ConocoPhillips doubled Q2 2026 net income to $3.93B ($3.23 per share) as its realized crude price rose 55% on Middle East supply disruptions, even though production fell 6% to 2,248 MBOED.
Revenue
$19.2B
+36.8% YoY
Net income
$3.9B
+99.4% YoY
Diluted EPS
$3.23
+107.1% YoY
Oil at $100 doubled the profit, even as volumes fell
ConocoPhillips' net income roughly doubled in the second quarter of 2026, to $3.93 billion ($3.23 per diluted share) from $1.97 billion ($1.56) a year earlier. Almost none of that came from producing more: output actually fell 6%, to 2,248 thousand barrels of oil equivalent per day (MBOED, which converts oil, gas and gas liquids into one "barrel-equivalent" unit). What changed was the price of oil. Brent, the international benchmark, averaged $104.52 a barrel versus $67.82 a year earlier (+54%), which the 10-Q attributes to "Middle East supply disruptions that began in the first quarter of 2026" that persisted through the second.
The mechanics are simple: a producer like ConocoPhillips is a price-taker. Its cost of pumping a barrel barely moves when oil prices jump, so most of each extra dollar per barrel drops straight to profit. The company also says plainly that it is unhedged, meaning it doesn't lock in prices in advance with financial contracts, so it keeps the full upside (and would take the full downside). Of the $5.16 billion rise in sales revenue, the filing credits $3.73 billion to higher crude and bitumen prices, partly offset by $409 million from lower volumes.
Metric
Q2 2026
Q2 2025
YoY Change
Sales and other operating revenues
$19,161M
$14,004M
+36.8%
Total revenues and other income
$19,522M
$14,740M
+32.4%
Net income
$3,931M
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Pre-tax margin (pre-tax income / total revenues and other income)
31.2%
20.5%
+10.7 pts
Total production (MBOED)
2,248
2,391
-6.0%
Average realized price ($ per BOE)
$62.33
$45.77
+36%
Realized crude price ($/bbl)
$99.40
$64.23
+55%
Realized natural gas price ($/mcf)
$2.58
$4.16
-38%
Revenue here is "sales and other operating revenues" from the income statement; "total revenues and other income" also includes earnings from joint ventures, gains on asset sales and other income. ConocoPhillips' income statement has no "operating income" line (interest expense sits inside total costs), so no operating margin is shown; the pre-tax margin above is our own calculation from the income statement. Adjusted EPS comes from the company's Q2 earnings release (8-K Exhibit 99.1, Aug. 6, 2026), not the 10-Q.
Takeaway: This quarter was a price story, not a growth story. Production fell 143 MBOED year over year (98 MBOED, or 4%, after stripping out assets bought and sold), yet profit doubled because the realized crude price rose 55%. The earnings power is real but borrowed from the oil market: the same unhedged exposure that added about $3.7 billion of revenue this quarter works in reverse if Middle East supply normalizes.
The year so far
For the first six months, sales and other operating revenues were $34,922M vs $30,521M (+14.4%), net income $6,114M vs $4,820M (+26.8%) and diluted EPS $5.00 vs $3.79 (+31.9%). The half-year gains are much smaller than the quarter's because the price spike was concentrated in Q2: the realized crude price averaged $86.60 for the half versus $99.40 in Q2 alone. The earnings release puts the six-month total realized price at $56.37/BOE, up 14%, and six-month adjusted EPS at $5.13 vs $3.52.
Where the barrels come from
Segment
Q2 2026 production (MBOED)
Q2 2025
Change
Q2 2026 segment net income
Q2 2025
Lower 48 (US shale)
1,479
1,508
-1.9%
$2,584M
$1,399M
Alaska
185
205
-9.8%
$522M
$135M
Canada
152
191
-20.4%
$320M
$149M
Europe, Middle East & N. Africa (consolidated)
215
208
+3.4%
$346M
$237M
Asia Pacific (consolidated)
70
70
0%
$389M
$330M
Equity affiliates (derived: total minus segments)
147
209
-29.7%
included above
included above
Corporate and other
n/a
n/a
n/a
-$230M
-$279M
Total
2,248
2,391
-6.0%
$3,931M
$1,971M
The equity-affiliate production row is our own subtraction of the five segments' consolidated volumes from the company total; it covers joint ventures such as the Qatar LNG and Australia Pacific LNG (APLNG) stakes, whose earnings are included in the segment profit figures.
Lower 48 is two-thirds of the company. The earnings release breaks it down as 720 MBOED from the Delaware Basin, 202 from the Midland Basin, 363 from the Eagle Ford and 189 from the Bakken, and CEO Ryan Lance cited "record production" from the Permian. The small segment-wide decline reflects "normal field decline and dispositions of assets in 2025," partly offset by new wells. Higher crude and gas-liquids prices added $1,892M to segment earnings, but gas pulled the other way: the Lower 48's realized gas price averaged negative $1.44 per mcf (vs +$1.60 a year ago), costing $459M. A negative average price means that, on balance, the company effectively paid to have that gas taken off its hands; the filing itself only says "lower gas realizations." Lower 48 also lapped a $254M gain on an asset sale in the prior-year quarter.
Canada fell 20% largely because oil prices rose. Royalties at the Surmont oil-sands project run on a sliding scale from 25% to 40% of revenue, indexed to WTI, and a 2025 "post-payout" event pushed the rate higher, so a bigger slice of each barrel now goes to the Alberta government as royalty, shrinking ConocoPhillips' net volumes. Bitumen output dropped from 144 to 115 thousand barrels a day. Earnings still more than doubled to $320M on a 55% higher bitumen price ($61.01/bbl), net of a $58M pending claim.
Alaska earnings nearly quadrupled to $522M on $480M of higher realized prices (crude realized $108.49/bbl), despite a 20 MBOED volume drop from natural field decline.
Qatar is the swing factor. The 10-Q says the company's Qatar LNG facilities "have not been damaged, though production remained constrained through the second quarter of 2026" amid the conflict involving Iran. Equity-affiliate gas volumes fell to 865 million cubic feet a day from 1,150, and the earnings release names "the impact of the Middle East conflict on Qatar and higher Surmont royalties" as what more than offset Lower 48 organic growth. Qatar was about 4% of company production in 2025.
Costs: the Marathon Oil deal shows up in depreciation, not in cash costs
Production and operating expenses fell $141M to $2,431M, which the filing puts down to "increased efficiencies." In the second half of 2025 the company announced more than $1 billion of cost reductions and margin improvements on a run-rate basis by year-end 2026; the 10-Q doesn't quantify progress against that figure or break out Marathon Oil synergies separately.
Depreciation, depletion and amortization (DD&A, the accounting charge that spreads the cost of wells and fields over the oil they produce) rose $145M to $2,983M, "driven by higher net book values from the finalized allocations of our Marathon Oil purchase price to specific assets and lower proved developed reserves as of December 31, 2025." In plain terms: the acquisition put the acquired fields on the books at a higher value, so each barrel produced now carries a higher non-cash charge.
Corporate G&A fell to $110M from $147M, "primarily due to the absence of transaction and integration expenses associated with our acquisition of Marathon Oil," meaning the one-time deal costs are now behind it.
Taxes other than income taxes rose to $793M from $572M. Production and severance taxes scale with the value of what's pumped, so this is a direct cost of higher prices. The income tax provision more than doubled to $2,151M (a 35.4% effective rate vs 34.7%, our calculation).
Interest and debt expense dropped to $182M from $232M; net interest expense fell on "higher interest income and higher capitalized interest."
Cash, capital spending and shareholder returns
Cash from operations: $7.4B in Q2 under GAAP; the earnings release puts cash from operations excluding working-capital swings (a non-GAAP measure) at $7.2B. For the half, operating cash flow was $11,729M vs $9,600M, which the 10-Q attributes to "higher commodity prices, partly offset by working capital timing."
Capital expenditures and investments: $3.0B in Q2, with "over half" going to short-cycle Lower 48 shale. First-half spend was $5,972M, down 10% from $6,664M, with Alaska ($1,861M, including the Willow development on the Western North Slope) the second-biggest bucket after Lower 48 ($3,145M). Full-year 2026 guidance is unchanged at about $12-12.5 billion vs $12.6B spent in 2025.
Shareholder returns: $3.0B in Q2, made up of $2.0B of buybacks (the release says repurchases doubled from Q1) and $1.0B of dividends. First-half buybacks were $3,006M (26.3 million shares) and dividends $2,057M. By our arithmetic that is about 40% of the first half's $12.6B of cash from operations excluding working capital; the company says it is "on track for 45% return of CFO in 2026," which implies a heavier second half. The diluted share count fell 3.6% year over year to 1,214 million, so per-share earnings grew faster than total earnings. The Q3 dividend was declared at $0.84 per share.
Balance sheet: total debt of $23.3B against $7.7B of cash and short-term investments plus $1.2B of long-term debt securities; debt-to-capital 26%. Credit ratings are A (Fitch), A- (S&P) and A2 (Moody's), all with stable outlooks.
Portfolio moves: selling US assets, buying into the Middle East
Asset-sale target hit early: in Q2 the company agreed to sell noncore Lower 48 assets for about $1.7 billion (they produced about 21 MBOED in 2025 and were carried at about $1.5B as held for sale at June 30). The deals closed in July, which the company says completes its $5 billion disposition target ahead of the year-end 2026 deadline. The cash arrives in Q3; first-half disposal proceeds were only $190M.
Iraq: in July it agreed to buy a 42% stake in a bp joint venture redeveloping four producing oil fields around Kirkuk, for $0.3-0.5B at close plus $0.2B deferred, expected to close by end-2026.
Syria: a June agreement to restore and expand production at certain gas fields, with no material impact expected in 2026.
LNG (liquefied natural gas, shipped by tanker): new agreements lifted its commercial LNG offtake from 10.2 to 12.2 million tonnes a year, and the company added roughly $7 billion of long-term LNG and shipping purchase commitments in 2026. It holds 30% of Port Arthur LNG in Texas (carrying value about $1.7B), 47.5% of APLNG in Australia, and stakes in one producing and two under-construction Qatar LNG projects (North Field East and North Field South).
Outlook
Management guides Q3 2026 production to 2.29-2.32 million BOE per day and left all full-year guidance unchanged. That range sits above Q2's 2.248 million even though roughly 21 MBOED of Lower 48 production was sold in July, so the guidance implies a sequential recovery elsewhere; the filing doesn't say where it comes from.
Our read: Q2 is close to the best this portfolio can earn at current volumes, and the drivers of the next few quarters sit mostly outside the company's control: the oil price (it is fully unhedged), Qatar LNG output, and US gas prices, which were negative on average in the Lower 48 this quarter. What is within its control is moving the right way: cash operating costs are falling, Marathon integration costs have rolled off, capex is down 10% year to date, and buybacks doubled while debt stayed flat. The key test in Q3 is whether production actually lands in the guided range after the July asset sales, since volumes on a like-for-like basis were down 4% year over year this quarter.