Diamondback Energy, which produces oil and natural gas mainly in West Texas, used stronger oil sales to fund drilling and reduce debt in the first half of 2026. Cash from operations reached $5.42 billion, while debt recorded on its balance sheet fell by $1.88 billion from year-end. Gas sales remained a cost rather than a source of revenue in the second quarter. The business gained financial breathing room, but its next operating test is getting more gas to paying customers while containing costs.
Reporting basis: Diamondback Energy, Inc. (NASDAQ: FANG), unaudited consolidated Form 10-Q for the quarter ended June 30, 2026; filed August 5, 2026; SEC accession 0001539838-26-000142; CIK 1539838. Quarterly comparisons cover April–June; first-half comparisons cover January–June. Balance-sheet comparisons use December 31, 2025. Information cutoff: August 5, 2026, including the August 3 results and shareholder letter. Later developments are outside this analysis.
Sources: SEC filing and consolidated accounts, cover, financial statements and Notes 1–2; SEC filing details.
1. Oil drove the recovery; purchased-oil sales added little profit
Higher oil prices contributed more to first-half production-sales growth than higher volumes did. Diamondback sells oil, gas and liquids separated from gas. Its mineral subsidiary, Viper, also receives payments from production on land where it owns mineral or royalty rights. These businesses depend on market prices as well as the amount produced.
| Consolidated results, US dollars in millions except per-share amounts | Second quarter 2025 | Second quarter 2026 | First half 2025 | First half 2026 |
|---|---|---|---|---|
| Total revenue | 3,678 | 5,562 | 7,726 | 9,802 |
| Oil, gas and natural gas liquid sales | 3,316 | 4,786 | 6,973 | 8,611 |
| Operating profit | 1,139 | 2,512 | 2,812 | 2,628 |
| Operating margin, calculated | 31.0% | 45.2% | 36.4% | 26.8% |
| Consolidated net income | 739 | 2,055 | 2,230 | 2,199 |
| Net income attributable to Diamondback | 699 | 1,882 | 2,104 | 1,907 |
| Diluted earnings per common share, US dollars | 2.38 | 6.65 | 7.20 | 6.72 |
Reporting basis: Operating margin is operating profit divided by total revenue. Consolidated net income includes earnings belonging to outside owners of subsidiaries; income attributable to Diamondback excludes their share.
Source: 2026 second-quarter 10-Q, consolidated statements of operations, page 1, and Note 3, page 8.
Quarterly oil sales increased by $1.78 billion. Negative gas revenue took back $373 million of that improvement compared with the prior-year quarter, while natural gas liquid sales added $68 million. The resulting $1.47 billion increase in production sales explains most of the operating recovery.
A separate activity makes total revenue look larger without adding much profit. Diamondback buys and resells third-party oil to use pipeline capacity it has committed to pay for. In the second quarter, this generated $739 million of sales but $730 million of purchase expense. Its $404 million increase in sales therefore contributed just $5 million of additional profit before other costs compared with 2025. In the first half, the activity generated only $1 million after purchased-oil expense.
Source: 2026 second-quarter 10-Q, statements of operations and management discussion, “Net Sales of Purchased Oil,” pages 30 and 34.
The longer comparison separates price from volume. First-half oil output rose 7.7%, while combined production rose 12.8%. More gas and liquids made total production grow faster than oil production. A barrel of oil equivalent combines products by their energy content; it does not mean each equivalent barrel earns the same revenue.
The prices below exclude gains and losses from contracts used to manage price exposure, called derivatives.
| Operating measures, consolidated | First half 2025 | First half 2026 |
|---|---|---|
| Oil production, million barrels | 87.943 | 94.680 |
| Combined production, million barrels of oil equivalent | 160.268 | 180.749 |
| Oil realized price before derivatives, US dollars per barrel | 66.99 | 85.26 |
| Gas realized price before derivatives, US dollars per thousand cubic feet | 1.47 | -1.03 |
| Natural gas liquids realized price before derivatives, US dollars per barrel | 20.77 | 17.66 |
Reporting basis: Six thousand cubic feet of gas count as one barrel of oil equivalent.
Source: 2026 second-quarter 10-Q, management discussion, results for the six months ended June 30, pages 33–34.
Management attributes $973 million of the first-half production-revenue increase to net price effects and $665 million to volume. It attributes approximately 33% of incremental combined production to Viper’s Sitio acquisition and 16% to Double Eagle, with the remainder largely from new wells. Acquisitions therefore explain a meaningful part of growth; the comparison includes different sets of properties.
The timing matters. Double Eagle closed on April 1, 2025, so it was already included throughout the comparison quarter but for only half of the comparison six-month period. Sitio closed in August 2025 and was absent from both 2025 comparison periods. About 93% of second-quarter production revenue came from the Midland Basin, leaving results heavily tied to that region’s prices and infrastructure.
Calculation notes: Midland’s share is $4,429 million divided by $4,786 million, or 92.5%, rounded to about 93%.
Source: 2026 second-quarter 10-Q, Notes 3–4, pages 8–10, and management discussion, page 34.
2. Getting gas out of the field also protects oil production
Gas remained an economic cost in the quarter even after price-protection contracts helped. Diamondback’s average realized gas price was negative $2.15 per thousand cubic feet before derivatives. Including settlements of matured commodity contracts improved that to negative $0.34. A negative realized price means the gas generated a net payment obligation rather than sales proceeds.
Oil wells also produce gas. If that gas cannot leave the field, producers may have to restrict oil production too. The Dallas Fed documented regional transport limits and increasingly negative prices at the Waha gas trading hub from late 2025 into spring 2026. Its 2024 survey had already found that 57% of responding producers active in the Permian expected low Waha prices to hurt their drilling and completion plans. This is a recurring regional constraint, not simply a weak national gas price.
Sources: 2026 second-quarter 10-Q, management discussion, pages 27 and 29; Dallas Fed, “Oil prices are up; whither the Texas boom?”, June 5, 2026, discussion of short-run constraints; Dallas Fed second-quarter 2024 survey, special question on Waha prices.
Calculation notes: The survey’s 57% combines 43% expecting a slightly negative effect and 14% expecting a significant negative effect. The question covered the remainder of 2024 and was answered by executives at 28 exploration and production firms that had drilled or completed a horizontal well in the Permian during the preceding two years.
Management’s response is to secure more pipeline access to Gulf Coast markets and develop local outlets for gas. Its August letter expects secured long-distance capacity to more than double by year-end. It also estimates that its gas handling strategy protected about 1.4 million barrels of second-quarter oil production that otherwise would have been restricted. These are management’s capacity outlook and operating estimate, respectively.
The letter also reported that Waha prices turned positive in July as new transport capacity came online. That is an encouraging development after quarter-end, although it does not yet establish a sustained improvement in Diamondback’s own gas receipts.
The strategy can reduce payments to dispose of gas and protect higher-revenue oil output. But transport contracts carry minimum-payment obligations, and new capacity must arrive before it can help. Better realized gas prices and fewer production restrictions would demonstrate success. National demand growth by itself would not.
Source: August 3, 2026 shareholder letter, “Second Quarter 2026 Operational Performance” and “Gas Monetization.”
Oil remains the larger near-term revenue exposure in the following illustration. A $10 change in price applied to second-quarter oil volume would change revenue before derivatives by about $478 million. A $1 change per thousand cubic feet applied to that quarter’s gas volume would change gas revenue by about $128 million. These are different assumed price moves, not equally likely scenarios.
Calculation notes: Oil sensitivity is 47.791 million barrels × $10 per barrel = $477.91 million. Gas volume of 128.279 billion cubic feet equals 128.279 million units of one thousand cubic feet; multiplying by $1 per unit gives $128.279 million. Both hold volumes constant and exclude taxes, transport changes, derivatives and outside ownership of Viper. They illustrate business exposure, not forecasts.
Source: 2026 second-quarter 10-Q, management discussion, page 29.
3. The profit rebound does not erase the earlier property write-down
Second-quarter earnings improved strongly, while first-half earnings still absorbed a $1.4 billion property impairment. Diamondback uses full-cost accounting, which collects oil and gas development costs in a pool. A quarterly test limits the amount that can remain recorded as an asset. The first-quarter write-down reduced that asset value and profit without requiring a new cash payment at the time.
Neither the second quarter of 2026 nor the second quarter of 2025 had an impairment charge. The absence of a new charge therefore does not explain the year-over-year quarterly profit increase. The first-quarter charge does help explain why first-half operating profit fell 6.5% despite the second-quarter recovery. Stronger current oil prices do not remove that earlier expense from first-half results.
The write-down also lowered later accounting costs. Management attributes an $89 million reduction in second-quarter depletion expense versus the first quarter to the lower depletion rate following the impairment. Higher production offset $64 million of that benefit, leaving a $25 million net decline. This helped reported profit without representing a cash saving from operating the wells.
Second-quarter profit also included a $134 million pretax gain from retiring debt and $49 million of net derivative gains. The comparison quarter included $55 million of debt-retirement gains and a $197 million derivative loss. Together, changes in these two lines added $325 million to the year-over-year pretax earnings increase. They should be separated from improvement in selling production.
Reporting basis: The impairment, depletion effects and debt gains here are pretax; no assumed after-tax adjusted profit is presented. The depletion comparison is against the first quarter of 2026; the $325 million gain comparison is against the second quarter of 2025.
Source: 2026 second-quarter 10-Q, statements of operations, Notes 5, 8 and 12, and management discussion of depletion and impairment, page 31.
Costs provide a counterweight to stronger prices. First-half lease operating expense—the cost of running producing wells—rose from $848 million to $1.10 billion. The cost per equivalent barrel increased from $5.29 to $6.08. Management identifies higher water-disposal charges after the sale of water assets, a favorable water-cost adjustment in the comparison period, added acquired wells, maintenance and greater production as contributors.
The water transaction illustrates a spending tradeoff. Selling the infrastructure brought in cash that could reduce borrowing, but continued use requires payments to its new owner. Lower investment in owned assets does not necessarily mean lower future operating costs.
Quarterly cash operating expense per equivalent barrel improved from the first quarter, but the year-over-year comparison was less favorable.
| Consolidated cash operating costs, US dollars per barrel of oil equivalent | Second quarter 2025 | First quarter 2026 | Second quarter 2026 |
|---|---|---|---|
| Lease operating expense | 5.26 | 6.21 | 5.96 |
| Gathering, processing and transportation expense | 1.73 | 1.36 | 1.22 |
| Total cash operating expense | 10.10 | 11.26 | 10.96 |
Reporting basis: Total cash operating expense also includes production and property taxes and cash administrative expense.
The lower quarterly total does not by itself measure operating efficiency. Management attributes part of the improvement in well-operating costs to cost controls. Separately, the filing attributes the first-half decline in gathering and transport expense mainly to greater use of contracts whose charges are deducted from revenue. That changes where costs appear, without eliminating them; it is not evidence of a new accounting policy. Reported unit costs improved from the first quarter, while total cash operating cost per equivalent barrel remained above the prior-year quarter.
Sources: 2026 second-quarter 10-Q, Note 4 and management discussion, pages 30–31 and 34–35; August 3 results, “Average Cash Costs per BOE.”
4. Cash covered development spending and helped repay borrowing
Cash generation improved enough to support development, shareholder payments and debt reduction. First-half cash from operations increased 34.4% even though reported profit declined. Depletion—the accounting cost of using up oil and gas properties—and the impairment help explain the gap between profit and cash. These charges reduced income without being current-period cash outflows; they did not themselves generate cash.
| First-half consolidated cash reconciliation, US dollars in millions | 2025 | 2026 |
|---|---|---|
| Net cash from operating activities | 4,032 | 5,417 |
| Cash additions to oil and gas properties, positive spending amount | 1,806 | 1,929 |
| Cash remaining after those additions, calculated | 2,226 | 3,488 |
| Property acquisitions, positive spending amount | 3,875 | 752 |
| Asset-sale proceeds | 57 | 657 |
| Other investing outflows, positive amount | 8 | 29 |
| Cash remaining after all investing activities, calculated | -1,600 | 3,364 |
| Net financing cash flow | 1,657 | -3,006 |
| Increase in cash including restricted cash | 57 | 358 |
Calculation notes: The development-spending remainder uses the reported cash additions line and excludes acquisitions. It is not management’s defined Free Cash Flow.
Source: 2026 second-quarter 10-Q, consolidated cash-flow statement, page 3.
The $3.49 billion development-spending remainder is smaller than management’s $4.04 billion first-half Free Cash Flow. Management’s measure excludes changes in operating assets and liabilities, such as unpaid customer bills and amounts awaiting payment to suppliers or royalty owners. Those changes consumed $547 million in the first half. Keeping them in the calculation shows how much cash actually remained during this period.
The largest timing use was $563 million tied to receivables: sales entered earnings before the cash was collected. Accounts payable and accrued liabilities used another $204 million. Conversely, revenue and royalties awaiting payment to other owners supplied $324 million. This last amount is cash held temporarily, not additional income belonging to Diamondback.
Sources: 2026 second-quarter 10-Q, cash-flow statement; August 3 results, reconciliation of operating cash and Free Cash Flow.
Starting with $2.20 billion of consolidated net income, the cash statement adds back $2.57 billion of depreciation, depletion and related charges and $1.40 billion of impairment. It removes the $133 million debt-retirement gain and the $166 million accounting derivative gain, then includes $246 million of actual derivative settlements received. A $206 million deferred-tax benefit is also removed. Other adjustments and payment-timing movements complete the reconciliation to $5.42 billion.
Cash taxes totaled $826 million, compared with $924 million a year earlier. The $206 million deferred-tax adjustment is not another cash saving to add to that reduction. It removes a tax benefit included in accounting income that was not a current-period cash receipt.
Source: 2026 second-quarter 10-Q, cash-flow statement and Notes 11–14, pages 18–23.
Financing used $3.01 billion. Principal cash movements included $1.76 billion of debt repayments net of new borrowing, $689 million of Diamondback share repurchases, $228 million of Viper repurchases, $605 million of common dividends and $279 million paid to outside owners of subsidiaries. Selling Viper shares supplied $589 million. Other financing outflows were $37 million, including items outside those headline lines.
Operating cash was the main funding source, but asset sales and the Viper share sale also helped. Cash increased from $106 million to $464 million including restricted cash; unrestricted cash rose from $104 million to $462 million. The shift from acquisition-heavy spending in 2025 to cash generation and repayment in 2026 is visible in the cash statement.
Reporting basis: Dividend-equivalent payments are included in other financing items rather than added again to common dividends.
Source: 2026 second-quarter 10-Q, consolidated cash-flow statement, page 3.
5. Debt fell, but Viper’s resources are separate
Liquidity improved, although consolidated resources are not all freely available to the parent. Diamondback controls and consolidates Viper despite owning approximately 39% on the disclosed fully diluted basis. It therefore reports all Viper assets, debt and operating results, then separately identifies the portion belonging to outside owners.
Viper’s assets cannot be used for Diamondback’s general corporate purposes, and Viper creditors do not have recourse to Diamondback’s assets. Of consolidated cash of $462 million, $77 million belonged to Viper. Diamondback’s remaining $385 million, together with its fully undrawn $3.0 billion revolving credit facility, provided $3.39 billion of standalone liquidity. Viper separately had about $1.9 billion of unused borrowing capacity.
Reporting basis: A revolving credit facility allows borrowing up to an agreed limit. Available borrowing capacity is a funding option, not cash already owned.
Source: 2026 second-quarter 10-Q, Notes 1–2 and 8, pages 6–7 and 13–14.
| Consolidated financial position, US dollars in millions | December 31, 2025 | June 30, 2026 |
|---|---|---|
| Cash and cash equivalents | 104 | 462 |
| Oil and gas sales receivables | 1,128 | 1,669 |
| Net property and equipment | 68,621 | 66,772 |
| Current debt maturities | 763 | 1,548 |
| Total debt, accounting carrying amount | 14,489 | 12,614 |
| Total liabilities | 28,092 | 26,233 |
| Total equity, including outside subsidiary owners | 42,967 | 43,985 |
| Total assets | 71,059 | 70,218 |
Reporting basis: Accounting debt includes discounts, issuance costs and other carrying adjustments; it differs from principal owed. Current maturities are amounts due within the following 12 months.
Source: 2026 second-quarter 10-Q, consolidated balance sheets, page 2, and Note 8.
The debt schedule shows $698 million of 3.25% notes due in 2026 and $850 million of 5.20% notes due in 2027. Together these explain the $1.55 billion current maturity balance. The increase in current debt therefore does not mean total borrowing increased. It shows more existing debt approaching repayment.
Both acquisition-related term loans were paid off: $550 million at Diamondback and $500 million at Viper. Diamondback also bought back approximately $777 million of long-dated notes for about $632 million including accrued interest. The transaction reduced future principal owed by more than the immediate cash payment, producing a debt-retirement gain. It also eliminated approximately $33.4 million of annual stated interest payments on the purchased notes, calculated before any replacement-funding cost.
Both revolving facilities were extended to June 2031. The annual filing describes a maximum contractual net-debt-to-capitalization ratio of 65% for each borrower. This limits debt, after specified cash deductions, relative to debt and equity under the credit agreements’ definitions. The quarterly filing reports compliance with all financial maintenance covenants, but does not disclose a June calculation. A simple balance-sheet ratio should not be substituted for the contractual test.
Calculation notes: Annual stated interest removed is $283 million × 4.40% + $494 million × 4.25% = $33.447 million, or approximately $33.4 million using the displayed inputs.
Sources: 2026 second-quarter 10-Q, Note 8; 2025 Form 10-K, Note 8, credit-facility covenants.
Interest expense alone understates the cash cost of borrowing. First-half net interest expense was $119 million. The supplemental statement reports $141 million of interest paid after subtracting $258 million recorded as part of property costs. Adding those amounts gives approximately $399 million of interest paid before that adjustment. Recording borrowing costs in assets postpones their effect on earnings; it does not eliminate the payment.
Source: 2026 second-quarter 10-Q, statements of operations and Note 14, page 23.
6. Recorded property values fell while repurchases reduced share count
Lower recorded property values reflect accounting charges as well as changes in the assets owned. Net property and equipment fell $1.85 billion. Gross oil and gas properties increased $2.05 billion, but accumulated depletion, depreciation and impairment rose substantially. Proved properties increased while unevaluated properties declined; these movements are not a simple measure of new productive capacity or changes in market value.
Inventories fell from $86 million to $67 million and remained small relative to the asset base. Joint-interest and other receivables barely changed, while production-sale receivables rose $541 million. Other assets increased from $523 million to $796 million, including $25 million held in escrow for Viper’s July acquisition. That deposit explains only part of the increase; the filing does not support assigning the whole movement to acquisitions. No separate material goodwill or intangible-asset balance appears on the consolidated balance sheet.
Revenue and royalty payables increased $320 million, broadly consistent with the operating cash timing benefit. Accounts payable and accrued capital spending increased $96 million, while other accrued liabilities fell $225 million. These are operating and investment obligations, distinct from financing debt. Deferred tax liabilities fell $208 million, with both income-statement and ownership-transaction tax effects involved.
Source: 2026 second-quarter 10-Q, balance sheets and Notes 5, 11 and 16.
Retained earnings—accumulated profit after distributions—rose from $4.74 billion to $6.04 billion. Parent-attributable profit of $1.91 billion exceeded $605 million of dividends and $4 million of dividend-equivalent payments.
Additional paid-in capital, an equity account affected by share issuance, compensation and repurchases, fell $370 million. Repurchases and employee tax withholding exceeded stock compensation and increases related to Viper ownership transactions. Accumulated other comprehensive loss stayed at $7 million. Total equity rose $1.02 billion after including the increase in outside subsidiary owners’ equity.
Repurchases return cash to selling shareholders and, when the shares are retired, increase each remaining share’s ownership fraction. Management describes growth in per-share business results through commodity-price cycles as a core objective. The benefit uses cash that could otherwise fund operations or reduce debt.
Diamondback retired repurchased shares, removing them from the outstanding share count. Shares outstanding fell from 284.595 million to 280.568 million. The company repurchased about 1.02 million shares through its regular program and 3 million from related party SGF during the first half. Equity-award vesting and employee tax withholding account for the remaining share movements. The SGF repurchase used $509 million before excise tax; SGF’s separate sale of shares to outside buyers did not raise cash for Diamondback.
Sources: 2026 second-quarter 10-Q, statements of stockholders’ equity, pages 4–5, and Notes 7, 9 and 10; August 3 shareholder letter, “Second Quarter 2026 Financial Performance.”
Fewer shares softened the first-half decline in earnings per share. Parent-attributable profit fell 9.4%, while diluted earnings per share fell 6.7%. Average diluted shares declined 3.1%. The calculation also allocates earnings to employee awards with dividend rights, so dividing all parent profit by common shares would not reproduce reported earnings per share exactly.
The board removed its minimum quarterly cash-return commitment beginning in the second quarter, giving management more discretion over cash allocation. It later doubled the repurchase authorization to $16 billion, with about $9.9 billion remaining at July 31. An authorization sets the amount the company may spend; it is not a completed cash outflow. Future repurchases will compete with debt repayment, acquisitions and drilling for the same funds.
Source: 2026 second-quarter 10-Q, Notes 9 and 16 and management discussion, “Return of Capital Commitment,” page 40.
7. Higher annual production targets come with years of infrastructure payments
The full-year production forecast rose without another budget increase, while infrastructure commitments extend well beyond this year. August guidance raised full-year oil production to at least 522,000 barrels a day and combined production to at least 1 million equivalent barrels a day. The approximately $3.9 billion annual capital budget was unchanged from the preceding update, although it had already been increased earlier in the second quarter.
The higher annual forecast does not promise production growth in every remaining quarter. Third-quarter guidance allows oil output to be roughly level with the second quarter and combined output to be lower.
| Consolidated daily production | Second quarter 2026 actual | Third quarter 2026 management forecast |
|---|---|---|
| Oil, barrels per day | 525,176 | 517,000–527,000 |
| Combined production, barrels of oil equivalent per day | 1,017,659 | 995,000–1,015,000 |
Sources: 2026 second-quarter 10-Q, production data, page 29; August 3 results, “Updated 2026 Guidance.”
First-half cash additions of $1.93 billion leave about $1.97 billion against that budget. Most planned spending supports drilling and completing wells. The filing describes turning previously drilled wells into production as one source of flexibility. It does not disclose a split between spending to maintain production and spending to grow it; comparing spending with depreciation cannot supply one.
Sources: August 3 results, cash capital expenditures and updated guidance; 2026 second-quarter 10-Q, management discussion, “2026 Capital Spending Plan,” page 39.
Pipeline access requires paying for capacity even when it is not fully used. At December 31, 2025, disclosed minimum transportation commitments totaled $3.01 billion over their remaining terms. Other operating agreements, including compressor rentals, water disposal and miscellaneous operating leases, totaled $207 million. Electrical power and electric-fracturing commitments were another $495 million and $124 million, respectively. These are year-end contractual schedules, not updated June liabilities or separate debt balances.
The second-quarter filing added a fixed-price electricity contract with $519 million of payments expected from 2028 through 2034. Reliable power supports field operations, while fixed prices reduce one source of uncertainty. The tradeoff is a longer payment commitment if future activity or market prices change. The mixed operating-agreement category does not provide a standalone lease-liability total, so treating all $207 million as leases would be incorrect.
Reporting basis: Historical commitment totals are not added to current reported debt. The transportation total is $3,013 million, rounded to $3.01 billion. The new electricity commitment comprises $28 million in 2028, $132 million across 2029–2030 and $359 million across 2031–2034.
Sources: 2025 Form 10-K, Note 15, page 111; 2026 second-quarter 10-Q, Note 15, page 24.
Water disposal presents another operational exposure. Diamondback’s Deep Blue arrangement includes a 15-year dedication of water services and contingent payments linked to well-completion thresholds. Depending on those thresholds, Diamondback could receive up to $200 million or owe up to $150 million across the stated 2026–2028 arrangement. Those alternatives are conditional transaction terms, not forecast income or an assumed loss.
The company also carries $547 million of obligations to plug wells and restore sites, discounted to their present value. Separate Louisiana coastal litigation involves five cases with uncertain scope and damages. The filing does not quantify a reasonably possible loss range. Management’s belief that the claims lack merit does not eliminate that exposure. Management expects a separate offshore decommissioning trust contribution to be immaterial.
Source: 2026 second-quarter 10-Q, Notes 4, 6–7 and 15, pages 9, 11 and 24.
Portfolio spending continues after quarter-end. Viper completed Riverbend on July 1 for approximately $339 million in cash, including escrow already funded, plus 3.69 million Viper shares. The August agreement to transfer additional Diamondback mineral interests to Viper is different: it is a transaction within the controlled group in exchange for Viper units and shares. It does not generate new group cash from an external buyer. Keeping these transactions separate avoids overstating either disposal proceeds or growth.
Source: 2026 second-quarter 10-Q, Note 16, pages 24–25.
8. Financial flexibility improved faster than operating constraints eased
Diamondback converted stronger oil sales into a stronger funding position. Operating cash covered cash development spending, while debt repayments and asset monetization reduced borrowing. Removing the fixed minimum cash-return commitment gave management more room to direct cash toward debt reduction.
The operating plan offers specific tests of further progress: meeting the higher full-year production forecast within the updated annual budget, improving gas access and reducing debt obligations. The third-quarter forecast does not require another step up from second-quarter production. Meanwhile, second-quarter profit depended heavily on oil prices, and higher well-operating costs than a year earlier show that greater production alone has not removed cost pressure.
Successful execution would mean improved gas receipts and delivery of the annual production plan without another budget increase. That would make the enlarged asset base more useful to the business even if oil prices retreat from the quarter’s realized level.
Sources: 2026 second-quarter 10-Q, cash-flow statement and management discussion; August 3 results and guidance.
Calculation notes
Reporting basis: Financial statement amounts are consolidated US GAAP figures unless marked otherwise. Viper is fully consolidated with intercompany transactions eliminated; parent-attributable profit excludes outside owners’ share. Dollar amounts in the financial tables are in millions except where a header specifies per-share or per-unit amounts. Share counts and production volumes use their stated units. Source amounts are rounded. No subsidiary operating profits have been added to parent results.
- Growth equals current amount divided by comparable prior amount minus one. Revenue growth is 51.2% for the quarter and 26.9% for the first half. First-half operating-profit change is $2,628 million ÷ $2,812 million − 1 = -6.5%. Quarterly operating-margin improvement is 14.2 percentage points, not 14.2%.
- Production growth: 94.680 million oil barrels ÷ 87.943 million − 1 = 7.7%; 180.749 million equivalent barrels ÷ 160.268 million − 1 = 12.8%.
- Revenue bridge: first-half production sales of $6,973 million + $973 million net price effect + $665 million volume effect = $8,611 million. Quarterly product changes are oil +$1,775 million, gas -$373 million and liquids +$68 million = +$1,470 million.
- Purchased-oil contribution: second-quarter 2026 sales less purchase expense were 739 − 730 = 9, versus 335 − 331 = 4 in 2025, an increase of $5 million. First-half 2026 sales less purchase expense were 1,124 − 1,123 = $1 million.
- Profit-to-cash reconciliation, US dollars in millions: 2,199 + 2,565 + 1,400 − 206 − 133 − 166 + 246 + 59 − 563 − 204 + 0 + 324 − 104 = 5,417. Payment-timing items sum to -547. Removing them produces management’s 5,964 operating cash before working-capital changes; subtracting 1,929 produces its 4,035 Free Cash Flow. The actual-cash remainder used here is 5,417 − 1,929 = 3,488.
- Cash reconciliation: 106 + 5,417 − 2,053 − 3,006 = 464, including 2 of restricted cash at both endpoints. Investing outflow is 1,929 + 752 − 657 + 29 = 2,053. Financing is 6,290 − 8,047 − 180 − 509 − 228 + 589 − 605 − 279 − 37 = -3,006.
- Balance-sheet checks: June assets of 70,218 = liabilities of 26,233 + equity of 43,985. December assets of 71,059 = liabilities of 28,092 + equity of 42,967. Accounting debt is 1,548 current + 11,066 long-term = 12,614, down 1,875 from year-end. Gross principal is approximately 12,766; carrying adjustments explain the difference and are not additional repayments.
- Equity reconciliation, US dollars in millions: paid-in capital 32,236 + 59 stock compensation − 26 net award-tax effects − 181 regular repurchases including excise tax − 514 related-party repurchases including excise tax + 219 Viper share-sale equity effect + 73 net ownership changes = 31,866. Retained earnings 4,740 + 1,907 − 605 − 4 = 6,038. Outside owners’ equity 5,995 + 5 compensation − 1 award-tax effect − 228 repurchases − 279 dividends + 308 share-sale equity effect − 7 ownership changes + 292 income = 6,085.
- The $589 million Viper share-sale cash receipt differs from the $527 million direct equity entry because the transaction also recognized tax effects. The direct equity entry comprises $219 million attributable to Diamondback and $308 million attributable to outside owners. Disclosed amounts are rounded.
- Earnings per share uses the two-class method, which allocates some earnings to participating employee awards: first-half parent profit of $1,907 million less $11 million allocated to those awards, divided by 281.993 million average diluted common shares, rounds to $6.72. Second-quarter $1,882 million less $11 million, divided by 281.202 million shares, rounds to $6.65.
Sources: 2026 second-quarter 10-Q, pages 1–5, Notes 8–14 and management discussion; August 3 results, non-GAAP cash reconciliation. Calculations above use the displayed source inputs.
This analysis is for information and education. It is not investment advice.