Northern Oil and Gas, Inc. press release

NOG Announces Fourth Quarter and Full Year 2025 Results; Provides Detailed 2026 Guidance

2026-02-25

NYSE - New York Stock Exchange · Oil · Natural Gas · Natural Gas Liquids · United States · Corporate Finance

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

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 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.

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.

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

_____________

(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.

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.