NORTHERN OIL & GAS, INC. (NOG): Results of Operations and Financial Condition
NORTHERN OIL & GAS, INC. (NOG) filed an SEC Form 8-K — Results of Operations and Financial Condition. Exhibit 99.1 NOG Announces Second Quarter 2026 Results HIGHLIGHTS • Total quarterly production of 145,659 Boe per day (47% oil), a 9% increase from the second quarter of 2025 • Record natural gas production of 464,330 Mcf per day, a 35% increase from the second quarter of 2025 an
How this was made
The 30-second read
Why it matters
Traders can update near-term expectations for production cadence (TIL acceleration in 2H), realized pricing/differentials, and capital return (repurchases and dividend) based on the disclosed quarter metrics and liquidity position.
Market read
The filing combines production growth, improved differentials, strong free cash flow, and an increased share repurchase authorization, which together can shift valuation and positioning for NOG.
What to watch
Higher G&A includes Duvernay transaction costs, and oil volumes were impacted by shut-ins and deferred turn-in-lines that are only expected to TIL in Q3, which could affect near-term production trajectory.
NOG Announces Second Quarter 2026 Results
Production increased 9% from the second quarter of 2025, free cash flow increased 424% from the first quarter of 2026 and 26% from the second quarter of 2025, and Adjusted EBITDA increased 17% sequentially. Oil volumes declined 11% year over year following well shut-ins and deferred turn-in-lines, while the company maintained annual production and capital-expenditure guidance.
Actuals vs. the company’s prior outlook
from its previous release| Metric | Guided | Reported | Verdict |
|---|---|---|---|
| Annual Production (2-stream, Boe per day) | 143,000 - 148,000 | 145,659 Boe per day | in line |
| Annual Oil Production (Bbls per day) | 71,500 - 73,500 | 68,275 Bbls per day | below |
| Total Budgeted Capital Expenditures ($ in millions) | $850 - $900 | $195.8 million | n/a |
| Net Total Wells Turned-in-Line | 74.0 - 76.0 | 12.7 net wells | n/a |
| LOE/Production Expenses (per Boe) | $9.70 - $9.90 | $9.59 per Boe | below |
| Production Taxes (as a percentage of Oil & Gas Sales) | 7.5% - 8.0% | 3.45 per Boe | n/a |
| Oil Differential to NYMEX WTI (per Bbl) | ($5.25 - $5.60) | ($3.03) | above |
| Gas Realization as a Percentage of NYMEX Henry Hub (per Mcf) | 70.0% - 72.5% | 90% realization compared with Henry Hub pricing | above |
| DD&A Rate (per Boe) | $15.00 - $15.50 | 14.55 per Boe | below |
| General and Administrative Expense (per Boe), Non-Cash | $0.25 - $0.30 | $4.4 million | n/a |
| General and Administrative Expense (per Boe), Cash (excluding transaction costs on non-budgeted acquisitions) | $0.83 - $0.86 | $0.94 per Boe | above |
Key metrics
as reported| Metric | Value | q/q | y/y |
|---|---|---|---|
| Oil and natural gas salesGAAP | $670.8 million | – | – |
| GAAP net incomeGAAP | $236.6 million | – | – |
| GAAP net income per diluted shareGAAP | $2.19 per diluted share | – | – |
| Adjusted Net Incomenon-GAAP | $122.5 million | – | – |
| Adjusted Net Income per adjusted diluted sharenon-GAAP | $1.13 per adjusted diluted share | – | – |
| Adjusted EBITDAnon-GAAP | $401.0 million | 17% increase from the first quarter of 2026 | – |
| Cash flow from operationsGAAP | $321.6 million | – | – |
| Cash flow from operations excluding changes in net working capitalother | $353.7 million | – | – |
| Free Cash Flownon-GAAP | $159.0 million | 424% from the first quarter of 2026 | 26% from the second quarter of 2025 |
| Capital expendituresother | $195.8 million | – | – |
| Total drilling and completion capital on organic assetsother | $151.0 million | – | – |
| Ground Game activityother | $44.7 million | – | – |
| Total productionother | 145,659 Boe per day | – | 9% |
| Oil productionother | 68,275 Bbls per day | – | (11)% |
| Natural gas productionother | 464,330 Mcf per day | 3.5% increase from the first quarter of 2026 | 35% |
| Oil average sales priceother | $90.02 per Bbl | – | 54% |
| Natural gas and NGLs average sales priceother | $2.64 per Mcf | – | (9)% |
| Oil net of settled oil derivativesother | 69.37 per Bbl | – | 7% |
| Natural gas and NGLs net of settled natural gas and NGL derivativesother | 3.63 per Mcf | – | 5% |
| Realized price on a Boe basis excluding settled commodity derivativesother | 50.61 | – | 24% |
| Realized price on a Boe basis including settled commodity derivativesother | 44.10 | – | (4)% |
| Production expensesother | $9.59 per Boe | – | (4)% |
| Production taxesother | 3.45 per Boe | – | 18% |
| General and administrative expensesother | 1.85 per Boe | – | 45% |
| Depletion, depreciation, amortization and accretionother | 14.55 per Boe | – | (14)% |
| Lease operating costsother | $127.1 million | – | – |
| Lease operating costsother | $9.59 per Boe | – | 4% lower on a per unit basis compared to the second quarter of 2025 |
| Production taxesother | $45.7 million | – | – |
| General and administrative costsother | $24.5 million | – | – |
| Adjusted cash G&A costsnon-GAAP | $12.4 million | – | – |
| Adjusted cash G&A costsnon-GAAP | $0.94 per Boe | – | up $0.05 per Boe compared to the second quarter of 2025 |
| Non-cash unrealized mark-to-market gain on derivativesother | approximately $156.5 million | – | – |
| Realized hedge lossesother | $86.3 million | – | – |
| Total liquidityother | $1.0 billion | – | – |
| Committed borrowing availability under Revolving Credit Facilityother | $975.0 million | – | – |
| Cash on handother | $47.6 million | – | – |
| Net producing wells at period endother | 1,369.7 | – | 19% |
Revised FY 2026 Guidance outlook
- NoteAnnual Production (2-stream, Boe per day): 143,000 - 148,000
- NoteAnnual Oil Production (Bbls per day): 71,500 - 73,500
- NoteTotal Budgeted Capital Expenditures ($ in millions): $850 - $900
- NoteNet Total Wells Turned-in-Line: 74.0 - 76.0
- NoteLOE/Production Expenses (per Boe): $9.70 - $9.80
- NoteProduction Taxes (as a percentage of Oil & Gas Sales): 7.5% - 8.0%
- NoteOil Differential to NYMEX WTI (per Bbl): ($5.00 - $5.40)
- NoteGas Realization as a Percentage of NYMEX Henry Hub (per Mcf): 70.0% - 75.0%
- NoteDD&A Rate (per Boe): $15.00 - $15.50
- NoteGeneral and Administrative Expense (per Boe), Non-Cash: $0.25 - $0.30
- NoteGeneral and Administrative Expense (per Boe), Cash (excluding transaction costs on non-budgeted acquisitions): $0.83 - $0.86
Capital returns
- Repurchased 2.95 million shares of common stock at an average price of $20.37, including commissions.
- In May 2026, the board declared a cash dividend of $0.45 per share, paid on July 31, 2026, to stockholders of record as of June 29, 2026.
- In August 2026, the board declared a cash dividend of $0.45 per share, payable on October 30, 2026, to stockholders of record as of September 29, 2026.
- On July 10, 2026, the Board of Directors authorized a $150.0 million increase to the common stock repurchase program, providing current total repurchase capacity of approximately $243.0 million.
What drove it
- Adjusted EBITDA increased 17% from the first quarter of 2026, driven primarily by a 13% improvement in realized commodity price per boe.
- Natural gas production increased 35% from the second quarter of 2025 and reached a record 464,330 Mcf per day.
- Appalachian volumes set another production record as the West Virginia joint development program culminated mid-quarter and the Utica joint development contributed a full quarter of production.
- Uinta Assets significantly outperformed internal estimates on legacy production and the 2026 development program.
- The Duvernay Light Oil Joint Development closed on June 1 for total consideration of $262.1 million.
- The company completed 30 ground game transactions adding over 2,300 net acres and an additional 6.2 net wells for $44.7 million, inclusive of associated development costs.
Concerns
- Oil production was 68,275 Bbls per day, down 11% from 76,944 Bbls per day in the second quarter of 2025.
- Oil volumes were impacted by approximately 7,000 Boe per day of well shut-ins and 3 deferred turn-in-lines in certain Permian assets in April, May and part of June.
- Natural gas realizations were pressured throughout the majority of the quarter due to weak Waha pricing.
- Realized hedge losses were $86.3 million as gains on natural gas hedges were more than offset by losses on crude oil hedges.
- G&A costs totaled $24.5 million, including $7.7 million mainly for transaction costs associated with the Duvernay acquisition.
What to watch
- The expected third-quarter turn-in-lines for the 3 deferred Permian assets and the anticipated acceleration of TILs through the second half of 2026.
- Delivery of revised FY 2026 production guidance of 143,000 - 148,000 Boe per day and oil-production guidance of 71,500 - 73,500 Bbls per day.
- The revised oil differential guidance of ($5.00 - $5.40) per Bbl and revised gas realization guidance of 70.0% - 75.0%.
- Execution of the $850 - $900 total budgeted capital-expenditure program and 74.0 - 76.0 net total wells turned-in-line guidance.
- Deployment of approximately $243.0 million of current total repurchase capacity.
Balance sheet and cash flow
- Cash flow from operations was $321.6 million.
- Excluding changes in net working capital, cash flow from operations was $353.7 million.
- Generated $159.0 million of Free Cash Flow.
- Total liquidity was $1.0 billion as of June 30, 2026, consisting of $975.0 million of committed borrowing availability under its Revolving Credit Facility and $47.6 million of cash on hand.
Analysis
NOG reported $670.8 million of oil and natural gas sales, GAAP net income of $236.6 million, and Adjusted EBITDA of $401.0 million in the second quarter. Adjusted EBITDA increased 17% from the first quarter of 2026, which the company attributed primarily to a 13% improvement in realized commodity price per boe. Cash flow from operations was $321.6 million, while Free Cash Flow was $159.0 million, up 424% from the first quarter of 2026 and 26% from the second quarter of 2025.
Production reached 145,659 Boe per day, up 9% year over year, led by record natural gas production of 464,330 Mcf per day, up 35%. Oil production was 68,275 Bbls per day, down 11% from the prior-year quarter. NOG attributed the oil-volume shortfall to approximately 7,000 Boe per day of well shut-ins and 3 deferred Permian turn-in-lines during April, May and part of June. The shut-in wells are back online and the deferred turn-in-lines are expected in the third quarter.
Pricing improved materially before hedges. The unhedged net realized oil price was $90.02 per Bbl, up 54% from $58.37 per Bbl, while the average differential to WTI was ($3.03), a 43% improvement from the second quarter of 2025. Natural gas and NGLs averaged $2.64 per Mcf, down 9%, and management cited weak Waha pricing for pressure on natural gas realizations. Settled commodity derivatives reduced realized price on a Boe basis by $6.51, and realized hedge losses were $86.3 million.
Operating costs showed a mixed pattern. Production expenses were $9.59 per Boe, down 4% year over year, and DD&A was 14.55 per Boe, down 14%. Production taxes increased to $45.7 million from $35.6 million due to higher oil prices. G&A expenses rose to $24.5 million, or 1.85 per Boe, largely reflecting $7.7 million of Duvernay transaction costs. Adjusted cash G&A was $12.4 million, or $0.94 per Boe.
Capital allocation combined development, acquisitions, repurchases and dividends. Capital expenditures were $195.8 million, including $151.0 million of D&C capital on organic assets and $44.7 million of Ground Game activity. NOG closed the Duvernay Light Oil Joint Development for $262.1 million, repurchased 2.95 million shares at an average price of $20.37, and increased repurchase capacity to approximately $243.0 million. The company maintained annual production, oil-production, capital-expenditure and well turn-in-line guidance, while revising LOE, oil-differential and gas-realization assumptions.
Management, verbatim
The strength of the NOG model shows most clearly when the macro backdrop is at its most volatile, and the flexibility of our diversified, non-operated business model is precisely what carried us through this quarter. Adjusted EBITDA was up 17% sequentially over the first quarter and we reiterated our full year production guidance despite less than ideal operating conditions.
Nick O’Grady, Chief Executive Officer
Not in the filing
stated, not guessed- Total revenue not separately reported. The filing reports oil and natural gas sales of $670.8 million.
- Gross profit and gross margin not reported.
- GAAP operating income not reported.
- Non-GAAP operating income not reported.
- Prior-year and prior-quarter total sales figures not reported.
- Prior-year and prior-quarter GAAP net income and GAAP diluted EPS figures not reported.
- Prior-year and prior-quarter Adjusted Net Income and adjusted diluted EPS figures not reported.
- Prior-year and prior-quarter Adjusted EBITDA dollar figures not reported.
- Debt balance not reported.
- Net debt not reported.
- Cash flow from operations and Free Cash Flow prior-period dollar amounts not reported.
- Segment revenue disclosure not reported.
- FY 2026 revenue, gross margin, tax rate and aggregate operating-expense guidance not reported.
- Non-cash G&A expense per Boe for the second quarter of 2026 not reported.
AlphaAI analysis generated from the company’s SEC earnings filing (Form 8-K Item 2.02, or Form 6-K for a foreign private issuer). Every figure was cross-checked against the filing text; consensus estimates, price targets and share-price reactions are not shown because they are not in the filing. AI-generated research, not investment advice.
Background
This is an SEC 8-K (Item 2.02) with an attached press release covering Northern Oil and Gas’s second quarter 2026 operating and financial results.
Ticker impact
Northern Oil and Gas reported Q2 2026 results, including GAAP net income of $236.6M, Adjusted EBITDA of $401.0M, and $159.0M free cash flow.
Moderately positive bias for the next few sessions as traders price in stronger cash generation and capital return.
The filing provides multiple concrete, decision-relevant datapoints (production growth, realized pricing/differentials, FCF, and buyback authorization) that can move expectations for 2H 2026 and capital allocation.
Market effects
Strength in a diversified US E&P’s realized differentials and cash flow can modestly reinforce sentiment toward upstream operators with similar basin exposure.
Appalachian and Uinta outperformance and Permian shut-in/turn-in normalization may influence regional production expectations.
Limited direct global linkage beyond commodity-price sensitivity and hedging mark-to-market effects.
Counterpoint
The quarter’s GAAP profitability and derivative mark-to-market gains may overstate underlying cash earnings if realized hedge losses and operating cost trends re-tighten later.
Key entities
- public_companyNorthern Oil and Gas, Inc.
NYSE-listed upstream operator reporting Q2 2026 results, production, pricing, hedging impacts, liquidity, and capital allocation.
- asset_transactionDuvernay Light Oil Joint Development
Joint development closed June 1 for total consideration of $262.1M, referenced as part of strategic expansion.
