Northern OIL & Gas, Inc.: Q2 FY2026 earnings call

What management said about Q2 FY2026, from the documents filed with the SEC on 6 August 2026: press release. Guidance figures: 1 raised, 1 lowered, 4 kept. The quarter’s numbers.

Read the filing

Key takeaways

• Total production grew 9% year-over-year: Second quarter 2026 production averaged 145,659 Boe per day, up from 134,094 Boe per day in second quarter 2025. Oil represented 47% of production at 68,275 Bbls per day, down from 76,944 due to temporary Permian shut-ins. Natural gas hit record 464,330 Mcf per day, up 35% year-over-year. Source
• Net income and EBITDA significantly improved: Second quarter GAAP net income was $236.6 million or $2.19 per diluted share. Adjusted EBITDA of $401.0 million was up 17% sequentially from first quarter 2026, driven by 13% improvement in realized commodity prices per Boe. Adjusted Net Income was $122.5 million or $1.13 per adjusted diluted share. Source
• Free cash flow surged 26% year-over-year: Generated $159.0 million of Free Cash Flow, up 424% from first quarter 2026 and 26% from second quarter 2025. Cash flow from operations reached $321.6 million, or $353.7 million excluding working capital changes. Source
• Temporary production curtailment in Permian: Oil volumes were impacted by approximately 7,000 Boe per day of well shut-ins and 3 deferred turn-in-lines in Permian assets during April, May, and part of June. Shut-ins driven by adverse wellhead economics as significantly negative Waha realizations offset strong oil prices. Shut-in wells were back on line as quarter ended. Source
• Duvernay acquisition expansion into Canada: Closed Duvernay Light Oil Joint Development on June 1 for total consideration of $262.1 million. Entry into high-quality, low-breakeven Canadian basin with significant growth potential strategically expands addressable market. Source
• Diversified model proved resilient: CEO noted that NOG model demonstrates strength during volatile macro periods with flexibility of diversified non-operated portfolio. Company reiterated full-year production guidance despite second-quarter operational challenges, directly demonstrating platform resiliency. Source

“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

Guidance

What changed from last quarter

• New: Company entered Duvernay basin in Canada with joint development acquisition, expanding addressable market into new high-quality, low-breakeven basin with significant growth potential. Source
• Guidance lowered: Operating cost guidance improved with LOE per Boe range tightened on upper end from $9.90 to $9.80, reflecting better unit cost expectations. Source
• Guidance raised: Oil price realization guidance improved with differential to WTI narrowing from ($5.25-$5.60) to ($5.00-$5.40), indicating higher net realized prices expected. Source
• Guidance raised: Natural gas realization guidance improved with expected percentage of Henry Hub increased from 72.5% to 75.0% at upper end. Source

Production Growth Drivers

• Total production grew 9% year-over-year: Second quarter 2026 production averaged 145,659 Boe per day, up from 134,094 Boe per day in second quarter 2025. Oil represented 47% of production at 68,275 Bbls per day, down from 76,944 due to temporary Permian shut-ins. Natural gas hit record 464,330 Mcf per day, up 35% year-over-year. Source
• Appalachian production reached new record: Appalachian volumes set another production record as joint development program in West Virginia culminated mid-quarter and Utica joint development contributed a full quarter of production for the first time. Source
• Uinta assets outperformed internal estimates: Uinta assets significantly outperformed internal expectations both on legacy production and on the 2026 development program, while Williston basin topped expectations by 4.0%. Source

Financial Performance and Cash Flow

• Net income and EBITDA significantly improved: Second quarter GAAP net income was $236.6 million or $2.19 per diluted share. Adjusted EBITDA of $401.0 million was up 17% sequentially from first quarter 2026, driven by 13% improvement in realized commodity prices per Boe. Adjusted Net Income was $122.5 million or $1.13 per adjusted diluted share. Source
• Free cash flow surged 26% year-over-year: Generated $159.0 million of Free Cash Flow, up 424% from first quarter 2026 and 26% from second quarter 2025. Cash flow from operations reached $321.6 million, or $353.7 million excluding working capital changes. Source
• Strong liquidity position maintained: Total liquidity of $1.0 billion at June 30, 2026 consisting of $975.0 million committed borrowing availability under Revolving Credit Facility and $47.6 million of cash on hand. Source

“We strategically expanded our total addressable market by entering the Duvernay, a high quality, low break-even basin with significant growth potential, while also further enhancing our lower 48 footprint through our accretive and dynamic ground game program. Additionally, we opportunistically repurchased ~3 million shares of our stock at a highly attractive valuation, exactly the kind of disciplined capital allocation the NOG model is built to enable.”

Nick O'Grady, Chief Executive Officer

Operational Challenges and Resolutions

• Temporary production curtailment in Permian: Oil volumes were impacted by approximately 7,000 Boe per day of well shut-ins and 3 deferred turn-in-lines in Permian assets during April, May, and part of June. Shut-ins driven by adverse wellhead economics as significantly negative Waha realizations offset strong oil prices. Shut-in wells were back on line as quarter ended. Source
• Deferred completions expected to recover: Three deferred turn-in-lines expected to come online in third quarter as completion operations finish. Management expects higher oil production in Q3 as improved Waha market conditions take hold and prices normalize. Source

Pricing Realization and Hedging

• Oil differentials improved significantly: Unhedged net realized oil price was $90.02 per Bbl with differential to WTI of ($3.03), a 43% improvement from second quarter 2025. Oil price improvement reflects better market conditions relative to prior year. Source
• Gas prices pressured by Waha weakness: Unhedged net realized gas price was $2.64 per Mcf, representing 90% realization compared with Henry Hub. Natural gas realizations pressured by weak Waha pricing throughout most of quarter, offset by solid NGL realizations and improved differentials in other regions. Conditions began improving in late June. Source
• Mark-to-market derivatives gain on hedges: Non-cash unrealized mark-to-market gain on derivatives of approximately $156.5 million driven by changes to derivatives portfolio value. Realized hedge losses were $86.3 million as gains on natural gas hedges were offset by losses on crude oil hedges. Source

“NOG remains as strong and as well positioned as ever with an asset base that is materially undervalued by the public market juxtaposed against one of the strongest private asset markets in decades. We believe our value proposition will be well illuminated over time, and we remain steadfast in executing a business plan built to ensure the market recognizes both the value inherent in what we own today and our ability to generate attractive risk-adjusted returns across the cycle.”

Nick O'Grady, Chief Executive Officer

Operating Costs and Efficiency

• Lease operating costs improved per unit: Lease operating costs were $127.1 million or $9.59 per Boe, down 4% on per-unit basis compared to second quarter 2025. Production taxes increased to $45.7 million due to higher oil prices, while G&A increased to $24.5 million including $7.7 million in Duvernay transaction costs. Source
• Adjusted cash G&A costs modest increase: Adjusted cash G&A costs excluding stock-based compensation and acquisition costs totaled $12.4 million or $0.94 per Boe, up $0.05 per Boe versus second quarter 2025. The $7.7 million increase in reported G&A primarily reflected Duvernay transaction costs. Source

Capital Deployment and Acquisitions

• Duvernay acquisition expansion into Canada: Closed Duvernay Light Oil Joint Development on June 1 for total consideration of $262.1 million. Entry into high-quality, low-breakeven Canadian basin with significant growth potential strategically expands addressable market. Source
• Ground game M&A program results: Completed 30 ground game transactions adding over 2,300 net acres and 6.2 net wells for $44.7 million inclusive of development costs. Nearly 80% of capital deployed to oil-focused basins: Permian, Williston, and Uinta. Source
• Capital spending distribution across basins: Permian Basin spending was 37% of capex, Williston 33%, Appalachian 14%, Uinta 14%, and Duvernay 2%. Basin allocation reflects company's diversified non-operated strategy. Source

Shareholder Returns

• Share repurchase program expanded: Repurchased 2.95 million shares of common stock in second quarter at average price of $20.37 per share including commissions, approximately 3% of outstanding shares. Approximately 81% of repurchases occurred before dividend record date. Board increased authorized repurchase program by $150.0 million to total repurchase capacity of approximately $243.0 million. Source
• Quarterly dividend maintained and increased: Board declared cash dividend of $0.45 per share in May 2026, paid on July 31, 2026. Board declared additional $0.45 per share dividend in August 2026, payable October 30, 2026. Dividend level reflects disciplined capital allocation and shareholder return commitment. Source

Strategy and Business Model Resilience

• Diversified model proved resilient: CEO noted that NOG model demonstrates strength during volatile macro periods with flexibility of diversified non-operated portfolio. Company reiterated full-year production guidance despite second-quarter operational challenges, directly demonstrating platform resiliency. Source

Coming up, as management said on 6 August 2026

• Permian shut-in wells returning to production: Wells shut in during April-June due to Waha economics are back on line. Company expects improved Waha market conditions and pricing normalization to support sustained production through second half 2026. Source
• Deferred turn-in-lines expected in Q3: Three deferred turn-in-lines from Permian operations expected to come on line in third quarter, contributing to higher oil production volumes.
• Turn-in-line acceleration through H2 2026: Company anticipates acceleration of turn-in-lines through second half of 2026 backed by development schedule and improving field performance. Source
• Waha pricing normalization expected: Natural gas pricing in Waha region expected to return to normalized levels, supporting improved margins and production economics on previously shut-in assets. Source

Risks management discussed

• Demand: Natural gas realizations pressured throughout quarter by weak Waha pricing. While conditions improving in late June, regional pricing weakness could continue to impact margins on gas-heavy production. Source
• Financial: Hedge book exposure to commodity prices includes open derivative contracts through 2029. At current strip prices, company anticipates de minimis gains or losses on hedge book for second half 2026, but significant price movements could affect results. Source
• Operational: Well shut-ins and deferred completions in Permian affected second quarter production. While shut-in wells were back on line by quarter end and deferred turn-in-lines expected in Q3, commodity price and infrastructure constraints could impact future production. Source

Earlier plans management reported on

• On track: Despite second-quarter operational challenges including well shut-ins and deferred completions, company reiterated full-year production guidance. Management stated guidance reaffirmed as operations returned to normal and wells came back online. Source
• On track: Company confirmed full-year capex guidance including organic drilling and ground game acquisitions despite second-quarter Duvernay transaction closing.

Other quarters

• Q1 FY2026 earnings call
• Q4 FY2025 results
• Q3 FY2025 results
• Q2 FY2025 results

Summarised with AI from the documents the company filed with the SEC. Every point is checked against the filing before it is shown: management’s own words word for word, figures against the line or table row they come from. A point that fails the check is left out. Source opens the filing at that line.