Diamondback earned $1.88B ($6.65/share) in Q2 2026, up from $699M, as a $96.82 realized oil price and record 1.02M BOE/d output outweighed negative Permian gas prices; debt fell ~$1.3B.
Revenue
$5.6B
+51.2% YoY
Net income
$1.9B
+169.2% YoY
Diluted EPS
$6.65
+179.4% YoY
Operating margin
45.2%
Overview
Diamondback Energy, one of the largest oil producers in the Permian Basin of West Texas, earned $1.88 billion attributable to its shareholders in Q2 2026 ($6.65 per diluted share). A year earlier it earned $699 million ($2.38). Almost all of the jump came from a higher oil price. Diamondback realized $96.82 per barrel of oil, up 53% from $63.23. The 10-Q links the rise to the conflict in the Middle East, which in 2026 "shifted [the global crude market] from a supply-demand surplus to a deficit." Volumes also grew. Average production passed 1.0 million barrels of oil equivalent per day (1,017,659 BOE/d) for the first time, and oil output was 525,176 barrels per day.
Two things pulled the other way:
Natural gas revenue was negative. Diamondback booked −$276 million of gas sales, an average realized price of −$2.15 per Mcf. Pipelines leaving the Permian are full, so gas at the local Waha Hub traded at times below zero. In effect, producers paid to have their gas taken away.
Derivatives and other non-operating items helped the GAAP headline. A $134 million gain came from buying back bonds below face value, and hedging contracts added a $49 million gain.
(A barrel of oil equivalent, or BOE, converts natural gas into oil-sized units at 6,000 cubic feet per barrel, so oil, gas and natural gas liquids can be added together.)
Key metrics
Metric
Q2 2026
Q2 2025
YoY Change
Total revenues
$5,562M
$3,678M
+51.2%
Oil, gas & NGL sales (excl. purchased oil)
$4,786M
$3,316M
Read 0 community reports on Diamondback Energy, or write your own.Write a report
Operating margin is the share of revenue left after running the business (production costs, depletion, overhead) and before interest, hedging results and tax. Total revenues include $739 million of "purchased oil" (Q2 2025: $335 million). Diamondback buys this oil from third parties and resells it to fill unused pipeline capacity it has committed to. That oil costs almost exactly what it sells for ($730 million of purchased-oil expense), so it inflates revenue but not profit.
Takeaway: This quarter was about price, not a change in the business. Oil at nearly $97 a barrel produced about $2.3 billion of free cash flow (company-defined), and Diamondback put most of it toward debt, not shareholders. Debt fell by about $1.3 billion, while dividends plus buybacks came to $452 million. The board also scrapped its promise to return at least 50% of free cash flow each quarter. The payout story now matters less than how much cash Diamondback keeps while oil stays this high.
Where the revenue came from
Oil, gas and NGL (natural gas liquids such as ethane and propane) sales totaled $4.79 billion in Q2, up $1.47 billion from a year earlier:
Oil: $4,627M vs. $2,852M. Most of the gain came from price (+53%), with volume adding about 6%. Compared with Q1 2026, the 10-Q attributes $861 million of the $961 million sequential increase in product revenue "largely to higher average prices received for our oil production" and $100 million to higher volumes.
Natural gas: −$276M vs. +$97M. The 10-Q says Waha–Henry Hub price gaps widened because of "regional natural gas takeaway constraints in the Permian Basin, which resulted in periods of negative pricing at Waha Hub." Management expects the effect to lessen "later in 2026" as its contracted pipeline capacity increases.
NGLs: $435M vs. $367M. Volume drove this. The realized NGL price barely changed ($18.56 vs. $18.13 per barrel).
For the first half, WTI (the US oil benchmark) averaged $83.00 per barrel, versus $70.81 a year earlier. Diamondback's realized oil price over the same six months was $85.26, slightly above WTI. The filing does not give the Q2-only WTI average.
Production and drilling
Total output of 1,017,659 BOE/d rose 10.6% from a year ago and 3.9% from Q1 (979,356). Oil grew more slowly, up 5.9% year over year and less than 1% from Q1. As a result, oil fell to 52% of volumes in H1 2026, from 55% in H1 2025. The mix is shifting toward cheaper gas and NGLs.
Over the first half, volume growth came from acquisitions as well as new wells. The 10-Q attributes about 33% of the increase to Viper's Sitio acquisition and 16% to the Double Eagle acquisition, and "largely" the rest to new wells.
Wells: 97 gross horizontal wells drilled and 168 turned to production in Q2, all in the Midland Basin, with an average lateral (horizontal section) length of 11,983 feet. Completing far more wells than it drilled means Diamondback is drawing down its backlog of drilled-but-uncompleted wells. That is the stated way it plans to lift output: "continuing to convert portions of our drilled but uncompleted well balance."
The company runs 17 drilling rigs and five completion crews.
Costs
Cash operating costs were $10.96 per BOE, down from $11.26 in Q1 but up from $10.10 a year ago:
Cash cost per BOE
Q2 2026
Q1 2026
Q2 2025
Lease operating expenses
$5.96
$6.21
$5.26
Production & ad valorem taxes
$3.26
$3.04
$2.56
Gathering, processing & transportation
$1.22
$1.36
$1.73
Cash G&A
$0.52
$0.65
$0.55
Total
$10.96
$11.26
$10.10
Production and ad valorem taxes (+$0.70) and lease operating expenses (+$0.70) drove the year-over-year rise, partly offset by lower gathering and transport costs (−$0.51). Production taxes follow revenue, so higher prices raise them automatically. That part doesn't signal worsening efficiency. Lease operating expenses (the day-to-day cost of running wells) went up for identifiable reasons. For the first half, the 10-Q cites $54 million more for water disposal after Diamondback sold its water subsidiary (Environmental Disposal Systems) to Deep Blue in Q4 2025. It also cites a prior-year one-off: a $43 million reduction in estimated water costs that flattered H1 2025. In effect, some of the gain from that sale now shows up as a recurring operating cost.
Depletion, depreciation and amortization, the non-cash charge that spreads the cost of wells over the oil they produce, fell to $13.74/BOE from $15.12. The asset base was smaller after ceiling-test impairments in Q4 2025 and Q1 2026. The Q1 2026 write-down was $1.4 billion, taken when the 12-month average prices used in SEC rules declined. Management says it does not currently expect another impairment in Q3 2026.
Hedging: what derivatives did to GAAP profit
Diamondback uses derivatives (price-protection contracts) to limit the damage from falling prices. It doesn't use hedge accounting, so every quarter the change in these contracts' market value goes straight through the income statement, whether or not any cash changed hands.
Q2 2026: $49 million gain. This combines $113 million of cash received on contracts that settled and about $64 million of paper losses on open contracts. Compared with Q1, the value of open gas contracts fell by $290 million, which the 10-Q attributes largely to "unfavorable basis differentials" on its gas basis swaps (contracts tied to the Waha-to-Henry Hub price gap). Open oil contracts rose $270 million in value as oil prices dropped between March 31 and June 30.
Q2 2025: $197 million loss.
That swing added about $246 million to pre-tax income compared with a year earlier. Bond buybacks helped too. In April, Diamondback repurchased $777 million face value of its 2051/2052 notes at an average of 81.1% of par, producing a $134 million gain (vs. $55 million in Q2 2025). The company's own adjusted net income, which strips out non-cash derivative moves, the debt gain and other items, was $1,833 million, or $6.48 per share (per the Aug. 3 earnings release, Exhibit 99.1). That is close to the GAAP figure. This quarter, the GAAP profit is not being flattered much by accounting items.
Hedges also cushioned the gas problem in cash terms. After hedges, the realized gas price was −$0.34/Mcf instead of −$2.15.
Viper Energy and portfolio moves
Viper Energy is Diamondback's publicly traded subsidiary that owns mineral and royalty rights. Diamondback owned about 39% of it at June 30 and still consolidates it (its results are included in Diamondback's). Its share of profit going to Viper's other shareholders, the "non-controlling interest," rose to $173 million from $40 million. That reflects Viper's larger size after acquisitions and Diamondback's smaller stake. Deals described in the filing:
Mar. 2026: Viper secondary offering. Diamondback sold about 12.9 million Viper shares for about $589 million, used partly "to accelerate debt reduction."
Feb. 2026: Viper sold all its non-Permian assets (including acreage acquired with Sitio) for about $610 million. The proceeds repaid Viper's $500 million term loan.
July 1, 2026: Viper acquired Riverbend for about $339 million in cash plus 3.69 million Viper shares.
Aug. 3, 2026: Diamondback agreed to a new "2026 Drop Down", selling mineral and royalty interests to Viper in exchange for 3.65 million Viper units and shares.
Endeavor, the 2024 merger partner, still shapes the capital picture. Former Endeavor owners (mostly SGF FANG Holdings) held about 26.7% of Diamondback at June 30. In H1, Diamondback bought back 3.0 million shares from SGF for about $509 million, all in Q1. It bought none from SGF in Q2.
Cash flow and capital return
Cash flow item (Q2 2026)
Amount
Net cash from operating activities
$3,589M
Operating cash flow before working-capital changes*
$3,326M
Cash capital expenditures
$996M
Free cash flow*
$2,330M
Base dividends paid
$311M ($1.10/share)
Share buybacks
$141M (756,385 shares at $186.63 avg.)
Non-GAAP measures from the Aug. 3 earnings release (Exhibit 99.1). Free cash flow is operating cash flow before working-capital changes minus cash capex.
Payouts were only about 19% of free cash flow ($452 million of $2,330 million). No variable dividend was declared on top of the $1.10 base dividend.
Debt got the rest. Diamondback retired about $828 million of senior notes and repaid and terminated the remaining $550 million of its 2025 term loan. Consolidated total debt fell by about $1.3 billion in the quarter to $12.8 billion, and net debt to $12.3 billion, down from $15.1 billion a year earlier (per the release). About $1.5 billion of notes mature within 12 months.
Policy change: starting in Q2, the board dropped the "minimum 50% return of capital quarterly commitment" to allow "more discretion in the allocation of Free Cash Flow." It then doubled the buyback authorization to $16.0 billion on July 30, with about $9.9 billion left. In Q3 through the release date, Diamondback repurchased about $100 million of stock. It says it will buy back shares "opportunistically," including with proceeds from asset sales.
The weighted diluted share count was 281.2 million, down 3.7% from 292.1 million. Buybacks therefore account for part of the EPS gain.
First half 2026
Metric
H1 2026
H1 2025
YoY Change
Total revenues
$9,802M
$7,726M
+26.9%
Net income attributable to Diamondback
$1,907M
$2,104M
−9.4%
Diluted EPS
$6.72
$7.20
−6.7%
Total production (BOE/d)
998,613
885,459
+12.8%
Realized oil price ($/bbl)
$85.26
$66.99
+27.3%
Net cash from operating activities
$5,417M
$4,032M
+34.4%
Cash capital expenditures
$1,929M
$1,806M
+6.8%
Half-year profit is lower despite much higher revenue because of Q1's $1.4 billion non-cash impairment. Cash flow tells the clearer story: operating cash flow was up 34%.
Guidance and outlook
From the Aug. 3 earnings release (Exhibit 99.1) and the 10-Q:
2026 production raised to 1,000+ MBOE/d (from 972+) and oil to 522+ MBO/d (from 520+), with full-year cash capex unchanged at about $3.9 billion. Capex had already been raised 4% in Q2.
Q3 2026: oil of 517–527 MBO/d (995–1,015 MBOE/d); capex of $950–1,050 million; cash taxes of $400–460 million.
Unit-cost guidance was mostly trimmed: gathering/transport to $1.40–1.60/BOE (from $1.50–1.70) and DD&A to $13.50–14.50/BOE. The cash tax rate was raised to 19–22% of pre-tax income (from 18–21%).
Our read: The higher full-year output target comes with no extra capex. Diamondback is getting it by completing wells it already drilled, so capital efficiency looks good for 2026. But completions ran well ahead of new drilling in H1 (315 completed vs. 215 drilled), and that backlog is finite. Q3 oil guidance, with a 522 MBO/d midpoint, is essentially flat with Q2's 525 MBO/d, so extra volume is now coming mostly from gas and NGLs, which are worth much less per barrel. Three things to watch:
Waha gas prices. Whether new pipeline capacity turns realized gas back to positive in H2 as management expects. The company's Waha basis swaps cover 650,000 MMBtu/d in Q3 and Q4 2026.
Oil price exposure. Oil hedges are mostly puts struck around $50–55 per barrel. These protect against a crash but leave nearly all of the benefit (and the risk of a reversal) from a high oil price with Diamondback.
Free cash flow split. With the 50% floor gone and a $16 billion buyback authorization, how much free cash flow goes back to shareholders versus toward the $12.8 billion of debt is now a quarter-by-quarter decision.