NOG Announces Fourth Quarter and Full Year 2025 Results; Provides Detailed 2026 Guidance
FOURTH QUARTER HIGHLIGHTS
•Production of 140,064 Boe per day (53% oil), a 6% increase from the fourth quarter of the prior year
•Record natural gas production of 392,163 Mcf per day, a 24% increase from the fourth quarter of the prior year
•GAAP cash flow from operations of $312.6 million. Excluding changes in net working capital, cash flow from operations was $316.6 million
•Capital expenditures of $270.2 million, excluding previously-announced non-budgeted acquisitions and other items
•Free Cash Flow (non-GAAP) was $43.2 million in the fourth quarter. See “Non-GAAP Financial Measures” below
•Declared $0.45 per share common dividend for the first quarter of 2026
•Repurchased 326,301 shares of common stock at an average price of $21.47 per share
SUBSEQUENT EVENTS
•In February 2026, closed Joint Utica Acquisition for $464.6 million cash closing payment, which reflects preliminary purchase price adjustments and is subject to post-closing settlements with the seller
•In February 2026, expanded availability under revolving credit facility by $200.0 million, with borrowing base increased to $1.975 billion and elected commitment amount increased to $1.8 billion
•In February 2026, the Company gave notice to the holders of its Senior Notes due 2028 that it would redeem all remaining outstanding notes on March 4, 2026
MINNEAPOLIS (BUSINESS WIRE) - February 25, 2026 - Northern Oil and Gas, Inc. (NYSE: NOG) (“NOG”) today announced the company’s fourth quarter and full year 2025 results and provided 2026 guidance.
MANAGEMENT COMMENTS
“Despite a challenging commodity price environment, NOG delivered growth in Adjusted EBITDA and production while further strengthening our balance sheet,” said Nick O’Grady, Chief Executive Officer. “Production increased 9% year over year, supported by increased investment in our natural gas portfolio and continued disciplined capital allocation. We expanded our asset base through approximately $340.0 million of value‑accretive acquisitions, including a record level of Ground Game activity in 2025, and our recently closed marquee Joint Ohio Utica transaction will add substantial scale to our Appalachian position. In tandem with a rigorous business development focus, we also strengthened our balance sheet by extending maturities and enhancing our liquidity.”
“While we expect commodity price volatility to persist, our 2026 capital plan is designed to perform across a range of market conditions,” continued O’Grady. “Our diversified asset base provides meaningful upside exposure to changes in operator activity, while also ensuring that NOG is positioned to generate value in either a lower‑price or recovery scenario.”
FINANCIAL RESULTS
Oil and natural gas sales for the fourth quarter were $447.7 million, as compared to $545.5 million for the prior year period; the year over year decline in sales reflects weaker oil pricing despite a 6% increase in aggregate production. Fourth quarter GAAP net loss was $70.7 million or $0.73 per diluted share. Fourth quarter Adjusted Net Income was $82.0 million or $0.83 per adjusted diluted share. Adjusted EBITDA in the fourth quarter was $366.5 million.
Oil and natural gas sales for full year 2025 were $2.1 billion. Full year 2025 GAAP net income was $38.8 million or $0.39 per diluted share. Full year 2025 Adjusted Net Income was $453.4 million or $4.57 per adjusted diluted share. Full year 2025 Adjusted EBITDA was $1.6 billion, an increase of 1% over the prior year. (See “Non-GAAP Financial Measures” below.)
PRODUCTION
Fourth quarter production was 140,064 Boe per day, a 6% increase from the prior year period. Oil production was 74,703 Bbl per day, a 3% sequential increase over the third quarter, and represented 53.3% of total production in the fourth quarter. Gas production set a record for the third consecutive quarter with an average 392,163 Mcf per day, up 11% compared to the third quarter and up 24% compared to the fourth quarter of 2024.
NOG had 24.2 net wells turned in line during the fourth quarter, compared to 16.5 net wells turned in line in the third quarter of 2025. NOG’s fourth quarter marked the highest number of net wells turned in line for the year even with approximately 3 net wells being subject to deferrals due to price sensitivity or weather. Full year 2025 production was 135,045 Boe per day, a 9% increase from the prior year.
PRICING
During the fourth quarter, NYMEX West Texas Intermediate (“WTI”) crude oil averaged $59.14 per Bbl, and NYMEX natural gas at Henry Hub averaged $4.04 per Mcf. NOG’s unhedged net realized oil price in the fourth quarter was $54.09 per Bbl, representing a $5.05 differential to WTI prices (as adjusted). NOG’s fourth quarter unhedged net realized gas price was $2.35 per Mcf, representing approximately 58% realizations compared with Henry Hub pricing. In the fourth quarter, crude oil differentials widened from the third quarter of 2025 due to constrained takeaway capacity in the Williston, partially offset by improvement in the Permian. Natural gas realizations in the fourth quarter were lower than prior periods, driven primarily by lower absolute NGL prices, a lower NGL to natural gas ratio and extremely low pricing for Waha natural gas.
For full year 2025, NOG’s realized oil price differential was $5.53 per Bbl (as adjusted) as compared to $3.88 per Bbl in 2024, reflecting higher year-over-year differentials in the Williston and Permian and a full year of impact from the Uinta Basin, which carries a higher differential to WTI. NOG’s full year unhedged net realized gas price was $2.87 per Mcf, representing approximately 79% realizations compared with Henry Hub pricing versus 93% realizations in 2024. The difference in gas realizations was primarily due to lower NGL prices, a lower NGL to natural gas ratio and persistent weakness at the Waha Hub reflecting infrastructure bottlenecks in the wake of record-high associated gas production.
OPERATING COSTS
Lease operating costs were $119.9 million in the fourth quarter of 2025, or $9.30 per Boe, a 5% decrease on a per unit basis compared to the third quarter and a 3% improvement over the fourth quarter of 2024.
Fourth quarter general and administrative (“G&A”) costs totaled $17.1 million, which includes non-cash stock-based compensation. Cash G&A costs totaled $13.0 million or $1.01 per Boe in the fourth quarter. Excluding approximately $1.4 million of transaction costs, remaining cash G&A was $11.7 million, or $0.91 per Boe.
CAPITAL EXPENDITURES AND ACQUISITIONS
Capital spending for the fourth quarter, excluding non-budgeted acquisitions and other items, was $270.2 million. This was comprised of $192.5 million of organic drilling and completion (“D&C”) capital and $77.7 million of total acquisition spending, inclusive of ground game D&C spending. NOG had 24.2 net wells turned in line in the fourth quarter. Wells in process totaled 45.6 net wells as of December 31, 2025. Total 2025 capital expenditures, excluding non-budgeted acquisitions were $1.0 billion, reflecting $173.5 million in elective ground game opportunities executed.
LIQUIDITY, CAPITAL RESOURCES AND RECENT ACQUISITIONS
As of December 31, 2025, NOG had $14.3 million in cash, $58.8 million of restricted cash and $478.0 million of borrowings outstanding on its revolving credit facility. NOG had total liquidity of $1.1 billion as of December 31, 2025, consisting of cash and committed borrowing availability under the revolving credit facility.
In October 2025, NOG issued $725.0 million of 7.875% Senior Notes due 2033 in a significantly oversubscribed offering. Proceeds from the offering were used to fund the repurchase of approximately 97.14%, or $684.9 million, of NOG’s 8.125% Senior Notes due 2028. The issuance of the 2033 Senior Notes and concurrent tender offer for the 2028 Senior Notes at the time of issuance extended the Company’s weighted average debt maturity from 3.3 years to 5.4 years.
In November 2025, the Company entered into an amended and restated revolving credit facility. The size of the revolving credit facility was unchanged, with the borrowing base at $1.8 billion and an elected commitment amount of $1.6 billion. The maturity date was extended from June 2027 to November 2030, further enhancing NOG’s weighted average debt maturity to 5.4 years. In addition, the cost of borrowing on the facility was substantially improved with a reduction of 60 basis points.
In February 2026, the Company further amended its revolving credit facility reflecting the addition of its Joint Utica Acquisition to its asset base. The Company’s borrowing base was increased from $1.8 billion to $1.975 billion and the elected commitment amount was increased from $1.6 billion to $1.8 billion. All other terms and conditions remain substantially unchanged.
In February 2026, the Company gave notice to the holders of the Senior Notes due 2028 (the “Notice of Full Redemption”) that it elected to redeem all of the outstanding Senior Notes due 2028, in accordance with the terms of the 2028 Notes Indenture. Pursuant to the Notice of Full Redemption, the Redemption Date is March 4, 2026, and the Redemption Price is 100%. As of December 31, 2025, there were $20.2 million of the 2028 Senior Notes outstanding.
In February 2026, the Company closed on its previously announced joint acquisition of interests in the Ohio Utica Shale Upstream and Midstream Assets from Antero Resources Corporation and Antero Midstream Corporation. As previously announced, NOG acquired a 40% stake with Infinity Natural Resources acquiring 60%. The closing payment by NOG was $464.6 million million in cash, which includes a $58.8 million deposit paid at signing in December 2025. The closing payment is net of preliminary and customary purchase price adjustments and remains subject to post-closing settlements with the sellers. NOG funded the acquisition with cash on hand, operating free cash flow and borrowings from NOG’s revolving credit facility.
OTHER MATTERS
NOG accounts for its assets under the Full Cost method, as opposed to the Successful Efforts method, which does not perform historical price-based asset tests. Driven by lower average oil prices, the Company recorded a non-cash impairment charge of $268.5 million in the fourth quarter of 2025 under the “ceiling test” of its full cost pool of oil and gas assets. This non-cash charge will have no impact on cash flows of the Company.
SHAREHOLDER RETURNS
In January 2026, the Company paid a cash dividend of $0.45 per share to NOG’s stockholders of record as of December 30, 2025.
In February 2026, the Company declared a cash dividend of $0.45 per share to NOG’s stockholders of record as of March 30, 2026, which is payable on April 30, 2026.
In the fourth quarter of 2025, NOG repurchased 326,301 shares of its common stock at a weighted average price of $21.47 per share, inclusive of commissions. In total during 2025, the Company repurchased a total of 1,948,996 shares at a weighted average price of $29.25, inclusive of commissions.
For the year ended December 31, 2025, the Company returned over $230.4 million to shareholders in the form of dividends of $173.4 million and common stock repurchases of $57.0 million.
2026 ANNUAL GUIDANCE
Given the volatile pricing outlook, particularly for oil, NOG is providing guidance reflecting a low price/low activity scenario and a high price/high activity scenario for production, Wells Turned-in-Line (TIL) and capital expenditures. For additional information and assumptions related to company guidance please refer the company’s earnings presentation which can be found on the company’s website at www.noginc.com.
| | | | | | | | | |
| Low Activity | | High Activity |
Annual Production (Boe per day) | 139,000 – 143,000 | | 144,000 – 148,000 |
Annual Oil Production (Bbls per day) | 68,000 – 72,000 | | 72,000 – 76,000 |
Total Capital Expenditures ($ in millions) | $850 – $900 | | $1,000 – $1,100 |
| | | |
| Net Total Wells Turned-in-Line (TIL) | 67.5 – 71.5 | | 83.0 – 87.0 |
| | | |
| | | | | | | | | |
| Operating Expenses and Differentials | Low Activity | | High Activity |
Production Expenses (per Boe) | $9.65 - $10.10 | | $9.45 - $9.90 |
Production Taxes (as a percentage of Oil & Gas Sales) | 7% - 8% | | 7% - 8% |
Average Differential to NYMEX WTI (per Bbl) | ($5.50) – ($6.50) | | ($5.50) – ($6.50) |
Average Realization as a Percentage of NYMEX Henry Hub (per Mcf) | 75% - 85% | | 75% - 85% |
DD&A (per Boe) | $15.00 – $16.00 | | $15.00 – $16.00 |
| | | | | | | | | |
General and Administrative Expense (per Boe): | Low Activity | | High Activity |
| Non-Cash | $0.25 - $0.30 | | $0.25 - $0.30 |
Cash (excluding transaction costs on non-budgeted acquisitions) | $0.81 - $0.86 | | $0.79 - $0.84 |
PROVED RESERVES AS OF DECEMBER 31, 2025
Total proved reserves at December 31, 2025, increased 1% from year-end 2024 to 384,068 million barrels of oil equivalent (74% proved developed) with an associated pre-tax PV-10 value of $4.5 billion (80% proved developed) at SEC Pricing. The reserves are calculated under SEC guidelines relating to both commodity price assumptions and a maximum five year drill schedule. See “Non-GAAP Financial Measures” below regarding PV-10 value.
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| SEC Pricing Proved Reserves(1) |
| Reserve Volumes | | PV-10(3) |
| Reserve Category | Oil
(MBbls) | | Natural Gas
(MMcf) | | Total (MBoe)(2) | | % | | Amount
(In thousands) | | % |
| PDP Properties | 123,102 | | | 899,512 | | | 273,021 | | | 71 | | | $ | 3,498,946 | | | 77 | |
| PDNP Properties | 3,952 | | | 34,892 | | | 9,768 | | | 3 | | | 140,004 | | | 3 | |
| PUD Properties | 57,807 | | | 260,833 | | | 101,279 | | | 26 | | | 891,706 | | | 20 | |
| Total | 184,861 | | | 1,195,237 | | | 384,068 | | | 100 | | | $ | 4,530,656 | | | 100 | |
_____ ___________
(1)The SEC Pricing Proved Reserves table above values oil and natural gas reserve quantities and related discounted future net cash flows as of December 31, 2025, based on average prices of $65.34 per barrel of oil and $3.39 per MMbtu of natural gas. Under SEC guidelines, these prices represent the average prices per barrel of oil and per MMbtu of natural gas at the beginning of each month in the 12-month period prior to the end of the reporting period. The average resulting price used as of December 31, 2025, after adjustment to reflect applicable transportation and quality differentials, was $59.72 per barrel of oil and $3.18 per Mcf of natural gas.
(2)Boe are computed based on a conversion ratio of one Boe for each barrel of oil and one Boe for every 6,000 cubic feet (i.e., 6 Mcf) of natural gas.
(3)Pre-tax PV10%, or “PV-10,” may be considered a non-GAAP financial measure as defined by the SEC. See “Non-GAAP Financial Measures” below.
FOURTH QUARTER 2025 RESULTS
The following table sets forth selected operating and financial data for the periods indicated.
| | | | | | | | | | | | | | | | | |
| Three Months Ended
December 31, |
| 2025 | | 2024 | | % Change |
| Net Production: | | | | | |
| Oil (MBbl) | 6,873 | | | 7,262 | | | (5) | % |
| Natural Gas (MMcf) | 36,079 | | | 29,167 | | | 24 | % |
| Total (MBoe) | 12,886 | | | 12,123 | | | 6 | % |
| | | | | |
| Average Daily Production: | | | | | |
| Oil (MBbl) | 75 | | | 79 | | | (5) | % |
| Natural Gas (MMcf) | 392 | | | 317 | | | 24 | % |
| Total (MBoe) | 140 | | | 132 | | | 6 | % |
| | | | | |
| Average Sales Prices: | | | | | |
Oil (per Bbl) (1) | $ | 54.09 | | | $ | 65.40 | | | (17) | % |
| Effect of Loss on Settled Derivatives on Average Price (per Bbl) | 8.15 | | | 2.17 | | | |
Oil Net of Settled Derivatives (per Bbl) (1) | 62.24 | | | 67.57 | | | (8) | % |
| | | | | |
Natural Gas and NGLs (per Mcf) (1) (2) | $ | 2.35 | | | $ | 2.42 | | | (3) | % |
| Effect of Gain (Loss) on Settled Derivatives on Average Price (per Mcf) | 0.47 | | | 0.33 | | | |
Natural Gas Net of Settled Derivatives (per Mcf) (1) (2) | 2.82 | | | 2.75 | | | 3 | % |
| | | | | |
Realized Price on a Boe Basis Excluding Settled Commodity Derivatives (1) (2) | $ | 35.42 | | | $ | 44.99 | | | (21) | % |
| Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe) | 5.66 | | | 2.10 | | | |
Realized Price on a Boe Basis Including Settled Commodity Derivatives (1) (2) | 41.08 | | | 47.09 | | | (13) | % |
| | | | | |
| | | | | |
| Costs and Expenses (per Boe): | | | | | |
| Production Expenses | $ | 9.30 | | | $ | 9.62 | | | (3) | % |
| Production Taxes | 2.40 | | | 3.52 | | | (32) | % |
| General and Administrative Expense | 1.33 | | | 1.28 | | | 4 | % |
| Depletion, Depreciation, Amortization and Accretion | 15.84 | | | 16.88 | | | (6) | % |
| | | | | |
| Net Producing Wells at Period End | 1,195.4 | | | 1,108.0 | | | 8 | % |
_____________
(1) Excludes the impact of certain non-cash adjustments to revenues
(2) Excludes the impact of a legal settlement (See Note 2 to our financial statements on Form 10-K for year ended December 31, 2025)
FULL YEAR 2025 RESULTS
The following table sets forth selected operating and financial data for the periods indicated.
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2025 | | 2024 | | % Change |
| Net Production: | | | | | |
| Oil (MBbl) | 27,611 | | | 26,511 | | | 4 | % |
| Natural Gas (MMcf) | 130,084 | | | 113,476 | | | 15 | % |
| Total (MBoe) | 49,292 | | | 45,423 | | | 9 | % |
| | | | | |
| Average Daily Production: | | | | | |
| Oil (MBbl) | 76 | | | 72 | | | 4 | % |
| Natural Gas (MMcf) | 356 | | | 310 | | | 15 | % |
| Total (Boe) | 135 | | | 124 | | | 9 | % |
| | | | | |
| Average Sales Prices: | | | | | |
Oil (per Bbl) (1) | $ | 59.20 | | | $ | 71.59 | | | (17) | % |
| Effect of Loss on Settled Oil Derivatives on Average Price (per Bbl) | 5.15 | | | (0.11) | | | |
Oil, Net of Settled Oil Derivatives (per Bbl) (1) | 64.35 | | | 71.48 | | | (10) | % |
| | | | | |
Natural Gas and NGLs (per Mcf) (1) (2) | $ | 2.87 | | | $ | 2.24 | | | 28 | % |
| Effect of Gain on Settled Natural Gas Derivatives on Average Price (per Mcf) | 0.45 | | | 0.76 | | | |
Natural Gas and NGLs, Net of Settled Natural Gas and NGL Derivatives (per Mcf) (1) (2) | 3.32 | | | 3.00 | | | 11 | % |
| | | | | |
Realized Price on a Boe Basis Excluding Settled Commodity Derivatives (1) (2) | $ | 40.74 | | | $ | 47.38 | | | (14) | % |
| Effect of Gain on Settled Commodity Derivatives on Average Price (per Boe) | 4.08 | | | 1.83 | | | |
Realized Price on a Boe Basis Including Settled Commodity Derivatives (1) (2) | 44.82 | | | 49.21 | | | (9) | % |
| | | | | |
| Costs and Expenses (per Boe): | | | | | |
| Production Expenses | $ | 9.61 | | | $ | 9.46 | | | 2 | % |
| Production Taxes | 2.66 | | | 3.46 | | | (23) | % |
| General and Administrative Expenses | 1.24 | | | 1.11 | | | 12 | % |
| Depletion, Depreciation, Amortization and Accretion | 16.53 | | | 16.31 | | | 1 | % |
| | | | | |
| Net Producing Wells at Period-End | 1,195.4 | | | 1,108.0 | | | 8 | % |
_____________
(1) Excludes the impact of certain non-cash adjustments to revenues
(2) Excludes the impact of a legal settlement (See Note 2 to our 2025 financial statements on Form 10-K for year ended December 31, 2025)
HEDGING
NOG hedges portions of its expected production volumes to increase the predictability of its cash flow and to help maintain a strong financial position. The following table summarizes NOG’s open crude oil commodity derivative swap contracts scheduled to settle after December 31, 2025.
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| | Crude Oil Commodity Derivative Swaps(1) | | Crude Oil Commodity Derivative Collars and Puts |
| Contract Period | | Volume (Bbls/Day) | | Weighted Average Price ($/Bbl) | | Collar Call Volume (Bbls/Day) | | Weighted Average Collar Call Prices
($/Bbl) | | Collar Put Volume (Bbls/Day) | | Weighted Average Collar Put Prices
($/Bbl) |
| | | | | | | | | | | | |
2026(1): | | | | | | | | | | | | |
| Q1 | | 25,465 | | $68.34 | | 34,680 | | $72.98 | | 27,187 | | $62.94 |
| Q2 | | 23,719 | | $66.00 | | 25,680 | | $71.17 | | 18,187 | | $63.22 |
| Q3 | | 20,745 | | $67.78 | | 23,180 | | $71.49 | | 15,687 | | $62.94 |
| Q4 | | 18,745 | | $67.87 | | 23,180 | | $71.49 | | 15,687 | | $62.94 |
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_____________
(1)Includes derivative contracts entered into through February 16, 2026. This table does not include volumes subject to swaptions and call options, which are crude oil derivative contracts that NOG has entered into, which may increase swapped volumes at the option of NOG’s counterparties. This table also does not include basis swaps. For additional information, see Notes 11 and 12 to our financial statements included in our Form 10-K filed with the SEC for the year ended December 31, 2025.
The following table summarizes NOG’s open natural gas commodity derivative swap contracts scheduled to settle after December 31, 2025.
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| | Natural Gas Commodity Derivative Swaps(1) | | Natural Gas Commodity Derivative Collars |
| Contract Period | | Volume
(MMBTU/Day) | | Weighted Average Price ($/MMBTU) | | Collar Call Volume
(MMBTU/Day) | | Weighted Average Collar Call Prices ($/MMBTU) | | Collar Put Volume
(MMBTU/Day) | | Weighted Average Collar Put Prices ($/MMBTU) |
| | | | | | | | | | | | |
2026(1): | | | | | | | | | | | | |
| Q1 | | 143,389 | | $4.08 | | 145,481 | | $4.88 | | 145,481 | | $3.42 |
| Q2 | | 136,484 | | $3.97 | | 152,140 | | $4.93 | | 152,140 | | $3.42 |
| Q3 | | 145,000 | | $4.02 | | 150,486 | | $4.89 | | 150,486 | | $3.45 |
| Q4 | | 158,370 | | $4.14 | | 150,105 | | $5.06 | | 150,105 | | $3.47 |
2027(1): | | | | | | | | | | | | |
| Q1 | | 108,833 | | $4.01 | | 77,389 | | $4.79 | | 77,389 | | $3.46 |
| Q2 | | 111,209 | | $4.00 | | 65,714 | | $4.43 | | 65,714 | | $3.45 |
| Q3 | | 110,000 | | $4.00 | | 65,000 | | $4.43 | | 65,000 | | $3.45 |
| Q4 | | 84,674 | | $3.97 | | 46,467 | | $4.41 | | 46,467 | | $3.45 |
2028(1): | | | | | | | | | | | | |
| Q1 | | 28,077 | | $3.83 | | 9,890 | | $4.17 | | 9,890 | | $3.50 |
| Q2 | | 20,220 | | $3.83 | | 10,110 | | $4.17 | | 10,110 | | $3.50 |
| Q3 | | 20,000 | | $3.83 | | 10,000 | | $4.17 | | 10,000 | | $3.50 |
| Q4 | | 16,630 | | $3.85 | | 10,000 | | $4.07 | | 10,000 | | $3.50 |
2029(1): | | | | | | | | | | | | |
| Q1 | | — | | — | | 9,889 | | $3.88 | | 9,889 | | $3.50 |
| Q2 | | — | | — | | 10,110 | | $3.88 | | 10,110 | | $3.50 |
| Q3 | | — | | — | | 10,000 | | $3.88 | | 10,000 | | $3.50 |
| Q4 | | — | | — | | 6,630 | | $3.88 | | 6,630 | | $3.50 |
_____________
(1)Includes derivative contracts entered into through February 16, 2026. This table does not include volumes subject to swaptions and call options, which are natural gas derivative contracts that NOG has entered into, which may increase swapped volumes at the option of NOG’s counterparties. This table also does not include basis swaps. For additional information, see Notes 11 and 12 to our financial statements included in our Form 10-K filed with the SEC for the year ended December 31, 2025.
The following table summarizes NOG’s open NGL commodity derivative swap contracts scheduled to settle after December 31, 2025.
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| NGL Contracts | | |
| | Swaps | | | | | | | | | | |
| Contract Period | | Volume
(BBL) | | Weighted Average Price
($/BBL) | | | | | | | | |
| | | | | | | | | | | | |
2026(1): | | | | | | | | | | | | |
| Q1 | | 92,250 | | $36.00 | | | | | | | | |
| Q2 | | 106,925 | | $33.32 | | | | | | | | |
| Q3 | | 96,600 | | $33.03 | | | | | | | | |
| Q4 | | 80,500 | | $33.32 | | | | | | | | |
2027(1): | | | | | | | | | | | | |
| Q1 | | 65,250 | | $32.30 | | | | | | | | |
| Q2 | | 59,150 | | $30.73 | | | | | | | | |
| Q3 | | 57,500 | | $30.69 | | | | | | | | |
| Q4 | | 52,900 | | $30.87 | | | | | | | | |
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(1)Includes derivative contracts entered into through February 16, 2026. This table does not include volumes subject to swaptions and call options, which are natural gas derivative contracts that NOG has entered into, which may increase swapped volumes at the option of NOG’s counterparties. This table also does not include basis swaps. For additional information, see Notes 11 and 12 to our financial statements included in our Form 10-K filed with the SEC for the year ended December 31, 2025.
The following table presents NOG’s settlements on commodity derivative instruments and unsettled gains and losses on open commodity derivative instruments for the periods presented, which is included in the revenue section of NOG’s statement of operations:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended December 31, | | Twelve Months Ended December 31, |
(In thousands) | 2025 | | 2024 | | 2025 | | 2024 |
| Cash Received on Settled Derivatives | $ | 72,938 | | | $ | 25,504 | | | $ | 201,321 | | | $ | 83,225 | |
| Non-Cash Mark-to-Market Gain (Loss) on Derivatives | 86,376 | | | (59,728) | | | 179,343 | | | (21,258) | |
| Gain on Commodity Derivatives, Net | $ | 159,314 | | | $ | (34,224) | | | $ | 380,664 | | | $ | 61,967 | |
CAPITAL EXPENDITURES & DRILLING ACTIVITY
| | | | | | | | | | | | | | |
| (In millions, except for net well data) | | Three Months Ended December 31, 2025 | | Twelve Months Ended December 31, 2025 |
| Capital Expenditures Incurred: | | | | |
| Organic Drilling and Development Capital Expenditures | | $192.5 | | $828.6 |
| Ground Game Drilling and Development Capital Expenditures | | $51.4 | | $76.0 |
| Ground Game Acquisition Capital Expenditures | | $26.3 | | $97.5 |
| Other | | $3.2 | | $9.2 |
| Non-Budgeted Acquisitions | | $5.4 | | $166.5 |
| | | | |
| Net Wells Turned In Line | | 24.2 | | 80.7 |
| | | | |
| Net Producing Wells (Period-End) | | 1,195.4 | | 1,195.4 |
| | | | |
| Net Wells in Process (Period-End) | | 45.6 | | 45.6 |
| Change in Wells in Process over Prior Period | | (7.8) | | (4.8) |
| | | | |
| Weighted Average AFE for Wells Elected to | | $10.1 | | $10.2 |
Capitalized costs reflect ongoing development activities and are primarily influenced by the number of net wells-in-process additions and net well turn-in-lines during the reporting period. Additionally, capital can be incurred via workover activity for enhancement of existing producing wells.
FOURTH QUARTER 2025 EARNINGS RELEASE CONFERENCE CALL
In conjunction with NOG’s release of its financial and operating results, investors, analysts and other interested parties are invited to listen to a conference call with management on Thursday, February 26, 2026 at 8:00 a.m. Central Time.
Those wishing to listen to the conference call may do so via the company’s website, www.noginc.com, or by phone as follows:
Webcast: https://events.q4inc.com/attendee/457076072
Dial-In Number: (800) 715-9871 (US/Canada) and (646) 307-3411 (International)
Conference ID: 4503139 - Fourth Quarter and Year-End 2025 Earnings Conference Call
Replay Dial-In Number: (800) 770-2030 (US/Canada) and (647) 362-9199 (International)
Replay Access Code: 4503139 - Replay will be available through February 25, 2027
ABOUT NORTHERN OIL AND GAS
NOG is a real asset company with a primary strategy of acquiring and investing in non-operated minority working and mineral interests in the premier hydrocarbon producing basins within the contiguous United States. More information about NOG can be found at www.noginc.com.
SAFE HARBOR
This press release contains forward-looking statements regarding future events and future results that are subject to the safe harbors created under the Securities Act of 1933 (the “Securities Act”) and the Securities Exchange Act of 1934 (the “Exchange Act”). All statements other than statements of historical facts included in this release regarding NOG’s financial position, operating and financial performance, business strategy, dividend plans and practices, plans and objectives of management for future operations, industry conditions, and indebtedness covenant compliance are forward-looking statements. When used in this release, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “continue,” “anticipate,” “target,” “could,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may” or other words and similar expressions that convey the uncertainty of future events or outcomes. Items contemplating or making assumptions about actual or potential future production and sales, market size, collaborations, and trends or operating results also constitute such forward-looking statements.
Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond NOG’s control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following: changes in crude oil and natural gas prices, the pace of drilling and completions activity on NOG’s current properties and properties pending acquisition, infrastructure constraints and related factors affecting NOG’s properties; cost inflation or supply chain disruptions, ongoing legal disputes over and potential shutdown of the Dakota Access Pipeline; NOG’s ability to acquire additional development opportunities, potential or pending acquisition transactions, the projected capital efficiency savings and other operating efficiencies and synergies resulting from NOG’s acquisition transactions, integration and benefits of property acquisitions, or the effects of such acquisitions on NOG’s cash position and levels of indebtedness; changes in NOG’s reserves estimates or the value thereof, disruption to NOG’s business due to acquisitions and other significant transactions; general economic or industry conditions, nationally and/or in the communities in which NOG conducts business; changes in the interest rate environment, legislation or regulatory requirements; conditions of the securities markets; risks associated with NOG’s Convertible Notes, including the potential impact that the Convertible Notes may have NOG’s financial position and liquidity, potential dilution, and that provisions of the Convertible Notes could delay or prevent a beneficial takeover of NOG; the potential impact of the capped call transaction undertaken in tandem with the Convertible Notes issuance, including counterparty risk; increasing attention to environmental, social and governance matters; NOG’s ability to consummate any pending acquisition transactions; other risks and uncertainties related to the closing of pending acquisition transactions; NOG’s ability to raise or access capital; cyber-incidents could have a material adverse effect NOG’s business, financial condition or results of operations; changes in accounting principles, policies or guidelines; events beyond NOG’s control, including a global or domestic health crisis, acts of terrorism, political or economic instability or armed conflict in oil and gas producing regions; and other economic, competitive, governmental, regulatory and technical factors affecting NOG’s operations, products and prices. Additional information concerning potential factors that could affect future results is included in the section entitled “Item 1A. Risk Factors” and other sections of NOG’s more recent Annual Report on Form 10-K and Quarterly Report on Form 10-Q, as updated from time to time in amendments and subsequent reports filed with the SEC, which describe factors that could cause NOG’s actual results to differ from those set forth in the forward-looking statements.
NOG has based these forward-looking statements on its current expectations and assumptions about future events. While management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond NOG’s control. NOG does not undertake any duty to update or revise any forward-looking statements, except as may be required by the federal securities laws.
CONTACT:
Evelyn Infurna
Vice President of Investor Relations
952-476-9800
ir@northernoil.com
Source: Northern Oil and Gas, Inc.
NORTHERN OIL AND GAS, INC.
STATEMENTS OF OPERATIONS
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended
December 31, | | Year Ended
December 31, |
| (In thousands, except share and per share data) | 2025 | | 2024 | | 2025 | | 2024 |
| Revenues | | | | | | | |
| Oil and Gas Sales | $ | 447,724 | | | $ | 545,472 | | | $ | 2,081,288 | | | $ | 2,152,079 | |
| Gain on Commodity Derivatives, Net | 159,314 | | | (34,224) | | | 380,664 | | | 61,967 | |
| Other Revenue | 3,140 | | | 3,729 | | | 13,771 | | | 11,682 | |
| Total Revenues | 610,178 | | | 514,977 | | | 2,475,723 | | | 2,225,728 | |
| | | | | | | |
| Operating Expenses | | | | | | | |
| Production Expenses | 119,880 | | | 116,583 | | | 473,666 | | | 429,792 | |
| Production Taxes | 30,961 | | | 42,621 | | | 131,334 | | | 157,091 | |
| General and Administrative Expenses | 17,121 | | | 15,528 | | | 61,332 | | | 50,463 | |
| Depletion, Depreciation, Amortization and Accretion | 204,076 | | | 204,674 | | | 814,859 | | | 740,901 | |
| Impairment of Oil and Gas Assets | 268,497 | | | — | | | 702,747 | | | — | |
| Legal Settlement Expense | — | | | — | | | 33,090 | | | — | |
| Other Expenses | 3,482 | | | 2,937 | | | 12,848 | | | 9,650 | |
| Total Operating Expenses | 644,017 | | | 382,343 | | | 2,229,876 | | | 1,387,897 | |
| | | | | | | |
| Income (Loss) From Operations | (33,839) | | | 132,634 | | | 245,847 | | | 837,831 | |
| | | | | | | |
| Other Income (Expense) | | | | | | | |
| Interest Expense | (41,120) | | | (45,259) | | | (172,380) | | | (157,717) | |
| | | | | | | |
| Gain (Loss) on Interest Rate Derivatives, Net | (292) | | | 283 | | | (566) | | | 263 | |
| Gain on the Extinguishment of Debt, Net | (10,833) | | | — | | | (10,833) | | | — | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Other Income | 26 | | | 180 | | | 637 | | | 440 | |
| Total Other Expense | (52,219) | | | (44,796) | | | (183,142) | | | (157,014) | |
| | | | | | | |
| Income (Loss) Before Income Taxes | (86,058) | | | 87,838 | | | 62,705 | | | 680,817 | |
| | | | | | | |
| Income Tax Expense (Benefit) | (15,326) | | | 16,140 | | | 23,944 | | | 160,509 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Net Income (Loss) Attributable to Common Shareholders | $ | (70,732) | | | $ | 71,698 | | | $ | 38,761 | | | $ | 520,308 | |
| | | | | | | |
| Net Income (Loss) Per Common Share – Basic | $ | (0.73) | | | $ | 0.72 | | | $ | 0.40 | | | $ | 5.21 | |
| Net Income (Loss) Per Common Share – Diluted | $ | (0.73) | | | $ | 0.71 | | | $ | 0.39 | | | $ | 5.14 | |
| Weighted Average Common Shares Outstanding – Basic | 97,123,991 | | | 99,217,821 | | | 97,711,444 | | | 99,852,539 | |
| Weighted Average Common Shares Outstanding – Diluted | 97,123,991 | | | 100,934,410 | | | 99,314,382 | | | 101,267,625 | |
| | | | | | | |
NORTHERN OIL AND GAS, INC.
BALANCE SHEETS | | | | | | | | | | | |
| (In thousands, except par value and share data) | December 31, 2025 | | December 31, 2024 |
| Assets | | | |
| Current Assets: | | | |
| Cash and Cash Equivalents | $ | 14,299 | | | $ | 8,933 | |
| Accounts Receivable, Net | 349,927 | | | 389,673 | |
| Advances to Operators | 29,996 | | | 12,291 | |
| Prepaid Expenses and Other | 7,065 | | | 5,271 | |
| Derivative Instruments | 166,678 | | | 46,525 | |
| Income Tax Receivable | 18,066 | | | 38,050 | |
| Total Current Assets | 586,031 | | | 500,743 | |
| | | |
| Property and Equipment: | | | |
| Oil and Natural Gas Properties, Full Cost Method of Accounting | | | |
| Proved | 11,441,786 | | | 10,307,376 | |
| Unproved | 86,034 | | | 42,702 | |
| Less – Accumulated Depletion and Impairment | (6,784,649) | | | (5,271,807) | |
| Total Oil and Natural Gas Properties, Net | 4,743,171 | | | 5,078,271 | |
| Other Property and Equipment, Net | 3,196 | | | 3,899 | |
| Total Property and Equipment, Net | 4,746,367 | | | 5,082,170 | |
| | | |
| Derivative Instruments | 3,036 | | | 9,832 | |
| | | |
| | | |
| Other Noncurrent Assets | 73,941 | | | 11,077 | |
| | | |
| Total Assets | $ | 5,409,375 | | | $ | 5,603,822 | |
| | | |
| Liabilities and Stockholders’ Equity | | | |
| Current Liabilities: | | | |
| Accounts Payable | $ | 218,620 | | | $ | 202,866 | |
| Accrued Liabilities | 293,779 | | | 290,792 | |
| | | |
| Accrued Interest | 23,018 | | | 25,992 | |
| | | |
| Derivative Instruments | — | | | 19,915 | |
| | | |
| | | |
| Other Current Liabilities | 3,876 | | | 4,705 | |
| | | |
| Total Current Liabilities | 539,293 | | | 544,270 | |
| | | |
| Long-term Debt, Net | 2,395,393 | | | 2,369,294 | |
| | | |
| Derivative Instruments | 48,102 | | | 93,606 | |
| | | |
| | | |
| Deferred Tax Liability | 247,645 | | | 228,038 | |
| Asset Retirement Obligations | 50,831 | | | 45,907 | |
| Other Noncurrent Liabilities | 1,770 | | | 2,272 | |
| | | |
| Total Liabilities | $ | 3,283,034 | | | $ | 3,283,387 | |
| | | |
| Commitments and Contingencies | | | |
| | | |
| | | |
| | | |
Common Stock, Par Value $0.001; 270,000,000 authorized; 97,265,559 Shares Outstanding at 12/31/2025 270,000,000 Authorized; 99,113,645 Shares Outstanding at 12/31/2024 | 499 | | | 501 | |
| Additional Paid-In Capital | 1,644,563 | | | 1,877,416 | |
| Retained Earnings | 481,279 | | | 442,518 | |
| Total Stockholders’ Equity | 2,126,341 | | | 2,320,435 | |
| Total Liabilities and Stockholders’ Equity | $ | 5,409,375 | | | $ | 5,603,822 | |
Non-GAAP Financial Measures
Adjusted Net Income, Adjusted EBITDA and Free Cash Flow are non-GAAP measures. Net income (loss) is the most directly comparable GAAP measure for both Adjusted Net Income and Adjusted EBITDA. Cash flows from operations is the most directly comparable GAAP measure for Free Cash Flow. NOG defines Adjusted Net Income (Loss) as net income (loss) excluding (i) (gain) loss on unsettled commodity derivatives, net of tax, (ii) (gain) loss on the extinguishment of debt, net of tax, (iii) (gain) loss on unsettled interest rate derivatives, net of tax, (iv) contingent consideration (gain) loss, net of tax, and (v) acquisition transaction costs, net of tax. NOG defines Adjusted EBITDA as net income (loss) before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion, amortization, and accretion, (iv) non-cash stock based compensation expense, (v) (gain) loss on the extinguishment of debt, (vi) contingent consideration (gain) loss, (vii) acquisition transaction expense, (viii) (gain) loss on unsettled interest rate derivatives, (ix) (gain) loss on unsettled commodity derivatives, and (x) other non-cash adjustments. NOG defines Free Cash Flow as cash flows from operations before changes in working capital and other items, less (i) capital expenditures, excluding non-budgeted acquisitions and (ii) preferred stock dividends. A reconciliation of each of these measures to the most directly comparable GAAP measure is included below.
A reconciliation of each of these measures to the most directly comparable GAAP measure is included below. Management believes the use of these non-GAAP financial measures provides useful information to investors to gain an overall understanding of current financial performance. Specifically, management believes the non-GAAP financial measures included herein provide useful information to both management and investors by excluding certain items that management believes are not indicative of NOG’s core operating results. In addition, these non-GAAP financial measures are used by management for budgeting and forecasting as well as subsequently measuring NOG’s performance, and management believes it is providing investors with financial measures that most closely align to its internal measurement processes.
Pre-tax PV10%, or PV-10, may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP measure for proved reserves calculated using SEC pricing. PV-10 is a computation of the Standardized Measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the Standardized Measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. Management believes that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to NOG’s estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of NOG’s oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of NOG’s reserves to other companies. Management uses this measure when assessing the potential return on investment related to NOG’s oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure of discounted future net cash flows. A reconciliation of PV-10 to the Standardized Measure is included below.
Reconciliation of Adjusted Net Income
| | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended
December 31, | | Year Ended
December 31, |
| (In thousands, except share and per share data) | 2025 | | 2024 | | 2025 | | 2024 |
| Income (Loss) Before Taxes | $ | (86,058) | | | $ | 87,838 | | | $ | 62,705 | | | $ | 680,817 | |
| Add: | | | | | | | |
| Impact of Selected Items: | | | | | | | |
| (Gain) Loss on Unsettled Commodity Derivatives | (86,376) | | | 59,728 | | | (179,343) | | | 21,258 | |
| Loss on the Extinguishment of Debt | 10,833 | | | — | | | 10,833 | | | — | |
| (Gain) Loss on Unsettled Interest Rate Derivatives | 292 | | | (283) | | | 566 | | | (263) | |
| | | | | | | |
| Impairment of Oil and Gas Assets | 268,497 | | | — | | | 702,747 | | | — | |
| Acquisition Transaction Costs | 1,366 | | | 760 | | | 3,001 | | | 1,742 | |
| Adjusted Income Before Adjusted Income Tax Expense | 108,554 | | | 148,043 | | | 600,509 | | | 703,554 | |
| | | | | | | |
Adjusted Income Tax Expense (1) | 26,596 | | | 36,271 | | | 147,125 | | | 172,371 | |
| | | | | | | |
| Adjusted Net Income (non-GAAP) | $ | 81,958 | | | $ | 111,772 | | | $ | 453,384 | | | $ | 531,184 | |
| | | | | | | |
| Weighted Average Shares Outstanding – Basic | 97,123,991 | | | 99,217,821 | | | 97,711,444 | | | 99,852,539 | |
| Weighted Average Shares Outstanding – Diluted | 99,047,368 | | | 100,934,410 | | | 99,314,382 | | | 101,267,625 | |
| Less: | | | | | | | |
Dilutive Effect of Convertible Notes (2) | — | | | (521,596) | | | — | | | (343,860) | |
| Weighted Average Shares Outstanding – Adjusted Diluted | 99,047,368 | | | 100,412,814 | | | 99,314,382 | | | 100,923,765 | |
| | | | | | | |
| Income (Loss) Before Income Taxes Per Common Share – Basic | $ | (0.89) | | | $ | 0.89 | | | $ | 0.64 | | | $ | 6.82 | |
| Add: | | | | | | | |
| Impact of Selected Items | 2.00 | | | 0.61 | | | 5.50 | | | 0.23 | |
| Impact of Income Tax | (0.27) | | | (0.37) | | | (1.50) | | | (1.73) | |
| Adjusted Net Income Per Common Share – Basic | $ | 0.84 | | | $ | 1.13 | | | $ | 4.64 | | | $ | 5.32 | |
| | | | | | | |
| Income (Loss) Before Income Taxes Per Common Share – Adjusted Diluted | $ | (0.87) | | | $ | 0.87 | | | $ | 0.63 | | | $ | 6.75 | |
| Add: | | | | | | | |
| Impact of Selected Items | 1.96 | | | 0.60 | | | 5.42 | | | 0.23 | |
| Impact of Income Tax | (0.26) | | | (0.36) | | | (1.48) | | | (1.72) | |
| Adjusted Net Income Per Common Share – Adjusted Diluted | $ | 0.83 | | | $ | 1.11 | | | $ | 4.57 | | | $ | 5.26 | |
_______________
(1)This represents a tax impact using an estimated tax rate of 24.5% for the three and twelve months ended December 31, 2025 and 2024.
(2)Weighted average shares outstanding - diluted, on a GAAP basis, includes diluted shares attributable to the Company’s Convertible Notes due 2029. However, the offsetting impact of the capped call transactions that the Company entered into in connection therewith is not recognized on a GAAP basis. As a result, for purposes of this calculation, the Company excludes the dilutive shares to the extent they would be offset by the capped calls.
Reconciliation of Adjusted EBITDA
| | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended
December 31, | | Year Ended
December 31, |
| (In thousands) | 2025 | | 2024 | | 2025 | | 2024 |
| Net Income (Loss) | $ | (70,732) | | | $ | 71,698 | | | $ | 38,761 | | | $ | 520,308 | |
| Add: | | | | | | | |
| Interest Expense | 41,120 | | | 45,259 | | | 172,380 | | | 157,717 | |
| Income Tax Expense | (15,326) | | | 16,140 | | | 23,944 | | | 160,509 | |
| Depreciation, Depletion, Amortization and Accretion | 204,076 | | | 204,674 | | | 814,859 | | | 740,901 | |
| | | | | | | |
| Non-Cash Stock-Based Compensation | 4,078 | | | 3,539 | | | 15,363 | | | 11,858 | |
| | | | | | | |
| Loss on the Extinguishment of Debt | 10,833 | | | — | | | 10,833 | | | — | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Other Adjustments | 8,719 | | | 5,116 | | | 25,719 | | | 5,116 | |
| Acquisition Transaction Costs | 1,366 | | | 760 | | | 3,001 | | | 1,742 | |
| (Gain) Loss on Unsettled Interest Rate Derivatives | 292 | | | (283) | | | 566 | | | (263) | |
| (Gain) Loss on Unsettled Commodity Derivatives | (86,376) | | | 59,728 | | | (179,343) | | | 21,258 | |
| Impairment of Oil and Gas Assets | 268,497 | | | — | | | 702,747 | | | — | |
| | | | | | | |
| Adjusted EBITDA | $ | 366,547 | | | $ | 406,631 | | | 1,628,830 | | | 1,619,146 | |
Reconciliation of Free Cash Flow
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended
December 31, | | Year Ended
December 31, |
| (In thousands) | 2025 | | 2024 | | 2025 | | 2024 |
| Net Cash Provided by Operating Activities | $ | 312,630 | | | $ | 290,278 | | | $ | 1,505,288 | | | $ | 1,408,663 | |
| Exclude: Changes in Working Capital and Other Items | 3,929 | | | 68,581 | | | (70,063) | | | 53,887 | |
Less: Capital Expenditures (1) | (273,350) | | | (262,477) | | | (1,011,250) | | | (1,001,307) | |
| | | | | | | |
| Free Cash Flow | $ | 43,209 | | | $ | 96,382 | | | $ | 423,975 | | | $ | 461,243 | |
_______________
(1) Capital expenditures are calculated as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended
December 31, | | Year Ended
December 31, |
| (In thousands) | 2025 | | 2024 | | 2025 | | 2024 |
| Cash Paid for Capital Expenditures | $ | 308,032 | | | $ | 662,623 | | | $ | 1,251,703 | | | $ | 1,674,626 | |
| Less: Non-Budgeted Acquisitions | (67,195) | | | (508,147) | | | (230,490) | | | (862,321) | |
| Plus: Change in Accrued Capital Expenditures and Other | 32,513 | | | 108,001 | | | (9,963) | | | 189,002 | |
| Capital Expenditures | $ | 273,350 | | | $ | 262,477 | | | $ | 1,011,250 | | | $ | 1,001,307 | |
Reconciliation of PV-10
The following table reconciles the pre-tax PV10% value of our SEC Pricing Proved Reserves as of December 31, 2025 to the Standardized Measure of discounted future net cash flows.
| | | | | |
SEC Pricing Proved Reserves (In thousands) |
| Standardized Measure Reconciliation |
| Pre-Tax Present Value of Estimated Future Net Revenues (Pre-Tax PV10%) | $ | 4,530,656 | |
Future Income Taxes, Discounted at 10%(1) | (707,854) | |
| Standardized Measure of Discounted Future Net Cash Flows | $ | 3,822,802 | |
_______________
(1)The expected tax benefits to be realized from utilization of the net operating loss and tax credit carryforwards are used in the computation of future income tax cash flows. As a result of available net operating loss carryforwards and the remaining tax basis of our assets at December 31, 2025, our future income taxes were significantly reduced.
