protected Q2 and limits how much further price weakness can hurt in the second half.
Our read: volumes are up about 4% and adjusted earnings are up. There are two pressure points. First, rising per-unit transport and operating costs leave less margin at each price level. Second, the company is spending on several things at once: buybacks, Twin Eagle, and higher capex. Q2's $343M of free cash flow did not cover the quarter's roughly $530M of buybacks plus about $140M of dividends, so the gap came from the first half's earlier cash build. Buying Twin Eagle with borrowed money will push net debt back up from $3.1B. That leaves H2 results depending more on where Henry Hub goes than the 0.5x leverage figure suggests. Leadership is also in transition: Michael Wichterich has been interim CEO since February 2026, and Marcel Teunissen was named CFO in April.