Exhibit 99.1
NOG Announces Second Quarter 2025 Results and
Updates 2025 Guidance

SECOND QUARTER HIGHLIGHTS

•Total quarterly production of 134,094 Boe per day (57% oil), up 9% from the second quarter of 2024
•Oil volumes of 76,944 Bbl per day, up 10.5% from the second quarter of 2024
•Record Appalachian volumes of 123.5 MMcf per day
•Uinta volumes up over 18.5% sequentially, marking the second consecutive quarter of double digit growth
•GAAP net income of $99.6 million, Adjusted Net Income of $136.3 million and record Adjusted EBITDA of $440.4 million. See “Non-GAAP Financial Measures” below
•Cash flow from operations of $362.1 million. Excluding changes in net working capital, cash flow from operations was $387.0 million, an increase of 3% from the second quarter of 2024
•Generated $126.2 million of Free Cash Flow. See “Non-GAAP Financial Measures” below
•Capital expenditures of $210.0 million, excluding non-budgeted acquisitions and other items, down 12% from the second quarter of 2024
•Completed twenty-two ground game transactions adding approximately 2,600 net acres and 4.8 net wells for $31.2 million, inclusive of associated development costs
•In April 2025, closed on previously announced Upton County, Texas acquisition adding 2,275 net acres for total cash consideration of $61.7 million, net of closing adjustments.
•Raised $211.2 million in a re-opening of 2029 Convertible Notes and repurchased over 1.1 million shares of common stock at an average price of $31.15 per share in conjunction with the offering
•Expect to receive a $48.6 million legal settlement, net of legal expenses
•Updates guidance on operating costs, production levels and capital expenditures


MINNEAPOLIS (BUSINESS WIRE) - July 31, 2025 - Northern Oil and Gas, Inc. (NYSE: NOG) (“NOG” or “Company”) today announced the Company’s second quarter results.

MANAGEMENT COMMENTS

“NOG’s diverse and scaled platform delivered solid results, with strong free cash flow generation and continued growth from our Appalachian and Uinta Basin properties. The Ground Game continues to gain momentum, providing accretive opportunities that should benefit the Company through cycle, featuring both near term development and longer dated inventory rich opportunities. With a focus on creating shareholder value for the long-term, we anticipate incremental growth being focused on the strong backlog of inorganic opportunities available to us in the marketplace today,” commented Nick O’Grady, NOG’s Chief Executive Officer.


SECOND QUARTER FINANCIAL RESULTS

Oil and natural gas sales for the second quarter were $574.4 million. Second quarter GAAP net income was $99.6 million or $1.00 per diluted share. Second quarter Adjusted Net Income was $136.3 million or $1.37 per adjusted diluted share. Adjusted EBITDA in the second quarter was $440.4 million, a 7% increase from the second quarter of 2024. See “Non-GAAP Financial Measures” below.

PRODUCTION

Second quarter production was 134,094 Boe per day, inline with the first quarter of 2025 and a 9% increase from the prior year. Oil represented 57% of total production in the second quarter with 76,944 Bbls per day, down 2% from the first quarter of 2025 and an increase of 10.5% from the second quarter of 2024. NOG had 20.8 net wells added to production during the second quarter, compared to 27.3 net wells added to production in the first quarter of 2025. Despite modest commodity price related shut ins, the Company saw strong well performance across multiple basins. Uinta volumes were again exceptional, growing over 18.5% sequentially, and Appalachian volumes set a new record for the second straight quarter during a period of strong natural gas pricing.


1

PRICING

During the second quarter, NOG’s unhedged net realized oil price was $58.37. The Company’s average differential to WTI prices was $5.31, an 8% improvement from the first quarter of 2025, driven primarily by lower differentials in the Uinta Basin. NOG’s unhedged net realized gas price in the second quarter was $2.89 per Mcf, representing a 82% realization compared with Henry Hub pricing. Natural gas realizations declined from the first quarter of 2025 primarily driven by continued widening in Waha pricing in the Permian.

OPERATING COSTS

Lease operating costs were $121.4 million in the second quarter of 2025, or $9.95 per Boe, 6% higher on a per unit basis compared to the first quarter of 2025. LOE costs increased primarily due to higher processing and salt water disposal costs. Production taxes were $35.6 million in the second quarter of 2025, compared to $36.1 million in the first quarter of 2025, a decrease primarily due to lower realized oil prices. Second quarter general and administrative (“G&A”) costs totaled $15.6 million or $1.28 per Boe, as compared to $1.19 per Boe in the first quarter of 2025. NOG’s adjusted cash G&A costs, which excludes non-cash share-based compensation and acquisition cost amounts of $3.7 million and $1.0 million, respectively, totaled $10.9 million or $0.89 per Boe in the second quarter, up $0.02 per Boe compared to the first quarter of 2025.

CAPITAL EXPENDITURES AND ACQUISITIONS    

Capital expenditures for the second quarter were $210.0 million (excluding non-budgeted acquisitions and other). This was comprised of $178.8 million of total drilling and completion (“D&C”) capital on organic assets, and $31.2 million of Ground Game activity inclusive of associated development costs. Notably, capital expenditures were down 16.0% quarter over quarter and 11.5% year over year while production volumes remained robust. D&C spending was largely as expected during the quarter, with significant spud activity and steady AFE activity. Normalized well costs on the Company’s D&C list declined sequentially, now averaging approximately $800 per lateral foot. NOG’s Permian Basin spending was 34% of the capital expenditures for the second quarter, the Williston was 25%, the Uinta was 15% and the Appalachian was 26%. On the Ground Game acquisition front, NOG closed on twenty two transactions across the Company’s four operating areas and featuring various structures totaling over 2,600 net acres and separately 4.8 net current and future development wells.

On April 1, 2025, NOG closed on its previously announced Upton County, Texas acquisition from a private operator. The assets add 2,275 net acres and were acquired for total cash consideration of $61.7 million, net of closing adjustments.

LIQUIDITY AND CAPITAL RESOURCES

NOG had total liquidity in excess of $1.1 billion as of June 30, 2025, consisting of $1.1 billion of committed borrowing availability under its Revolving Credit Facility and $25.9 million cash on hand.

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 $115.6 million in the second 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.

In June 2025, the Company entered into a settlement and mutual release agreement (the “Settlement Agreement”) with an operator in North Dakota (the “Operator”). Pursuant to the Settlement Agreement, the Operator and the Company have settled and permanently released certain claims of the Company relating to certain post-production costs previously deducted from revenues. Pursuant to the settlement, the Company will receive approximately $81.7 million, recorded within Oil and Gas Sales in the accompanying condensed statements of operations. The Company expects to receive a net cash settlement of $48.6 million after deducting approximately $33.1 million in legal settlement expenses. The cash proceeds are expected to be received in the third quarter of 2025.

SHAREHOLDER RETURNS

In the second quarter of 2025, the Company repurchased 1.1 million shares of common stock at an average price of $31.15 per share in connection with the re-opening of the Company’s 2029 Convertible Notes.

2

In the second quarter of 2025, the Company paid a cash dividend of $0.45 per share to NOG’s stockholders of record as of March 28, 2025. This represented an increase of 7% over the dividend per share paid in the previous quarter.

In July 2025, the Company paid a cash dividend of $0.45 per share to NOG’s stockholders of record as of June 27, 2025.

2025 ANNUAL GUIDANCE

Given the recent volatility in commodity markets, the reduction of activity in the Williston Basin and a reduction in discretionary spending, the Company is reducing overall capital spending for 2025 by $125 - $150 million from the prior range. In accordance with the reduced capital spending, oil volume guidance is reduced, at the midpoint, to the low end of the prior range of guidance. Additionally, total production guidance was reduced by approximately 1,000 Boe per day at the midpoint. NOG continues to be highly flexible with its capital spending, and should commodity prices and thus, returns, increase, the Company could accelerate capital spending to prior levels if warranted.

NOG currently expects total capital spending in the range of $925 - $1,050 million for 2025, with approximately 57% of its 2025 budget to be spent on the Permian, 17% on the Williston, 16% on the Appalachian and 11% on the Uinta Basin. In addition to revisions to capital spending and oil volumes, the Company has made modest additional guidance changes to production expenses, NYMEX WTI differentials and production taxes, which are detailed in the table below.

Prior GuidanceRevised Guidance
Annual Production (Boe per day)
130,000 - 135,000130,000 - 133,000
Annual Oil Production (Bbls per day)
75,000 - 79,00074,000 - 76,000
Total Capital Expenditures ($ in millions)
$1,050 - $1,200$925 - $1,050
Net Oil Wells Turned-in-Line (TIL)87.0 - 91.073.0 - 76.0
Net Total Wells Turned-in-Line (TIL)97.0 - 99.083.0 - 85.0
Net Wells Spud106.0 - 110.075.0 - 85.0

Operating Expenses and Differentials
Production Expenses (per Boe)
$9.15 - $9.40$9.25 - $9.60
Production Taxes (as a percentage of Oil & Gas Sales)
8.5% - 9.0%7.5% - 8.5%
Average Differential to NYMEX WTI (per Bbl)
($4.75) - ($5.50)($5.25) - ($5.75)
Average Realization as a Percentage of NYMEX Henry Hub (per Mcf)
85% - 90%85% - 90%
DD&A (per Boe)
$16.50 - $17.50$16.00 - $17.00

General and Administrative Expense (per Boe):
Non-Cash$0.25 - $0.30$0.25 - $0.30
Cash (excluding transaction costs on non-budgeted acquisitions)
$0.85 - $0.90$0.85 - $0.90





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SECOND QUARTER 2025 RESULTS

The following tables set forth selected operating and financial data for the periods indicated.

 Three Months Ended June 30,
 20252024% Change
Net Production:
Oil (MBbl)7,002 6,338 10 %
Natural Gas (MMcf)31,204 29,319 6 %
Total (MBoe)12,203 11,224 9 %
Average Daily Production:
Oil (Bbl)76,944 69,645 10 %
Natural Gas (Mcf)342,900 322,183 6 %
Total (Boe)134,094 123,342 9 %
Average Sales Prices:
Oil (per Bbl) (1)
$58.37 $77.11 (24)%
Effect of Gain (Loss) on Settled Oil Derivatives on Average Price (per Bbl)6.21 (2.30)
Oil Net of Settled Oil Derivatives (per Bbl) (1)
64.58 74.81 (14)%
Natural Gas and NGLs (per Mcf) (2)
2.89 2.47 17 %
Effect of Gain on Settled Natural Gas Derivatives on Average Price (per Mcf)0.56 0.80 
Natural Gas and NGLs Net of Settled Natural Gas and NGL Derivatives (per Mcf) (2)
3.45 3.27 6 %
Realized Price on a Boe Basis Excluding Settled Commodity Derivatives (1) (2)
40.87 49.98 (18)%
Effect of Gain on Settled Commodity Derivatives on Average Price (per Boe)4.99 0.79 
Realized Price on a Boe Basis Including Settled Commodity Derivatives (1) (2)
45.86 50.77 (10)%
Costs and Expenses (per Boe):
Production Expenses$9.95 $8.99 11 %
Production Taxes2.92 4.33 (33)%
General and Administrative Expenses1.28 1.21 6 %
Depletion, Depreciation, Amortization and Accretion16.86 15.73 7 %
Net Producing Wells at Period End1,151.7 1,015.2 13 %
______________
(1)    Excludes the impact of certain non-cash adjustments to oil revenues.
(2)    Excludes the impact of a legal settlement (See Note 2 to our financial statements included in our Form 10-Q filed with the SEC for the quarter ended June 30, 2025).
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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 June 30, 2025.

Crude Oil Commodity Derivative Swaps(1)
Crude Oil Commodity Derivative Collars
Contract PeriodVolume (Bbls/Day)Weighted Average Price ($/Bbl)Collar Call Volume (Bbls/Day)Collar Put Volume (Bbls/Day)Weighted Average Ceiling Price
($/Bbl)		Weighted Average Floor Price
($/Bbl)
2025:
Q331,913 $72.76 25,054 19,761 $77.43 $69.15 
Q432,933 72.75 24,766 19,473 77.55 69.15 
2026:
Q115,930 $69.84 34,680 27,187 $72.98 $62.94 
Q211,430 68.11 24,680 17,187 71.35 63.55 
Q315,430 69.06 19,680 12,187 72.33 65.01 
Q415,430 69.04 19,680 12,187 72.33 65.01 
_____________
(1)Includes derivative contracts entered into as of July 25, 2025. This table does not include volumes subject to swaptions and call options, which are crude oil derivative contracts 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 Note 10 to our financial statements included in our Form 10-Q filed with the SEC for the quarter ended June 30, 2025.


5

The following table summarizes NOG’s open natural gas commodity derivative swap contracts scheduled to settle after June 30, 2025.

Natural Gas Commodity Derivative Swaps(1)
Natural Gas Commodity Derivative Collars
Contract PeriodVolume (MMBTU/Day)Weighted Average Price ($/MMBTU)Collar Call Volume (MMBTU/Day)Collar Put Volume (MMBTU/Day)Weighted Average Ceiling Price
($/MMBTU)		Weighted Average Floor Price
($/MMBTU)
2025:
Q3102,929 $3.99 101,828 101,828 $4.56 $2.93 
Q4108,188 4.09 106,364 106,364 4.73 3.08 
2026:
Q187,333 $4.13 114,203 114,203 $5.07 $3.36 
Q274,121 3.93 113,348 113,348 5.05 3.37 
Q370,000 4.02 105,486 105,486 5.02 3.39 
Q479,891 4.25 76,681 76,681 4.95 3.37 
2027:
Q15,000 $3.04 14,833 14,833 $3.86 $3.00 
Q25,055 2.96 15,165 15,165 3.86 3.00 
Q35,000 2.96 15,000 15,000 3.86 3.00 
Q44,946 2.96 9,946 9,946 3.86 3.00 
_____________
(1)Includes derivative contracts entered into as of July 25, 2025. This table does not include basis swaps. For additional information, see Note 10 to our financial statements included in our Form 10-Q filed with the SEC for the quarter ended June 30, 2025.





6

The following table summarizes NOG’s open NGL commodity derivative swap contracts scheduled to settle after June 30, 2025.

NGL Contracts
Swaps
Contract PeriodVolume
(BBL)		Weighted Average Price
($/BBL)
2025:
Q359,800 $36.16 
Q4133,400 36.71 
2026:
Q192,250 $36.00 
Q2106,925 33.32 
Q396,600 33.03 
Q480,500 33.32 
2027:
Q165,250 $32.30 
Q259,150 30.73 
Q357,500 30.69 
Q452,900 30.87 

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
June 30,
(In thousands)20252024
Cash Received on Settled Derivatives$60,931 $8,896 
Non-Cash Mark-to-Market Gain (Loss) on Derivatives67,888 (12,324)
Gain (Loss) on Commodity Derivatives, Net$128,819 $(3,428)

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CAPITAL EXPENDITURES & DRILLING ACTIVITY

(In thousands, except for net well data and dollars per foot)Three Months Ended June 30, 2025
Capital Expenditures Incurred:
Organic Drilling and Development Capital Expenditures$178,820 
Ground Game Drilling and Development Capital Expenditures$7,305 
Ground Game Acquisition Capital Expenditures inclusive of pre-closing development costs$23,851 
Other$2,261 
Non-Budgeted Acquisitions$63,926 
Net Wells Added to Production20.8 
Net Producing Wells (Period-End)1,151.7 
Net Wells in Process (Period-End)53.2 
Weighted Average Gross AFE for Wells Elected to$9,606 
Weighted Average Gross AFE for Wells Elected to, normalized for lateral length ($ per foot)$841 

SECOND 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 Friday, August 1, 2025 at 8:00 a.m. Central Time.

Those wishing to listen to the conference call may do so via webcast or phone as follows:

Webcast: https://events.q4inc.com/attendee/790034429
Dial-In Number: (800) 715-9871 (US/Canada) and (646) 307-1963 (International)
Conference ID: 4503139 - NOG Second Quarter 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 August 15, 2025

ABOUT NOG

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.


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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, as amended, and the Securities Exchange Act of 1934, as amended. 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; general economic or industry conditions, whether internationally, nationally and/or in the communities in which NOG conducts business, including any future economic downturn, supply chain disruptions, the impact of continued or further inflation, disruption in the financial markets, changes in the interest rate environment and actions taken by OPEC and other oil producing countries as it pertains to the global supply and demand of, and prices for, crude oil, natural gas and NGLs; ongoing legal disputes over, and potential shutdown of, the Dakota Access Pipeline; NOG’s ability to identify and consummate additional development opportunities and 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; changes in local, state, and federal laws, regulations or policies that may affect NOG’s business or NOG’s industry (such as the effects of tax law changes, and changes in environmental, health, and safety regulation and regulations addressing climate change, and trade policy and tariffs); conditions of the securities markets; risks associated with NOG’s 3.625% convertible senior notes due 2029 (the “Convertible Notes”), including the potential impact that the Convertible Notes may have on 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 raise or access capital on acceptable terms; cyber-incidents could have a material adverse effect on 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 most recent Annual Report on Form 10-K for the year ended December 31, 2024, 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. Accordingly, results actually achieved may differ materially from expected results described in these statements. 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



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CONDENSED STATEMENTS OF OPERATIONS
(UNAUDITED)

Three Months Ended
June 30,
(In thousands, except share and per share data)20252024
Revenues
Oil and Gas Sales$574,369 $561,025 
Gain (Loss) on Commodity Derivatives, Net128,819 (3,428)
Other Revenues3,621 3,169 
Total Revenues706,809 560,766 
Operating Expenses
Production Expenses121,430 100,859 
Production Taxes35,616 48,589 
General and Administrative Expenses15,628 13,538 
Legal Settlement Expense 33,091 — 
Depletion, Depreciation, Amortization and Accretion205,741 176,612 
Impairment of Oil and Gas Assets115,576 — 
Other Expenses3,561 2,232 
Total Operating Expenses530,643 341,830 
Income From Operations176,166 218,936 
Other Income (Expense)
Interest Expense, Net of Capitalization(44,435)(37,696)
Gain (Loss) on Unsettled Interest Rate Derivatives, Net1 — 
Other Income46 63 
Total Other Expense, Net(44,388)(37,633)
Income Before Income Taxes131,778 181,303 
Income Tax Expense32,193 42,746 
Net Income$99,585 $138,556 
Net Income Attributable to Common Stockholders$99,585 $138,556 
Net Income Per Common Share – Basic$1.02 $1.38 
Net Income Per Common Share – Diluted$1.00 $1.36 
Weighted Average Common Shares Outstanding – Basic98,060,407 100,266,462 
Weighted Average Common Shares Outstanding – Diluted99,394,539 101,985,074 


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CONDENSED BALANCE SHEETS
(UNAUDITED)
(In thousands, except par value and share data)June 30, 2025December 31, 2024
Assets
Current Assets:  
Cash and Cash Equivalents$25,856 $8,933 
Accounts Receivable, Net410,245 389,673 
Advances to Operators24,641 12,291 
Prepaid Expenses and Other6,517 5,271 
Derivative Instruments109,281 46,525 
Income Tax Receivable11,817 38,050 
Total Current Assets588,357 500,743 
Property and Equipment:  
Oil and Natural Gas Properties, Full Cost Method of Accounting  
Proved10,850,664 10,307,376 
Unproved35,307 42,702 
Other Property and Equipment8,678 8,197 
Total Property and Equipment10,894,649 10,358,275 
Less – Accumulated Depreciation, Depletion and Impairment(5,801,503)(5,276,105)
Total Property and Equipment, Net5,093,146 5,082,170 
Derivative Instruments1,311 9,832 
Other Noncurrent Assets, Net19,679 11,077 
Total Assets$5,702,493 $5,603,822 
Liabilities and Stockholders’ Equity
Current Liabilities:  
Accounts Payable$173,911 $202,866 
Accrued Liabilities and Other310,162 321,489 
Derivative Instruments4,124 19,915 
Total Current Liabilities488,197 544,270 
Long-term Debt, Net2,365,942 2,369,294 
Deferred Tax Liability298,749 228,038 
Derivative Instruments86,187 93,606 
Asset Retirement Obligations48,376 45,907 
Other Noncurrent Liabilities2,023 2,272 
Total Liabilities$3,289,474 $3,283,387 
Commitments and Contingencies
Stockholders’ Equity  
Common Stock, Par Value $0.001; 270,000,000 Shares Authorized;
 97,594,682 Shares Outstanding at 6/30/2025
 99,113,645 Shares Outstanding at 12/31/2024
500 501 
Additional Paid-In Capital1,731,434 1,877,416 
Retained Earnings681,085 442,518 
Total Stockholders’ Equity2,413,019 2,320,435 
Total Liabilities and Stockholders’ Equity$5,702,493 $5,603,822 
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Non-GAAP Financial Measures

Adjusted Net Income, Adjusted EBITDA and Free Cash Flow are non-GAAP measures. NOG defines Adjusted Net Income as income before income taxes, excluding (i) (gain) loss on unsettled commodity derivatives, net of tax, (ii) (gain) loss on extinguishment of debt, net of tax, (iii) contingent consideration (gain) loss, net of tax, (iv) acquisition transaction costs, net of tax, (v) (gain) loss on unsettled interest rate derivatives, net of tax, and (vi) impairment of long-lived assets, net of tax. NOG defines Adjusted EBITDA as net income before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion, amortization and accretion, (iv) non-cash stock-based compensation expense, (v) (gain) loss on extinguishment of debt, (vi) contingent consideration (gain) loss (vii) acquisition transaction costs, (viii) (gain) loss on unsettled interest rate derivatives, (ix) (gain) loss on unsettled commodity derivatives, (x) impairment of long-lived assets, and (xi) 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 changes in accrued capital expenditures and other items. 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. Management believes Adjusted Net Income and Adjusted EBITDA provide useful information to both management and investors by excluding certain expenses and unrealized commodity gains and losses that management believes are not indicative of NOG’s core operating results. Management believes that Free Cash Flow is useful to investors as a measure of a company’s ability to internally fund its budgeted capital expenditures, to service or incur additional debt, and to measure success in creating stockholder value. 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. The non-GAAP financial measures included herein may be defined differently than similar measures used by other companies and should not be considered an alternative to, or more meaningful than, the comparable GAAP measures. From time to time NOG provides forward-looking Free Cash Flow estimates or targets; however, NOG is unable to provide a quantitative reconciliation of the forward looking non-GAAP measure to its most directly comparable forward looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward looking GAAP measure. The reconciling items in future periods could be significant.

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Reconciliation of Adjusted Net Income

 Three Months Ended
June 30,
(In thousands, except share and per share data)20252024
Income Before Income Taxes$131,778 $181,303 
Add:  
Impact of Selected Items:  
(Gain) Loss on Unsettled Commodity Derivatives(67,888)12,324 
Acquisition Transaction Costs1,046 2,112 
Gain on Unsettled Interest Rate Derivatives(1)— 
Impairment of Oil and Gas Assets115,576 — 
Adjusted Income Before Adjusted Income Tax Expense 180,511 195,739 
Adjusted Income Tax Expense (1)
(44,225)(47,956)
Adjusted Net Income (non-GAAP)$136,286 $147,783 
Weighted Average Shares Outstanding – Basic98,060,407 100,266,462 
Weighted Average Shares Outstanding – Diluted99,394,539 101,985,074 
Less:
Dilutive Effect of Convertible Notes (2)
— 738,227 
Weighted Average Shares Outstanding – Adjusted Diluted99,394,539 101,246,847 
Income Before Income Taxes Per Common Share – Basic$1.34 $1.81 
Add:  
Impact of Selected Items0.50 0.14 
Impact of Income Tax(0.45)(0.48)
Adjusted Net Income Per Common Share – Basic$1.39 $1.47 
Income Before Income Taxes Per Common Share – Adjusted Diluted$1.33 $1.79 
Add:  
Impact of Selected Items0.49 0.14 
Impact of Income Tax(0.45)(0.47)
Adjusted Net Income Per Common Share – Adjusted Diluted$1.37 $1.46 
______________
(1)For the three months ended June 30, 2025 and June 30, 2024, this represents a tax impact using an estimated tax rate of 24.5%.
(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.




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Reconciliation of Adjusted EBITDA

Three Months Ended
June 30,
(In thousands)20252024
Net Income$99,585 $138,556 
Add:  
Interest Expense44,435 37,696 
Income Tax Expense32,193 42,747 
Depreciation, Depletion, Amortization and Accretion205,741 176,612 
Non-Cash Stock-Based Compensation3,729 3,026 
Other Adjustments6,000 — 
Acquisition Transaction Costs1,046 2,112 
Gain on Unsettled Interest Rate Derivatives(1)— 
(Gain) Loss on Unsettled Commodity Derivatives(67,888)12,324 
Impairment of Oil and Gas Assets115,576 — 
Adjusted EBITDA$440,416 $413,073 


Reconciliation of Free Cash Flow

Three Months Ended
June 30,
(In thousands)2025
Net Cash Provided by Operating Activities$362,112 
Exclude: Changes in Working Capital and Other Items (1)
(23,700)
Less: Capital Expenditures (2)
(212,234)
Free Cash Flow$126,178 
_______________
(1)    Excludes the net impact of a legal settlement receivable (See Note 2 to our condensed financial statements on Form 10-Q for quarter ended June 30, 2025).
(2)    Capital expenditures are calculated as follows:

Three Months Ended
June 30,
(In thousands)2025
Cash Paid for Capital Expenditures$327,361 
Less: Non-Budgeted Acquisitions(61,555)
Plus: Change in Accrued Capital Expenditures and Other(53,572)
Capital Expenditures$212,234 


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