Northern Oil and Gas (NOG) Q3 2026 earnings review
Northern Oil raises its output plan, while derivative losses bite
Northern Oil and Gas, which buys minority stakes in oil and gas wells, hit record output while paying down debt. Total production rose 19% from a year ago as delayed West Texas wells returned and gas pricing recovered. Chief executive Nick O'Grady lifted the full-year production outlook without raising the capital budget, though by our math the plan points to a seasonal dip in the fourth quarter.
| Average daily production | 156,239 Boe/d +19.2% from a year ago |
|---|---|
| Profit per share, excluding one-offs | $1.32 +28.2% from a year ago |
| Free cash flow | $148.6M +25.0% from a year ago |
| Full-year production outlook | Raised 2% middle of the range: 148,500 Boe/d |
⚖️ Verdict: 🟢 Bullish
The story got better because the company resolved its second-quarter volume dip and repaired its balance sheet ahead of schedule. Issuing long-term bonds and generating $149 million of free cash flow let management slash credit-line borrowings and bring debt below 1.5 times cash earnings. One caution: rallying crude prices triggered $51 million in cash derivative losses and forced the company to raise its unit cost outlook.
The question now is whether management can unlock the asset value it claims without giving away future oil upside to its derivative contracts. Either an asset sale at the upcoming Investor Day proves the portfolio's worth, or price caps and higher share counts keep diluting per-share cash flow. Fourth-quarter derivative settlements and Investor Day disclosures will tell.
🐂 Bull Case
Returning Wells and Gas Deals Lift Production
Northern Oil and Gas buys minority stakes in oil and gas wells run by other drillers. Chief executive Nick O'Grady raised the full-year production outlook after third-quarter output hit a record. "Put simply, we expect to deliver more for the same capital," O'Grady said. Operators connected 23.9 net wells, nearly double the second quarter's pace, as previously delayed Permian wells came online.
- Total daily production: 156,239 barrels of oil equivalent (Boe), up 19.2% from a year ago
- Daily natural gas production: 488,391 thousand cubic feet (Mcf), up 38.6% from a year ago
- Daily oil production: 74,837 barrels, up 9.6% from last quarter and 3.4% from a year ago
The rebound confirms that second-quarter oil weakness was a temporary dip from pipeline shut-ins rather than field exhaustion. Recent joint ventures in Ohio's Utica shale and Alberta's Duvernay basin also ran ahead of internal plans. However, by our math, the new full-year target points to about 143,760 Boe per day in the fourth quarter, a sequential drop as winter weather slows completions.
What to watch: fourth-quarter daily oil production against the 73,800 barrels per day implied by the full-year outlook. Beating that mark would show that new oil wells are offsetting winter slowdowns and natural field declines.
Normalizing Permian Gas Prices Lift Cash Flow
Pipeline bottlenecks at the Waha hub in West Texas had forced operators to shut in wells and accept steep discounts for natural gas during the first half of the year. Those constraints eased in the third quarter, so the energy producer collected 98% of the benchmark Henry Hub gas price across its portfolio, up from 90% in the second quarter.
In the Permian Basin, gas price realizations jumped to 85% of the benchmark from 39% last quarter, finance chief Chad Allen said. Oil price discounts to the US benchmark also narrowed to $2.84 per barrel. Better pricing added $12 million in revenue, or $0.85 per Boe, which helped lift free cash flow 25.0% from a year ago to $148.6 million despite higher drilling bills.
What to watch: fourth-quarter gas price realizations against the raised full-year target of 77.5% to 82.5% of Henry Hub. Holding realizations above 85% would show that West Texas pipeline capacity remains sufficient for winter volumes.
Bond Issue and Cash Pay Down Debt
Borrowings on the company's credit line had climbed to $825 million in June after a string of acquisitions. In the third quarter, the non-operator issued $500 million of 7.5% senior notes due in 2034 and used excess cash flow to cut total debt. "We cut total debt by more than $100 million, brought leverage below 1.5 times a quarter ahead of our year-end goal, and continued buying back our own shares," O'Grady said.
Credit line borrowings dropped to $223 million, leaving $1.6 billion in total liquidity. Banks also reaffirmed the $1.975 billion borrowing base in November, and O'Grady told analysts, "I do not think we are interested at this point in doing a levering transaction." Paying down the credit line and ruling out debt-funded deals removes the near-term balance-sheet pressure.
What to watch: net debt to annualized Ebitda excluding one-offs at year-end. Keeping the ratio below the 1.47 times reached in September will confirm that acquisition spending is staying inside free cash flow.
Small Deals Add Oil Wells at Lower Cost
Alongside large joint ventures, Northern Oil and Gas runs a "ground game" strategy of buying small, piecemeal acreage and well stakes directly from operators looking to share drilling costs. During the third quarter, President Adam Dirlam's team closed 19 such transactions for $56.5 million, adding 1,060 net acres and 2.9 net wells with "nearly 85% of capital deployed to the Permian, Williston, and Uinta basins".
At the same time, well proposals elected by the team averaged $739 per lateral foot, down 2.9% from $761 in the second quarter as operators drilled longer horizontal wells. Dirlam said the team rejected only about 3% of proposed wells, mostly "delineation type wells, more science experiments". Lower per-foot drilling costs let the company maintain its $850 million to $900 million capital budget while raising output.
What to watch: normalized well costs per lateral foot in the fourth quarter. Holding costs near $739 per foot will show whether longer wells continue to offset oilfield service inflation into 2027.
🐻 Bear Case
Oil Price Caps Cost $51 Million in Cash
In August, the company's outlook stated that second-half derivative contracts would produce minimal gains or losses at prevailing oil and gas prices. Instead, crude oil rallied to an unhedged average price of $82.83 per barrel in the third quarter, which pushed the company's oil swaps and price collars into a loss position.
- Settled derivative cash losses: $51.4 million, or $3.58 per Boe, driven by $10.51 per barrel lost on oil contracts
- Non-cash mark-to-market derivative losses: $308.0 million, driving a $111.8 million reported net loss
- Net derivative liability on the balance sheet: $547.1 million at September 30, by our math, vs a $121.6 million net asset at year-end
Because the company locked in fourth-quarter oil swaps at $68.26 per barrel and collar ceilings at $71.44, along with options that let counterparties add swaps through 2030, its realized oil price net of hedges was flat from a year ago at $44.96 per Boe even as benchmark oil jumped 36%.
What to watch: fourth-quarter cash paid on settled derivatives if oil stays near $85 to $90 per barrel. Continued heavy cash settlements will show how much oil price upside the derivative book gives away.
Higher Costs and Share Count Dilute Gains
While stronger gas volumes and prices lifted oil and gas sales 44.7% from a year ago, operating expenses per barrel also climbed. Lease operating expenses — the daily field costs of pumping and processing oil and gas — rose to $9.98 per Boe, "driven in part by higher processing costs" in the Williston Basin. Overhead expenses also rose 7% per unit "to support the Company’s growth initiatives".
As a result, Allen raised the full-year outlook for both lease operating expenses and cash overhead per Boe. Meanwhile, the company bought back 667,989 shares for $16.0 million ($23.96 per share), but the diluted share count excluding one-offs still rose 9.2% from a year ago to 107.9 million because of shares issued in March and June for acquisitions. That share dilution kept per-share profit growth (+28.2%) well below total profit growth (+39.7%).
What to watch: fourth-quarter share repurchases out of the remaining $227.2 million authorization. Unless buybacks shrink the total share count below 105 million, past equity issuances will continue to dilute per-share cash flow.
Risks this quarter didn't answer
Four standing concerns from prior quarters received no new quantitative resolution in the third-quarter release or call, though O'Grady noted plans for a first Investor Day in the coming months that may address portfolio strategy.
- Asset-value bridge: O'Grady again said shares trade below underlying asset value and mentioned "divestitures that bring value forward", but only an actual asset sale or a year-end reserve report will test that figure.
- Accounting method review: the company recorded no asset write-downs this quarter as oil rose, and gave no update on whether it will switch from full-cost to successful-efforts accounting at year-end.
- Reliance on outside operators: Uinta Basin partner commentary worried investors this week; O'Grady said Uinta is 8% of volume and on track, which fourth-quarter basin volumes will test.
- 2029 convertible notes and Canadian currency exposure: $700 million of convertible debt due in 2029 and small foreign-exchange losses ($0.5 million in Q3) remain unchanged background items.
💲 Other KPIs
Sales of physical oil and gas before derivative contracts rose 44.7% from a year ago and 4.0% from the second quarter. A 35.6% jump in unhedged oil prices and a 38.6% increase in natural gas volumes drove the gain. Reported total revenue fell 37.9% to $345.9 million only because accounting rules include $308.0 million of non-cash derivative losses.
The backlog of wells being drilled or waiting for completion shrank by 6.0 net wells from the end of June. Operators connected 23.9 net wells to sales lines during the quarter while adding 18.1 new net wells to the drilling list. This pipeline of unfinished wells supplies the company's production over the next five to six months.
Diluted profit per share excluding non-cash derivative swings and transaction costs climbed 28.2% from $1.03 a year ago and 16.8% from $1.13 in the second quarter. That reversed a year-over-year decline in the prior quarter. Total net income excluding one-offs reached $142.2 million, up 39.7% from a year ago on stronger volumes and narrower price discounts.
🔮 Guidance
Raised. The middle of the full-year range moved up by 3,000 Boe per day, pointing to 11.2% growth from last year. By our math, the new outlook leaves about 143,760 Boe per day for the fourth quarter, down 8.0% from the third quarter's record pace as winter slows North Dakota completions, but up 2.8% from a year ago.
Raised. Management lifted the bottom of the range by 250 barrels per day, raising the middle of the range to 72,625 barrels per day. By our math, that implies about 73,800 barrels per day in the fourth quarter, down slightly from 74,837 in the third quarter and roughly even with last year's fourth quarter.
Unchanged. The company kept its full-year capital budget range intact, though Allen said spending will land toward the $900 million top end because of brisk ground game dealmaking. After $709.9 million spent across the first three quarters, by our math the plan leaves $165 million at the middle of the range and $190 million at the top for the fourth quarter.
Unchanged. The target remains 75.0 net wells at the middle of the range. With 53.7 net wells connected through September, by our math the plan calls for 20.3 to 22.3 net wells in the fourth quarter, down slightly from 23.9 in the third quarter as operators wrap up annual drilling budgets.
Raised (higher cost). Management moved the unit field cost range up by $0.05 per Boe after third-quarter costs hit $9.98 per Boe on Williston gas processing fees. Year-to-date costs stand at $9.77 per Boe, and Allen said the updated range points to fourth-quarter unit costs similar to the third quarter.
Cut (lower tax rate). The company lowered its expected production tax rate by 0.625 percentage points at the middle of the range to match year-to-date actuals of 6.94% of oil and gas sales. In the third quarter, production taxes were 6.92% of sales ($48.3 million) as tax-exempt or lower-tax natural gas took a larger share of output.
Raised (narrower discount). The company tightened its expected full-year oil price discount by $0.95 per barrel at the middle of the range after third-quarter discounts averaged just $2.84 per barrel. It is the second consecutive quarter management has improved this target.
Raised. Management lifted the full-year gas price realization target by 7.5 percentage points at the middle of the range after third-quarter realizations reached 98% of Henry Hub. This is the second straight raise as West Texas pipeline pressure eased and natural gas liquids prices held firm.
Unchanged. Depletion, depreciation and amortization remains projected at $15.25 per Boe at the middle of the range, even though third-quarter depletion ran lower at $14.47 per Boe and nine-month depletion averaged $14.59 per Boe.
Raised (higher cost). Management lifted the cash overhead target by $0.03 per Boe at the middle of the range after first-half costs ($0.96 and $0.94 per Boe) and third-quarter costs ($0.88 per Boe) ran above the prior $0.83 to $0.86 target. Non-cash overhead remains unchanged at $0.25 to $0.30 per Boe.
❓ Key Questions
What bridges your reserve value to your internal asset estimate?
Chief executive Nick O'Grady plans a first Investor Day and again stated that the company's underlying assets are worth far more than the market recognizes. Investors need a quantitative bridge from the last reported reserve value to management's internal estimate, or an actual asset sale.
How much 2027 oil upside is capped by sold options?
The company lost $51.4 million in cash on settled derivatives this quarter, and its footnotes state that derivative tables exclude swaptions and call options that let counterparties increase hedged volumes. Investors need to know the exact strike prices and volumes of those options for 2027.
Will you report basin-level operating margins again this quarter?
Last quarter's presentation introduced a breakdown of operating costs and margins by basin, which was not in the third-quarter earnings release. Seeing those figures in the presentation or filing will show whether higher Williston processing fees are hurting returns there.
When will you decide on switching to successful-efforts accounting?
After nearly $1 billion of full-cost ceiling-test write-downs over 2025 and early 2026, management said it was evaluating a switch to successful-efforts accounting. With year-end approaching, investors need to know if the accounting basis for 2027 earnings will change.