EX-99.1 2 exhibit991-2025qx1earnings.htm EX-99.1 Document
Exhibit 99.1
NOG Announces First Quarter 2025 Results

FIRST QUARTER HIGHLIGHTS

•Record total quarterly production of 134,959 Boe per day (58% oil), up 13% from the first quarter of 2024
•Oil volumes of 78,675 Bbl per day, driven by strong well performance
•Record Appalachian volumes of 113.5 Mmcfe per day
•Uinta volumes up over 15% from prior quarter in first period of SM Energy Company’s operatorship
•GAAP net income of $139.0 million, Adjusted Net Income of $133.4 million and Record Adjusted EBITDA of $434.7 million. See “Non-GAAP Financial Measures” below
•Cash flow from operations of $407.4 million. Excluding changes in net working capital, cash flow from operations was $387.4 million, an increase of 10% from the first quarter of 2024
•Generated $135.7 million of Free Cash Flow, up 41% from the fourth quarter of 2024. See “Non-GAAP Financial Measures” below
•Capital expenditures of $249.9 million, excluding non-budgeted acquisitions and other items
•Completed seven ground game transactions adding over 1,000 acres and 1.1 net wells for $4.8 million, inclusive of associated development costs
•Repurchased 499,100 shares of common stock at an average price of $30.07 per share
•Reaffirms annual guidance

SUBSEQUENT EVENTS

•On April 1, 2025 NOG closed on its previously announced Upton County, Texas acquisition from a private operator adding 2,275 net acres for total cash consideration of $61.7 million, net of closing adjustments.
MINNEAPOLIS (BUSINESS WIRE) - April 29, 2025 - Northern Oil and Gas, Inc. (NYSE: NOG) (“NOG” or “Company”) today announced the Company’s first quarter results.

MANAGEMENT COMMENTS

“The first quarter highlighted the strengths of NOG’s business model and strategic decisions,” commented Nick O’Grady, NOG’s Chief Executive Officer. “We continue to improve our margins, generate prodigious free cash flow, reduce leverage and add value through shareholder returns and Ground Game acquisitions. The inherent flexibility of the non-operated model and our broad basin and production mix will allow for dynamic capital allocation to adjust for any changes in the commodity pricing backdrop, while our robust hedge book keeps our cash flows insulated, providing optionality to capitalize on value creation opportunities in any environment.”

FIRST QUARTER FINANCIAL RESULTS

Oil and natural gas sales for the first quarter were $577.0 million. First quarter GAAP net income was $139.0 million or $1.39 per diluted share. First quarter Adjusted Net Income was $133.4 million or $1.33 per adjusted diluted share. Adjusted EBITDA in the first quarter was $434.7 million, a 12% increase from the first quarter of 2024. See “Non-GAAP Financial Measures” below.

PRODUCTION

First quarter production was 134,959 Boe per day, an increase of 2.4% from the fourth quarter of 2024 and a 13% increase from the prior year. Oil represented 58% of total production in the first quarter with 78,675 Bbls per day, roughly flat from the fourth quarter of 2024 and an increase of 12.1% from the first quarter of 2024. NOG had 27.3 net wells turned in-line during the first quarter, compared to 30.1 net wells turned in-line in the fourth quarter of 2024. Despite modest freeze offs, the Company saw strong well performance across multiple basins. Uinta volumes were exceptional in their first quarter under SM Energy Company’s stewardship, growing sequentially more than 15%, and Appalachian volumes set a new record for the Company during a period of strong natural gas pricing.

PRICING

During the first quarter, NOG’s unhedged net realized oil price was $64.92. The Company’s average differential to WTI prices was $5.79, slightly wider than the prior quarter, driven primarily by higher seasonal differentials in the Permian and the


Williston as well as full quarter contribution from the Uinta Basin, which carries higher transportation costs. NOG’s unhedged net realized gas price in the first quarter was $3.86 per Mcf, representing a 100% realization compared with Henry Hub pricing. Natural gas realizations modestly improved sequentially, despite declines in Waha pricing in the Permian late in the quarter, driven by higher absolute natural gas prices and stronger seasonal NGL prices.

OPERATING COSTS

Lease operating costs were $114.0 million in the first quarter of 2025, or $9.39 per Boe, 2% lower on a per unit basis compared to the fourth quarter of 2024. LOE costs decreased primarily due to reduced field disruptions and benefits from the low cost Uinta Basin. Production taxes were $36.1 million in the first quarter of 2025, compared to $48.6 million in the fourth quarter of 2024, a decrease primarily due to lower realized oil prices and an increase in Uinta volumes, which have a lower tax rate. First quarter general and administrative (“G&A”) costs totaled $14.5 million or $1.19 per Boe, as compared to $1.28 per Boe in the fourth quarter of 2024. NOG’s adjusted cash G&A costs, which excludes non-cash and acquisition cost amounts of $3.5 million and $0.4 million, respectively, totaled $10.5 million or $0.87 per Boe in the first quarter, down $0.06 per Boe compared to the fourth quarter of 2024.

CAPITAL EXPENDITURES AND ACQUISITIONS    

Capital expenditures for the first quarter were $249.9 million (excluding non-budgeted acquisitions and other). This was comprised of $245.1 million of total drilling and completion (“D&C”) capital on organic assets, and $4.8 million of Ground Game activity inclusive of associated development costs. D&C spending was largely as expected during the quarter, with significant spud activity and steady AFE activity. NOG’s weighted average gross authorization for expenditure (or AFE) elected to in the first quarter was $10.5 million, which was slightly higher compared with the fourth quarter of 2024 but down 10% on a per foot normalized basis.

NOG’s Permian Basin spending was 57% of the capital expenditures for the first quarter, the Williston was 20%, the Uinta was 15% and the Appalachian was 8%. On the Ground Game acquisition front, NOG closed on seven transactions acquired through various structures during the first quarter totaling 1,015 net acres and separately 1.1 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 $0.9 billion as of March 31, 2025, consisting of $0.9 billion of committed borrowing availability under its Revolving Credit Facility and $33.6 million in cash in the form of $33.6 million of unrestricted cash and $4.0 million in the form of a restricted cash deposit for the pending Midland Basin acquisition that closed in April 2025.

SHAREHOLDER RETURNS

In the first quarter of 2025, the Company repurchased 499,100 shares of common stock at an average price, inclusive of commissions, of $30.07 per share in the open market. In March 2024, the Company’s board of directors increased the prior stock repurchase program, to acquire up to an additional $100.0 million of the Company’s outstanding common stock.

In January 2025, NOG’s Board of Directors declared a regular quarterly cash dividend for NOG’s common stock of $0.45 per share for stockholders of record as of March 28, 2024, which will be paid on April 30, 2025, a 7% increase sequentially and a 12.5% increase from the prior year’s quarter.

2025 ANNUAL GUIDANCE

NOG anticipates no material changes to its initial guidance. Given the recent volatility in commodity markets and NOG’s focus on returns, NOG will remain flexible and adapt as appropriate. NOG would expect potential increases in Ground Game capital allocation as a percentage of the total in the event that commodity prices materially weaken, and would expect total completions, spuds and total capital spending to move in tandem with overall commodity prices.

NOG continues to expect approximately 130,000 - 135,000 Boe per day of production in 2025. NOG currently expects total capital spending in the range of $1,050 - $1,200 million for 2025, with approximately 66% of its 2025 budget to be spent on the Permian, 20% on the Williston, 7% on the Appalachian and 7% on the Uinta.



2025 Guidance
Annual Production (Boe per day)
130,000 - 135,000
Annual Oil Production (Bbls per day)
75,000 - 79,000
Total Capital Expenditures ($ in millions)
$1,050 - $1,200
Net Oil Wells Turned-in-Line87.0 - 91.0
Net Total Wells Turned-in-Line97.0 - 99.0
Net Wells Spud106.0 - 110.0

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

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







FIRST QUARTER 2025 RESULTS

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

 Three Months Ended March 31,
 20252024% Change
Net Production:
Oil (MBbl)7,081 6,386 11 %
Natural Gas (MMcf)30,394 26,893 13 %
Total (MBoe)12,146 10,869 12 %
Average Daily Production:
Oil (Bbl)78,675 70,181 12 %
Natural Gas (Mcf)337,706 295,526 14 %
Total (Boe)134,959 119,436 13 %
Average Sales Prices:
Oil (per Bbl)$64.92 $72.92 (11)%
Effect of Gain (Loss) on Settled Oil Derivatives on Average Price (per Bbl)1.55 (0.84)
Oil Net of Settled Oil Derivatives (per Bbl)66.47 72.08 (8)%
Natural Gas and NGLs (per Mcf)3.86 2.47 56 %
Effect of Gain on Settled Natural Gas Derivatives on Average Price (per Mcf)0.04 0.91 
Natural Gas and NGLs Net of Settled Natural Gas and NGL Derivatives (per Mcf)3.90 3.38 15 %
Realized Price on a Boe Basis Excluding Settled Commodity Derivatives47.50 48.95 (3)%
Effect of Gain on Settled Commodity Derivatives on Average Price (per Boe)0.99 1.76 
Realized Price on a Boe Basis Including Settled Commodity Derivatives48.49 50.71 (4)%
Costs and Expenses (per Boe):
Production Expenses$9.39 $9.70 (3)%
Production Taxes2.97 4.71 (37)%
General and Administrative Expenses1.19 1.05 13 %
Depletion, Depreciation, Amortization and Accretion16.93 16.01 6 %
Net Producing Wells at Period End1,133.9 985.3 15 %




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 March 31, 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:
Q231,623 $74.41 27,502 22,189 $77.45 $69.41 
Q328,413 73.51 25,054 19,761 77.43 69.15 
Q430,433 73.17 24,766 19,473 77.55 69.15 
2026:
Q113,430 $70.12 34,680 27,187 $72.98 $62.94 
Q25,430 68.16 19,680 12,187 72.33 65.01 
Q35,430 68.13 19,680 12,187 72.33 65.01 
Q45,430 68.08 19,680 12,187 72.33 65.01 
_____________
(1)Includes derivative contracts entered into as of April 29, 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 March 31, 2025.




The following table summarizes NOG’s open natural gas commodity derivative swap contracts scheduled to settle after March 31, 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:
Q2100,952 $3.88 108,348 108,348 $4.82 $3.12 
Q3102,929 3.99 106,828 106,828 4.81 3.12 
Q4109,872 4.08 106,309 106,309 4.87 3.20 
2026:
Q192,278 $4.11 99,369 99,369 $4.99 $3.37 
Q279,176 3.94 101,590 101,590 4.99 3.37 
Q375,000 4.01 100,486 100,486 4.99 3.37 
Q474,783 4.09 71,681 71,681 4.91 3.35 
2027:
Q11,722 $3.20 14,833 14,833 $3.86 $3.00 
Q2— — 15,165 15,165 3.86 3.00 
Q3— — 15,000 15,000 3.86 3.00 
Q4— — 9,946 9,946 3.86 3.00 
_____________
(1)Includes derivative contracts entered into as of April 29, 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 March 31, 2025.







The following table summarizes NOG’s open NGL commodity derivative swap contracts scheduled to settle after March 31, 2025.

NGL Contracts
Swaps
Contract PeriodVolume
(BBL)		Weighted Average Price
($/BBL)
2025:
Q24,550 $37.03 
Q329,900 36.39 
Q466,700 36.75 
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
March 31,
(In thousands)20252024
Cash Received on Settled Derivatives$12,062 $19,117 
Non-Cash Mark-to-Market Gain (Loss) on Derivatives9,699 (157,648)
Gain (Loss) on Commodity Derivatives, Net$21,761 $(138,531)



CAPITAL EXPENDITURES & DRILLING ACTIVITY

(In thousands, except for net well data and dollars per foot)Three Months Ended March 31, 2025
Capital Expenditures Incurred:
Organic Drilling and Development Capital Expenditures$245,063 
Ground Game Drilling and Development Capital Expenditures$1,444 
Ground Game Acquisition Capital Expenditures inclusive of pre-closing development costs$3,377 
Other$1,850 
Non-Budgeted Acquisitions$7,997 
Net Wells Added to Production27.3 
Net Producing Wells (Period-End)1,133.9 
Net Wells in Process (Period-End)38.9 
Weighted Average Gross AFE for Wells Elected to$10,534 
Weighted Average Gross AFE for Wells Elected to, normalized for lateral length ($ per foot)$833 

FIRST 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 Wednesday, April 30, 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/388978134
Dial-In Number: (800) 715-9871 (US/Canada) and (646) 307-1963 (International)
Conference ID: 4503139 - NOG First 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 May 14, 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.




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





CONDENSED STATEMENTS OF OPERATIONS
(UNAUDITED)

Three Months Ended
March 31,
(In thousands, except share and per share data)20252024
Revenues
Oil and Gas Sales$576,952 $532,041 
Gain (Loss) on Commodity Derivatives, Net21,761 (138,531)
Other Revenues3,385 2,838 
Total Revenues602,098 396,348 
Operating Expenses
Production Expenses114,040 105,447 
Production Taxes36,069 51,210 
General and Administrative Expenses14,481 11,393 
Depletion, Depreciation, Amortization and Accretion205,690 173,958 
Other Expenses2,537 2,019 
Total Operating Expenses372,817 344,027 
Income From Operations229,281 52,321 
Other Income (Expense)
Interest Expense, Net of Capitalization(43,850)(37,925)
Loss on Unsettled Interest Rate Derivatives, Net(144)— 
Other Income500 56 
Total Other Expense, Net(43,494)(37,869)
Income Before Income Taxes185,787 14,452 
Income Tax Expense46,805 2,846 
Net Income$138,982 $11,606 
Net Income Per Common Share – Basic$1.41 $0.12 
Net Income Per Common Share – Diluted$1.39 $0.11 
Weighted Average Common Shares Outstanding – Basic98,559,724 100,442,472 
Weighted Average Common Shares Outstanding – Diluted99,992,487 101,636,132 




CONDENSED BALANCE SHEETS

(In thousands, except par value and share data)March 31, 2025December 31, 2024
Assets(Unaudited)
Current Assets:  
Cash and Cash Equivalents$33,576 $8,933 
Accounts Receivable, Net409,624 389,673 
Advances to Operators10,586 12,291 
Prepaid Expenses and Other5,076 5,271 
Derivative Instruments52,904 46,525 
Income Tax Receivable9,846 38,050 
Total Current Assets521,612 500,743 
Property and Equipment:  
Oil and Natural Gas Properties, Full Cost Method of Accounting  
Proved10,566,985 10,307,376 
Unproved42,825 42,702 
Other Property and Equipment8,783 8,197 
Total Property and Equipment10,618,593 10,358,275 
Less – Accumulated Depreciation, Depletion and Impairment(5,480,999)(5,276,105)
Total Property and Equipment, Net5,137,594 5,082,170 
Derivative Instruments1,250 9,832 
Acquisition Deposit4,000 — 
Other Noncurrent Assets, Net10,158 11,077 
Total Assets$5,674,614 $5,603,822 
Liabilities and Stockholders’ Equity
Current Liabilities:  
Accounts Payable$230,924 $202,866 
Accrued Liabilities273,435 290,792 
Accrued Interest26,637 25,992 
Derivative Instruments27,855 19,915 
Other Current Liabilities5,467 4,705 
Total Current Liabilities564,318 544,270 
Long-term Debt, Net2,310,500 2,369,294 
Deferred Tax Liability274,684 228,038 
Derivative Instruments73,908 93,606 
Asset Retirement Obligations46,975 45,907 
Other Noncurrent Liabilities2,148 2,272 
Total Liabilities$3,272,533 $3,283,387 
Commitments and Contingencies
Stockholders’ Equity  
Common Stock, Par Value $.001; 270,000,000 Shares Authorized;
 98,702,027 Shares Outstanding at 3/31/2025
 99,113,645 Shares Outstanding at 12/31/2024
501 501 
Additional Paid-In Capital1,820,080 1,877,416 


Retained Earnings581,500 442,518 
Total Stockholders’ Equity2,402,081 2,320,435 
Total Liabilities and Stockholders’ Equity$5,674,614 $5,603,822 



Non-GAAP Financial Measures

Adjusted Net Income, Adjusted EBITDA and Free Cash Flow are non-GAAP measures. NOG defines Adjusted Net Income (Loss) as income (loss) 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, and (v) (gain) loss on unsettled interest rate derivatives, 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 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, 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 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.



Reconciliation of Adjusted Net Income

 Three Months Ended
March 31,
(In thousands, except share and per share data)20252024
Income Before Income Taxes$185,787 $14,452 
Add:  
Impact of Selected Items:  
(Gain) Loss on Unsettled Commodity Derivatives(9,699)157,648 
Acquisition Transaction Costs423 772 
Loss on Unsettled Interest Rate Derivatives144 — 
Adjusted Income Before Adjusted Income Tax Expense 176,655 172,873 
Adjusted Income Tax Expense (1)
(43,280)(42,354)
Adjusted Net Income (non-GAAP)$133,375 $130,519 
Weighted Average Shares Outstanding – Basic98,559,724 100,442,472 
Weighted Average Shares Outstanding – Diluted99,992,487 101,636,132 
Income Before Income Taxes Per Common Share – Basic$1.89 $0.14 
Add:  
Impact of Selected Items(0.09)1.58 
Impact of Income Tax(0.45)(0.42)
Adjusted Net Income Per Common Share – Basic$1.35 $1.30 
Income Before Income Taxes Per Common Share – Adjusted Diluted$1.86 $0.14 
Add:  
Impact of Selected Items(0.09)1.56 
Impact of Income Tax(0.44)(0.42)
Adjusted Net Income Per Common Share – Adjusted Diluted$1.33 $1.28 
______________
(1)For the three months ended March 31, 2025 and March 31, 2024, this represents a tax impact using an estimated tax rate of 24.5%.






Reconciliation of Adjusted EBITDA

Three Months Ended
March 31,
(In thousands)20252024
Net Income$138,982 $11,606 
Add:  
Interest Expense43,850 37,925 
Income Tax Expense46,805 2,846 
Depreciation, Depletion, Amortization and Accretion205,690 173,958 
Non-Cash Stock-Based Compensation3,540 2,274 
Other Adjustments5,000 — 
Acquisition Transaction Costs423 772 
Loss on Unsettled Interest Rate Derivatives144 — 
(Gain) Loss on Unsettled Commodity Derivatives(9,699)157,648 
Adjusted EBITDA$434,735 $387,030 


Reconciliation of Free Cash Flow

Three Months Ended
March 31,
(In thousands)2025
Net Cash Provided by Operating Activities$407,426 
Exclude: Changes in Working Capital and Other Items(19,998)
Less: Capital Expenditures (1)
(251,735)
Free Cash Flow$135,693 
_______________
(1) Capital expenditures are calculated as follows:
Three Months Ended
March 31,
(In thousands)2025
Cash Paid for Capital Expenditures$263,971 
Less: Non-Budgeted Acquisitions(22,204)
Plus: Change in Accrued Capital Expenditures and Other9,968 
Capital Expenditures$251,735