[FANG] Diamondback Energy: Q3 2026 Earnings Test Oil Output After the DUC Drawdown

Diamondback Energy (FANG) is an independent oil and gas producer that operates almost entirely in the Permian Basin of West Texas, drilling horizontal wells for crude oil, natural gas and natural gas liquids (NGLs) and holding mineral and royalty interests through its consolidated subsidiary Viper Energy[1]. The company will hold its earnings call on 2026-11-03 to report Third quarter 2026 (three months ended September 30, 2026) results[2]. In the latest disclosed quarter, the second quarter of 2026, Diamondback produced 525.2 thousand barrels of oil a day and 1,017.7 thousand barrels of oil equivalent a day, crossing 1 million BOE a day for the first time; it realized $96.82 a barrel for oil, booked $4.786 billion of oil, gas and NGL sales, up about 44% year over year, and earned $1.882 billion attributable to the company, or $6.65 per diluted share[3]. In the same quarter, operating cash flow was about $3.6 billion, cash capital expenditures were $996 million, adjusted free cash flow was about $2.3 billion and net debt fell by about $1.6 billion to $12.3 billion[4]. The third-quarter guidance issued on August 3 calls for 517,000 to 527,000 barrels of oil a day (midpoint 522,000), 995,000 to 1,015,000 BOE a day, $950 million to $1.05 billion of cash capital expenditures and $400 million to $460 million of cash taxes; management also raised full-year oil guidance to 522,000-plus barrels a day while holding full-year capital spending at about $3.9 billion[4]. The 18 analysts compiled by Drillr have a third-quarter consensus of $5.72 in earnings per share and about $1.608 billion in net income[5].

Three things in this report deserve the closest attention. The first is whether Diamondback oil output can stay above 520,000 barrels a day: in May the company decided to draw down part of its drilled-but-uncompleted (DUC) well inventory to sustain production and to add two or three rigs afterward to backfill it[6], so the third quarter is the first full quarter that can show whether the higher output was a one-off inventory release or durable capacity. The second is whether the realized gas price turns positive: the second-quarter pre-hedge gas realization was negative $2.15 per Mcf and natural gas sales were negative $276 million[3], while the company says Waha prices have been positive since July[4], so the report can confirm whether better takeaway actually reached realized prices. The third is whether low costs and debt reduction can continue together: lease operating expense (LOE) fell to $5.96 per BOE in the second quarter[4], yet management has just dropped its minimum free-cash-flow return commitment[7], so third-quarter unit costs and the change in net debt will show whether free cash flow goes to debt reduction or buybacks.

Company Background and Business Structure

Diamondback's assets are heavily concentrated in the Midland Basin portion of the Permian. At the end of 2025 the company held about 869,000 net acres in the Permian, including about 775,000 net acres in the Midland Basin and about 94,000 net acres in the Delaware Basin; its subsidiary Viper also owned about 87,000 net royalty acres across the two basins, about 35% of which Diamondback operates[1]. In the second quarter of 2026 the Midland Basin produced $4.429 billion of revenue from contracts with customers, against only $354 million from the Delaware Basin[3], so the company's geographic concentration is far higher than that of peers operating across several basins.

The company reached its current scale through a sequence of acquisitions and its own drilling. Combined production grew 54% in 2025; about 42% of that increase came from new wells, 41% from the Endeavor acquisition and 12% from the Double Eagle acquisition[1]. On February 9, 2026, Viper sold all of its non-Permian assets for about $610 million in net cash, covering about 9,400 net royalty acres in the Denver-Julesburg, Eagle Ford and Williston basins with about 4,750 barrels of oil a day of production[8], which narrowed the company further into a single-basin producer.

Diamondback has a single exploration and production business and discloses volumes and prices by product. Crude oil dominates: oil sales of $11.621 billion made up about 86% of the $13.453 billion of 2025 oil, gas and NGL sales, while natural gas and NGLs contributed only $400 million and $1.432 billion[1]. The company also buys third-party crude for resale; that line produced $739 million of revenue in the second quarter against $730 million of purchase cost[3], contributing almost no profit, so operating performance is better read from oil, gas and NGL sales than from total revenue.

Financial History and Current Position

Fiscal 2025 combined a large production increase, lower oil prices and a big impairment. According to the 10-K, 2025 oil, gas and NGL sales were $13.453 billion, up from $10.100 billion in 2024; full-year production averaged 921.0 thousand BOE a day, including 497.2 thousand barrels of oil, while the realized oil price fell from $73.52 to $64.04 a barrel[1]. Operating cash flow that year was $8.758 billion and additions to oil and gas properties were $3.523 billion, but falling commodity prices forced a $3.7 billion non-cash ceiling test impairment, and net income fell from $3.701 billion in 2024 to $1.547 billion[1].

In the first quarter of 2026, production kept rising but another impairment again depressed earnings. Oil output averaged 521.0 thousand barrels a day and total production 979.4 thousand BOE a day; operating cash flow was about $1.8 billion, cash capital expenditures were $933 million, adjusted free cash flow was about $1.7 billion, and the company repurchased 3.3 million shares for about $548 million[6]. Because SEC prices declined, the company recorded another $1.4 billion non-cash impairment in the quarter, leaving net income attributable to Diamondback at only $25 million, compared with $1.405 billion a year earlier[8].

In the second quarter of 2026, high oil prices sharply improved both earnings and cash flow. Total revenue was $5.562 billion ($3.678 billion a year earlier), operating income was $2.512 billion ($1.139 billion), net income attributable to the company was $1.882 billion and diluted EPS was $6.65 ($2.38), with no ceiling test impairment in the quarter[3]. Operating cash flow was about $3.6 billion, or $3.3 billion before working-capital changes; the company repurchased about $141 million of stock, cut total debt by about $1.3 billion to $12.8 billion and lowered net debt to $12.3 billion[4]. The 10-Q shows $1.548 billion of debt due within a year at the end of June, including $698 million of notes maturing in 2026[3], and management said it is building cash to cover bond maturities in 2026 and 2027[7].

Operating Model

Diamondback's revenue is determined almost entirely by volume multiplied by realized price. Oil, gas and NGL sales equal the sum of each product's volume times its realized price; in the second quarter of 2026, 47.791 million barrels of oil at $96.82 produced $4.627 billion, NGLs produced $435 million and natural gas contributed negative $276 million because of negative prices[3]. Volume usually responds to capital decisions with a lag of one to two quarters: in May the company announced the DUC drawdown, kept five completion crews running continuously and planned to add two or three rigs to rebuild inventory later[6], which means first-half growth came from wells already drilled while wells from the new rigs reach production later.

Operating income depends on revenue minus unit cash costs, production taxes and depletion. In the second quarter, LOE was $552 million, production and ad valorem taxes were $302 million, gathering, processing and transportation was $113 million (about $1.22 per BOE), depreciation, depletion and amortization was $1.272 billion, and operating income was $2.512 billion[3]; the company guides full-year production taxes to about 7% of revenue[4]. The full cost method requires a ceiling test every quarter, so impairments move with trailing 12-month average commodity prices; the 2025 and first-quarter 2026 impairments cut GAAP earnings but did not reduce cash flow[8].

The order in which cash is allocated determines the direction of the balance sheet. Free cash flow is roughly operating cash flow minus drilling and completion capital: $8.758 billion minus $3.523 billion in 2025[1], and about $3.6 billion minus $996 million in the second quarter of 2026, leaving about $2.3 billion of adjusted free cash flow[4]. That cash first pays the $1.10-per-share quarterly base dividend, and the remainder is split between buybacks and debt repayment; in the second quarter net debt fell by about $1.6 billion while buybacks were only about $141 million[4], showing that the company put debt reduction first in a high-price quarter.

Industry and Competitive Position

Diamondback's main advantage is its concentrated Midland Basin position and low unit costs. In 2025 its cash operating cost was $10.23 per BOE, down from $11.09 in 2024, including $5.55 of LOE and $0.62 of cash G&A[1]; in the second quarter of 2026 cash operating cost was $10.96, down about 3% from the prior quarter[4]. In the Permian it competes with large producers such as EOG, ConocoPhillips, Occidental and Devon for drilling locations and oilfield services, and the 10-K notes that some competitors have greater resources[1].

Concentration in a single basin is also Diamondback's clearest weakness. In the second quarter, insufficient Permian takeaway capacity trapped gas in West Texas, and spring pipeline maintenance drove Waha prices to a record low of about negative $10 per Mcf[4], turning the company's natural gas revenue negative[3]. Management also said oilfield service prices have not risen meaningfully outside fuel-related costs, but that fixed costs such as casing will rise through the rest of 2026 and into 2027 as the Permian rig count grows[4]. The comparison also has a clear limit: the frozen record holds no peer unit-cost or well-return figures on a matching basis, so the company's cost rank among peers cannot be established here.

Core Debates

After drawing down its drilled-but-uncompleted wells, can Diamondback hold oil output above 520,000 barrels a day with new rigs?

This question decides whether first-half growth carries into the second half. Oil contributes about 86% of oil, gas and NGL sales[1], and WTI averaged $83.00 a barrel in the first half of 2026, up from $70.81 a year earlier[3]. At the start of the year the company planned to hold output roughly at fourth-quarter 2025 levels, about 926,000 to 962,000 BOE a day, with $3.6 billion to $3.9 billion of capital[1]; in May it switched to drawing down DUCs to keep oil output above 520,000 barrels a day and raised full-year capital to about $3.9 billion[6]. The third quarter is the first full quarter after the DUC drawdown in which new rigs must backfill.

Current evidence shows output holding at the top of guidance. Oil production was 521.0 thousand barrels a day in the first quarter and 525.2 thousand in the second, up about 1% sequentially and at the top end of guidance[6][4]; cash capital expenditures were $933 million and $996 million, both within guidance[6][4]. On the first-quarter call management said DUCs would mainly be drawn down in the second quarter and then backfilled with rig activity while keeping a high DUC balance[9]. An alternative reading is equally possible: first-half growth came mainly from inventory wells, wells from the new rigs will not arrive in volume until year-end, third-quarter output could slip to the 522,000 midpoint or lower, and management already estimates that the quarterly capital needed to hold production flat exiting 2026 is $1 billion or slightly more[7].

Changes in volume pass directly into revenue and free cash flow. At 525.2 thousand barrels a day and a $96.82 realized price, second-quarter oil sales were $4.627 billion, up from $3.445 billion in the first quarter and $2.852 billion in the second quarter of 2025[3]; the $996 million of capital spent in the same quarter set how much operating cash flow remained as free cash flow[4]. If output holds while capital stays near $1 billion, capital efficiency is confirmed; if output falls while capital does not, free cash flow becomes more dependent on oil prices.

Three numbers matter in the third quarter. The first is whether oil output is at least the 522,000-barrel guidance midpoint, the second is whether cash capital spending stays within the $950 million to $1.05 billion range[4], and the third is whether the company keeps its preliminary framework of low-single-digit organic growth for 2027[7]. Oil output below the 517,000-barrel low end would show that backfilling after the drawdown fell short; a lower oil price, meanwhile, would cut revenue and could hide the change in volume itself.

With new Permian pipelines online, can Diamondback’s negative gas price turn positive in the third quarter?

Natural gas is a byproduct of Diamondback's oil wells, and its price has moved from a minor detail to a drag on earnings. Natural gas sales were negative $276 million in the second quarter, compared with $21 million in the first quarter and $97 million in the second quarter of 2025[3]. Takeaway shortages and spring maintenance pushed Waha to about negative $10, and the company said the basis hedges it built over several years helped protect it but that the quarter still took a loss[4].

The evidence points to near-term improvement, but the structural problem is not yet shown to be solved. The second-quarter gas realization was negative $2.15 before hedges and negative $0.34 after hedges, compared with $0.18 and $1.90 in the first quarter, and the 2025 full-year pre-hedge realization was $0.89[3][1]. The company says Waha turned positive in July after new takeaway capacity came online and has held there, and that its secured long-haul takeaway will more than double by year-end, shifting price exposure toward larger demand hubs[4]; management is also pursuing long-term contracts to the Gulf Coast and LNG export markets, plus a roughly 30,000-acre in-basin power project at Bryant Ranch targeting first power in the second half of 2027[7]. An alternative reading is that July's improvement came mainly from the end of spring maintenance; if new pipelines slip, Barnett development will also raise gas-to-oil ratios[7], prices could turn negative again, and the third-quarter Waha basis swaps of 650,000 MMBtu a day at negative $1.87 offer only partial protection[4].

Gas production magnifies price changes into revenue and cash flow. Second-quarter gas output was 128,279 million cubic feet[3], so at that volume each $1 change in the realized gas price moves quarterly natural gas revenue by about $128 million. Basis swap settlements flow through derivative gains and losses and the hedged realization, so the pre-hedge price reflects takeaway conditions themselves while the hedged price shows what the company actually bears; the company also holds Henry Hub costless collars of 840,000 MMBtu a day with a $2.87 floor for the third quarter[4].

Three points matter in the third quarter: whether the pre-hedge gas realization returns to positive territory, whether natural gas sales turn positive, and whether the Bryant Ranch project has received the ERCOT eligibility confirmation expected in August[7]. A pre-hedge gas price that remains negative would show that easier takeaway has not reached the company's realized price; disclosure of pipeline delays and renewed negative Waha prices would weaken the current reading of improvement.

With lease operating costs just below $6, can Diamondback keep costs low and keep paying down debt with free cash flow?

Low unit costs and steady debt reduction are the two pillars of Diamondback's operating story. The company recorded a $3.7 billion impairment in 2025[1] and another $1.4 billion in the first quarter of 2026[8]; high second-quarter oil prices produced about $2.3 billion of adjusted free cash flow, most of which went to debt reduction as net debt fell by about $1.6 billion[4]. At the same time the company removed its minimum free-cash-flow return commitment to keep flexibility[7], whereas at the time of the 10-K the board had approved returning at least 50% of quarterly adjusted free cash flow[1].

The latest cost evidence is positive, but part of it may come from volume dilution. Second-quarter LOE was $5.96 per BOE, down from $6.21 in the first quarter, cash G&A fell from $0.65 to $0.52, and total cash operating cost was $10.96[4]; first-quarter LOE was elevated partly by one-time charges to restore production after Winter Storm Fern[6]. Management attributed the second-quarter decline to production outperformance and automation efficiencies after the Endeavor integration, and said it looks for LOE to settle around $6 for the rest of 2026[7]. An alternative reading is that if output returns to the guidance midpoint, the dilution effect fades and LOE could drift back toward about $6.20; full-year 2025 LOE was $5.55[1], so the current level is not a historical low.

The path of debt reduction depends on how free cash flow is allocated. On the first-quarter call management targeted net debt of $10 billion within 12 to 18 months[9]; starting from about $13.9 billion at the end of March, that implies an average reduction of roughly $650 million to $980 million a quarter, so a third-quarter figure below about $11.65 billion would fit the slower end of that path. But in July the board doubled the buyback authorization from $8.0 billion to $16.0 billion, the company had already repurchased about $100 million of stock in the third quarter by early August[4], and management said it buys back stock during periods of price weakness[7], so cash could shift from debt repayment to buybacks.

In the third quarter, watch whether LOE is no higher than $6.15, the midpoint of the $5.90 to $6.40 guidance[4], whether net debt falls below about $11.65 billion, and whether the split between buybacks and debt repayment shifts clearly toward buybacks. LOE above the $6.40 top of guidance would show that the cost decline is not sustainable; a sequential rise in net debt would call the debt-reduction path into question.

Risks and Falsifiers

Impairment risk from lower oil prices could again depress GAAP earnings. Under the full cost method the company runs a ceiling test every quarter; it recorded a $3.7 billion impairment in 2025[1] and another $1.4 billion in the first quarter of 2026, leaving only $25 million of net income attributable to the company that quarter[8], and the 10-Q warns that material write-downs may follow if trailing 12-month commodity prices fall below those used in prior quarters[3]. Impairments do not affect cash flow, but oil prices themselves do: on the second quarter's 47.791 million barrels of oil sales, each $10 change in the realized oil price moves quarterly oil revenue by about $480 million. If the third quarter carries no impairment and the realized oil price stays above $80 a barrel, this risk does not materialize for now.

A shift in capital allocation is the second risk to the balance sheet. The company has dropped its commitment to return at least 50% of adjusted free cash flow[1][7] and doubled its buyback authorization to $16.0 billion[4], so future allocation will depend more on management's view of the share price. A pivot to large buybacks would slow the decline in net debt, and a pivot to acquisitions could add both debt and integration risk. If the company keeps reporting sequential declines in net debt and announces no large cash acquisition, the risk has not materialized.

A shortfall in DUC backfilling could pull output down in the second half. Part of first-half growth came from drawing down drilled-but-uncompleted wells, the company planned to add two or three rigs to backfill[6], and management said backfilling would follow the second-quarter drawdown[9]. At the second quarter's $96.82 realized oil price[3], each 5,000-barrel-a-day shortfall in oil output costs about $44 million of quarterly oil revenue; drilling more to make up volume could push capital above the $1.05 billion top of guidance[4]. Third-quarter oil output of at least 522,000 barrels a day with capital inside guidance would falsify this risk.

A return of takeaway bottlenecks would make natural gas a negative revenue line again. Negative gas prices left second-quarter natural gas revenue at negative $276 million, and at that quarter's 128,279 million cubic feet of gas output, each $1 change in the realized gas price moves quarterly gas revenue by about $128 million[3]. Pipeline delays or maintenance could push Waha prices negative again. A positive third-quarter pre-hedge gas realization, together with confirmation that the year-end doubling of long-haul capacity is on schedule[4], would support the current reading of improvement.

Service cost inflation would raise both capital spending and operating costs. The company says fixed costs such as casing will rise through the rest of 2026 and into 2027[4], and management estimates that higher casing prices add about 1% to total well costs, an increase it believes efficiency gains can offset[7]. If efficiency gains fall short, capital spending and LOE would rise together and squeeze free cash flow. If third-quarter capital spending and LOE both land inside their guidance ranges, this risk has not yet materialized.

What to Watch Next

• Oil output after the DUC drawdown: second-quarter 2026 oil production was 525.2 thousand barrels a day (521.0 in the first quarter). Output at or above the 522,000 midpoint confirms the current reading; below 517,000 signals insufficient backfilling.
• Capital discipline: second-quarter cash capital spending was $996 million ($933 million in the first quarter). Holding output while staying within $950 million to $1.05 billion confirms efficiency; exceeding the top end weakens it.
• 2027 framework: management's preliminary plan is low-single-digit organic growth. Keeping it confirms durability; cutting or withdrawing it weakens the case.
• Permian gas realization: the second-quarter pre-hedge price was negative $2.15 per Mcf (positive $0.18 in the first quarter). A return to positive territory confirms better takeaway; a still-negative price shows it has not reached realizations.
• Gas revenue and Bryant Ranch: second-quarter natural gas sales were negative $276 million. Positive gas revenue and confirmed ERCOT eligibility confirm progress; pipeline delays weaken it.
• Unit costs: second-quarter LOE was $5.96 per BOE ($6.21 in the first quarter). LOE at or below $6.15 confirms cost control; above $6.40 shows the decline is not sustainable.
• Net debt and capital allocation: net debt was $12.3 billion at the end of June. A drop below about $11.65 billion confirms the debt path; a sequential increase falsifies it, and a sharp rise in buybacks signals a shift in priorities.

Conclusion

Diamondback's results turn mainly on three things: Permian oil output, the oil price and unit costs. In the second quarter of 2026, oil output of 525.2 thousand barrels a day and a $96.82 realized price produced $1.882 billion of net income attributable to the company[3], and about $2.3 billion of adjusted free cash flow cut net debt to $12.3 billion[4]. That record also contains three unresolved relationships: how much of the growth came from a one-off DUC drawdown, whether negative gas prices end as takeaway improves, and whether cash goes to debt repayment or buybacks now that the return commitment is gone.

Outside commentary since the results has been thin. Since the second-quarter report, only Zacks Equity Research has published an independent assessment of the business, arguing on August 13 that Diamondback's higher 2026 production guidance with unchanged capital of about $3.9 billion shows efficiency gains supporting earnings momentum[10]. That view maps onto the first core debate and treats more output from the same capital as durable efficiency, while the alternative reading set out here attributes first-half growth mainly to the DUC drawdown; third-quarter output and capital spending will test the difference. On gas takeaway and capital allocation, no independent outside view was found to compare against, and that coverage gap should be stated plainly.

The combination of observations that would materially strengthen the current understanding is third-quarter oil output of at least 522,000 barrels a day, capital spending within $1.05 billion, a positive pre-hedge gas realization, LOE no higher than $6.15 and a further decline in net debt. Conversely, oil output below 517,000 barrels a day, capital above guidance, a still-negative gas price, or a sequential rise in net debt alongside a sharp increase in buybacks would indicate that the strong first half owed more to a one-off combination of inventory wells and high oil prices than to a lasting operating improvement.

Sources

[1] FANG 10-K filed 2026-02-25 · 2026-02-25 · 10-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001539838&type=10-K&dateb=&owner=include&count=40

[2] FANG Q3 2026 conference call schedule announcement 2026-09-30 · 2026-09-30 · Diamondback Energy announcement

[3] FANG Q2 2026 10-Q filed 2026-08-05 · 2026-08-05 · 10-Q · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001539838&type=10-Q&dateb=&owner=include&count=40

[4] FANG Q2 2026 8-K filed 2026-08-03 · 2026-08-03 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001539838&type=8-K&dateb=&owner=include&count=40

[5] Drillr analyst estimates FANG Q3 2026 retrieved 2026-10-28 · 2026-10-28 · Drillr analyst estimates · https://gateway.drillr.ai/mcp/private

[6] FANG Q1 2026 8-K filed 2026-05-04 · 2026-05-04 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001539838&type=8-K&dateb=&owner=include&count=40

[7] FANG Q2 2026 earnings call 2026-08-04 · 2026-08-04 · earnings-call · https://gateway.drillr.ai/mcp/private

[8] FANG Q1 2026 10-Q filed 2026-05-06 · 2026-05-06 · 10-Q · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001539838&type=10-Q&dateb=&owner=include&count=40

[9] FANG Q1 2026 earnings call 2026-05-05 · 2026-05-05 · earnings-call · https://gateway.drillr.ai/mcp/private

[10] Zacks view on FANG 2026-08-13 · 2026-08-13 · Zacks Equity Research · https://www.zacks.com/stock/news/2974394/can-fang-s-higher-2026-output-guidance-keep-earnings-momentum-alive