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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
_________________________________
FORM 10-Q
_________________________________
 
  ☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2026
   ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the transition period from ____________ to____________
 
Commission File No. 001-33999
NORTHERN OIL AND GAS, INC.
(Exact Name of Registrant as Specified in Its Charter)
Delaware95-3848122
(State or Other Jurisdiction of
Incorporation or Organization)		(I.R.S. Employer Identification No.)
4350 Baker Road – Suite 400
Minnetonka, Minnesota 55343
(Address of Principal Executive Offices)
(952) 476-9800
(Registrant’s Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common Stock, par value $0.001NOGNew York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes ☒  No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes ☒  No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer   ☒
Accelerated Filer  ☐
Non-Accelerated Filer    ☐

Smaller Reporting Company  ☐
Emerging Growth Company  ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐  No ☒

As of August 3, 2026, there were 106,549,128 shares of our common stock, par value $0.001, outstanding.

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GLOSSARY OF TERMS

Unless otherwise indicated in this report, natural gas volumes are stated at the legal pressure base of the state or geographic area in which the reserves are located at 60 degrees Fahrenheit.  Crude oil and natural gas equivalents are determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.

The following definitions shall apply to the technical terms used in this report.

Terms used to describe quantities of crude oil and natural gas:

“Bbl.”  One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or NGLs.

“Boe.”  A barrel of oil equivalent and is a standard convention used to express crude oil, NGL and natural gas volumes on a comparable crude oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of crude oil or NGL.

“Boepd.” Boe per day.

“Bopd.” Barrel of oil per day.

“Btu” or “British Thermal Unit.”  The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

“MBbl.”  One thousand barrels of crude oil, condensate or NGLs.

“MBoe.”  One thousand Boe.

“Mcf.”  One thousand cubic feet of natural gas.

“MMBbl.”  One million barrels of crude oil, condensate or NGLs.

“MMBoe.”  One million Boe.

“MMBtu.”  One million British Thermal Units.

“MMcf.”  One million cubic feet of natural gas.

“NGLs.”  Natural gas liquids.  Hydrocarbons found in natural gas that may be extracted as liquefied petroleum gas and natural gasoline.

Terms used to describe our interests in wells and acreage:

“Basin.”  A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“Completion.”  The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil, NGLs, and/or natural gas.

“Conventional play.”  An area that is believed to be capable of producing crude oil, NGLs, and natural gas occurring in discrete accumulations in structural and stratigraphic traps.

“Developed acreage.”  Acreage consisting of leased acres spaced or assignable to productive wells.  Acreage included in spacing units of infill wells is classified as developed acreage at the time production commences from the initial well in the spacing unit.  As such, the addition of an infill well does not have any impact on a company’s amount of developed acreage.

“Development well.”  A well drilled within the proved area of a crude oil, NGL, or natural gas reservoir to the depth of a stratigraphic horizon (rock layer or formation) known to be productive for the purpose of extracting proved crude oil, NGL, or natural gas reserves.

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“Differential.” The difference between a benchmark price of crude oil and natural gas, such as the NYMEX crude oil spot price, and the wellhead price received.

“Dry hole.”  A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“Exploratory well.”  A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well.

“Extension well.” An extension well is a well drilled to extend the limits of a known reservoir.

“Field.”  An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“Formation.”  A layer of rock which has distinct characteristics that differs from nearby rock.

“Gross acres” or “Gross wells.”  The total acres or wells, as the case may be, in which a working interest is owned.

“Held by operations.”  A provision in an oil and gas lease that extends the stated term of the lease as long as drilling operations are ongoing on the property.

“Held by production.”  A provision in an oil and gas lease that extends the stated term of the lease as long as the property produces a minimum quantity of crude oil, NGLs, and natural gas.

“Hydraulic fracturing.”  The technique of improving a well’s production by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.

“Infill well.”  A subsequent well drilled in an established spacing unit of an already established productive well in the spacing unit.  Acreage on which infill wells are drilled is considered developed commencing with the initial productive well established in the spacing unit.  As such, the addition of an infill well does not have any impact on a company’s amount of developed acreage.

“Net acres.”  The percentage ownership of gross acres.  Net acres are deemed to exist when the sum of fractional ownership working interests in gross acres equals one (e.g., a 10% working interest in a lease covering 640 gross acres is equivalent to 64 net acres).

“Net well.”  A well that is deemed to exist when the sum of fractional ownership working interests in gross wells equals one.

“NYMEX.”  The New York Mercantile Exchange.

“OPEC.”  The Organization of Petroleum Exporting Countries.

“Productive well.”  A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“Recompletion.”  The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil, NGLs or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“Reservoir.”  A porous and permeable underground formation containing a natural accumulation of producible crude oil, NGLs and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“Service well.” A service well is drilled or completed for the purpose of supporting production in an existing field. Wells in this class are drilled for the following specific purposes: gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.
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“Spacing.”  The distance between wells producing from the same reservoir.  Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“Stratigraphic test well.” A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

“Unconventional play.”  An area believed to be capable of producing crude oil, NGLs, and/or natural gas occurring in cumulations that are regionally extensive but require recently developed technologies to achieve profitability.  These areas tend to have low permeability and may be closely associated with source rock as this is the case with crude oil and natural gas shale, tight crude oil and natural gas sands and coal bed methane.

“Undeveloped acreage.”  Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of crude oil, NGLs, and natural gas, regardless of whether such acreage contains proved reserves.  Undeveloped acreage includes net acres held by operations until a productive well is established in the spacing unit.

“Unit.”  The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests.  Also, the area covered by a unitization agreement.

“Wellbore.”  The hole drilled by the bit that is equipped for natural gas production on a completed well.  Also called well or borehole.

“West Texas Intermediate or WTI.”  A light, sweet blend of oil produced from the fields in West Texas.

“Working interest.”  The right granted to the lessee of a property to explore for and to produce and own crude oil, NGLs, natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

“Workover.” Operations on a producing well to restore or increase production.

Terms used to assign a present value to or to classify our reserves:

“Developed Oil and Gas Reserves.” Oil and natural gas reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

“Possible reserves.”  The additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves.

“Pre-tax PV-10%” or “PV-10.”  The estimated future net revenue, discounted at a rate of 10% per annum, before income taxes and with no price or cost escalation or de-escalation in accordance with guidelines promulgated by the SEC.

“Probable reserves.”  The additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but which together with proved reserves, are as likely as not to be recovered.

“Proved developed non-producing reserves (PDNPs).” Proved crude oil, NGLs, and natural gas reserves that are developed behind pipe, shut-in or that can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor.  Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate, but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production.

“Proved developed producing reserves (PDPs).”  Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.  Additional crude oil, NGLs, and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms
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of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

“Proved reserves.”  The quantities of crude oil, NGLs and natural gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.  The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.

(i)    The area of the reservoir considered as proved includes: (A) the area identified by drilling and limited by fluid contacts, if any, and (B) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible crude oil, NGLs or natural gas on the basis of available geoscience and engineering data.

(ii)    In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establish a lower contact with reasonable certainty.

(iii)    Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv)    Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) the project has been approved for development by all necessary parties and entities, including governmental entities.

(v)    Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions.

“Proved undeveloped drilling location.”  A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

“Proved undeveloped reserves” or “PUDs.”  Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for development. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation.  Estimates for proved undeveloped reserves will not be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir or an analogous reservoir.

“Reserves.” Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

“Standardized measure.”  Discounted future net cash flows estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying
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the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

“Undeveloped Oil and Gas Reserves.” Oil and natural gas reserves of any category that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.


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NORTHERN OIL AND GAS, INC.
FORM 10-Q

June 30, 2026

C O N T E N T S
Page
PART I – FINANCIAL INFORMATION
Item 1.Condensed Consolidated Financial Statements (unaudited)
Condensed Consolidated Balance Sheets
Condensed Consolidated Statements of Operations
Condensed Consolidated Statements of Comprehensive Income
Condensed Consolidated Statements of Cash Flows
Condensed Consolidated Statements of Stockholders’ Equity
Notes to Condensed Consolidated Financial Statements
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.Quantitative and Qualitative Disclosures about Market Risk
Item 4. Controls and Procedures
PART II – OTHER INFORMATION
Item 1.Legal Proceedings
Item 1A.Risk Factors
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds
Item 3.Defaults Upon Senior Securities
Item 4.Mine Safety Disclosures
Item 5.Other Information
Item 6.Exhibits
Signatures

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PART I - FINANCIAL INFORMATION
Item 1. Condensed Consolidated Financial Statements.
NORTHERN OIL AND GAS, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
(In thousands, except par value and share data)June 30, 2026December 31, 2025
Assets
Current Assets:
Cash and Cash Equivalents$47,603 $14,299 
Accounts Receivable, Net377,818 349,927 
Advances, Prepaid Expenses, and Other27,968 37,061 
Derivative Instruments30,914 166,678 
Income Tax Receivable17,799 18,066 
Total Current Assets502,102 586,031 
Property and Equipment:
Oil and Natural Gas Properties, Full Cost Method of Accounting
Proved12,429,203 11,441,786 
Unproved301,755 86,034 
Less – Accumulated Depletion and Impairment(7,440,256)(6,784,649)
Total Oil and Natural Gas Properties, Net5,290,702 4,743,171 
Other Property and Equipment, Net2,438 3,196 
Total Property and Equipment, Net5,293,140 4,746,367 
Derivative Instruments9,726 3,036 
Deferred Income Taxes8,152 — 
Other Noncurrent Assets, Net14,745 73,941 
Total Assets$5,827,865 $5,409,375 
Liabilities and Stockholders’ Equity
Current Liabilities:
Accounts Payable$206,275 $218,620 
Accrued Liabilities and Other399,176 320,673 
Derivative Instruments25,041 — 
Total Current Liabilities630,492 539,293 
Long-term Debt, Net2,724,814 2,395,393 
Deferred Tax Liability158,290 247,645 
Derivative Instruments255,868 48,102 
Contingent Consideration6,614 — 
Asset Retirement Obligations54,949 50,831 
Other Noncurrent Liabilities1,505 1,770 
Total Liabilities$3,832,532 $3,283,034 
Commitments and Contingencies
Stockholders’ Equity
Common Stock, Par Value $0.001; 270,000,000 Shares Authorized;
106,549,128 Shares Outstanding at 6/30/2026
97,265,559 Shares Outstanding at 12/31/2025
509 499 
Additional Paid-In Capital1,802,928 1,644,563 
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Retained Earnings195,060 481,279 
Accumulated Other Comprehensive Loss(3,164)— 
Total Stockholders’ Equity1,995,333 2,126,341 
Total Liabilities and Stockholders’ Equity$5,827,865 $5,409,375 
______________
The accompanying notes are an integral part of these condensed consolidated financial statements.

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NORTHERN OIL AND GAS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
Three Months Ended
June 30,		Six Months Ended
June 30,
(In thousands, except share and per share data)2026202520262025
Revenues
Oil and Gas Sales$670,796 $574,369 $1,210,651 $1,151,321 
Gain (Loss) on Commodity Derivatives, Net70,182 128,819 (468,874)150,581 
Other Revenues4,257 3,621 8,487 7,006 
Total Revenues745,235 706,809 750,264 1,308,908 
Operating Expenses
Production Expenses127,089 121,430 256,836 235,470 
Production Taxes45,699 35,616 84,042 71,685 
General and Administrative Expenses24,529 15,628 47,703 30,109 
Legal Settlement Expense — 33,091 — 33,091 
Depletion, Depreciation, Amortization and Accretion192,885 205,741 389,983 411,432 
Impairment of Oil and Gas Assets— 115,576 268,276 115,576 
Other Expenses2,496 3,561 5,771 6,098 
Total Operating Expenses392,698 530,643 1,052,611 903,461 
Income (Loss) From Operations352,537 176,166 (302,347)405,447 
Other Income (Expense)
Interest Expense, Net(41,442)(44,389)(84,027)(87,739)
Gain (Loss) on Unsettled Interest Rate Derivatives, Net1,474 1 3,040 (143)
Loss on Foreign Currency Transactions(4,655)— (4,655)— 
Loss on Extinguishment of Debt— — (14)— 
Gain on Contingent Consideration 2,682 — 2,682 — 
Total Other Expense, Net(41,941)(44,388)(82,974)(87,882)
Income (Loss) Before Income Taxes310,596 131,778 (385,321)317,565 
Income Tax Expense (Benefit)73,968 32,193 (99,102)78,998 
Net Income (Loss)$236,628 $99,585 $(286,219)$238,567 
Net Income (Loss) Attributable to Common Stockholders$236,628 $99,585 $(286,219)$238,567 
Net Income (Loss) Per Common Share – Basic$2.24 $1.02 $(2.80)$2.43 
Net Income (Loss) Per Common Share – Diluted$2.19 $1.00 $(2.80)$2.39 
Weighted Average Common Shares Outstanding – Basic105,871,269 98,060,407 102,207,355 98,308,686 
Weighted Average Common Shares Outstanding – Diluted108,091,366 99,394,539 102,207,355 99,692,134 
______________
The accompanying notes are an integral part of these condensed consolidated financial statements.
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NORTHERN OIL AND GAS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended June 30,Six Months Ended June 30,
(In thousands)2026202520262025
Net Income (Loss)$236,628 $99,585 $(286,219)$238,567 
Other Comprehensive Loss:
Foreign Currency Translation Adjustment(3,164)— (3,164)— 
Total Other Comprehensive Loss(3,164)— (3,164)— 
Comprehensive Income (Loss)$233,464 $99,585 $(289,383)$238,567 

______________
The accompanying notes are an integral part of these condensed consolidated financial statements.

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    NORTHERN OIL AND GAS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended
June 30,		Six Months Ended
June 30,
(In thousands)2026202520262025
Cash Flows from Operating Activities
Net Income (Loss)$236,628 $99,585 $(286,219)$238,567 
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
Depletion, Depreciation, Amortization, and Accretion192,885 205,741 389,983 411,432 
Amortization of Debt Issuance Costs2,556 2,584 5,071 4,974 
Loss on Extinguishment of Debt— — 14 — 
Amortization of Bond Premium/Discount on Long-term Debt(508)(395)(1,028)(676)
Deferred Income Taxes73,714 28,027 (97,507)74,673 
Unrealized Loss on Foreign Currency Transactions4,655 — 4,655 — 
Unrealized Loss (Gain) on Derivative Instruments(157,976)(67,890)361,881 (77,445)
Gain on Contingent Consideration(2,682)— (2,682)— 
Stock-Based Compensation Expense4,410 3,777 8,120 7,353 
Impairment of Oil and Gas Assets— 115,576 268,276 115,576 
Other(4)(27)287 (48)
Changes in Working Capital and Other Items:
Accounts Receivable, Net17,389 (621)(27,975)(20,572)
Prepaid and Other Expenses2,432 (1,858)1,109 (1,023)
Income Tax Receivable(3,918)(1,971)267 26,233 
Accounts Payable, Accrued Liabilities, and Other(47,964)(20,416)20,980 (9,506)
Net Cash Provided by Operating Activities321,617 362,112 645,232 769,538 
Cash Flows from Investing Activities
Acquisitions of and Capital Expenditures on Oil and Natural Gas Properties(379,811)(327,361)(1,014,434)(591,332)
Purchases of Other Property and Equipment— 106 (55)(481)
Net Cash Used for Investing Activities(379,811)(327,255)(1,014,489)(591,813)
Cash Flows from Financing Activities
Advances on Revolving Credit Facility304,000 118,000 784,000 173,000 
Repayments on Revolving Credit Facility(132,000)(268,000)(437,000)(383,000)
Repurchase of Senior Notes Due 2028— — (20,165)— 
Entry into Additional Capped Call Transactions— (16,947)— (16,947)
Issuance of Additional Convertible Notes— 200,000 — 200,000 
Premium Received on Additional Convertible Notes— 11,194 — 11,194 
Debt Issuance Costs Paid— (7,554)(1,627)(7,554)
Issuance of Common Stock— — 227,928 — 
Repurchases of Common Stock(50,047)(35,000)(50,047)(50,005)
Common Stock Issuance Costs Paid(353)— (384)— 
Restricted Stock Surrenders - Tax Obligations— — (2,822)(1,486)
Common Dividends Paid(47,370)(44,270)(91,848)(86,004)
Net Cash Provided by (Used for) Financing Activities74,230 (42,577)408,035 (160,802)
Effect of Exchange Rate Changes on Cash and Cash Equivalents(5,474)— (5,474)— 
Net Increase (Decrease) in Cash and Cash Equivalents10,562 (7,720)33,304 16,923 
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Cash and Cash Equivalents - Beginning of Period37,041 33,576 14,299 8,933 
Cash and Cash Equivalents - End of Period47,603 25,856 47,603 25,856 
______________
The accompanying notes are an integral part of these condensed consolidated financial statements.
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NORTHERN OIL AND GAS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(UNAUDITED)

(In thousands, except share data)Common StockAdditional Paid-InRetained EarningsAccumulated Other Comprehensive Total Stockholders’
SharesAmountCapital(Deficit)LossEquity
December 31, 202597,265,559 $499 $1,644,563 $481,279 $— $2,126,341 
Issuance of Common Stock8,288,289 9 227,551 — 227,560 
Share Based Compensation343,040 — 3,764 — 3,764 
Restricted Stock Forfeitures(1,467)— — — — 
Restricted Stock Surrenders - Tax Obligations(104,298)— (2,822)— (2,822)
Common Stock Dividends Declared— — (47,600)— (47,600)
Net Loss— — — (522,847)(522,847)
March 31, 2026105,791,123 $508 $1,825,456 $(41,568)$— $1,784,396 
Issuance of Common Stock3,689,413 3 81,225 — — 81,228 
Share Based Compensation19,764 — 4,499 — — 4,499 
Restricted Stock Forfeitures(2,725)— (10)— — (10)
Repurchases of Common Stock(2,948,447)(2)(60,056)— — (60,058)
Cumulative Translation Adjustments— — — — (3,164)(3,164)
Common Stock Dividends Declared— — (48,186)— — (48,186)
Net Income— — — 236,628 — 236,628 
June 30, 2026106,549,128 $509 $1,802,928 $195,060 $(3,164)$1,995,333 

(In thousands, except share data)Common StockAdditional Paid-InRetained
Accumulated Other Comprehensive
Total Stockholders’
SharesAmountCapitalEarnings
Income
Equity
December 31, 202499,113,645 $501 $1,877,416 $442,518 $— $2,320,435 
Share Based Compensation139,175 — 3,576 — — 3,576 
Restricted Stock Forfeitures(1,313)— (1)— — (1)
Restricted Stock Surrenders - Tax Obligations(50,380)— (1,486)— — (1,486)
Repurchases of Common Stock(499,100)— (15,155)— — (15,155)
Common Stock Dividends Declared— — (44,270)— — (44,270)
Net Income— — — 138,982 — 138,982 
March 31, 202598,702,027 $501 $1,820,080 $581,500 $— $2,402,081 
Share Based Compensation16,250 — 3,777 — — 3,777 
Repurchases of Common Stock(1,123,595)(1)(35,349)— — (35,350)
Entry into Additional Capped Call Transactions, Net of Deferred Tax Impact— — (12,985)— — (12,985)
Common Stock Dividends Declared— — (44,089)— — (44,089)
Net Income— — — 99,585 — 99,585 
June 30, 202597,594,682 $500 $1,731,434 $681,085 $— $2,413,019 
___________
The accompanying notes are an integral part of these condensed consolidated financial statements.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2026
(UNAUDITED)

NOTE 1     ORGANIZATION AND NATURE OF BUSINESS

When we use the terms the “Company,” “NOG,” “our” and words of similar import, we are referring to Northern Oil and Gas, Inc., a Delaware corporation, and its consolidated subsidiaries unless the context otherwise requires. NOG is an independent energy company engaged as a non-operator in the acquisition, exploration, development and production of oil and natural gas properties in North America, primarily in the Permian Basin, the Williston Basin, the Appalachian Basin, the Uinta Basin, and the Duvernay Basin. The Company’s common stock trades on the New York Stock Exchange under the symbol “NOG”.

The Company’s principal business is crude oil and natural gas exploration, development, and production across North America. The Company’s primary strategy is investing in non-operated minority working and mineral interests in oil and natural gas properties, with a core area of focus in five premier basins across North America.

In May 2026, the Company formed two new wholly-owned subsidiaries: (i) NOG Energy Canada Holdco, LLC, a Delaware limited liability company, and (ii) NOG Energy Canada, Ltd., a corporation organized under the laws of Alberta, Canada. These two new entities were formed pursuant to the Duvernay Acquisition, as described in Note 3. Accordingly, they are included in the accompanying condensed consolidated financial statements from their respective dates of formation.


NOTE 2     BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

These financial statements, which are unaudited, have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”). Such information includes all adjustments (consisting of normal recurring adjustments) that are, in the opinion of management, necessary for a fair presentation of the financial position, results of operations and cash flows for the interim periods. The results of operations for interim periods are not necessarily indicative of the results to be expected for an entire year.

Certain information, accounting policies, and footnote disclosures normally included in the financial statements prepared in accordance with GAAP have been condensed or omitted in this Quarterly Report on Form 10-Q pursuant to certain rules and regulations of the Securities and Exchange Commission (“SEC”).  The condensed consolidated financial statements should be read in conjunction with the audited financial statements for the year ended December 31, 2025, which were included in the Company’s 2025 Annual Report on Form 10-K for the fiscal year ended December 31, 2025.

Principle of Consolidation

The condensed consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. All intercompany transactions and balances have been eliminated in consolidation.

Foreign Currency Transactions

Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in Accumulated Other Comprehensive Loss in the condensed consolidated balance sheets and the condensed consolidated statements of stockholders’ equity. Foreign currency transaction gains and losses arising from remeasurement are recognized in current earnings.

Contingent Consideration

When contingent consideration is included as part of an acquisition of oil and gas properties, the Company recognizes the contingent consideration at fair value as of the acquisition date. Contingent consideration is classified as either a liability or equity based on the nature of the arrangement. Contingent consideration classified as a liability is remeasured at fair value at each reporting date, with changes in fair value recognized in earnings, until the contingency is resolved and the obligation is settled. Contingent consideration classified as equity is not remeasured subsequent to the acquisition date. The fair value of contingent consideration is classified within the appropriate level of the fair value hierarchy based on the significance of the inputs used in the valuation. See Note 3 and Note 9 for further discussion.
9
Use of Estimates

The preparation of financial statements under GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  

The most significant estimates relate to proved crude oil and natural gas reserves, which include limited control over future development plans as a non-operator, estimates relating to certain crude oil and natural gas revenues and expenses, fair value of derivative instruments, fair value of contingent consideration, acquisition date fair values of assets acquired and liabilities assumed, impairment of crude oil and natural gas properties, asset retirement obligations at initial recognition, and deferred income taxes.

Management’s estimates and assumptions were based on historical data and consideration of future market conditions. Given the uncertainty inherent in any projection, actual results may differ from the estimates and assumptions used, and conditions may change, which could materially affect amounts reported in the unaudited condensed consolidated financial statements.

Reclassifications

Certain prior period balances in the condensed consolidated statements of operations have been reclassified to conform to the current year presentation. Such reclassifications had no impact on net income (loss), cash flows or stockholders’ equity previously reported.

Recently Adopted and Recently Issued Accounting Pronouncements

From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”), in the form of Accounting Standard Updates (“ASU”), that are adopted by the Company as of the specified effective date, as applicable. If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption.

Recently Adopted Accounting Pronouncements:

In November 2024, the FASB issued ASU 2024-04, Debt - Debt With Conversion and Other Options (Subtopic 470-20): Induced Conversion of Convertible Debt Instruments. The objective of the standard is to improve the relevance and consistency in application of the induced conversion guidance in Subtopic 470-20, Debt with Conversion and Other Options. This standard will affect entities that settle convertible debt instruments for which the conversion privileges are changed to induce conversion. ASU 2024-04 is effective for annual reporting periods beginning after December 15, 2025, and interim reporting periods within those annual reporting periods. The Company adopted ASU 2024-04 as of March 31, 2026, with no material impact on its financial statements and related disclosures.

Recently Issued Accounting Pronouncements:

In November 2024, the FASB issued ASU 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The standard requires disclosure, in the notes to financial statements, of specified information about certain costs and expenses. The objective of the standard is to provide disaggregated information about a public business entity’s expenses to help investors better understand the components of an entity’s expenses, which should enable investors to better assess an entity’s prospects for future cash flows. ASU 2024-03 is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The Company is currently evaluating the impact of the new standard on its financial statements and related disclosures.

Revenue Recognition

The Company’s revenues are primarily derived from its interests in the sales of oil and natural gas production. The Company recognizes revenue from its interests in the sales of crude oil and natural gas in the period that its performance obligations are satisfied. Performance obligations are satisfied when the customer obtains control of the product, when the Company has no further obligations to perform related to the sale, when the transaction price has been determined and when collectability is probable. The sales of oil and natural gas are made under contracts which the third-party operators of the wells have negotiated with customers, which typically include variable consideration that is based on pricing tied to local indices and volumes delivered in the current month. The Company receives payment from the sale of oil and natural gas production from one to
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three months after delivery. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in Accounts Receivable, Net in the condensed consolidated balance sheets. Variances between the Company’s estimated revenue and actual payments are recorded in the month the payment is received. Historically, differences have been insignificant. Accordingly, the variable consideration is not constrained.

The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical expedient exemption, which applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

The Company’s oil is typically sold at delivery points under contract terms that are common in our industry. The Company’s natural gas produced is delivered by the well operators to various purchasers at agreed upon delivery points under a limited number of contract types that are also common in our industry. Regardless of the contract type, the terms of these contracts compensate the well operators for the value of the oil and natural gas at specified prices, and then the well operators will remit payment to the Company for its share in the value of the oil and natural gas sold.

From time to time, the Company’s share of gas sold may exceed its entitlement, resulting in a gas production imbalance. To the extent that such an imbalance exists, the Company only records a corresponding liability if the Company’s gas volumes sold are in excess of its share of remaining reserves in an underlying property. No well imbalance liability was recorded as of June 30, 2026.

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 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 received approximately $81.7 million, recorded within Oil and Gas Sales in the accompanying condensed consolidated statements of operations. The Company received a net cash settlement of $48.6 million after deducting approximately $33.1 million in legal settlement expenses.

The Company reports volumes and revenues on a two-stream basis. Accordingly, the Company’s disaggregated revenue has two primary sources: (i) oil sales and (ii) natural gas and NGL sales. Substantially all of the Company’s sales come from five operating areas in North America: the Williston Basin, the Permian Basin, the Appalachian Basin, the Uinta Basin and the Duvernay Basin.

The following table presents the disaggregation of the Company’s oil revenues and natural gas and NGL revenues for the three and six months ended June 30, 2026 and 2025.

Three Months Ended
June 30,		Six Months Ended
June 30,
(In thousands)2026202520262025
Oil Sales$559,264 $402,672 $998,346 $862,354 
Natural Gas and NGL Sales (1)
111,532 171,697 212,305 288,967 
Total$670,796 $574,369 $1,210,651 $1,151,321 
________________
(1)Balances for the three and six months ended June 30, 2025 include $81.7 million in legal settlement from an Operator in North Dakota.

Concentrations of Market, Credit Risk and Other Risks

The future results of the Company’s crude oil and natural gas operations will be affected by the market prices of crude oil and natural gas.  The availability of a ready market for crude oil and natural gas products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of crude oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of crude oil, natural gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty.

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The Company operates in the exploration, development and production sector of the crude oil and natural gas industry.  The Company’s receivables include amounts due, indirectly via the third-party operators of the wells, from purchasers of its crude oil and natural gas production.  While certain of these customers, as well as third-party operators of the wells, are affected by periodic downturns in the economy in general or in their specific segment of the crude oil or natural gas industry, the Company believes that its level of credit-related losses due to such economic fluctuations have been immaterial.

As a non-operator, 100% of the Company’s wells are operated by third-party operating partners. As a result, the Company is highly dependent on the success of these third-party operators. If they are not successful in the exploration, development and production activities relating to the Company’s leasehold interests, or are unable or unwilling to perform, the Company’s financial condition and results of operations could be adversely affected. These risks are heightened in a low commodity price environment, which may present significant challenges to these third-party operators. The Company’s third-party operators will make decisions in connection with their operations that may not be in the Company’s best interests, and the Company may have little or no ability to exercise influence over the operational decisions of its third-party operators. For the three months ended June 30, 2026, the Company’s top six operators made up 46% of total oil and natural gas sales, with one operator comprising more than 10% but less than 15%. For the six months ended June 30, 2026, the Company’s top six operators made up 46% of total oil and natural gas sales, with one operator comprising more than 10% but less than 15%. For the three months ended June 30, 2025, the Company’s top six operators made up 54% of total oil and natural gas sales, with two operators comprising more than 10% but less than 15%. For the six months ended June 30, 2025, the Company’s top six operators made up 52% of total oil and natural gas sales, with two operators comprising more than 10% but less than 15%.

The Company faces concentration risk due to the fact that substantially all of its oil and natural gas revenue is sourced from a limited number of geographic areas of operations. As a result, the Company is disproportionately exposed to risks that affect one or more of those areas in the Williston Basin, the Permian Basin, the Appalachian Basin, the Uinta Basin and the Duvernay Basin.

Pursuant to the Company’s recent acquisition of oil and gas properties in Canada (See Note 3), the Company is now subject to foreign currency risks. The Company’s wholly-owned Canadian subsidiary uses the Canadian dollar (“CAD”) as its functional currency. Fluctuations in the USD/CAD exchange rate will affect the USD equivalent of the Canadian subsidiary’s assets, liabilities, revenues, and operating expenses as reported in the consolidated financial statements.

The Company manages and controls market and counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Financial instruments which potentially subject the Company to credit risk consist principally of cash balances and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company. The Company believes the credit quality of its counterparties is generally high. In the normal course of business, letters of credit or parent guarantees may be required for counterparties which management perceives to have a higher credit risk.

Net Income (Loss) Per Common Share

Basic earnings per share (“EPS”) are computed by dividing net income (loss) attributable to common stockholders (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include vesting of restricted stock awards and shares issuable upon conversion of the Convertible Notes (see Note 4). The number of potential common shares outstanding are calculated using the treasury stock or if-converted method.

In those reporting periods in which the Company has reported net income available to common stockholders, anti-dilutive shares generally are comprised of the restricted stock that has average unrecognized stock compensation expense greater than the average stock price. In those reporting periods in which the Company has a net loss, anti-dilutive shares are comprised of the impact of those number of shares that would have been dilutive had the Company had net income plus the number of common stock equivalents that would be anti-dilutive had the company had net income.

Restricted stock awards are excluded from the calculation of basic weighted average common shares outstanding until they vest. For restricted stock awards that vest based on achievement of performance and/or market conditions, the number of contingently issuable common shares included in diluted weighted-average common shares outstanding is based on the number of common shares, if any, that would be issuable under the terms of the arrangement if the performance and/or market conditions were met at the end of the reporting period, assuming the result would be dilutive.
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The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three and six months ended June 30, 2026 and 2025 are as follows:

Three Months Ended
June 30,		Six Months Ended
June 30,
(In thousands, except share and per share data)2026202520262025
Net Income (Loss) Attributable to Common Stockholders
$236,628 $99,585 $(286,219)$238,567 
Weighted Average Common Shares Outstanding:
Weighted Average Common Shares Outstanding – Basic105,871,269 98,060,407 102,207,355 98,308,686 
Plus: Dilutive Effect of Restricted Stock and Contingently Issuable Shares2,220,097 1,334,132 — 1,383,447 
Weighted Average Common Shares Outstanding – Diluted108,091,366 99,394,539 102,207,355 99,692,134 
Net Income (Loss) per Common Share:
Basic$2.24 $1.02 $(2.80)$2.43 
Diluted$2.19 $1.00 $(2.80)$2.39 
Shares Excluded from EPS Due to Anti-Dilutive Effect:
Restricted Stock89,037 63,093 2,075,976 74,873 


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Supplemental Cash Flow Information

The following table reflects the Company’s supplemental cash flow information for the three and six months ended June 30, 2026 and 2025:

Three Months Ended
June 30,		Six Months Ended
June 30,
(In thousands)2026202520262025
Supplemental Cash Items:
Cash Paid During the Period for Interest$77,636 $43,714 $85,975 $85,602 
Cash Paid (Refunded) During the Period for Income Taxes, Net
U.S. Federal— — — (1,950)
U.S. State and Local:5 665 447 (345)
Non-cash Investing Activities:
Capital Expenditures on Oil and Natural Gas Properties Included in Accounts Payable and Accrued Liabilities359,958 295,758 359,958 295,758 
Capitalized Asset Retirement Obligations871 1,294 2,480 2,184 
Issuance of Common Stock - Acquisition of Oil and Natural Gas Properties 81,388 — 81,388 — 
Contingent Consideration - Acquisition of Oil and Natural Gas Properties9,507 — 9,507 — 
Compensation Costs Capitalized in Oil and Natural Gas Properties255 208 485 402 
Non-cash Financing Activities:
Common Stock Dividends Declared, But Not Paid49,612 44,270 49,612 44,270 
Common Stock Repurchases Included In Accounts Payable and Accrued Liabilities10,244 — 10,244 — 
Repurchases of Common Stock - Excise Tax— 350 — 500 


NOTE 3     CRUDE OIL AND NATURAL GAS PROPERTIES

The Company follows the full cost method of accounting to account for its crude oil and natural gas operations, whereby all costs related to the exploration and development of crude oil and natural gas properties are capitalized into a separate full cost pool for each country in which it operates. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities.  Internal costs that are capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities.  Costs associated with production and general corporate activities are expensed in the period incurred.

Under the full cost method of accounting, the Company is required to perform a ceiling test, each quarter, for each full cost pool. The test determines a limit, or ceiling, for each full cost pool, on the book value of the Company’s oil and natural gas properties.  For each full cost pool, net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the full cost ceiling. As a result of its ceiling tests, the Company recorded a non-cash impairment charge of approximately $268.3 million in the six months ended June 30, 2026 for the United States full cost pool. No impairment charges were recorded in the three months ended June 30, 2026. Conversely, the Company recorded a non-cash impairment charge of approximately $115.6 million in the three and six months ended and June 30, 2025.

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Average commodity prices used in our ceiling test calculations have fluctuated significantly in recent quarters. If said prices trend downward, and/or if our proved reserves decrease significantly in future months, the present value of the Company’s future net revenues could decline, which could trigger the need for the Company to record an additional non-cash ceiling test impairment of its oil and natural gas property costs in future periods.

The book value of the Company’s crude oil and natural gas properties consists of all acquisition costs, drilling costs and other associated capitalized costs.  Acquisitions are accounted for as purchases and, accordingly, the results of operations are included in the accompanying condensed consolidated statements of operations from the closing date of the acquisition. Acquired assets and liabilities assumed are recorded based on their estimated fair value at the time of the acquisition.

2026 Acquisitions

In addition to the closing of the Utica Acquisition and the Duvernay Acquisition, as defined below, during the three and six months ended June 30, 2026, the Company acquired oil and natural gas properties through a number of smaller independent transactions for a total of $44.7 million and $88.3 million, respectively, inclusive of related development costs.

Utica Acquisition

In February 2026, the Company completed its acquisition of certain upstream and midstream assets in the state of Ohio from Antero Resources Corporation and certain affiliated entities (collectively, “Antero”), effective as of July 1, 2025 (together, the “Utica Acquisition”). At closing, the Company acquired a 40% undivided working interest in the assets sold by Antero, with Infinity Natural Resources, LLC, an unaffiliated third party, acquiring the other 60% and becoming the operator of the acquired assets.

The total consideration paid to the seller at closing, net of customary purchase price adjustments, and net to the Company, was $464.6 million in cash, a portion of which was funded by a $58.8 million acquisition deposit paid in December 2025 and recorded in Other Noncurrent Assets, Net as of December 31, 2025.

The Company accounted for its Utica Acquisition as a business combination. Accordingly, transaction costs of approximately $6.7 million were included in general and administrative expense in the Company’s condensed consolidated statements of operations. The results of operations from the date of the Utica Acquisition through June 30, 2026 represented approximately $16.7 million of revenue and $9.3 million of income from operations. The following table reflects the fair value of the net assets and liabilities as of the closing date of the acquisition:

(In thousands)
Fair value of net assets:
Proved oil and natural gas properties$325,941 
Unproved oil and natural gas properties140,029 
Total assets acquired465,970 
Asset retirement obligations(1,334)
Net assets acquired$464,636 
Fair value of consideration paid for net assets:
Cash consideration$464,636 
Total fair value of consideration transferred$464,636 

Duvernay Acquisition

In June 2026, the Company completed its acquisition of certain oil and natural gas properties located in the Duvernay East Shale Basin of Alberta, Canada, from Parallax Energy Operating, Inc. (“Parallax”), effective as of April 1, 2026 (the “Duvernay Acquisition”). At closing, the Company acquired a 25% undivided working interest in the assets sold by Parallax, who continued as operator. NOG Energy Canada, Ltd acted as the purchaser of the assets.

The total consideration paid at closing, net of customary purchase price adjustments, was approximately $262.1 million, which included $171.2 million in cash, 3,689,413 shares of the Company’s common stock, par value $0.001 per share, with a total
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estimated fair value of $81.4 million, and $9.5 million in value attributable to potential additional contingent consideration (described in more detail below).

The Company accounted for its Duvernay Acquisition as a business combination. Accordingly, transaction costs of approximately $7.6 million were included in general and administrative expense in the Company’s condensed consolidated statements of operations. The results of operations from the date of the Duvernay Acquisition through June 30, 2026 represented approximately $7.9 million of revenue and $7.4 million of income from operations. The following table reflects the fair value of the net assets and liabilities as of the closing date of the acquisition:

(In thousands)
Fair value of net assets:
Proved oil and natural gas properties$205,309 
Unproved oil and natural gas properties57,327 
Total assets acquired262,636 
Asset retirement obligations(498)
Net assets acquired$262,138 
Fair value of consideration paid for net assets:
Cash consideration$171,243 
Issuance of common stock81,388 
Contingent consideration9,507 
Total fair value of consideration transferred$262,138 

The amount of additional contingent consideration payable by the Company, if any, is payable in January 2028. The payout amount is dependent upon the NYMEX WTI oil price reaching an average of $72.50 per Bbl during the period from April 1, 2026 to December 31, 2027. The fair value of the contingent consideration liability was approximately $9.5 million at the acquisition date. Upon remeasurement, the fair value of the contingent consideration was approximately $6.6 million at June 30, 2026. Accordingly, a remeasurement gain of $2.7 million was recorded in the condensed consolidated statements of operations.

2025 Acquisitions

During 2025, the Company acquired oil and natural gas properties through a number of smaller independent transactions for a total of $173.5 million, inclusive of related development costs.

In April 2025, the Company completed its acquisition of certain oil and natural gas properties, interests and related assets in the Midland Permian basin from a private seller, effective June 1, 2024. The total consideration paid to the seller at closing, net to the Company, was approximately $61.7 million in cash, a portion of which was funded by a $4.0 million acquisition deposit paid in February 2025.

In August 2025, the Company completed its acquisition of certain oil and natural gas properties, interests and related assets in the Uinta basin from a private seller, effective July 1, 2025. The total consideration paid to the seller at closing, net to the Company, was approximately $98.3 million in cash, a portion of which was funded by a $9.8 million acquisition deposit paid in June 2025.



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Pro Forma Information

The following summarized unaudited pro forma consolidated statements of operations for the three and six months ended June 30, 2026 and 2025 provides summarized information for the acquisitions accounted for as business combinations. The information provided assumes that the acquisitions accounted for as business combinations occurred as of January 1, 2025.

The Company prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma information may not be indicative of the results that would have occurred had the Company completed the acquisitions as of January 1, 2025, or that would be attained in the future.

Three Months Ended
June 30,		Six Months Ended
June 30,
(In thousands)2026202520262025
Total Revenues$767,946 $752,071 $807,043 $1,407,916 
Net Income (Loss) from Operations370,763 205,745 (256,779)471,332 


Divestitures

From time-to-time the Company may divest assets. In addition, the Company may trade leasehold interests with operators to balance working interests in spacing units to facilitate and encourage a more expedited development of the Company’s acreage.

Unproved Properties

All oil and natural gas properties that are not classified as proved properties are considered unproved properties and, thus, the costs associated with such properties are not subject to depletion until the properties are evaluated for reserves. Once a property is evaluated, all associated acreage and drilling costs are subject to depletion.

The Company historically has acquired unproved properties by purchasing individual or small groups of leases directly from mineral owners, landmen, or lease brokers, which leases historically have not been subject to specified drilling projects, and by purchasing lease packages in identified project areas controlled by specific operators.  The Company generally participates in drilling activities on a heads up basis by electing whether to participate in each well on a well-by-well basis at the time wells are proposed for drilling.

The Company believes that the majority of its unproved property will be evaluated, and thus the related costs will become subject to depletion within the next five years. The timing by which all unproved properties will become subject to depletion will be dependent upon the timing of future drilling activities and delineation of its reserves.

Capitalized costs associated with evaluated leasehold costs, which includes leases that have expired or have been deemed uneconomic, and capitalized costs related to properties having proved reserves, plus the estimated future development costs and asset retirement costs, are depleted and amortized using the unit-of-production method. Under this method, depletion is calculated at the end of each period by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the period. The costs of unproved properties are withheld from the depletion base until such time that they are evaluated.

When unproved properties are evaluated, their cost is added to costs subject to depletion and full cost ceiling calculations. For the three months ended June 30, 2026 and 2025, unproved properties of $6.6 million and $3.8 million, respectively, were transferred to evaluated leasehold costs. For the six months ended June 30, 2026 and 2025, unproved properties of $14.1 million and $5.6 million, respectively, were transferred to evaluated leasehold costs.







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NOTE 4     LONG-TERM DEBT

The Company’s long-term debt consists of the following:

June 30, 2026
(In thousands)Principal BalancePremium/(Discount)Debt Issuance Costs, NetLong-term Debt, Net
Revolving Credit Facility (1)
$825,000 $— $— $825,000 
Convertible Notes due 2029700,000 8,158 (12,828)695,330 
Senior Notes due 2031500,000 (4,386)(5,813)489,801 
Senior Notes due 2033725,000 — (10,317)714,683 
Total$2,750,000 $3,772 $(28,958)$2,724,814 
December 31, 2025
Principal BalancePremium/(Discount)Debt Issuance Costs, NetLong-term Debt, Net
Revolving Credit Facility (1)
$478,000 $— $— $478,000 
Senior Notes due 202820,165 124 (139)20,150 
Convertible Notes due 2029700,000 9,619 (15,125)694,494 
Senior Notes due 2031500,000 (4,828)(6,399)488,773 
Senior Notes due 2033725,000 — (11,024)713,976 
Total$2,423,165 $4,915 $(32,687)$2,395,393 
________________
(1)Unamortized debt issuance costs related to the Company’s Revolving Credit Facility of $13.2 million and $13.1 million as of June 30, 2026 and December 31, 2025, are recorded in “Other Noncurrent Assets, Net” in the condensed consolidated balance sheets.

Revolving Credit Facility

In November 2025, the Company entered into a Fourth Amended and Restated Credit Agreement (as amended, modified or supplemented through the date of this filing, the “Revolving Credit Facility”) with Wells Fargo Bank, National Association, as administrative agent and collateral agent (“Agent”), and the lenders from time to time party thereto, which amended and restated the Company’s prior revolving credit facility that was entered into in June 2022. The Revolving Credit Facility matures on November 5, 2030.

The Revolving Credit Facility is comprised of revolving loans and letters of credit and is subject to a borrowing base with maximum loan value to be assigned to the proved reserves attributable to the Company and its subsidiaries’ (if any) oil and natural gas properties. In February 2026, the Company completed a wildcard redetermination. In connection therewith, the borrowing base was increased from $1.8 billion to $1.975 billion, and the aggregate elected commitment amount was increased from $1.6 billion to $1.8 billion.

As of June 30, 2026, the borrowing base was $1.975 billion, and the aggregate elected commitment amount was $1.8 billion. The Company’s borrowing availability under the Revolving Credit Facility is set at the lesser of the borrowing base and the elected commitment amount. The borrowing base will be redetermined semiannually on or around April 1 and October 1, with one interim “wildcard” redetermination available to each of the Company and the Agent (acting at the direction of the lenders holding at least two-thirds of commitments and loans outstanding under the Revolving Credit Facility) between scheduled redeterminations. Upon an acquisition of oil and natural gas properties with an aggregate value exceeding 5% of the borrowing base, the Company may request an additional redetermination.

The Company has the option to seek commitments for term loans, which such term loans (if obtained), together with any other then-outstanding principal amount of term loans, are capped at the least of (i) the borrowing base minus the aggregate elected commitment amount, (ii) the aggregate elected commitment amount and (iii) one-third of the sum of (x) the aggregate elected commitment amount plus (y) the then-outstanding principal amount of term loans plus (z) the term loans being established on a pro forma basis. Such term loans are subject to certain other terms of the Revolving Credit Facility.
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At the Company’s option, borrowings under the Revolving Credit Facility shall bear interest at the base rate or SOFR plus an applicable margin. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the Agent bank’s prime rate; (ii) the federal funds effective rate plus 50 basis points; and (iii) the adjusted SOFR rate for a one-month interest period plus 100 basis points. The applicable margin for base rate loans ranges from 75 to 175 basis points, and the applicable margin for SOFR loans ranges from 175 to 275 basis points, in each case depending on the percentage of the borrowing base utilized.

The Revolving Credit Facility contains customary events of default and affirmative and negative covenants. In addition, the Revolving Credit Facility requires that the Company comply with the following financial covenants: (i) the Net Leverage Ratio (as defined in the Revolving Credit Facility) shall be no more than 3.50 to 1.00, and (ii) the Current Ratio (as defined in the Revolving Credit Facility) shall not be less than 1.00 to 1.00. The Company was in compliance with all applicable covenants as of June 30, 2026.

The Company’s obligations under the Revolving Credit Facility are secured by mortgages on not less than 85% of the value of proven reserves associated with the oil and natural gas properties included in the determination of the borrowing base. Additionally, the Company entered into a Guaranty and Collateral Agreement in favor of the Agent for the secured parties, pursuant to which the Company’s obligations under the Revolving Credit Facility are secured by a first priority security interest in substantially all of the Company’s assets.

Senior Notes due 2028

In February 2021, the Company and Wilmington Trust, National Association, as trustee, entered into an indenture (the “2028 Notes Indenture”), pursuant to which the Company issued $550.0 million in aggregate principal amount of 8.125% senior notes due 2028 (the “Original 2028 Notes”). In November 2021, the Company issued an additional $200.0 million aggregate principal amount of 8.125% senior notes due 2028 (together with the Original 2028 Notes, the “Senior Notes due 2028”). The proceeds of the Senior Notes due 2028 were used primarily to refinance existing indebtedness, and for general corporate purposes.

During 2022, the Company repurchased and retired $25.8 million in aggregate principal amount of the Senior Notes due 2028 in open market transactions for a total of $24.9 million in cash, plus accrued interest. During 2023, the Company repurchased and retired $19.1 million in aggregate principal amount of the Senior Notes due 2028 in open market transactions for a total of $18.4 million in cash, plus accrued interest.

In October 2025, upon successfully completing the issuance of its Senior Notes due 2033, the Company repurchased approximately 97.14% of its outstanding Senior Notes due 2028, representing approximately $684.9 million in aggregate principal amount, for a total amount of $699.9 million, inclusive of tender premium and accrued interest due (the “Repurchase Event”). The Repurchase Event resulted in a loss on debt extinguishment of approximately $10.8 million, primarily due to the tender premium of $10.3 million paid in conjunction with the cash tender offer to holders of the Senior Notes due 2028 upon the Repurchase Event.

In March 2026, the Company redeemed all of the outstanding Senior Notes due 2028, in accordance with the terms of the 2028 Notes Indenture, at a Redemption price of 100% (the “Final Redemption Event”). Pursuant to the Final Redemption Event, the Company redeemed approximately $20.2 million in aggregate principal amount, and incurred approximately $14.0 thousand related loss on debt extinguishment.

Convertible Notes due 2029

In October 2022, the Company and Wilmington Trust, National Association, as trustee, entered into an indenture (as supplemented, the “Convertible Notes Indenture”), pursuant to which the Company issued $500.0 million in aggregate principal amount of 3.625% convertible senior notes due 2029 (the “Original Convertible Notes”). In June 2025, the Company issued an additional $200.0 million in aggregate principal amount of 3.625% convertible senior notes due 2029 (the “Additional Convertible Notes” and, together with the Original Convertible Notes, the “Convertible Notes”), at an issue price of 105.597% of the principal amount thereof. The proceeds of the Convertible Notes were used to refinance existing indebtedness and for other general corporate purposes. The Convertible Notes mature on April 15, 2029, unless earlier repurchased, redeemed or converted. The Convertible Notes accrue interest at a rate of 3.625% per annum, payable semi-annually in arrears on April 15 and October 15 of each year.

Before October 16, 2028, noteholders have the right to convert their Convertible Notes only upon the occurrence of certain events. From and after October 16, 2028, noteholders may convert their Convertible Notes at any time at their election until the
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close of business on the second scheduled trading day immediately before the maturity date. The Company will have the right to elect to settle conversions either entirely in cash or in a combination of cash and shares of its common stock. However, upon conversion of any Convertible Notes, the conversion value, which will be determined over a period of 40 trading days, will be paid in cash up to at least the principal amount of the Convertible Notes being converted. The conversion rate and conversion price are subject to customary anti-dilution and other adjustments upon the occurrence of certain events. As of June 30, 2026, the conversion rate was 27.8178 shares of common stock per $1,000 principal amount of Convertible Notes, which represented a conversion price of approximately $35.95 per share of common stock. In addition, if certain corporate events that constitute a “Make-Whole Fundamental Change” (as defined in the Convertible Notes Indenture) occur, then the conversion rate will, in certain circumstances, be increased for a specified period of time.

The Convertible Notes are redeemable, in whole or in part (subject to certain limitations), at the Company’s option at any time, and from time to time, on or before the 40th scheduled trading day immediately before the maturity date, at a cash redemption price equal to the principal amount of the Convertible Notes to be redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date, but only if the last reported sale price per share of the Company’s common stock exceeds 130% of the conversion price on (i) each of at least 20 trading days, whether or not consecutive, during the 30 consecutive trading days ending on, and including, the trading day immediately before the date the Company sends the related redemption notice; and (ii) the trading day immediately before the date the Company sends such notice. In addition, calling any Convertible Note for redemption will constitute a Make-Whole Fundamental Change with respect to that Convertible Note, in which case the conversion rate applicable to the conversion of that Convertible Note will be increased in certain circumstances if it is converted after it is called for redemption.

If certain corporate events that constitute a “Fundamental Change” (as defined in the Convertible Notes Indenture) occur, then, subject to a limited exception for certain cash mergers, noteholders may require the Company to repurchase their Convertible Notes at a cash repurchase price equal to the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest, if any, to, but excluding, the fundamental change repurchase date. The definition of Fundamental Change includes certain business combination transactions involving the Company and certain de-listing events with respect to the Company’s common stock.

The Convertible Notes Indenture contains customary events of default and affirmative and negative covenants. As of June 30, 2026, the Company was in compliance with all applicable covenants.

Capped Call Transactions

In October 2022, in connection with the Original Convertible Notes offering described above, the Company entered into privately negotiated capped call transactions (the “Original Capped Call Transactions”) with certain of the initial purchasers of the Original Convertible Notes and/or their respective affiliates and/or other financial institutions. The Company paid $36.1 million in total consideration to enter into the Original Capped Call Transactions. The Original Capped Call Transactions cover, subject to anti-dilution adjustments substantially similar to those applicable to the conversion rate of the Convertible Notes, the number of shares of common stock initially underlying the Original Convertible Notes. The Original Capped Call Transactions are expected generally to reduce potential dilution to the common stock upon any conversion of Original Convertible Notes and/or offset any potential cash payments the Company is required to make in excess of the principal amount of such converted Original Convertible Notes, as the case may be, with such reduction and/or offset subject to a cap. The cap price of the Original Capped Call Transactions was initially approximately $52.17 per share of common stock, which represents a premium of 75% over the last reported sale price of the common stock of $29.81 per share on October 11, 2022, and is subject to certain customary adjustments under the terms of the Original Capped Call Transactions.

In June 2025, in connection with the Additional Convertible Notes offering described above, the Company entered into new privately negotiated capped call transactions (the “Additional Capped Call Transactions”). The Additional Capped Call Transactions cover, subject to anti-dilution adjustments substantially similar to those applicable to the conversion rate of the Convertible Notes, the number of shares of common stock initially underlying the Additional Convertible Notes. The Additional Capped Call Transactions are expected generally to reduce potential dilution to the common stock upon any conversion of Additional Convertible Notes and/or offset any cash payments the Company is required to make in excess of the principal amount of such converted Additional Convertible Notes, as the case may be, with such reduction and/or offset subject to a cap. The cap price of the Additional Capped Call Transactions was initially approximately $50.61 per share of common stock, which represents a premium of approximately 63% over the last reported sale price of the common stock of $31.15 per share on June 12, 2025, and is subject to certain customary adjustments under the terms of the Additional Capped Call Transactions.

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As of June 30, 2026, the cap price of the Capped Call Transactions was approximately $49.34 per share of common stock for both the Original Capped Call Transactions and the Additional Capped Call Transactions.

Senior Notes due 2031

In May 2023, the Company and Wilmington Trust, National Association, as trustee, entered into an indenture (the “2031 Notes Indenture”), pursuant to which the Company issued $500.0 million in aggregate principal amount of the Company’s 8.750% senior notes due 2031 (the “Senior Notes due 2031”). The proceeds of the Senior Notes due 2031 were used primarily to refinance existing indebtedness, and for general corporate purposes.

The Senior Notes due 2031 will mature on June 15, 2031. Interest is payable semi-annually in arrears on each June 15 and December 15, to holders of record on the June 1 and December 1 immediately preceding the related interest payment date, at a rate of 8.750% per annum.

The Company may redeem all or a part of the Senior Notes due 2031 at redemption prices (expressed as percentages of principal amount) equal to 104.375% for the twelve-month period beginning on June 15, 2026, 102.188% for the twelve-month period beginning on June 15, 2027, and 100% beginning on June 15, 2028, plus accrued and unpaid interest to, but excluding, the redemption date.

If a Change of Control Triggering Event (as defined in the 2031 Notes Indenture) occurs, each holder of Senior Notes due 2031 may require the Company to repurchase all or any part of that holder’s Senior Notes due 2031 for cash at a price equal to 101% of the aggregate principal amount of the Senior Notes due 2031 repurchased, plus any accrued and unpaid interest on the Senior Notes due 2031 repurchased to, but excluding, the date of purchase (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date on or prior to the date of purchase).

The 2031 Notes Indenture contains customary event of default and certain affirmative and negative covenants. As of June 30, 2026, the Company was in compliance with all applicable covenants.

Senior Notes due 2033

In October 2025, the Company and Wilmington Trust, National Association, as trustee, entered into an indenture (the “2033 Notes Indenture”), pursuant to which the Company issued $725.0 million in aggregate principal amount of the Company’s 7.875% senior notes due 2033 (the “Senior Notes due 2033”). The proceeds of the Senior Notes due 2033 were used primarily to fund the purchase of the Senior Notes due 2028 validly tendered and accepted for purchase pursuant to the Tender Offer, and for general corporate purposes.

The Senior Notes due 2033 will mature on October 15, 2033. Interest is payable semi-annually in arrears on each April 15 and October 15, to holders of record on the April 1 and October 1 immediately preceding the related interest payment date, at a rate of 7.875% per annum. Prior to October 15, 2028, the Company may redeem up to 40% of the aggregate principal amount of Senior Notes due 2033, upon not less than 10 or more than 60 days’ notice, at a redemption price of 107.875% of the principal amount of the Senior Notes due 2033 redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date), in an amount not greater than the net cash proceeds of one or more equity offerings by the Company, provided that (i) at least 60% of the aggregate principal amount of Senior Notes due 2033 issued under the 2033 Notes Indenture (including any Additional Notes (as defined in the 2033 Notes Indenture) but excluding the Senior Notes due 2033 held by the Company and its Subsidiaries (as defined in the 2033 Notes Indenture)) remains outstanding immediately after the occurrence of such redemption (unless all Senior Notes due 2033 are redeemed substantially concurrently) and (ii) the redemption occurs within 180 days of the date of the closing of each such equity offering. In addition, prior to October 15, 2028, the Company may redeem all or a part of the Senior Notes due 2033, on any one or more occasions, upon not less than 10 or more than 60 days’ notice, at a redemption price equal to 100% of the principal amount of the Senior Notes due 2033 redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to, but excluding, the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date).

On or after October 15, 2028 the Company may redeem all or a part of the Senior Notes due 2033 at redemption prices (expressed as percentages of principal amount) equal to 103.938% for the twelve-month period beginning on October 15, 2028, 101.969% for the twelve-month period beginning on October 15, 2029, and 100% beginning on October 15, 2030, plus accrued and unpaid interest to, but excluding, the redemption date.
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If a Change of Control Triggering Event (as defined in the 2033 Notes Indenture) occurs, each holder of Senior Notes due 2033 may require the Company to repurchase all or any part of that holder’s Senior Notes due 2033 for cash at a price equal to 101% of the aggregate principal amount of the Senior Notes due 2033 repurchased, plus any accrued and unpaid interest on the Senior Notes due 2033 repurchased to, but excluding, the date of purchase (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date on or prior to the date of purchase).

The 2033 Notes Indenture contains customary event of default and certain affirmative and negative covenants. As of June 30, 2026, the Company was in compliance with all applicable covenants.


NOTE 5    COMMON AND PREFERRED STOCK

Common Stock

On May 23, 2024, the Company filed an amendment to its certificate of incorporation, which was effective upon filing, to increase the number of authorized shares of common stock, par value $0.001 per share, from 135,000,000 to 270,000,000, as approved by the Company’s stockholders at the 2024 Annual Meeting of Stockholders on May 23, 2024. As of June 30, 2026, the Company had 106,549,128 shares of common stock issued and outstanding.

Preferred Stock

The Company is authorized to issue up to 5,000,000 shares of preferred stock, par value $0.001 per share, with such designations, voting and other rights and preferences as may be determined from time to time by the Company’s board of directors. As of June 30, 2026, the Company had zero shares of preferred stock issued and outstanding.

2026 Activity

Common Stock

During the six months ended June 30, 2026, 104,298 shares of common stock were surrendered by certain employees of the Company to cover tax obligations in connection with the vesting of their restricted stock awards. The total value of these shares surrendered, based on the market prices on the dates the shares were surrendered, was approximately $2.8 million.

During the six months ended June 30, 2026, 4,192 shares of the Company’s stock, previously issued as stock-based compensation, were forfeited by former employees of the Company upon separation.

During the six months ended June 30, 2026, the Company issued 362,804 shares of its common stock to executive officers, employees, and directors as stock-based compensation (see Note 6).

During the six months ended June 30, 2026, the Company issued 8,288,289 shares of its common stock pursuant to a public offering of common stock.

During the six months ended June 30, 2026, the Company issued 3,689,413 shares of its common stock pursuant to the Duvernay Acquisition (see Note 3).

Dividends

In February 2026, the Company’s board of directors declared a cash dividend on the Company’s common stock in the amount of $0.45 per share. The dividend was paid on April 30, 2026, to stockholders of record as of the close of business on March 30, 2026.

In May 2026, the Company’s board of directors declared a cash dividend on the Company’s common stock in the amount of $0.45 per share. The dividend was paid on July 31, 2026, to stockholders of record as of the close of business on June 29, 2026.

In August 2026, the Company’s board of directors declared a cash dividend on the Company’s common stock in the amount of $0.45 per share. The dividend is payable on October 30, 2026, to stockholders of record as of the close of business on September 29, 2026.


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Stock Repurchase Program

In May 2022, the Company’s board of directors approved a stock repurchase program to acquire up to $150.0 million of the Company’s outstanding common stock.  In July 2024, the Company’s board of directors terminated the prior stock repurchase program, which was substantially depleted, and approved a new stock repurchase program to acquire up to $150.0 million of the Company’s outstanding common stock. In March 2025, the Company’s board of directors approved a $100.0 million increase to the authorization under this stock repurchase program. In July 2026, the Company’s board of directors approved an additional $150.0 million increase to the authorization under this stock repurchase program. The stock repurchase program allows the Company to repurchase its shares from time to time in the open market in block transactions and in negotiated transactions.

During the six months ended June 30, 2026, the Company repurchased 2,948,447 shares of its common stock for $60.1 million at an average price of $20.37 per share, inclusive of commissions, under the stock repurchase program. In connection therewith, the Company paid $50.0 million on or before June 30, 2026, and paid the remaining balance subsequent to June 30, 2026.

As of June 30, 2026, the Company had $93.2 million available under the stock repurchase program, and this amount was increased to $243.2 million with the increased authorization approved in July 2026.

The Company’s accounting policy upon the repurchase of shares is to deduct its par value from common stock and to reflect any excess of cost over par value as a deduction from Additional Paid-in Capital. All repurchased shares are included in the Company’s pool of authorized but unissued shares.


NOTE 6     STOCK-BASED COMPENSATION

Stock-Based Compensation

The Company maintains the Amended and Restated 2018 Equity Incentive Plan (the “2018 Plan”) for the purpose of making equity-based awards to employees, directors and other eligible persons. As of June 30, 2026, there were 2,239,598 shares available for future awards or settlement of awards under the 2018 Plan.

The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company’s stock-based compensation awards are accounted for as equity instruments and are included in the “General and administrative expenses” line item in the condensed consolidated statements of operations. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included in the “Oil and natural gas properties” line item in the condensed consolidated balance sheets.

Issuances made pursuant to the 2018 Plan are summarized as follows:

The Company issues share-based awards in the form of restricted stock awards (“RSAs”), restricted stock units (“RSUs”) and share appreciation awards (“SARs”), subject to various vesting conditions, as compensation to executive officers, employees and directors of the Company. Typically, RSAs issued to employees and executive officers contain a service condition only and generally vest over three or four years. Typically, RSUs and SARs contain both a service and market condition. Market conditions can be the Company’s absolute total shareholder return (“TSR”), the Company’s relative TSR ranking among its peer companies or the Company’s market capitalization growth measured over a defined performance period. Grantees’ continued employment through the end of the performance period is required for such RSUs and SARs to vest. RSAs issued to directors generally vest either immediately or over one year, subject to continued service and provided that any performance and/or market conditions are also met.

For awards subject to service and/or performance vesting conditions, the grant date fair value is established based on the closing price of the Company’s common stock on such date. Stock-based compensation expense for awards subject to only service conditions is recognized on a straight-line basis over the service period. Stock-based compensation expense for awards subject to both service and performance conditions are recognized on a graded basis if it is probable that the performance condition will be achieved. The Company accounts for forfeitures of awards granted under these plans as they occur in determining stock-based compensation expense.

For awards subject to a market condition, the grant date fair value is estimated using a Monte Carlo valuation model. The Company recognizes stock-based compensation expense for awards subject to market-based vesting conditions regardless of
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whether the market conditions are achieved or not, and stock-based compensation expense for any such awards is reversed only when the implied service requirement is not met. The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility is calculated based on the historical volatility and implied volatility of the Company’s common stock, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with the three-year vesting period.

Service-Based RSAs

The following table reflects the outstanding service-based RSAs and activity related thereto for the six months ended June 30, 2026:

Service-based Awards
Number of SharesWeighted-average Grant Date Fair Value
Outstanding at December 31, 2025402,340 $33.58 
Shares granted304,270 26.88 
Shares forfeited(4,192)28.61 
Shares vested(199,780)31.57 
Outstanding at June 30, 2026502,638 $30.36 

At June 30, 2026, there was $12.8 million of total unrecognized compensation expense related to unvested RSAs. That cost is expected to be recognized over a weighted average period of 1.11 years. For the six months ended June 30, 2026 and 2025, the total fair value of the Company’s restricted stock awards vested was $5.3 million and $4.1 million, respectively. For the six months ended June 30, 2026, the compensation expenses associated with these awards were $4.1 million.

Performance Equity Awards

The following table reflects the outstanding RSUs that are subject to market conditions linked to TSR (“TSR Awards”) and activity related thereto for the six months ended June 30, 2026:

TSR Awards
Number of UnitsWeighted-average Grant
 Date Fair Value
Outstanding at December 31, 2025511,919 $31.40 
Units granted (1)
305,498 28.65 
Units forfeited (2)
(45,239)44.49 
Units vested (3)
(38,471)44.49 
Outstanding at June 30, 2026733,707 $28.76 
________________
(1)Represents performance equity awards with a performance period ending on December 31, 2028
(2)Represents RSUs forfeited due to certain market performance metrics not being met as of the evaluation date
(3)The Company issued 20,063 additional shares in addition to the 38,471 awards vested, since the measured performance metrics exceeded the target performance metrics.

For the six months ended June 30, 2026, the compensation expenses associated with these awards were $3.4 million. As of June 30, 2026, the unrecognized compensation expenses for these awards were $12.3 million, which will be amortized over the remaining performance period.

In December 2023, the Company granted performance equity awards, in the form of SARs. The final payout (if any) will be a dollar amount, which may be settled in cash, shares or a combination of both at the Company’s option. The Company plans to settle the SARs that were granted in 2023 with shares. For the six months ended June 30, 2026, the compensation expenses
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associated with these awards were $0.7 million. As of June 30, 2026, the unrecognized compensation expenses for these awards were $2.2 million, which will be amortized over the remaining performance period.

The Company used Monte Carlo simulation models, described above, to estimate (i) the fair value of the TSR Awards that were granted in 2024, 2025 and 2026 based on the expected outcome of the Company’s absolute TSR as well as TSR relative to the defined peer group and (ii) the fair value of the SARs that were granted in 2023 based on the expected outcome of the Company’s market capitalization appreciation rate. The Company used the following key assumptions in its Monte Carlo simulation models: (a) risk-free rates ranging from 1.7% to 4.2%, (b) dividend yield ranging from nil to 4.3%, and (c) expected volatility ranging from 56.4% to 72.3%.


NOTE 7     COMMITMENTS & CONTINGENCIES

The Company is engaged in various proceedings incidental to the normal course of business. Due to their nature, such legal proceedings involve inherent uncertainties, including, but not limited to, court rulings, negotiations between affected parties and governmental intervention.  Based upon the information available to the Company and discussions with legal counsel, it is the Company’s opinion that the outcome of the various legal actions and claims that are incidental to its business will not have a material impact on the Company’s financial position, results of operations or cash flows.  Such matters, however, are subject to many uncertainties, and the outcome of any matter is not predictable with assurance.


NOTE 8     INCOME TAXES

Income tax expense or benefits during interim periods is based on applying an estimated annual effective income tax rate to year-to-date income, plus any significant unusual or infrequently occurring items which are recorded in the interim period. The provision for income taxes or benefits for the three and six months ended June 30, 2026 and 2025 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax income (loss) primarily due to the non-deductibility of permanent items, state and foreign income taxes, and discrete items during the three and six months ended June 30, 2026 and 2025.

In assessing the realizability of deferred tax assets (“DTAs”), management considers whether it is more likely than not that some portion, or all, of the Company’s DTAs will not be realized. In making such determination, the Company considers all available positive and negative evidence, including (i) its earnings history, (ii) its ability to recover net operating loss carry-forwards, (iii) the projected future income and results of operations, and (iv) its ability to use tax planning strategies. If the Company concludes that it is more likely than not that some portion, or all, of its DTAs will not be realized, the tax asset is reduced by a valuation allowance. The Company assesses the appropriateness of its valuation allowance on a quarterly basis.

The One Big Beautiful Bill (“OBBB”), which was enacted in July 2025, primarily makes permanent the tax implications of the Tax Cuts and Jobs Act from 2017. The income tax provisions include the reinstatement of the 100% additional first-year “bonus” depreciation deduction, updates to the calculation of disallowed interest, and updates to the determination of whether the Company is subject to the Corporate Alternative Minimum Tax.

In the three months ended June 30, 2026, the Company recorded an income tax expense of approximately $74.0 million, primarily from U.S. domestic tax expenses of $82.6 million, partially offset by $8.6 million income tax benefits derived from foreign operations. In the six months ended June 30, 2026, the Company recorded an income tax benefit of approximately $99.1 million, primarily from U.S. domestic income tax benefits of $90.5 million and foreign income tax benefits of $8.6 million. The effective tax rates for the three and six months ended June 30, 2026 were 23.8% and 25.7%, respectively.

The Company had an income tax expense of $32.2 million and $79.0 million for the three and six months ended June 30, 2025, respectively. The Company did not have any foreign income tax expenses or tax benefits in the three and six months ended June 30, 2025. The effective tax rates for the three and six months ended June 30, 2025 were 24.4% and 24.9%, respectively.


NOTE 9     FAIR VALUE

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date.  Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize
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the use of unobservable inputs.  The Company uses a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value which are the following:

Level 1 - Quoted prices in active markets for identical assets or liabilities.

Level 2 - Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.

Level 3 - Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.

Financial Assets and Liabilities

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2026 and December 31, 2025:

Fair Value Measurements at
June 30, 2026 Using
(In thousands)
(Level 1)
(Level 2)
(Level 3)		Effect of Counterparty NettingTotal
Commodity Derivatives – Current Assets$— $110,343 $— $(81,392)$28,951 
Commodity Derivatives – Noncurrent Assets— 45,443 — (36,491)8,952 
Commodity Derivatives – Current Liabilities— (106,433)— 81,392 (25,041)
Commodity Derivatives – Noncurrent Liabilities— (292,359)— 36,491 (255,868)
Interest Rate Derivatives – Current Assets— 1,963 — — 1,963 
Interest Rate Derivatives – Noncurrent Assets— 774 — — 774 
Contingent Consideration – Noncurrent Liabilities— (6,614)— — (6,614)
Total$— $(246,883)$— $— $(246,883)

Fair Value Measurements at
December 31, 2025 Using
 (In thousands)
(Level 1)
(Level 2)
(Level 3)		Effect of Counterparty NettingTotal
Commodity Derivatives – Current Assets$— $224,726 $— $(58,100)$166,626 
Commodity Derivatives – Noncurrent Assets— 30,986 — (27,950)3,036 
Commodity Derivatives – Current Liabilities— (58,100)— 58,100 — 
Commodity Derivatives – Noncurrent Liabilities— (75,697)— 27,950 (47,747)
Interest Rate Derivatives – Current Assets— 52 — — 52 
Interest Rate Derivatives – Noncurrent Liabilities— (355)— — (355)
Total$— $121,612 $— $— $121,612 

Commodity Derivatives. The Level 2 instruments presented in the tables above include commodity derivative instruments (see Note 10).  The fair value of the Company’s commodity derivative instruments is determined based upon future prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs.  The Company’s and the counterparties’ nonperformance risk is evaluated.  The fair value of commodity derivative contracts is
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reflected in the condensed consolidated balance sheets.  The current derivative asset and liability amounts represent the fair values expected to be settled in the subsequent twelve months.

Interest Rate Derivatives. The Level 2 instruments presented in the tables above include interest rate derivative instruments (see Note 10).  The fair value of the Company’s interest rate derivative instruments is determined based upon contracted notional amounts, active market-quoted interest yield curves, and time to maturity, among other things. Counterparty statements are utilized to determine the value of the interest rate derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The Company’s and the counterparties’ nonperformance risk is evaluated.  The fair value of interest rate derivative contracts is reflected in the condensed consolidated balance sheets.  The current interest rate derivative asset balances represent the fair values expected to be settled in the subsequent twelve months.

Contingent Consideration. The Level 2 instruments presented in the tables above include contingent consideration liabilities (see Note 3). The fair value of the Company's contingent consideration liability is determined using a Monte Carlo simulation model. The significant inputs used in the valuation include (i) the forward NYMEX WTI oil price curve, (ii) NYMEX WTI volatility and (iii) risk-free rates based on U.S. Treasury rates, which are observable in the marketplace or can be derived from observable market data. These inputs are reviewed and corroborated using various methodologies and significant observable inputs. The fair value of the contingent consideration liability is reflected in the condensed consolidated balance sheets. Changes in the fair value of this liability are included in other income (expense) in the Company's condensed consolidated statements of operations.

Fair Value of Other Financial Instruments

The carrying amounts of cash equivalents, receivables and payables approximate fair value due to the highly liquid or short-term nature of these instruments.

Long-term debt is not presented at fair value in the condensed consolidated balance sheets, as it is recorded at carrying value, net of unamortized debt issuance costs and unamortized premium (see Note 4).  The fair value of the Company’s Convertible Notes due 2029, Senior Notes due 2031 and Senior Notes due 2033 was $670.4 million, $514.4 million and $718.7 million, respectively, at June 30, 2026. These fair values are based on market quotes that represent Level 2 inputs.

There is no active market for the Revolving Credit Facility. The recorded value of the Revolving Credit Facility approximates its fair value because of its floating rate structure based on the SOFR spread, secured interest, and the Company’s borrowing base utilization. The fair value measurement for the Revolving Credit Facility represents Level 2 inputs.

Non-Financial Assets and Liabilities

The Company estimates asset retirement obligations pursuant to the relevant accounting standards.  The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and natural gas properties.  Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligations liability is deemed to use Level 3 inputs.  Asset retirement obligations incurred and acquired during the six months ended June 30, 2026 and 2025 were approximately $2.5 million and $2.2 million, respectively.

For all transactions accounted for as business combinations, the Company uses the acquisition method of accounting. In those instances, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction costs associated with the acquisitions are expensed as incurred. The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair value of oil and natural gas properties. The fair value of these properties is measured using a discounted cash flow model that converts future cash flows to a single discounted amount. The assumptions are unobservable inputs and represent Level 3 inputs under the fair value hierarchy. Key inputs include: (i) estimates of future production volumes, (ii) future commodity prices (adjusted for basis differentials), including WTI oil pricing ranging from $63.70 to $86.31 per barrel and Henry Hub gas pricing ranging from $1.37 to $3.83 per MMBtu, (iii) estimates of lease operating, development and abandonment costs, (iv) risk adjustment factors applied to proved reserves, ranging from 90% to 100%, and to unproved reserves, ranging from 60% to 75%, and (v) the application of a discount rate, ranging from 9.5% to 10%.

Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value.  There were no transfers of financial assets or liabilities between Level 1, Level 2 or Level 3 inputs for the six months ended June 30, 2026.
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NOTE 10     DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT

The Company utilizes various commodity price derivative instruments to (i) reduce the effects of volatility in price changes on the crude oil and natural gas commodities it produces and sells, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure it can execute at least a portion of its capital spending. In addition, from time to time the Company utilizes interest rate swaps to mitigate exposure to changes in interest rates on the Company’s variable-rate indebtedness.

All derivative instruments are recorded in the Company’s condensed consolidated balance sheets as either assets or liabilities measured at their fair value (see Note 9).  The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes.  If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in the fair value are recognized in the Company’s condensed consolidated statements of operations as a gain or loss on derivative instruments.  Mark-to-market gains and losses represent changes in fair values of derivative instruments that have not been settled.  The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty.  These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.

The Company has master netting agreements on individual derivative instruments with certain counterparties and therefore the current asset and liability are netted in the condensed consolidated balance sheets and the non-current asset and liability are netted in the condensed consolidated balance sheets for contracts with these counterparties.

Commodity Derivative Instruments

The following table presents settlements on commodity derivative instruments and unsettled gains and losses on open commodity derivative instruments for the periods presented which is recorded in the revenue section of our condensed consolidated statements of operations:

Three Months Ended
June 30,		Six Months Ended
June 30,
(In thousands)2026202520262025
Cash Received (Paid) on Settled Commodity Derivatives, Net$(86,320)$60,931 $(103,953)$72,993 
Non-Cash Mark-to-Market Gain (Loss) on Derivatives, Net156,502 67,888 (364,921)77,588 
Gain (Loss) on Commodity Derivatives, Net$70,182 $128,819 $(468,874)$150,581 


The following table summarizes open commodity derivative positions as of June 30, 2026, for commodity derivatives that were entered into through June 30, 2026, for the settlement periods presented:
28
20262027202820292030
Oil:
 NYMEX WTI - Swaps:
Volume (Bbl) 3,173,134 2,414,750 183,000 182,500 — 
Weighted Average Price ($/Bbl)$67.58 $69.90 $70.04 $70.04 $— 
NYMEX WTI - Short Swaptions(1):
Volume (Bbl) 920,000 8,034,900 17,101,350 14,715,250 3,438,300 
Weighted Average Price ($/Bbl)$65.00 $68.76 $65.03 $66.94 $65.24 
NYMEX WTI - Long Swaptions(1):
Volume (Bbl)920,000 1,620,500 — — — 
Weighted Average Price ($/Bbl)$65.00 $64.45 $— $— $— 
NYMEX WTI - Roll Swaps:
Volume (Bbl)1,836,000 — — — — 
Weighted Average Price ($/Bbl)$4.13 $— $— $— $— 
Argus WTI Midland CMA Diff - Basis Swaps:
Volume (Bbl)4,324,000 4,927,500 732,000 — — 
Weighted Average Price ($/Bbl)$0.91 $0.82 $0.79 $— $— 
Argus WTI Midland TMA Diff - Basis Swaps:
Volume (Bbl)720,858 668,000 — — — 
Weighted Average Price ($/Bbl)$1.16 $1.49 $— $— $— 
NYMEX WTI - Short Call Options(1):
Volume (Bbl)2,141,944 5,739,265 4,609,810 1,719,150 — 
Weighted Average Price ($/Bbl)$76.96 $80.51 $77.32 $85.00 $— 
NYMEX WTI - Long Call Options(1):
Volume (Bbl)717,784 405,515 — — — 
Weighted Average Price ($/Bbl)$66.43 $75.00 $— $— $— 
ICE Brent - Call Options (1):
Volume (Bbl)— — 316,590 — — 
Weighted Average Price ($/Bbl)$— $— $80.00 $— $— 
NYMEX WTI CMA - Two Way Collars:
Collar Put Volume (Bbl)3,116,326 1,360,000 — — — 
Collar Call Volume (Bbl)4,495,174 1,360,000 — — — 
Weighted Average Floor Price ($/Bbl)$62.65 $63.05 $— $— $— 
Weighted Average Ceiling Price ($/Bbl)$71.43 $75.18 $— $— $— 
NYMEX WTI - Three Way Collars:
Collar Sub Floor Volume (Bbl)414,000 491,250 — — — 
Collar Floor Volume (Bbl)414,000 491,250 — — — 
Collar Ceiling Volume (Bbl)414,000 491,250 — — — 
Weighted Average Sub Floor Price ($/Bbl)$47.22 $45.00 $— $— $— 
Weighted Average Floor Price ($/Bbl)$60.00 $58.85 $— $— $— 
Weighted Average Ceiling Price ($/Bbl)$71.56 $72.39 $— $— $— 
29
20262027202820292030
Natural Gas:
NYMEX Henry Hub - Swaps:
Volume (MMBtu) 22,245,000 29,320,000 7,610,000 — — 
Weighted Average Price ($/MMBtu)$4.13 $4.06 $3.85 $— $— 
Waha Gas Daily - Swaps:
Volume (MMBtu)915,000 1,825,000 155,000 — — 
Weighted Average Price ($/MMBtu)$3.20 $2.98 $2.96 $— $— 
NYMEX Henry Hub - Short Swaptions (1):
Volume (MMBtu) 920,000 35,945,000 37,530,000 30,280,000 — 
Weighted Average Price ($/MMBtu) $3.89 $4.30 $4.07 $3.83 $— 
NYMEX Henry Hub - Long Swaptions (1):
Volume (MMBtu)— — 7,320,000 — — 
Weighted Average Price ($/MMBtu)$— $— $4.00 $— $— 
Waha - Basis Swaps:
Volume (MMBtu) 9,200,000 7,300,000 — — — 
Weighted Average Price ($/MMBtu)$(0.84)$(0.87)$— $— $— 
Waha Gas Daily Average vs Henry Hub Last Day
Volume (MMBtu)— 10,020,000 930,000 — — 
Weighted Average Price ($/MMBtu)$— $(1.01)$(1.01)$— $— 
Waha Index - Swaps
Volume (MMBtu)9,150,000 4,890,000 310,000 — — 
Weighted Average Price ($/MMBtu)$— $(0.01)$(0.02)$— $— 
TETCO M2 - Basis - Swaps:
Volume (MMBtu)14,720,000 27,530,000 8,870,000 7,300,000 — 
Weighted Average Price ($/MMBtu)$(1.14)$(0.87)$(0.86)$(0.75)$— 
TCO Basis - Swaps:
Volume (MMBtu)— — — — — 
Weighted Average Price ($/MMBtu)$— $— $— $— $— 
REX Zone 3 Basis - Swap:
Volume (MMBtu)8,280,000 20,075,000 7,320,000 3,650,000 — 
Weighted Average Price ($/MMBtu)(0.26)(0.21)(0.18)(0.16)— 
NYMEX Henry Hub - Short Call Options (1):
Volume (MMBtu)920,000 2,325,000 27,450,000 26,755,000 18,370,000 
Weighted Average Price ($/MMBtu)$5.00 $5.23 $5.27 $5.62 $5.50 
NYMEX Henry Hub - Long Call Options (1):
Volume (MMBtu)— — — — — 
Weighted Average Price ($/MMBtu)— — — — — 
NYMEX Henry Hub - Two Way Collars:
Collar Put Volume (MMBtu)27,654,348 23,200,000 3,660,000 3,340,000 — 
Collar Call Volume (MMBtu)27,654,348 23,200,000 3,660,000 3,340,000 — 
Weighted Average Floor Price ($/MMBtu)$3.46 $3.45 $3.50 $3.50 $— 
Weighted Average Ceiling Price ($/MMBtu)$4.97 $4.53 $4.15 $3.88 $— 
30
20262027202820292030
NGL:
OPIS - Swaps:
Volume (Bbl)177,100 234,800 — — — 
Weighted Average Price ($/Bbl)$33.16 $31.19 $— $— $— 
______________
(1)Swaptions are crude oil and natural gas derivative contracts that give counterparties the option to extend certain derivative contracts for additional periods. Call Options are crude oil and natural gas derivative contracts sold by the Company that give counterparties the option to exercise certain derivative contracts. The volumes and prices reflected as Swaptions and Call Options in this table (i) will only be effective if the options are exercised by the applicable counterparties and (ii) are shown in the periods in which such volumes would be settled, in the event that the applicable counterparties exercise their options.

Interest Rate Derivative Instruments

At times, the Company uses interest rate swaps to effectively convert a portion of its variable rate indebtedness to fixed rate indebtedness. The settlement of derivative instruments is recognized as a component of interest expense in the condensed consolidated statements of operations. The mark-to-market component of these derivative instruments is recognized in gain (loss) on unsettled interest rate derivatives, net in the condensed consolidated statements of operations. The following table summarizes our open interest rate derivative contracts as of June 30, 2026.

Fixed Rate Swap Agreements (in thousands)
Swaps
Contract PeriodNotional AmountFixed RateFloating Benchmark
October 1, 2024 - October 1, 2026$25,000 3.423 %USD-SOFR CME
May 1, 2025 - May 1, 2027$50,000 3.423 %USD-SOFR CME
September 19, 2025 - October 1, 2027$50,000 3.300 %USD-SOFR CME
October 20, 2025 - November 1, 2027$100,000 3.187 %USD-SOFR CME
December 10, 2025 - December 1, 2027$50,000 3.393 %USD-SOFR CME
December 10, 2025 - December 1, 2028$50,000 3.392 %USD-SOFR CME

Other Information Regarding Derivative Instruments

The following table sets forth the amounts, on a gross basis, and classification of the Company’s outstanding derivative financial instruments at June 30, 2026 and December 31, 2025, respectively. Certain amounts may be presented on a net basis in the condensed consolidated financial statements when such amounts are with the same counterparty and subject to a master netting arrangement.

31
(In thousands)
Type of CommodityBalance Sheet LocationJune 30, 2026 Estimated Fair ValueDecember 31, 2025 Estimated Fair Value
Derivative Assets:
Commodity Price Swap ContractsCurrent Assets$41,301 $103,943 
Commodity Basis Swap ContractsCurrent Assets20,286 41,142 
Commodity Price Swaptions ContractsCurrent Assets12,127 1,428 
Commodity Price Collar ContractsCurrent Assets31,312 71,571 
Commodity Price Call Option ContractsCurrent Assets4,916 413 
Commodity Price Index Swap ContractsCurrent Assets401 6,230 
Interest Rate Swap ContractsCurrent Assets1,963 52 
Commodity Price Swap ContractsNoncurrent Assets16,357 12,975 
Commodity Basis Swap ContractsNoncurrent Assets12,356 5,330 
Commodity Price Swaptions ContractsNoncurrent Assets3,148 — 
Commodity Price Collar ContractsNoncurrent Assets12,687 12,680 
Commodity Price Call Option ContractsNoncurrent Assets895 — 
Commodity Price Index Swap ContractsNoncurrent Assets— — 
Interest Rate Swap ContractsNoncurrent Assets774 — 
Total Derivative Assets$158,523 $255,764 
Derivative Liabilities:
Commodity Price Swap ContractsCurrent Liabilities$(9,197)$(4,596)
Commodity Basis Swap ContractsCurrent Liabilities(10,320)(6,137)
Commodity Price Swaptions ContractsCurrent Liabilities(37,560)(25,987)
Commodity Price Collar ContractsCurrent Liabilities(29,529)(17,229)
Commodity Price Call Option ContractsCurrent Liabilities(14,853)(3,973)
Commodity Price Index Swap ContractsCurrent Liabilities(4,974)(178)
Interest Rate Swap ContractsCurrent Liabilities— — 
Commodity Price Swap ContractsNoncurrent Liabilities(2,485)(4,097)
Commodity Basis Swap ContractsNoncurrent Liabilities(5,841)(10,177)
Commodity Price Swaptions ContractsNoncurrent Liabilities(222,279)(25,111)
Commodity Price Collar ContractsNoncurrent Liabilities(8,794)(11,332)
Commodity Price Call Option ContractsNoncurrent Liabilities(52,869)(24,627)
Commodity Price Index Swap ContractsNoncurrent Liabilities(91)(354)
Interest Rate Swap ContractsNoncurrent Liabilities— (355)
Total Derivative Liabilities$(398,792)$(134,152)

The use of derivative transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions.  When the Company has netting arrangements with its counterparties that provide for offsetting payables against receivables from separate derivative instruments these assets and liabilities are netted in the condensed consolidated balance sheets.  The tables presented below provide a reconciliation between the gross assets and liabilities and the amounts reflected in the condensed consolidated balance sheets.  The amounts presented exclude derivative settlement receivables and payables as of the condensed consolidated balance sheet dates.

32
Estimated Fair Value at June 30, 2026
(In thousands)Gross Amounts of
Recognized Assets (Liabilities)		Gross Amounts Offset
on the Balance Sheet		Net Amounts of Assets (Liabilities) Presented on the Balance Sheet
Offsetting of Derivative Assets:
Current Assets$112,306 $(81,392)$30,914 
Non-Current Assets46,217 $(36,491)9,726 
Total Derivative Assets$158,523 $(117,883)$40,640 
Offsetting of Derivative Liabilities:
Current Liabilities$(106,433)$81,392 $(25,041)
Non-Current Liabilities(292,359)36,491 (255,868)
Total Derivative Liabilities$(398,792)$117,883 $(280,909)

Estimated Fair Value at December 31, 2025
 (In thousands)Gross Amounts of
Recognized Assets (Liabilities)		Gross Amounts Offset
on the Balance Sheet		Net Amounts of Assets (Liabilities) Presented on the Balance Sheet
Offsetting of Derivative Assets:
Current Assets$224,778 $(58,100)$166,678 
Non-Current Assets30,986 $(27,950)3,036 
Total Derivative Assets$255,764 $(86,050)$169,714 
Offsetting of Derivative Liabilities:
Current Liabilities$(58,100)$58,100 $— 
Non-Current Liabilities(76,052)27,950 (48,102)
Total Derivative Liabilities$(134,152)$86,050 $(48,102)

All of the Company’s outstanding derivative instruments are covered by International Swap Dealers Association Master Agreements (“ISDAs”) entered into with parties that are also lenders under the Company’s Revolving Credit Facility.  The Company’s obligations under the derivative instruments are secured pursuant to the Revolving Credit Facility, and no additional collateral had been posted by the Company as of June 30, 2026.  The ISDAs may provide that as a result of certain circumstances, such as cross-defaults, a counterparty may require all outstanding derivative instruments under an ISDA to be settled immediately.  See Note 9 for the aggregate fair value of all derivative instruments at June 30, 2026 and December 31, 2025.

33
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Cautionary Statement Concerning Forward-Looking Statements

We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect our company and to take advantage of the “safe harbor” protection for forward-looking statements that applicable federal securities law affords.

From time to time, our management or persons acting on our behalf may make forward-looking statements to inform existing and potential security holders about our company. All statements other than statements of historical facts included in this report regarding our financial position, business strategy, plans and objectives of management for future operations, industry conditions, indebtedness covenant compliance, capital expenditures, production, cash flow, borrowing base under our Revolving Credit Facility, our intention or ability to pay or increase dividends on our capital stock, and impairment are forward-looking statements.  When used in this report, 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, sales, market size, collaborations, cash flows, 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 our company’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 our current properties and properties pending acquisition;
•infrastructure constraints and related factors affecting our properties;
•general economic or industry conditions, whether internationally, nationally and/or in the communities in which our company conducts business, including any future economic downturn, cost inflation, 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;
•our 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 our acquisition transactions, integration and benefits of property acquisitions, or the effects of such acquisitions on our company’s cash position and levels of indebtedness;
•changes in our reserves estimates or the value thereof;
•disruption to our company’s business due to acquisitions and other significant transactions;
•changes in local, state, and federal laws, regulations or policies that may affect our business or our 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), and similar changes in foreign jurisdictions where we currently or in the future may operate, including Canada;
•conditions of the securities markets;
•exchange rate fluctuations;
•risks associated with our Convertible Notes, including the potential impact that the Convertible Notes may have on our financial position and liquidity, potential dilution, and that provisions of the Convertible Notes could delay or prevent a beneficial takeover of our company;
•the potential impact of the capped call transactions undertaken in tandem with the Convertible Notes issuances, including counterparty risk;
•increasing attention to environmental, social and governance matters;
•our ability to raise or access capital on acceptable terms;
•cyber-incidents could have a material adverse effect on our business, financial condition or results of operations;
•changes in accounting principles, policies or guidelines;
•events beyond our 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 shipping channels, including the joint U.S.-Israel strikes on Iran, continued instability in the Middle East and the effects of any changes to conditions in or impacting Venezuela; and
•other economic, competitive, governmental, regulatory and technical factors affecting our operations, products and prices.

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We have based any forward-looking statements on our current expectations and assumptions about future events.  While our 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 our control.  Accordingly, results actually achieved may differ materially from expected results described in these statements. Forward-looking statements speak only as of the date they are made. You should consider carefully the statements in the section entitled “Item 1A. Risk Factors” and other sections of our Annual Report on Form 10-K for the fiscal year ended December 31, 2025, as updated by subsequent reports we file with the SEC (including this report), which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. Our company does not undertake, and specifically disclaims, any obligation to update any forward-looking statements to reflect events or circumstances occurring after the date of such statements.

Readers are urged not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. We assume no obligation to update any forward-looking statements in order to reflect any event or circumstance that may arise after the date of this report, other than as may be required by applicable law or regulation. Readers are urged to carefully review and consider the various disclosures made by us in our reports filed with the SEC which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operation and cash flows. If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those expected or projected.

Overview

Our primary strategy is to invest in non-operated minority working and mineral interests in oil and natural gas properties, with a core area of focus in the premier basins in North America.  Using this strategy, we had participated in 12,507 gross (1,369.7 net) producing wells as of June 30, 2026. As of June 30, 2026, we had leased approximately 414,787 net acres, of which approximately 71% were developed and all were located in the United States and Canada.

We have grown and diversified our business significantly over the last several years through acquisitions of oil and natural gas properties. See Note 3 to our condensed consolidated financial statements for information regarding our recent acquisition activities.

Our average daily production in the second quarter of 2026 was approximately 145,659 Boe per day, of which approximately 47% was oil. This was a 9% increase in production compared to the second quarter of 2025, primarily due to production attributable to recent acquisitions and new wells added to production. During the three and six months ended June 30, 2026, we added 12.7 and 29.8 net wells to production, respectively.

Our weighted average percentage of production volumes by basin for the three months ended June 30, 2026 and 2025 were as follows:

Three Months Ended
June 30, 2026
WillistonPermianAppalachianUintaDuvernayTotal
Oil (Bbl)39 %44 %1 %14 %2 %100 %
Natural Gas (Mcf)17 %27 %55 %1 %— %100 %
Total (Boe)27 %34 %30 %8 %1 %100 %

Three Months Ended
June 30, 2025
WillistonPermianAppalachianUintaDuvernayTotal
Oil (Bbl)38 %49 %— %13 %— %100 %
Natural Gas (Mcf)22 %40 %36 %2 %— %100 %
Total (Boe)31 %45 %15 %9 %— %100 %





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Source of Our Revenues

We derive our revenues from the sale of oil, natural gas and NGLs produced from our properties.  Revenues are a function of the volume produced, the prevailing market price at the time of sale, oil quality, Btu content and transportation costs to market.  We use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our oil and natural gas production.  We expect our derivative activities will help us achieve more predictable cash flows and reduce our exposure to downward price fluctuations.  The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements but also mitigates the effects of declining price movements.

Principal Components of Our Cost Structure

•Commodity price differentials.  The price differential between our well head price for oil and the NYMEX WTI benchmark price (“Oil Price Differential”) is primarily driven by the cost to transport oil via train, pipeline or truck to refineries. The price differential between our well head price for natural gas and NGLs and the NYMEX Henry Hub benchmark price (“Gas Price Differential”) is primarily driven by gathering and transportation costs. As applicable, the calculations of both our Oil Price Differential and Gas Price Differential include certain immaterial non-cash revenue adjustments intended to reflect current period economic conditions.

•Gain (loss) on commodity derivatives, net.  We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the prices of oil and gas.  Gain (loss) on commodity derivatives, net is comprised of (i) cash gains and losses we recognize on settled commodity derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on commodity derivative instruments outstanding at period end.

•Production expenses.  Production expenses are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include field personnel compensation, natural gas processing, salt water disposal, utilities, maintenance, repairs and servicing expenses related to our oil and natural gas properties.

•Production taxes.  Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities.  We seek to take full advantage of all credits and exemptions in our various taxing jurisdictions.  In general, the production taxes we pay correlate to the changes in oil and natural gas revenues.

•Depreciation, depletion, amortization and accretion.  Depreciation, depletion, amortization and accretion includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas properties. As a full cost company, we capitalize all costs associated with our development and acquisition efforts and allocate these costs to each unit of production using the units-of-production method. Accretion expense relates to the passage of time of our asset retirement obligations.

•General and administrative expenses.  General and administrative expenses include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, audit and other professional fees and legal compliance.

•Interest expense.  We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings.  As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions.  We capitalize a portion of the interest paid on applicable borrowings into our unproved cost pool.  We include interest expense that is not capitalized into the unproved cost pool, the amortization of deferred financing costs (including origination and amendment fees), the amortization of bond premiums and discounts, commitment fees and annual agency fees as interest expense. Further, we record the settled amounts of our interest rate derivative instruments as interest expense.

•Impairment expense. Under the full cost method of accounting, the Company is required to perform a ceiling test impairment review each quarter.  The test determines a limit, or ceiling, on the book value of the Company’s oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. As a result of its ceiling test, the Company recorded a non-cash impairment charge of $268.3 million in the six months ended June 30, 2026. The Company did not have any ceiling test impairment charge in the three months ended June 30 2026. The Company recorded a non-cash impairment charge of $115.6 million in the three and six months ended June 30, 2025. Average commodity prices used in our ceiling test calculation have fluctuated significantly in recent quarters. If such prices trend downward, and/or if our proved reserves decrease significantly in
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future months, the present value of the Company’s future net revenues could decline, which could trigger the need for the Company to record an additional non-cash ceiling test impairment of its oil and gas property costs in future periods.

•Income tax expense.  Our provision for taxes includes, federal, state and foreign taxes. We record our income taxes in accordance with accounting for income taxes under GAAP, which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled.  The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.  A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.



Selected Factors That Affect Our Operating Results

Our revenues, cash flows from operations and future growth depend substantially upon:

•the timing and success of drilling and production activities by our operating partners;

•the prices and the supply and demand for oil, natural gas and NGLs;

•the quantity of oil and natural gas production from the wells in which we participate;

•changes in the fair value of the derivative instruments we use to reduce our exposure to fluctuations in commodity prices;

•our ability to continue to identify and acquire high-quality acreage and drilling opportunities;

•the level of our operating expenses; and

•the foreign currency exchange rates impacting our foreign operations.

In addition to the factors that affect companies in our industry generally, the location of substantially all of our acreage and wells in the Williston, Permian, Appalachian, Uinta and Duvernay Basins subjects our operating results to factors specific to these operating regions.  These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly during the winter and spring months, as well as infrastructure limitations, transportation capacity, regulatory matters and other factors that may specifically affect one or more of these operating regions.

The price at which our oil production is sold typically reflects a discount to the NYMEX WTI benchmark price.  The price at which our natural gas production is sold may reflect either a discount or premium to the NYMEX Henry Hub benchmark price. Thus, our operating results are also affected by changes in the price differentials between the applicable benchmark prices and the sales prices we receive for our production.

Our average oil price differential to the NYMEX WTI benchmark price during the three months ended June 30, 2026 was $3.03 per barrel, as compared to $5.31 per barrel for the three months ended June 30, 2025. Our average oil price differential to the NYMEX WTI benchmark price during the six months ended June 30, 2026 was $4.88 per barrel, as compared to $5.50 per barrel for the six months ended June 30, 2025.

Our net average realized gas price in the three months ended June 30, 2026 was $2.64 per Mcf, representing a 90% realization relative to the average NYMEX Henry Hub pricing. In comparison, our net average realized gas price was $2.89 per Mcf in the three months ended June 30, 2025, which represented a 82% realization relative to the average NYMEX Henry Hub pricing. Our net average realized gas price in the six months ended June 30, 2026 was $2.57 per Mcf, representing an 80% realization relative to the average NYMEX Henry Hub pricing. In comparison, our net average realized gas price was $3.37 per Mcf in the six months ended June 30, 2025, which represented a 91% realization relative to the average NYMEX Henry Hub pricing.

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Fluctuations in our oil and natural gas price realizations are due to several factors such as realized pricing by basin, gathering and transportation costs, transportation methods, takeaway capacity relative to production levels, regional storage capacity, seasonal refinery maintenance temporarily depressing demand, and in the case of gas realizations, the price of NGLs.

Another significant factor affecting our operating results is drilling costs.  The cost of drilling wells can vary significantly, driven in part by volatility in commodity prices that can substantially impact the level of drilling activity.  Generally, higher commodity prices have led to increased drilling activity, with the increased demand for drilling and completion services driving these costs higher.  Lower commodity prices have generally had the opposite effect.  In addition, individual components of drilling costs can vary depending on numerous factors, such as the length of the horizontal lateral, the number of fracture stimulation stages, and the type and amount of proppant used. During the six months ended June 30, 2026 and 2025, the weighted average gross authorization for expenditure (or AFE) cost for wells we elected to participate in was $10.4 million and $10.0 million, respectively.

Market Conditions

The crude oil and natural gas industry is cyclical and commodity prices are inherently volatile. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand.  Because our oil and gas revenues are heavily weighted toward oil, we are more significantly impacted by changes in oil prices than by changes in the price of natural gas.  World-wide supply in terms of output, especially production from properties within the United States, the production quota set by OPEC, and the strength of the U.S. dollar can significantly impact oil prices.  Factors impacting the future oil supply balance are world-wide demand for oil, as well as the growth in domestic oil production.

During 2025, a significant decline in oil prices occurred as a result of, among other things, (i) uncertainties regarding U.S. trade policies and tariffs driving concerns over increasing inflation, (ii) continued concerns over slowing global economic growth and resulting reductions in estimated global oil consumption, and (iii) the decision by OPEC to increase production starting in May 2025 and on multiple occasions subsequent thereto, creating additional global supply and further downward pressure on oil prices. However, in early 2026, significant increases in oil prices occurred as a result of the threatened and actual closing of oil shipping routes, including the Strait of Hormuz, by Iran and affiliated groups in connection with the joint U.S.-Israel strikes on Iran, with the NYMEX price for oil peaking in April 2026 at levels not seen since the second quarter of 2022. Oil prices have remained highly volatile since then.

Although U.S. inflation rates were relatively stable during the first half of 2026, they remain slightly higher than historical averages. Inflationary pressures, such as trade tariffs, can lead to economic slowdown and/or lead to a recession, which in turn can cause a decrease in short-term or longer-term demand for commodities, resulting in oversupply and potential for lower commodity prices.

The foregoing destabilizing factors have caused dramatic fluctuations in global financial markets and uncertainty about world-wide oil and natural gas supply and demand, which in turn has increased the volatility of oil and natural gas prices. Prolonged lower oil prices and inflationary costs could impact our operating partners’ development schedule for the non-operated wells in which we have a working interest. Additionally, such prolonged depressed prices could result in a significant triggering event indicating the need for further impairment of our oil and natural gas assets. Any of the foregoing events or circumstances could impact our future sales volumes, operating revenues and expenses, liquidity, per unit metrics and capital expenditures.

In light of current macroeconomic uncertainty and geopolitical tensions, including developments pertaining to Russia’s invasion of Ukraine, conflicts in the Middle East and Venezuela, and potential further imposition of domestic and foreign tariffs, we cannot predict any future volatility in or levels of commodity prices or demand for oil and natural gas.

Further, pursuant to our recent acquisition of oil and gas properties in Canada (See Note 3 to the condensed consolidated financial statements), we are now subject to foreign currency risks. Our wholly owned Canadian subsidiary uses the Canadian dollar (“CAD”) as its functional currency. Fluctuations in the USD/CAD exchange rate will affect the USD equivalent of our wholly owned Canadian subsidiary’s assets, liabilities, revenues, and operating expenses as reported in our condensed consolidated financial statements.

Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. The following table lists average NYMEX prices for oil and natural gas for the three and six months ended June 30, 2026 and 2025.

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Three Months Ended June 30,
20262025
Average NYMEX Prices(1)
Natural Gas (per MMbtu)$2.94 $3.51 
Oil (per Bbl)$93.05 $63.68 
_________
(1)Based on average NYMEX closing prices.


Six Months Ended June 30,
20262025
Average NYMEX Prices(1)
Natural Gas (per MMbtu)$3.21 $3.69 
Oil (per Bbl)$82.67 $67.52 
_________
(1)Based on average NYMEX closing prices.

We have entered into derivatives contracts to hedge commodity price risks on a portion of our future expected oil and natural gas production. For a summary as of June 30, 2026, of our open commodity price derivative contracts for future periods, see “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” in Part I, Item 3 below. See also Note 10 to our condensed consolidated financial statements.

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Results of Operations for the Three Months Ended June 30, 2026 and June 30, 2025

The following table sets forth selected operating data for the periods indicated. Production volumes and average sales prices are derived from accrued accounting data for the relevant period indicated.

Three Months Ended June 30,
20262025% Change
Net Production:
Oil (MBbl)6,2137,002(11)%
Natural Gas (MMcf)42,25431,20435 %
Total (MBoe)13,25512,2039 %
Net Sales (in thousands):
Oil Sales$559,264 $402,672 39 %
Natural Gas and NGL Sales111,532171,697(35)%
Gain (Loss) on Settled Commodity Derivatives(86,320)60,931(242)%
Gain on Unsettled Commodity Derivatives156,50267,888131 %
Other Revenue 4,2573,62118 %
Total Revenues745,235706,8095 %
Average Sales Prices:
Oil (per Bbl)$90.02 $58.37 54 %
Effect of Gain (Loss) on Settled Oil Derivatives on Average Price (per Bbl)(20.65)6.21 (433)%
Oil Net of Settled Oil Derivatives (per Bbl)69.37 64.58 7 %
Natural Gas and NGLs (per Mcf) (1)
$2.64 $2.89 (9)%
Effect of Gain on Settled Natural Gas Derivatives on Average Price (per Mcf)0.99 0.56 77 %
Natural Gas and NGLs Net of Settled Natural Gas and NGL Derivatives (per Mcf) (1)
3.63 3.45 5 %
Realized Price on a Boe Basis Excluding Settled Commodity Derivatives (1)
$50.61 $40.87 24 %
Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe)(6.51)4.99 (230)%
Realized Price on a Boe Basis Including Settled Commodity Derivatives (1)
44.10 45.86 (4)%
Operating Expenses (in thousands):
Production Expenses$127,089 $121,430 5 %
Production Taxes45,699 35,616 28 %
General and Administrative Expenses24,529 15,628 57 %
Depletion, Depreciation, Amortization and Accretion192,885 205,741 (6)%
Other Expense 2,496 3,561 (30)%
Costs and Expenses (per Boe):
Production Expenses$9.59 $9.95 (4)%
Production Taxes3.45 2.92 18 %
General and Administrative Expenses1.85 1.28 45 %
Depletion, Depreciation, Amortization and Accretion14.55 16.86 (14)%
Net Producing Wells at Period End1,369.7 1,151.7 19 %
______________
(1) The three months ended June 30, 2025 excludes the impact of a legal settlement (See Note 2 to our condensed consolidated financial statements).
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Oil and Natural Gas Sales

In the second quarter of 2026, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, was $670.8 million, compared to $574.4 million in the second quarter of 2025. In the second quarter of 2025, we recorded a legal settlement of approximately $81.7 million from an operator in North Dakota to resolve our claims related to certain post-production costs previously deducted from revenues (see Note 2 to our condensed consolidated financial statements).

Excluding the impact of the legal settlement, oil and natural gas sales increased by 36%. The increase in revenues was primarily driven by a 24% increase in weighted average realized prices and a 9% increase in production volumes.

We add production through drilling success as we place new wells into production and through additions from acquisitions, which is offset by the natural decline of our oil and natural gas production from existing wells. Acquisitions were a significant driver of our 9% increase in production volumes in the second quarter of 2026 compared to the same period of 2025.

Commodity Derivative Instruments

We enter into commodity derivative instruments to manage the price risk attributable to future oil and natural gas production. Our net result from commodity derivatives trade was a gain of $70.2 million in the second quarter of 2026, compared to a gain of $128.8 million in the second quarter of 2025. Net gain or loss on commodity derivatives is comprised of (i) cash gains and losses we recognize on settled commodity derivative instruments during the period, and (ii) unsettled gains and losses we incur on commodity derivative instruments outstanding at period-end.

For the second quarter of 2026, we realized a loss on settled commodity derivatives of $86.3 million, compared to a gain of $60.9 million in the second quarter of 2025. We incur realized losses on settled commodity derivatives when the average commodity market price at settlement is higher than our average hedge book price. Conversely, we incur gains when the average commodity market price at settlement is lower than our average hedge book price.

For the second quarter of 2026, we realized a gain on our unsettled commodity derivative of $156.5 million, compared to a gain of $67.9 million in the second quarter of 2025.

Our derivatives are not designated for hedge accounting, and thus are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings. Mark-to-market accounting treatment creates volatility in our revenues as gains and losses from unsettled derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying condensed consolidated balance sheets. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our commodity derivatives. Any gains on our unsettled commodity derivatives are expected to be offset by lower wellhead revenues in the future, while any losses are expected to be offset by higher future wellhead revenues based on the value at the settlement date. At June 30, 2026, all of our unsettled derivative contracts are recorded at their fair values, which was a net liability of $240.3 million, a change of $361.9 million from the $121.6 million net asset recorded as of December 31, 2025. The change in the net fair value or our unsettled derivative contracts at June 30, 2026 as compared to December 31, 2025 was primarily due to changes in forward commodity prices relative to prices on our open commodity derivative contracts since December 31, 2025. Our open commodity derivative contracts are summarized in “Item 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

Production Expenses

Production expenses were $127.1 million in the second quarter of 2026, compared to $121.4 million in the second quarter of 2025. On a per unit basis, production expenses were $9.59 per Boe in the second quarter of 2026 compared to $9.95 per Boe in the second quarter of 2025. The decrease in our production expenses per unit in the second quarter of 2026 compared to the second quarter of 2025 was primarily due to higher production volumes in the second quarter of 2026 as compared to the same period in 2025.

Production Taxes

We pay production taxes based on realized oil and natural gas sales. Production taxes were $45.7 million in the second quarter of 2026, compared to $35.6 million in the second quarter of 2025. As a percentage of oil and natural gas sales, our production taxes were 6.8% and 7.2% in the second quarter of 2026 and 2025, respectively.
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General and Administrative Expenses

General and administrative expenses were $24.5 million in the second quarter of 2026, or $1.85 per Boe, compared to $15.6 million in the second quarter of 2025, or $1.28 per Boe. The increase was primarily driven by the $7.6 million transaction costs recorded for the Duvernay Acquisition, which was accounted for as a business combination (see Note 3 to our condensed consolidated financial statements).

Legal Settlement Expense

In the second quarter of 2025, we incurred legal expenses of approximately $33.1 million in conjunction with our $81.7 million received from an operator in North Dakota, pursuant to a legal settlement resolving our claims related to certain post-production costs previously deducted from revenues (see Note 2 to our condensed consolidated financial statements).

Depletion, Depreciation, Amortization and Accretion

Depletion, depreciation, amortization and accretion (“DD&A”) was $192.9 million in the second quarter of 2026, compared to $205.7 million in the second quarter of 2025. Depletion expense, the largest component of DD&A, decreased by $13.0 million in the second quarter of 2026 compared to the second quarter of 2025, primarily due to a lower depletable property cost basis following certain non-cash ceiling test impairment charges recorded in recent periods. On a per unit basis, depletion expense was $14.45 per Boe in the second quarter of 2026 compared to $16.76 per Boe in the second quarter of 2025. Depreciation, amortization and accretion was $1.3 million and $1.2 million in the second quarter of 2026 and 2025, respectively. The following table summarizes DD&A expense per Boe for the second quarter of 2026 and 2025:

Three Months Ended June 30,
20262025$ Change% Change
Depletion$14.45 $16.76 $(2.31)(14)%
Depreciation, Amortization and Accretion0.10 0.10 — — %
Total DD&A Expense$14.55 $16.86 $(2.31)(14)%

Impairment Expense

The Company recorded an impairment charge of $115.6 million in the second quarter of 2025, as a result of its full cost ceiling test. No impairment charges were recorded in the second quarter of 2026.

Interest Expense, Net

Interest expense, Net was $41.4 million in the second quarter of 2026 compared to $44.4 million in the second quarter of 2025. The decrease was primarily due to lower weighted average borrowing rates, pursuant to the refinancing of the Company’s Senior Notes due 2028 by the Senior Notes due 2033 at a lower borrowing cost (See Note 4 to our condensed consolidated financial statements).

Loss on Foreign Currency Transactions

Foreign currency transaction losses were $4.7 million in the second quarter of 2026, primarily driven by the remeasurement of certain monetary assets and liabilities denominated in CAD, pursuant to the Company’s recent acquisition of oil and natural gas properties in Canada. The Company did not have any foreign currency transactions in the second quarter of 2025.

Gain on Contingent Consideration

During the second quarter of 2026, we recorded a contingent consideration gain of $2.7 million due to a change in the fair value of the contingent consideration liability incurred pursuant to the Duvernay Acquisition (see Notes 3 and 9 to our condensed consolidated financial statements). The contingent consideration gain was primarily driven by a favorable change in the forward NYMEX WTI oil price curve from the acquisition date to June 30, 2026.



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Income Tax

During the second quarter of 2026, we recorded an income tax expense of $74.0 million, as compared to $32.2 million recorded for the second quarter of 2025. The higher income tax expense in the second quarter of 2026 was driven by a higher taxable income as compared to the same period in 2025.

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Results of Operations for the Six Months Ended June 30, 2026 and June 30, 2025

The following table sets forth selected operating data for the periods indicated. Production volumes and average sales prices are derived from accrued accounting data for the relevant period indicated.

Six Months Ended June 30,
20262025% Change
Net Production:
Oil (MBbl)12,83414,083(9)%
Natural Gas (MMcf)82,61461,59734 %
Total (MBoe)26,60324,3499 %
Net Sales (in thousands):
Oil Sales$998,346 $862,354 16 %
Natural Gas and NGL Sales212,305288,967(27)%
Gain (Loss) on Settled Commodity Derivatives(103,953)72,993(242)%
Gain (Loss) on Unsettled Commodity Derivatives(364,921)77,588(570)%
Other Revenue 8,4877,00621 %
Total Revenues750,2641,308,908(43)%
Average Sales Prices:
Oil (per Bbl)$77.79 $62.01 25 %
Effect of Gain (Loss) on Settled Oil Derivatives on Average Price (per Bbl)(12.22)3.87 (416)%
Oil Net of Settled Oil Derivatives (per Bbl)65.57 65.88 — %
Natural Gas and NGLs (per Mcf) (1)
$2.57 $3.37 (24)%
Effect of Gain on Settled Natural Gas Derivatives on Average Price (per Mcf)0.64 0.30 113 %
Natural Gas and NGLs Net of Settled Natural Gas and NGL Derivatives (per Mcf) (1)
3.21 3.67 (13)%
Realized Price on a Boe Basis Excluding Settled Commodity Derivatives (1)
$45.51 $44.38 3 %
Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe)(3.91)3.00 (230)%
Realized Price on a Boe Basis Including Settled Commodity Derivatives (1)
41.60 47.38 (12)%
Operating Expenses (in thousands):
Production Expenses$256,836 $235,470 9 %
Production Taxes84,042 71,685 17 %
General and Administrative Expenses47,703 30,109 58 %
Depletion, Depreciation, Amortization and Accretion389,983 411,432 (5)%
Other Expense 5,771 6,098 (5)%
Costs and Expenses (per Boe):
Production Expenses$9.65 $9.67 — %
Production Taxes3.16 2.94 7 %
General and Administrative Expenses1.79 1.24 44 %
Depletion, Depreciation, Amortization and Accretion14.66 16.90 (13)%
Net Producing Wells at Period End1,369.7 1,151.7 19 %
______________
(1)The six months ended June 30, 2025, excludes the impact of a legal settlement (See Note 2 to our condensed financial statements).
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Oil and Natural Gas Sales

In the first six months of 2026, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, was $1,210.7 million, compared to $1,151.3 million in the first six months of 2025. In the first six months of 2025, we recorded a legal settlement of approximately $81.7 million from an operator in North Dakota to resolve our claims related to certain post-production costs previously deducted from revenues (see Note 2 to our condensed consolidated financial statements).

Excluding the impact of the legal settlement, oil and natural gas sales increased 13%. The increase in revenues was primarily driven by a 3% increase in weighted average realized prices and a 9% increase in production volumes.

We add production through drilling success as we place new wells into production and through additions from acquisitions, which is offset by the natural decline of our oil and natural gas production from existing wells. Acquisitions were a significant driver of our 9% increase in production volumes in the first six months of 2026 compared to the same period of 2025.

Commodity Derivative Instruments

We enter into commodity derivative instruments to manage the price risk attributable to future oil and natural gas production. Our net result from commodity derivatives trade was a loss of $468.9 million in the first six months of 2026, compared to a gain of $150.6 million in the first six months of 2025. Net gain or loss on commodity derivatives is comprised of (i) cash gains and losses we recognize on settled commodity derivative instruments during the period, and (ii) unsettled gains and losses we incur on commodity derivative instruments outstanding at period-end.

For the first six months of 2026, we realized a loss on settled commodity derivatives of $104.0 million, compared to a gain of $73.0 million in the first six months of 2025. For the first six months of 2026, we realized a loss on our unsettled commodity derivative of $364.9 million, compared to a gain of $77.6 million in the first six months of 2025.

Our derivatives are not designated for hedge accounting, and thus are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings. Mark-to-market accounting treatment creates volatility in our revenues as gains and losses from unsettled derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying condensed consolidated balance sheets. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our commodity derivatives. Any gains on our unsettled commodity derivatives are expected to be offset by lower wellhead revenues in the future, while any losses are expected to be offset by higher future wellhead revenues based on the value at the settlement date. At June 30, 2026, all of our unsettled derivative contracts are recorded at their fair values, which was a net liability of $240.3 million, a change of $361.9 million from the $121.6 million net asset recorded as of December 31, 2025. The change in the net fair value or our unsettled derivative contracts at June 30, 2026 as compared to December 31, 2025 was primarily due to changes in forward commodity prices relative to prices on our open commodity derivative contracts since December 31, 2025. Our open commodity derivative contracts are summarized in “Item 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

Production Expenses

Production expenses were $256.8 million in the first six months of 2026, compared to $235.5 million in the first six months of 2025. On a per unit basis, production expenses were $9.65 per Boe in the first six months of 2026 compared to $9.67 per Boe in the first six months of 2025.

Production Taxes

We pay production taxes based on realized oil and natural gas sales. Production taxes were $84.0 million in the first six months of 2026, compared to $71.7 million in the first six months of 2025. As a percentage of oil and natural gas sales, our production taxes were 6.9% and 6.7% in the first six months of 2026 and 2025, respectively.

General and Administrative Expenses

General and administrative expenses were $47.7 million in the first six months of 2026, or $1.79 per Boe, compared to $30.1 million in the first six months of 2025, or $1.24 per Boe. The increase was primarily driven by $14.3 million in
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transaction costs recorded for both the Utica Acquisition and the Duvernay Acquisition, which were both accounted for as business combinations (see Note 3 to our condensed consolidated financial statements).

Legal Settlement Expense

In the first six months of 2025, we incurred legal expenses of approximately $33.1 million in conjunction with our $81.7 million received from an operator in North Dakota, pursuant to a legal settlement resolving our claims related to certain post-production costs previously deducted from revenues (see Note 2 to our condensed consolidated financial statements).

Depletion, Depreciation, Amortization and Accretion

Depletion, depreciation, amortization and accretion (“DD&A”) was $390.0 million in the first six months of 2026, compared to $411.4 million in the first six months of 2025. Depletion expense, the largest component of DD&A, decreased by $21.7 million in the first six months of 2026 compared to the first six months of 2025, primarily due to a lower depletable property cost basis following certain non-cash ceiling test impairment charges recorded in recent periods. On a per unit basis, depletion expense was $14.56 per Boe in the first six months of 2026 compared to $16.80 per Boe in the first six months of 2025. Depreciation, amortization and accretion was $2.6 million and $2.4 million in the first six months of 2026 and 2025, respectively. The following table summarizes DD&A expense per Boe for the first six months of 2026 and 2025:

Six Months Ended June 30,
20262025$ Change% Change
Depletion$14.56 $16.80 $(2.24)(13)%
Depreciation, Amortization and Accretion0.10 0.10 — — %
Total DD&A Expense$14.66 $16.90 $(2.24)(13)%

Impairment Expense

In the first six months of 2026, the Company recorded a non-cash impairment charge of $268.3 million compared to $115.6 million in the first six months of 2025, as a result of its full cost ceiling tests.

Interest Expense, Net

Interest expense, Net was $84.0 million in the first six months of 2026 compared to $87.7 million in the first six months of 2025. The decrease was primarily due to lower weighted average borrowing rates, pursuant to the refinancing of the Company’s Senior Notes due 2028 by the Senior Notes due 2033 at a lower borrowing cost (See Note 4 to our condensed consolidated financial statements).

Loss on Foreign Currency Translations

Foreign currency transaction losses were $4.7 million in the first six months of 2026, primarily driven by the remeasurement of certain monetary assets and liabilities denominated in CAD, pursuant to the Company’s recent acquisition of oil and natural gas properties in Canada. The Company did not have any foreign currency transactions in the first six months of 2025.

Gain on Contingent Consideration

During the first six months of 2026, we recorded a contingent consideration gain of $2.7 million due to a change in the fair value of the contingent consideration liability incurred pursuant to the Duvernay Acquisition (see Notes 3 and 9 to our condensed consolidated financial statements). The contingent consideration gain was primarily driven by a favorable change in the forward NYMEX WTI oil price curve from the acquisition date to June 30, 2026.

Income Tax

During the first six months of 2026, we recorded an income tax benefit of $99.1 million due to our pretax losses caused, primarily, by our losses on commodity derivatives and our non-cash ceiling test impairment charge. Conversely, we recorded an income tax expense of $79.0 million for the first six months of 2025.

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Liquidity and Capital Resources

Overview

Our main sources of liquidity and capital resources as of the date of this report have been internally generated cash flow from operations, proceeds from equity and debt financings, credit facility borrowings and cash settlements of commodity derivative instruments.  Our primary uses of capital have been for the acquisition, development and operation of our oil and natural gas properties, cash settlements of commodity derivative instruments and for stockholder returns.  We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.

In March 2026, we issued 8,288,289 shares of our common stock in a public offering for total consideration of approximately $227.9 million.

In March 2026, we redeemed all of the outstanding Senior Notes due 2028 at a redemption price of 100%. Total consideration paid pursuant to the redemption of the Senior Notes due 2028 was approximately $20.2 million.

In June 2026, we issued 3,689,413 shares of our common stock in conjunction with the acquisition of oil and gas properties pursuant to the Duvernay Acquisition (See Note 3 to our condensed consolidated financial statements).

In June 2026, we repurchased and retired 2,948,447 shares of our common stock for total consideration of $60.1 million, or an average price of $20.37 per share.

As of June 30, 2026, we had outstanding total debt of $2.8 billion consisting of $825.0 million of borrowings under our Revolving Credit Facility, $700.0 million aggregate principal amount of our Convertible Notes due 2029, $500.0 million aggregate principal amount of our Senior Notes due 2031, and $725.0 million aggregate principal amount of our Senior Notes due 2033.

As of June 30, 2026, we had total liquidity of approximately $1.0 billion, consisting of $975.0 million of committed borrowing availability under the Revolving Credit Facility and $47.6 million of cash on hand.
One of the primary sources of variability in our cash flows from operating activities is commodity price volatility. Oil accounted for 83% and 82% of our total oil and gas sales in the second quarter of 2026 and 2025, respectively.  As a result, our operating cash flows are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas and NGL prices.  We seek to maintain a robust hedging program to mitigate volatility in commodity prices with respect to a portion of our expected production. For the six months ended June 30, 2026, we hedged approximately 80% of our crude oil production and approximately 60% of our natural gas production. For a summary as of June 30, 2026, of our open commodity swap contracts for future periods, see “Quantitative and Qualitative Disclosures about Market Risk” in Part I, Item 3 below.

With our cash on hand, cash flow from operations, and borrowing capacity under our Revolving Credit Facility, we believe that we will have sufficient cash flow and liquidity to fund our budgeted capital expenditures and operating expenses for at least the next twelve months and, based on current expectations, for the foreseeable future. However, we may seek additional access to capital and liquidity.  We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all.

Our recent capital commitments have been to fund acquisitions and development of oil and natural gas properties. We expect to fund our near-term capital requirements and working capital needs with cash flows from operations and available borrowing capacity under our Revolving Credit Facility.  Our capital expenditures could be curtailed if our cash flows decline from expected levels.  Because production from existing oil and natural gas wells declines over time, reductions of capital expenditures used to drill and complete new oil and natural gas wells would likely result in lower levels of oil and natural gas production in the future.

Working Capital

Our working capital balance fluctuates as a result of changes in commodity pricing and production volumes, collection of receivables, expenditures related to our development and production operations and the impact of our outstanding derivative instruments.

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At June 30, 2026, we had a working capital deficit of $128.4 million, compared to a surplus of $46.7 million at December 31, 2025. Current assets decreased by $83.9 million and current liabilities increased by $91.2 million at June 30, 2026, compared to December 31, 2025.

Cash Flows

Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and by changes in working capital. Any interim cash needs are funded by cash on hand, cash flows from operations or borrowings under our Revolving Credit Facility. We typically enter into commodity derivative transactions covering a substantial, but varying, portion of our anticipated future oil and gas production for the next 12 to 36 months. See “Quantitative and Qualitative Disclosures about Market Risk” in Part I, Item 3 below.

Our cash summary for the three and six months ended June 30, 2026 and 2025 is presented below:

Three Months Ended
June 30,		Six Months Ended
June 30,
(In thousands, unaudited)2026202520262025
Net Cash Provided by Operating Activities$321,617 $362,112 $645,232 $769,538 
Net Cash Used for Investing Activities$(379,811)(327,255)(1,014,489)(591,813)
Net Cash Provided by (Used for) Financing Activities74,230 (42,577)408,035 (160,802)
Effect of Exchange Rate Changes on Cash and Cash Equivalents$(5,474)$— $(5,474)$— 
Net Increase in Cash$10,562 $(7,720)$33,304 $16,923 

Cash Flows from Operating Activities

Net cash provided by operating activities for the three months ended June 30, 2026 was $321.6 million, compared to $362.1 million in the same period of the prior year. The lower cash provided by operating activities in the second quarter of 2026 was primarily due to realized losses from settled commodity derivatives, partially offset by increased revenues from higher prices and production volumes.

Net cash provided by operating activities for the six months ended June 30, 2026 was $645.2 million, compared to $769.5 million in the same period of the prior year. The lower cash provided by operating activities in the six months ended June 30, 2026 was primarily due to realized losses from settled commodity derivatives, partially offset by increased revenues from higher prices and production volumes.

Cash Flows from Investing Activities

Cash flows used in investing activities during the three months ended June 30, 2026 and 2025 were $379.8 million and $327.3 million, respectively.

Cash flows used in investing activities during the six months ended June 30, 2026 and 2025 were $1,014.5 million and $591.8 million, respectively. Cash used in investing activities was higher during the six months ended June 30, 2026 primarily due to the Utica Acquisition and the Duvernay Acquisition, as described in Note 3 to the Company’s condensed consolidated financial statements.

Our cash flows used in investing activities reflects actual cash spending, which can lag several months from when the related costs were incurred. As a result, our actual cash spending is not always reflective of current levels of development activity. For instance, during the three months ended June 30, 2026, our capitalized costs incurred, excluding non-cash consideration, for oil and natural gas properties (e.g., drilling and completion costs, acquisitions, and other capital expenditures) amounted to $463.4 million, while the actual cash spend in this regard amounted to $379.8 million. Further, during the six months ended June 30, 2026, our capitalized costs incurred, excluding non-cash consideration, for oil and natural gas properties (e.g., drilling and completion costs, acquisitions, and other capital expenditures) amounted to $1,203.1 million, while the actual cash spend in this regard amounted to $1,014.4 million.

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Development and acquisition activities are discretionary. We monitor our capital expenditures on a regular basis, adjusting the amount up or down, and between projects, depending on projected commodity prices, cash flows and returns. Our cash spend for development and acquisition activities for the six months ended June 30, 2026 and 2025 are summarized in the following table:
Six Months Ended
June 30,
(In thousands, unaudited)20262025
Drilling and Development Capital Expenditures$369.7 $478.6 
Acquisition of Oil and Natural Gas Properties637.0 110.8 
Other Capital Expenditures7.7 1.9 
Total$1,014.4 $591.3 

Cash Flows from Financing Activities

Net cash provided by financing activities was $74.2 million during the three months ended June 30, 2026, compared to net cash used for financing activities of $42.6 million during the three months ended June 30, 2025.

For the three months ended June 30, 2026, cash provided by financing activities was primarily due to $172.0 million net borrowings under our Revolving Credit Facility, partially offset by $50.0 million disbursed for our common stock repurchases and $47.4 million of common stock dividend payments.

For the three months ended June 30, 2025, cash used for financing activities was primarily due to $150.0 million net repayment of borrowings under our Revolving Credit Facility, $44.3 million of common stock dividend payments, $35.0 million in repurchases of common stock, and $16.9 million from the entry into Additional Capped Call Transactions, partially offset by the issuance of $200.0 million in aggregate principal amount of Additional Convertible Notes at an issue price of 105.597% of the principal amount thereof.

Net cash provided by financing activities was $408.0 million during the six months ended June 30, 2026, compared to net cash used for financing activities of $160.8 million during the six months ended June 30, 2025.

For the six months ended June 30, 2026, cash provided by financing activities was primarily due to $227.9 million proceeds from issuance of common stock, and $347.0 million net borrowings under our Revolving Credit Facility, partially offset by $91.8 million of common stock dividend payments, $50.0 million in repurchases of common stock, $20.2 million spent to redeem all of the outstanding Senior Notes due 2028, and $2.8 million to settle the tax obligations related to employee share based compensations.

For the six months ended June 30, 2025, cash used for financing activities was primarily due to $210.0 million net repayment of borrowings under our Revolving Credit Facility, $86.0 million of common stock dividend payments, $50.0 million in repurchases of common stock, and $16.9 million from the entry into Additional Capped Call Transactions, partially offset by the issuance of $200.0 million in aggregate principal amount of Additional Convertible Notes at an issue price of 105.597% of the principal amount thereof.

Revolving Credit Facility

We have entered into the Revolving Credit Facility with Wells Fargo Bank, as administrative agent, and the lenders from time to time party thereto. The Revolving Credit Facility is subject to a borrowing base with maximum loan value to be assigned to the proved reserves attributable to our oil and natural gas properties. In February 2026, the Company completed a wildcard redetermination, pursuant to which the borrowing base was increased from $1.8 billion to $1.975 billion, and the aggregate elected commitment amount was increased from $1.6 billion to $1.8 billion. As of June 30, 2026, the Revolving Credit Facility had a borrowing base of $1.975 billion and an elected commitment amount of $1.8 billion, and we had $825.0 million in borrowings outstanding under the facility, leaving approximately $1.0 billion in available committed borrowing capacity. See Note 4 to our condensed consolidated financial statements for further details regarding the Revolving Credit Facility.




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Senior Notes due 2028

In March 2026, we redeemed all of the outstanding Senior Notes due 2028, in accordance with the terms of the 2028 Notes Indenture, at a redemption price of 100%. See Note 4 to our condensed consolidated financial statements for further details regarding the Senior Notes due 2028.

Convertible Notes due 2029

As of June 30, 2026, we had outstanding $700.0 million aggregate principal amount of our Convertible Notes. See Note 4 to our condensed consolidated financial statements for further details regarding the Convertible Notes.

Senior Notes due 2031

As of June 30, 2026, we had outstanding $500.0 million aggregate principal amount of our Senior Notes due 2031. See Note 4 to our condensed consolidated financial statements for further details regarding the Senior Notes due 2031.

Senior Notes due 2033

As of June 30, 2026, we had outstanding $725.0 million aggregate principal amount of our Senior Notes due 2033. See Note 4 to our condensed consolidated financial statements for further details regarding the Senior Notes due 2033.

Effects of Inflation and Pricing

The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry.  Typically, as prices for oil and natural gas increase, so do all associated costs.  Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion.  Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions.  Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel.  Based on current conditions and expectations, we are not presently budgeting for any material change in per well drilling and completion and other associated costs in 2026 compared to 2025.  

Effects of Foreign Currency Exchange Rate Changes

Pursuant to our recent acquisition of oil and gas properties in Canada (See Note 3 to the condensed consolidated financial statements), we are now subject to foreign currency risks from fluctuations in the USD/CAD exchange rate.

Effects of Pricing on Contingent Consideration Liability

Pursuant to our recent acquisition of oil and gas properties in Canada (See Note 3 to the condensed consolidated financial statements), we incurred a contingent consideration liability payable in January 2028. The payable amount is dependent on the WTI oil price reaching an average of $72.50 per Bbl during the period from April 1, 2026 to December 31, 2027. In accordance with the applicable accounting guidelines, we remeasure the fair value of the contingent consideration liability each reporting period. Gains or losses from remeasurement are recorded in earnings.

Contractual Obligations and Commitments

Please see our disclosure of contractual obligations and commitments as of December 31, 2025, included in Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2025.

Critical Accounting Estimates

Critical accounting estimates are those estimates made in accordance with GAAP that involve a significant level of estimation uncertainty and have had or are reasonably likely to have a material impact on our financial condition or results of operations. Our critical accounting estimates include impairment testing of natural gas and crude oil production properties, and derivative instruments and hedging activity. There were no material changes in our critical accounting estimates from those reported in our Annual Report on Form 10-K for the fiscal year ended December 31, 2025.

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A description of our critical accounting policies, including estimates, was provided in Note 2 to our financial statements provided in Part II, Item 8 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2025.


Item 3.  Quantitative and Qualitative Disclosures about Market Risk

Our quantitative and qualitative disclosures about market risk are included in Item 7A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2025 and, except as set forth below, have not materially changed since that report was filed.

Commodity Price Risk

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth.  Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand and other factors.  Historically, the markets for oil and natural gas have been volatile, and we believe these markets will likely continue to be volatile in the future.  The prices we receive for our production depend on numerous factors beyond our control.  Our revenue generally would have increased or decreased along with any increases or decreases in oil or natural gas prices, but the exact impact on our income is indeterminable given the variety of expenses associated with producing and selling oil that also increase and decrease along with oil prices.

We enter into derivative contracts to achieve a more predictable cash flow by reducing our exposure to commodity price volatility.  All derivative positions are carried at their fair value on the condensed consolidated balance sheets and are marked-to-market at the end of each period.   Any realized gains and losses on settled derivatives, as well as mark-to-market gains or losses, are aggregated and recorded to gain (loss) on derivative instruments, net on the condensed consolidated statements of operations rather than as a component of other comprehensive income or other income (expense).

We generally use derivatives to economically hedge a significant, but varying portion of our anticipated future production.  Any payments due to counterparties under our derivative contracts are funded by proceeds received from the sale of our production.  Production receipts, however, lag payments to the counterparties.  Any interim cash needs are funded by cash from operations or borrowings under our Revolving Credit Facility.


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The following table summarizes our open crude oil derivative contracts as of June 30, 2026, by fiscal quarter.

Crude Oil Contracts
Swaps(1)
Collars
Contract PeriodVolume
(Bbls)		Weighted Average Price
($/Bbl)		Volume Ceiling
(Bbls)		Volume
Floor
(Bbls)		Volume
Sub-Floor
(Bbls)		Weighted Average Ceiling Price
($/Bbl)		Weighted Average Floor Price
($/Bbl)		Weighted Average Sub-Floor Price
($/Bbl)
2026(1)
Q31,678,567 $67.55 2,454,587 1,765,163 207,000 $71.44 $62.34 $47.22 
Q41,494,567 67.62 2,454,587 1,765,163 207,000 71.44 62.34 47.22 
2027(1)
Q1697,500 $69.47 607,500 607,500 225,000 $73.76 $61.14 $45.00 
Q2705,250 69.47 614,250 614,250 227,500 73.76 77.81 45.00 
Q3506,000 70.50 353,500 353,500 38,750 75.31 67.97 45.00 
Q4506,000 70.50 276,000 276,000 — 76.37 64.03 — 
2028(1)
Q145,500 $70.04 — — — $— $— $— 
Q245,500 70.04 — — — — — — 
Q346,000 70.04 — — — — — — 
Q446,000 70.04 — — — — — — 
2029(1)
Q145,000 $70.04 — — — $— $— $— 
Q245,500 70.04 — — — — — — 
Q346,000 70.04 — — — — — — 
Q446,000 70.04 — — — — — — 
_____________
(1)This table does not include volumes subject to swaptions and call options, which are crude oil derivative contracts we have entered into which may increase our swapped volumes at the option of our counterparties. This table also does not include basis swaps. See Note 10 to our condensed consolidated financial statements for further details regarding our commodity derivatives, including the swaptions and call options that are not included in the foregoing table.

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The following table summarizes our open natural gas derivative contracts as of June 30, 2026, by fiscal quarter.

Natural Gas Contracts
Swaps(1)
Collars
Contract PeriodVolume (MMBTU)Weighted Average Price ($/MMBTU)Volume Ceiling
(MMBTU)		Volume Floor
(MMBTU)		Weighted Average Ceiling Price
($/MMBTU)		Weighted Average Floor Price
($/MMBTU)
2026(1)
Q310,735,000 $4.02 13,844,706 13,844,706 $4.89 $3.45 
Q412,425,000 4.16 13,809,642 13,809,642 5.06 3.47 
2027(1)
Q18,015,000 $4.01 6,965,000 6,965,000 $4.79 $3.46 
Q28,280,000 4.00 5,980,000 5,980,000 4.43 3.45 
Q38,280,000 4.00 5,980,000 5,980,000 4.43 3.45 
Q46,570,000 3.96 4,275,000 4,275,000 4.41 3.45 
2028(1)
Q12,555,000 $3.83 900,000 900,000 $4.17 $3.50 
Q21,840,000 3.83 920,000 920,000 4.17 3.50 
Q31,840,000 3.83 920,000 920,000 4.17 3.50 
Q41,530,000 3.85 920,000 920,000 4.07 3.50 
2029(1)
Q1— $— 890,000 890,000 $3.88 $3.50 
Q2— — 920,000 920,000 3.88 3.50 
Q3— — 920,000 920,000 3.88 3.50 
Q4— — 610,000 610,000 3.88 3.50 
_____________
(1)This table does not include volumes subject to swaptions and call options, which are natural gas derivative contracts we have entered into which may increase our swapped volumes at the option of our counterparties. This table also does not include basis swaps. See Note 10 to our condensed consolidated financial statements for further details regarding our commodity derivatives, including the call options and basis swaps that are not included in the foregoing table.


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The following table summarizes our open NGL derivative contracts as of June 30, 2026, by fiscal quarter.

NGL Contracts
Swaps
Contract PeriodVolume
(BBL)		Weighted Average Price
($/BBL)
2026:
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 

Interest Rate Risk

Our long-term debt as of June 30, 2026 was comprised of borrowings that contain fixed and floating interest rates. Our Convertible Notes due 2029, Senior Notes due 2031, and Senior Notes due 2033 bear cash interest at fixed rates. Our Revolving Credit Facility interest rate is a floating rate option that is designated by us within the parameters established by the underlying agreement (see Note 4 to our condensed consolidated financial statements).

From time to time, the Company may use interest rate swaps to effectively convert a portion of its variable rate indebtedness to fixed rate indebtedness. The following table summarizes our open interest rate derivative contracts as of June 30, 2026.

Fixed Rate Swap Agreements (in thousands)
Swaps
Contract PeriodNotional AmountFixed RateFloating Benchmark
October 1, 2024 - October 1, 2026$25,000 3.423 %USD-SOFR CME
May 1, 2025 - May 1, 2027$50,000 3.423 %USD-SOFR CME
September 19, 2025 - October 1, 2027$50,000 3.300 %USD-SOFR CME
October 20, 2025 - November 1, 2027$100,000 3.187 %USD-SOFR CME
December 10, 2025 - December 1, 2027$50,000 3.393 %USD-SOFR CME
December 10, 2025 - December 1, 2028$50,000 3.392 %USD-SOFR CME

Changes in interest rates can impact results of operations and cash flows.  A 1% increase in short-term interest rates on our floating-rate debt outstanding at June 30, 2026 would cost us approximately $5.0 million in additional annual interest expense.

Foreign Currency Exchange Rate Risk

Our cash activities relating to our international operations are based on the U.S. dollar equivalent of cash flows measured in foreign currencies. Our Canadian production is sold under Canadian dollar contracts, while the majority of costs incurred are paid in Canadian dollars. Transactions denominated in Canadian dollars are converted to U.S. dollar equivalents based on applicable exchange rates during the period. We monitor foreign currency exchange rates of countries in which we are conducting business and may, from time to time, implement measures to protect against foreign currency exchange rate risk.

Foreign currency gains and losses also arise when monetary assets and liabilities denominated in foreign currencies are remeasured at the end of each month. Foreign currency gains and losses from remeasurements are included in current earnings.

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Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

We maintain a system of disclosure controls and procedures that is designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934, as amended (“Exchange Act”), reports is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures.

As of June 30, 2026, our management, including our principal executive officer and principal financial officer, had evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) pursuant to Rule 13a-15(b) under the Exchange Act. Based upon and as of the date of the evaluation, our principal executive officer and principal financial officer concluded that information required to be disclosed is recorded, processed, summarized and reported within the specified periods and is accumulated and communicated to management, including our principal executive officer and principal financial officer, to allow for timely decisions regarding required disclosure of material information required to be included in our periodic SEC reports.  Based on the foregoing, our management determined that our disclosure controls and procedures were effective as of June 30, 2026.

Changes in Internal Control over Financial Reporting

No change in our Company’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the quarter ended June 30, 2026, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
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PART II - OTHER INFORMATION

Item 1.  Legal Proceedings.

Our Company is subject from time to time to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business.


Item 1A.  Risk Factors.
 
Except as described below, there have been no material changes to the risk factors disclosed in the “Risk Factors” section of our Annual Report on Form 10-K filed with the SEC for the period ended December 31, 2025.

Our future results will suffer if we do not effectively manage our expanded operations and the risks inherent in operating in a foreign jurisdiction.

In recent years, the size and geographic footprint of our business has increased as a result of a series of acquisitions, including most recently our acquisition of certain oil and gas properties, interests and related assets located in the Duvernay East Shale Basin in Alberta, Canada. Our future success will depend, in part, upon our ability to manage this expanded business and the challenges associated with our international operations, including the need to understand, interpret and comply with applicable Canadian laws and regulations, potential tax issues, including, but not limited to, with respect to our corporate operating structure and intercompany arrangements, fluctuations in currency exchange rates, and increased legal, compliance and administrative costs. We may also face increased scrutiny from governmental authorities as a result of our international operations. There can be no assurances that we will be successful in managing these challenges or that we will realize the expected benefits currently anticipated from our recent acquisitions. If our efforts to effectively manage these risks are unsuccessful, our business, financial condition and results of operations could be adversely affected.

Fluctuations in exchange rates could affect expenses or result in realized and unrealized losses.

As a result of the recently completed Duvernay Acquisition, we have operations in Canada and, as a result, a portion of our revenues and expenses are denominated in Canadian dollars. In addition, our subsidiary that is domiciled in Canada may hold U.S. dollar denominated assets and liabilities. Fluctuations in the exchange rate between the U.S. dollar and the Canadian dollar have resulted in, and could in the future result in realized and unrealized losses, which could impact our revenue and expenses and have a material adverse effect on our business, financial condition and results of operations.


Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds.

Unregistered Sales of Equity Securities and Use of Proceeds

None, except to the extent previously reported by the Company in its Current Report on Form 8-K filed on June 1, 2026.

Issuer Purchases of Equity Securities

The table below sets forth the information with respect to purchases made by or on behalf of the Company, or any “affiliated purchaser” (as defined in Rule 10b-18(a)(3) under the Exchange Act) of our common stock during the quarter ended June 30, 2026.
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Period
Total Number of Shares
Purchased
Average Price Paid Per Share
Total Number of Shares
Purchased as Part of Publicly
Announced Plans or Programs
Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs
(at period end)(1)
Month #1
April 1, 2026 to April 30, 2026— $— — $153.3 million
Month #2
May 1, 2026 to May 31, 2026694,387 $21.62 — $138.3 million
Month #3
June 1, 2026 to June 30, 20262,254,060 $19.98 — $93.2 million
Total2,948,447 $20.37 — $93.2 million
______________

(1)In July 2024, the Company’s board of directors approved and promptly announced a stock repurchase program to acquire up to $150 million of the Company’s outstanding common stock. In March 2025, the Company’s board of directors approved and promptly announced an additional $100 million authorization under this stock repurchase program. The program allows the Company to repurchase its shares from time to time in the open market, block transactions and in negotiated transactions. Subsequent to June 30, 2026, in July 2026, the Company’s board of directors approved and promptly announced an additional $150 million authorization under this stock repurchase program.


Item 3.  Defaults Upon Senior Securities.

None.



Item 4.  Mine Safety Disclosures.

Not applicable.


Item 5.  Other Information.

(a)    None.

(b)    None.

(c)    The information required by Item 408(a) of Regulation S-K is included in the table below.
Name (Title)ActionDateTrading ArrangementTotal Shares to be SoldExpiration Date
Rule 10b5-1*Non-Rule 10b5-1**
Adam Dirlam (President)
AdoptJune 4, 2026X17,350August 31, 2027
* Intended to satisfy the affirmative defense of Rule 10b5-1(c) under the Exchange Act.
** Not intended to satisfy the affirmative defense of Rule 10b5-1(c) under the Exchange Act.





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Item 6.  Exhibits.

Exhibit No.DescriptionReference
Asset Purchase and Sale Agreement, dated May 22, 2026, among Parallax Energy Operating Inc., NOG Energy Canada, Ltd. and, for certain limited purposes, Northern Oil and Gas, Inc.Incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on May 26, 2026
Restated Certificate of Incorporation of Northern Oil and Gas, Inc., dated August 24, 2018Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on August 27, 2018
Certificate of Amendment to the Restated Certificate of Incorporation of Northern Oil and Gas, Inc., dated September 18, 2020Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on September 24, 2020
Certificate of Amendment of Restated Certificate of Incorporation of Northern Oil and Gas, Inc., dated May 23, 2024Incorporated by reference to Exhibit 3.3 to the Registrant’s Quarterly Report on Form 10-Q filed with the SEC on July 31, 2024
Amended and Restated Bylaws of Northern Oil and Gas, Inc.Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on January 20, 2023
Registration Rights Agreement, dated June 1, 2026, by and between Northern Oil and Gas, Inc. and Parallax Energy Operating Inc.Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on June 1, 2026
Second Amendment to the Fourth Amended and Restated Credit Agreement among Northern Oil and Gas, Inc., Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto, dated May 13, 2026Filed herewith
Certification of the Principal Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002Filed herewith
Certification of the Principal Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002Filed herewith
Certification of the Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C.  Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002Furnished herewith
101.INSInline XBRL Instance DocumentFiled herewith
101.SCHInline XBRL Taxonomy Extension Schema DocumentFiled herewith
101.CALInline XBRL Taxonomy Extension Calculation Linkbase DocumentFiled herewith
101.DEFInline XBRL Taxonomy Extension Definition Linkbase DocumentFiled herewith
101.LABInline XBRL Taxonomy Extension Label Linkbase DocumentFiled herewith
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101.PREInline XBRL Taxonomy Extension Presentation Linkbase DocumentFiled herewith
104
The cover page from Northern Oil and Gas, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2026, formatted in Inline XBRL and contained in Exhibit 101
Filed herewith
* Certain of the schedules and exhibits to this Exhibit have been omitted pursuant to Item 601(a)(5) of Regulation S-K. A copy of any omitted schedule or exhibit will be furnished to the SEC upon request. Certain personally identifiable information has also been omitted from this exhibit pursuant to Item 601(a)(6) of Regulation S-K.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

NORTHERN OIL AND GAS, INC.

Date:August 7, 2026By:/s/ Nicholas O’Grady
Nicholas O’Grady, Chief Executive Officer
(on behalf of Registrant)
Date:August 7, 2026By:/s/ Chad Allen
Chad Allen, Chief Financial Officer and principal financial and accounting officer
(on behalf of Registrant)

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Exhibit 10.2
Execution Version

SECOND AMENDMENT TO
FOURTH AMENDED AND RESTATED CREDIT AGREEMENT

This SECOND AMENDMENT TO FOURTH AMENDED AND RESTATED CREDIT AGREEMENT (this “Amendment”) dated as of May 13, 2026, is among NORTHERN OIL AND GAS, INC., a Delaware corporation (the “Borrower”) and WELLS FARGO BANK, NATIONAL ASSOCIATION, as administrative agent (in such capacity, together with its successors in such capacity, the “Administrative Agent”) and as collateral agent (in such capacity, together with its successors in such capacity, the “Collateral Agent”).
RECITALS
A.    The Borrower, the Administrative Agent and the Lenders are party to that certain Fourth Amended and Restated Credit Agreement dated as of November 5, 2025 (as amended, restated, amended and restated, supplemented or otherwise modified from time to time, the “Credit Agreement”), pursuant to which the Lenders have made certain credit available to and on behalf of the Borrower.
B.    Pursuant to Section 12.02(b) the Borrower, the Administrative Agent and the Collateral Agent may amend the Credit Agreement to correct, amend or cure any ambiguity, inconsistency or defect and the Borrower is requesting such an amendment to cure an inconsistency in Section 7.14 of the Credit Agreement.
C.    The Borrower, the Administrative Agent and the Collateral Agent have agreed to amend certain provisions of the Credit Agreement to cure such inconsistency in Section 7.14 of the Credit Agreement.
D.    NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:
Section 1.    Defined Terms. Each capitalized term which is defined in the Credit Agreement, but which is not defined in this Amendment, shall have the meaning ascribed such term in the Credit Agreement after giving effect to this Amendment. Unless otherwise indicated, all references to sections in this Amendment refer to sections in the Credit Agreement as amended by this Amendment.
Section 2.    Amendments to Credit Agreement. Effective as of the Second Amendment Effective Date (as defined below), the first two sentences of Section 7.14 of the Credit Agreement are hereby amended and restated in their entirety as follows:

As of the date hereof, or as of the date of the most recent certificate delivered pursuant to Section 8.01(c), except as set forth on Schedule 7.14 or as disclosed in writing to the Administrative Agent (which shall promptly furnish a copy to the Lenders), and which disclosure (including updates included in certificates delivered pursuant to Section 8.01(c)) shall be a supplement to Schedule 7.14, none of the Credit Parties has any direct or indirect Subsidiaries or Unrestricted Subsidiaries or any direct or indirect Foreign Subsidiaries that are Restricted Subsidiaries. The Borrower does not have any direct or indirect Foreign Subsidiaries that are Restricted Subsidiaries.




Section 3.    Conditions Precedent. This Amendment shall become effective on the date, when each of the following conditions is satisfied (the “Second Amendment Effective Date”):
3.1    The Administrative Agent shall have executed and received from the Collateral Agent and the Borrower, counterparts (in such number as may be requested by the Administrative Agent) of this Amendment signed on behalf of each such Person.
3.2    Each representation and warranty contained in Section 4 hereof shall be true and correct in all material respects (except for those which have a materiality qualifier, which are true and correct in all respects as so qualified), except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, on and as of the date hereof, such representations and warranties shall continue to be true and correct in all material respects (except for those which have a materiality qualifier, which shall be true and correct in all respects as so qualified) as of such specified earlier date.
Section 4.    Representations and Warranties. In order to induce the Administrative Agent and the Collateral Agent to enter into this Amendment, the Borrower hereby represents and warrants to the Administrative Agent and the Collateral Agent that:
4.1    Accuracy of Representations and Warranties. Each representation and warranty of each Credit Party contained in each Loan Document are true and correct in all material respects (except for those which have a materiality qualifier, which are true and correct in all respects as so qualified) on and as of the date hereof, except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, such representations and warranties continue to be true and correct in all material respects (except for those which have a materiality qualifier, which are true and correct in all respects as so qualified) as of such specified earlier date.
4.2    Due Authorization, No Conflicts. The execution, delivery and performance by the Borrower of this Amendment are within the Borrower’s corporate powers, have been duly authorized by necessary action, require no action by or in respect of, or filing with, any governmental body, agency or official (other than filings with the SEC required under applicable law) and do not violate or constitute a default under any provision of applicable law, the Second Lien Indenture or any agreement evidencing Material Debt binding upon any Credit Party, or result in the creation or imposition of any Lien upon any Property of any Credit Party.
4.3    Validity and Binding Effect. This Amendment constitutes the valid and binding obligations of the Borrower enforceable in accordance with its terms, except as the enforceability thereof may be limited by bankruptcy, insolvency, reorganization, moratorium or similar laws affecting creditor’s rights generally, and subject to general principles of equity, regardless of whether considered in a proceeding in equity or law.
4.4    Absence of Defaults. No Default or Event of Default has occurred or is continuing immediately prior to and after giving effect to this Amendment.
Section 5.    Miscellaneous.
5.1    Confirmation. The Credit Agreement and each of the other Loan Documents, as specifically amended by this Amendment, are and shall continue to be in full force and effect and are hereby in all respects ratified and confirmed. Without limiting the generality of the foregoing, the Security Instruments and all of the Collateral described therein do and shall continue to secure the payment of all Secured Obligations of the Credit Parties under the Loan Documents, in each case, as amended by this
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Amendment. The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of any Lender or the Administrative Agent under any of the Loan Documents, nor constitute a waiver of any provision of any of the Loan Documents. On and after the Second Amendment Effective Date, this Amendment shall for all purposes constitute a Loan Document. This Amendment does not constitute a novation of the obligations and liabilities under the Credit Agreement or evidence repayment of any such obligations and liabilities.
5.2    Counterparts. This Amendment may be executed in counterparts (and by different parties hereto on different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute a single contract. Delivery of an executed counterpart of a signature page to this Amendment by fax, facsimile, as an attachment to an email or other similar electronic means shall be effective as delivery of a manually executed counterpart of this Amendment. The words “execution,” “execute”, “signed,” “signature,” and words of like import in or related to any document to be signed in connection with this Amendment shall be deemed to include electronic signatures, the electronic matching of assignment terms and contract formations on electronic platforms approved by the Administrative Agent, or the keeping of records in electronic form, each of which shall be of the same legal effect, validity or enforceability as a manually executed signature or the use of a paper-based recordkeeping system, as the case may be, to the extent and as provided for in any applicable law, including the Federal Electronic Signatures in Global and National Commerce Act, the New York State Electronic Signatures and Records Act, or any other similar state laws based on the Uniform Electronic Transactions Act. Each party hereto agrees that any Electronic Signature or execution in the form of an Electronic Record shall be valid and binding on itself and each of the other parties hereto to the same extent as a manual, original signature.  For the avoidance of doubt, the authorization under this paragraph may include, without limitation, use or acceptance by the parties of a manually signed paper which has been converted into electronic form (such as scanned into PDF format), or an electronically signed paper converted into another format, for transmission, delivery and/or retention.
5.3    No Oral Agreement. This Amendment, the Credit Agreement and the other Loan Documents represent the final agreement among the parties hereto and thereto and may not be contradicted by evidence of prior, contemporaneous or subsequent oral agreements of the parties. There are no unwritten oral agreements between the parties.
5.4    GOVERNING LAW. THIS AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.
5.5    Payment of Expenses. The Borrower agrees to pay or reimburse the Administrative Agent for all of its reasonable and documented out-of-pocket costs and expenses incurred in connection with this Amendment, any other documents prepared in connection herewith and the transactions contemplated hereby in accordance with Section 12.03 of the Credit Agreement.
5.6    Severability. Any provision of this Amendment which is held to be invalid, illegal or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such invalidity, illegality or unenforceability without affecting the validity, legality and enforceability of the remaining provisions hereof or thereof; and the invalidity of a particular provision in a particular jurisdiction shall not invalidate such provision in any other jurisdiction.
5.7    Successors and Assigns. This Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective successors and permitted assigns.
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5.8    Miscellaneous. Section 12.09(b), (c) and (d) of the Credit Agreement shall apply to this Amendment, mutatis mutandis.
[Signature pages follow.]
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IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed effective as of the day and year first above written.
BORROWER:
NORTHERN OIL AND GAS, INC.
By:/s/ Chad Allen
Name:Chad Allen
Title:Chief Financial Officer



Signature Page to|
Second Amendment to Fourth Amended and Restated Credit Agreement


ADMINISTRATIVE AGENT:
WELLS FARGO BANK, NATIONAL ASSOCIATION,
as Administrative Agent
By:/s/ Jonathan Herrick
Name:Jonathan Herrick
Title:Managing Director



COLLATERAL AGENT:
WELLS FARGO BANK, NATIONAL ASSOCIATION,
as Collateral Agent
By:/s/ Jonathan Herrick
Name:Jonathan Herrick
Title:Managing Director




Signature Page to|
Second Amendment to Fourth Amended and Restated Credit Agreement

Exhibit 31.1
CERTIFICATION

I, Nicholas O’Grady certify that:
1.I have reviewed this quarterly report on Form 10-Q of Northern Oil and Gas, Inc.;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; and
b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; and
c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;
5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
a)All significant deficiencies and material weakness in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated:  August 7, 2026
By: /s/ Nicholas O’Grady                                                                
Nicholas O’Grady
Principal Executive Officer

Exhibit 31.2
CERTIFICATION

I, Chad Allen certify that:
1.I have reviewed this quarterly report on Form 10-Q of Northern Oil and Gas, Inc.;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; and
b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; and
c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;
5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a)All significant deficiencies and material weakness in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


Dated:  August 7, 2026
By: /s/ Chad Allen
Chad Allen
Principal Financial Officer

Exhibit 32.1

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002


In connection with the Quarterly Report of Northern Oil and Gas, Inc., (the “Company”) on Form 10-Q for the quarterly period ended June 30, 2026, as filed with the United States Securities and Exchange Commission on the date hereof, (the “Report”), the undersigned officers of the Company hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:
 
(1)The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated:  August 7, 2026
By:   /s/ Nicholas O’Grady                                                              
Nicholas O’Grady
Principal Executive Officer

Dated:  August 7, 2026
By:       /s/ Chad Allen                                                                
Chad Allen
Principal Financial Officer


A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.