nog-20230331

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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 March 31, 2023

☐ 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)


Delaware			95-3848122
(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 class

Trading Symbol(s)

Name of each exchange on which registered

Common Stock, par value $0.001

NOG

New 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 May 1, 2023, there were 85,363,723 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.

“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.

“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.

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“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 and produce crude oil, NGLs, or natural gas in an unproved area, to find a new reservoir in a field previously found to be producing crude oil, NGLs, or natural gas in another reservoir, or to extend 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.

“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.

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“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:

“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 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,

iii

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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.

“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 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.

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NORTHERN OIL AND GAS, INC.

FORM 10-Q

March 31, 2023

C O N T E N T S


		Page
PART I – FINANCIAL INFORMATION

Item 1.	Condensed Financial Statements (unaudited)	2
	Condensed Balance Sheets	2
	Condensed Statements of Operations	4
	Condensed Statements of Cash Flows	5
	Condensed Statements of Stockholders’ Equity	6
	Notes to Condensed Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	40

Item 4.	Controls and Procedures	42

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	43

Item 1A.	Risk Factors	43

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43

Item 3.	Defaults Upon Senior Securities	44

Item 4.	Mine Safety Disclosures	44

Item 5.	Other Information	44

Item 6.	Exhibits	45

Signatures		46

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PART I - FINANCIAL INFORMATION

Item 1. Condensed Financial Statements.

NORTHERN OIL AND GAS, INC.

CONDENSED BALANCE SHEETS


(In thousands, except par value and share data)	March 31, 2023		December 31, 2022
Assets	(Unaudited)
Current Assets:
Cash and Cash Equivalents	$	6,073	$	2,528
Accounts Receivable, Net	274,399		271,336
Advances to Operators	40,985		8,976
Prepaid Expenses and Other	2,328		2,014
Derivative Instruments	72,156		35,293
Income Tax Receivable	—		338
Total Current Assets	395,941		320,485

Property and Equipment:
Oil and Natural Gas Properties, Full Cost Method of Accounting
Proved	7,019,244		6,492,683
Unproved	41,846		41,565
Other Property and Equipment	7,096		6,858
Total Property and Equipment	7,068,185		6,541,106
Less – Accumulated Depreciation, Depletion and Impairment	(4,152,245)		(4,058,180)
Total Property and Equipment, Net	2,915,940		2,482,926

Derivative Instruments	14,495		12,547

Acquisition Deposit	—		43,000
Other Noncurrent Assets, Net	16,490		16,220

Total Assets	$	3,342,866	$	2,875,178

Liabilities and Stockholders' Equity
Current Liabilities:
Accounts Payable	$	134,264	$	128,582
Accrued Liabilities	162,066		121,737
Accrued Interest	15,221		24,347

Income Tax Payable	353		—
Derivative Instruments	27,560		58,418
Contingent Consideration	3,931		10,107



Other Current Liabilities	1,905		1,781
Total Current Liabilities	345,300		344,972

Long-term Debt, Net	1,756,949		1,525,413

Derivative Instruments	156,603		225,905


Asset Retirement Obligations	32,905		31,582
Other Noncurrent Liabilities	3,042		2,045

Total Liabilities	$	2,294,799	$	2,129,917

Commitments and Contingencies

Stockholders’ Equity

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Common Stock, Par Value $.001; 135,000,000 Shares Authorized; 85,370,223 Shares Outstanding at 3/31/2023 85,165,807 Shares Outstanding at 12/31/2022	487		487
Additional Paid-In Capital	1,708,147		1,745,532
Retained Deficit	(660,568)		(1,000,759)
Total Stockholders’ Equity	1,048,067		745,260
Total Liabilities and Stockholders’ Equity	$	3,342,866	$	2,875,178

______________

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

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NORTHERN OIL AND GAS, INC.

CONDENSED STATEMENTS OF OPERATIONS

(UNAUDITED)


	Three Months Ended March 31,
(In thousands, except share and per share data)	2023		2022
Revenues
Oil and Gas Sales	$	426,234	$	456,458
Gain (Loss) on Commodity Derivatives, Net	153,656		(489,388)
Other Revenues	2,324		—
Total Revenues	582,214		(32,930)

Operating Expenses
Production Expenses	78,088		54,540
Production Taxes	34,918		34,616
General and Administrative Expenses	13,000		13,813
Depletion, Depreciation, Amortization and Accretion	94,618		53,185
Other Expenses	1,001		—


Total Operating Expenses	221,625		156,154

Income (Loss) From Operations	360,589		(189,084)

Other Income (Expense)
Interest Expense, Net of Capitalization	(30,143)		(17,977)

Gain (Loss) on Unsettled Interest Rate Derivatives, Net	(1,017)		1,290
Gain on Extinguishment of Debt, Net	659		—

Contingent Consideration Gain	6,176		—


Other Income (Expense)	4,619		—
Total Other Income (Expense)	(19,706)		(16,687)

Income (Loss) Before Income Taxes	340,883		(205,771)

Income Tax Provision (Benefit)	692		789

Net Income (Loss)	$	340,191	$	(206,560)

Cumulative Preferred Stock Dividend	—		(3,016)

Premium on Repurchase of Preferred Stock	—		(14,957)

Net Income (Loss) Attributable to Common Stockholders	$	340,191	$	(224,533)

Net Income (Loss) Per Common Share – Basic	$	4.01	$	(2.92)
Net Income (Loss) Per Common Share – Diluted	$	3.98	$	(2.92)
Weighted Average Common Shares Outstanding – Basic	84,915,729		76,922,543
Weighted Average Common Shares Outstanding – Diluted	85,407,197		76,922,543

______________

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

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NORTHERN OIL AND GAS, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(UNAUDITED)


	Three Months Ended March 31,
(In thousands)	2023		2022
Cash Flows from Operating Activities
Net Income (Loss)	$	340,191	$	(206,560)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
Depletion, Depreciation, Amortization, and Accretion	94,618		53,185
Amortization of Debt Issuance Costs	1,751		1,078

(Gain) Loss on Extinguishment of Debt	(659)		—
Amortization of Bond Premium on Long-term Debt	(510)		(531)
Deferred Income Taxes	692		789
Unrealized (Gain) Loss of Derivative Instruments	(138,970)		382,937

(Gain) Loss on Contingent Consideration	(6,176)		—


Stock-Based Compensation Expense	2,151		1,447


Other	3,084		2,675
Changes in Working Capital and Other Items:
Accounts Receivable, Net	(2,866)		(102,033)
Prepaid and Other Expenses	(314)		(698)
Accounts Payable	(11,903)		33,243
Accrued Interest	(8,915)		(14,488)
Accrued Liabilities and Expenses	(2,866)		2,991

Net Cash Provided by Operating Activities	269,308		154,034

Cash Flows from Investing Activities
Capital Expenditures on Oil and Natural Gas Properties	(460,982)		(417,482)




Purchases of Other Property and Equipment	(238)		(117)
Net Cash Used for Investing Activities	(461,220)		(417,599)

Cash Flows from Financing Activities
Advances on Revolving Credit Facility	337,000		434,000
Repayments on Revolving Credit Facility	(87,000)		(118,000)
Repurchase of Senior Notes	(18,436)		—





Debt Issuance Costs Paid	(32)		(13)




Repurchases of Common Stock	(8,004)		—

Repurchases of Preferred Stock	—		(50,225)
Restricted Stock Surrenders - Tax Obligations	(2,616)		(2,206)

Common Dividends Paid	(25,454)		(6,176)
Net Cash Provided by Financing Activities	195,458		257,380

Net Increase (Decrease) in Cash and Cash Equivalents	3,545		(6,185)

Cash and Cash Equivalents - Beginning of Period	2,528		9,519

Cash and Cash Equivalents - End of Period	6,073		3,335

______________

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

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NORTHERN OIL AND GAS, INC.

CONDENSED STATEMENTS OF STOCKHOLDERS’ EQUITY

(UNAUDITED)


(In thousands, except share data)	Common Stock			Preferred Stock			Additional Paid-In		Retained Earnings		Total Stockholders’ Equity
	Shares	Amount		Shares	Amount		Capital		(Deficit)		(Deficit)
December 31, 2022	85,165,807	$	487	—	$	—	$	1,745,532	$	(1,000,759)	$	745,260

Issuance of Common Stock	193,293	—		—	—		—		—		—
Restricted Stock Forfeitures	(6,854)	—		—	—		(54)		—		(54)
Share Based Compensation	—	—		—	—		2,316		—		2,316
Restricted Stock Surrenders - Tax Obligations	(98,052)	—		—	—		(2,616)		—		(2,616)




Issuance of Common Stock in Exchange for Warrants	403,780	—		—	—		—		—		—


Repurchases of Common Stock	(287,751)	—		—	—		(8,004)		—		(8,004)



Common Stock Dividends Declared	—	—		—	—		(29,026)		—		(29,026)
Net Income	—	—		—	—		—		340,191		340,191
March 31, 2023	85,370,223	$	487	—	$	—	$	1,708,147	$	(660,568)	$	1,048,067


(In thousands, except share data)	Common Stock			Preferred Stock			Additional Paid-In		Retained Earnings		Total Stockholders’ Equity
	Shares	Amount		Shares	Amount		Capital		(Deficit)		(Deficit)
December 31, 2021	77,341,921	$	479	2,218,732	$	2	$	1,988,649	$	(1,773,996)	$	215,135

Issuance of Common Stock	15,651	—		—	—		—		—		—
Restricted Stock Forfeitures	(1,815)	—		—	—		—		—		—
Share Based Compensation	—	—		—	—		1,499		—		1,499
Restricted Stock Surrenders - Tax Obligations	(89,620)	—		—	—		(2,206)		—		(2,206)




Issuance of Common Stock Warrants - Acquisitions of Oil and Natural Gas Properties	—	—		—	—		17,870		—		17,870



Repurchases of Preferred Stock	—	—		(362,671)	—		(50,225)		—		(50,225)

Common Stock Dividends Declared	—	—		—	—		(10,815)		—		(10,815)
Net Loss	—	—		—	—		—		(206,560)		(206,560)

March 31, 2022	77,266,137	$	479	1,856,061	$	2	$	1,944,773	$	(1,980,556)	$	(35,302)

___________

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

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NOTES TO CONDENSED FINANCIAL STATEMENTS

MARCH 31, 2023

(UNAUDITED)

NOTE 1 ORGANIZATION AND NATURE OF BUSINESS

Northern Oil and Gas, Inc. (the “Company,” “Northern,” “our” and words of similar import), a Delaware corporation, is an independent energy company engaged in the acquisition, exploration, exploitation, development and production of crude oil and natural gas properties. 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 with operations in the United States. The Company’s primary strategy is investing in non-operated minority working and mineral interests in oil and gas properties in the United States.

NOTE 2 BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The financial information included herein is unaudited. The balance sheet as of December 31, 2022 has been derived from the Company’s audited financial statements for the year ended December 31, 2022. However, such information includes all adjustments (consisting of normal recurring adjustments) that are, in the opinion of management, necessary for a fair presentation of 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 accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted in this Form 10-Q pursuant to certain rules and regulations of the Securities and Exchange Commission (“SEC”). The condensed financial statements should be read in conjunction with the audited financial statements for the year ended December 31, 2022, which were included in the Company’s 2022 Annual Report on Form 10-K for the fiscal year ended December 31, 2022.

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 includes 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 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 financial statements.

Reclassifications

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

Adopted and Recently Issued Accounting Pronouncements

From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”) that are adopted by the Company as of the specified effective date. 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.

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Revenue Recognition

The Company’s revenues are primarily derived from its interests in the sale 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 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 trade receivables, net in the balance sheets. Variances between the Company’s estimated revenue and actual payments are recorded in the month the payment is received, however, differences have been and are 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 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 contracts 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.

A wellhead imbalance liability equal to the Company’s share is recorded to the extent that the Company’s well operators have sold volumes in excess of its share of remaining reserves in an underlying property. However, for the three months ended March 31, 2023 and 2022, the Company’s natural gas production was in balance, meaning its cumulative portion of natural gas production taken and sold from wells in which it has an interest equaled its entitled interest in natural gas production from those wells.

The Company’s disaggregated revenue has two primary sources: oil sales and natural gas and NGL sales. Substantially all of the Company’s oil and natural gas sales come from three geographic areas in the United States: the Williston Basin (North Dakota and Montana), the Appalachian Basin (Pennsylvania), and the Permian Basin (New Mexico and Texas). The following tables present the disaggregation of the Company’s oil revenues and natural gas and NGL revenues by basin for the three months ended March 31, 2023 and 2022.


	Three Months Ended March 31, 2023								Three Months Ended March 31, 2022
(In thousands)	Williston		Permian		Appalachian		Total		Williston		Permian		Appalachian		Total
Oil Revenues	$	212,723	$	142,655	$	—	$	355,378	$	268,010	$	80,816	$	—	$	348,826
Natural Gas and NGL Revenues	32,423		23,104		15,329		70,856		62,620		18,214		26,797		107,632
Other	—		2,324		—		2,324		—		—		—		—
Total	$	245,146	$	168,083	$	15,329	$	428,558	$	330,631	$	99,030	$	26,797	$	456,458

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.

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.

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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 development, exploitation, production and exploration activities relating to the Company’s leasehold interests, or are unable or unwilling to perform, the Company’s financial condition and results of operation 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 March 31, 2023, the Company’s top four operators made up 38% of total oil and natural gas sales, compared to 43% for the three months ended March 31, 2022.

The Company faces concentration risk due to the fact that a majority of its oil and natural gas revenue is sourced from North Dakota. Acquisitions since 2021 have diversified the Company’s portfolio to include New Mexico, Pennsylvania and Texas, but the Company remains disproportionately exposed to risks affecting a limited number of geographic areas of operations.

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 temporary 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 shares issuable upon exercise of stock options or warrants and vesting of restricted stock awards, and shares issuable upon conversion of the Preferred Stock or 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 end of the reporting period were the end of the contingency period, assuming the result would be dilutive.

The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three months ended March 31, 2023 and 2022 are as follows:

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	Three Months Ended March 31,
(In thousands, except share and per share data)	2023		2022
Net Income (Loss)	$	340,191	$	(206,560)
Less: Cumulative Dividends on Preferred Stock	—		(3,016)
Less: Premium on Repurchase of Preferred Stock	—		(14,957)
Net (Income) Loss Attributable to Common Stockholders	340,191		$	(224,533)

Weighted Average Common Shares Outstanding:
Weighted Average Common Shares Outstanding – Basic	84,915,729		76,922,543
Plus: Dilutive Effect of Restricted Stock, Warrants, Preferred Shares and Convertible Notes	491,468		—

Weighted Average Common Shares Outstanding – Diluted	85,407,197		76,922,543

Net Income (Loss) per Common Share:
Basic	$	4.01	$	(2.92)
Diluted	$	3.98	$	(2.92)

Shares Excluded from EPS Due to Anti-Dilutive Effect:
Restricted Stock	610		239,033

Supplemental Cash Flow Information

The following reflects the Company’s supplemental cash flow information:


	Three Months Ended March 31,
(In thousands)	2023		2022
Supplemental Cash Items:
Cash Paid During the Period for Interest, Net of Amount Capitalized	$	28,878	$	29,147
Cash Paid During the Period for Income Taxes	—		65




Non-cash Investing Activities:
Oil and Natural Gas Properties Included in Accounts Payable and Accrued Liabilities	217,065		139,799
Capitalized Asset Retirement Obligations	962		1,586

Compensation Capitalized on Oil and Gas Properties	111		53
Issuance of Common Stock Warrants - Acquisition of Oil and Natural Gas Properties	—		17,870




Non-cash Financing Activities:




Issuance of Common Stock Warrants - Acquisitions of Oil and Natural Gas Properties	—		17,870
Issuance of Common Stock in Exchange for Warrants	13,328		—
Common Stock Dividends Declared, But Not Paid	29,021		10,815

NOTE 3 CRUDE OIL AND NATURAL GAS PROPERTIES

The Company follows the full cost method of accounting for 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 single cost center (“full cost pool”). 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,

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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. The test determines a limit, or ceiling, on the book value of the proved oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The Company did not have any impairment of its proved oil and gas properties for the three months ended March 31, 2023 and 2022, respectively.

The book value of the Company’s crude oil and natural gas properties consists of all acquisition costs (including cash expenditures and the value of stock consideration), 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 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.

2023 Acquisitions

In addition to the closing of the MPDC Acquisition (defined below), during the three months ended March 31, 2023, the Company acquired oil and natural gas properties, through a number of independent transactions, for a total of $13.0 million.

MPDC Acquisition

On January 5, 2023, the Company completed its acquisition (the “MPDC Acquisition”) of certain oil and gas properties, interests and related assets from Midland Petro D.C. Partners, LLC and Collegiate Midstream LLC (collectively, “MPDC”), effective as of August 1, 2022. At closing, the Company acquired a 39.958% working interest in MPDC’s four-unit development project in the Permian Midland Basin, which includes an interest in gathering assets associated with the project.

The total consideration at closing was $319.9 million in cash. As a result of customary post-closing adjustments, the Company reduced its proved oil and natural gas properties and total consideration by $11.3 million subsequent to closing.

The results of operations from the acquisition from the January 5, 2023 closing date through March 31, 2023, represented approximately $27.3 million of revenue and $16.8 million of income from operations. The Company incurred $3.4 million of transaction costs in connection with the acquisition, which are included in general and administrative expense in the statement of operations. The following table reflects the fair values 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	$	320,395

Total assets acquired	320,395
Asset retirement obligations	(451)
Net assets acquired	$	319,944

Fair value of consideration paid for net assets:
Cash consideration	$	319,944
Total fair value of consideration transferred	$	319,944

2022 Acquisitions

During 2022, the Company completed the following larger bolt-on acquisitions (each as defined and described below): the Veritas Acquisition, the Incline Acquisition, the Laredo Acquisition, the Alpha Acquisition, and the Delaware Acquisition (collectively, the “2022 Bolt-on Acquisitions”).

During 2022, in addition to the 2022 Bolt-on Acquisitions, the Company acquired oil and natural gas properties through a number of smaller independent transactions for a total of $100.0 million.

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Veritas Acquisition

On January 27, 2022, the Company completed the acquisition of certain non-operated oil and gas properties, interests and related assets in the Permian Basin from Veritas TM Resources, LLC, Veritas Permian Resources, LLC, Veritas Lone Star Resources, LLC, and Veritas MOC Resources, LLC, effective as of October 1, 2021 (the “Veritas Acquisition”).

The total consideration was $408.8 million, which included $390.9 million in cash and warrants to purchase 1,939,998 shares of the Company’s common stock, par value $0.001 per share, at an exercise price equal to $28.30 per share. The warrants had a total estimated fair value of $17.9 million. As a result of customary post-closing adjustments, the Company further decreased its proved oil and natural gas properties and total consideration by $3.0 million subsequent to closing.

The results of operations from the acquisition from the January 27, 2022 closing date through December 31, 2022, represented approximately $244.1 million of revenue and $168.0 million of income from operations. The Company incurred $7.3 million of transaction costs in connection with the acquisition, which are included in general and administrative expense in the Company’s statement of operations. The following table reflects the fair values of the net assets and liabilities as of the date of acquisition:


	(In thousands)
Fair value of net assets:
Proved oil and natural gas properties	$	383,755
Unproved oil and natural gas properties	26,262

Total assets acquired	410,017
Asset retirement obligations	(1,219)
Net assets acquired	$	408,798

Fair value of consideration paid for net assets:
Cash consideration	$	390,928
Issuance of Common Stock Warrants (1.9 million shares at $28.30 per share)	17,870
Total fair value of consideration transferred	$	408,798

Incline Acquisition

On August 15, 2022, the Company completed the acquisition of certain non-operated oil and gas properties, interests and related assets in the Williston Basin from Incline Bakken, LLC, effective as of April 1, 2022 (the “Incline Acquisition”).

The total consideration at closing was $159.8 million which includes $158.0 million in cash and $1.8 million in value attributable to potential additional contingent consideration (described in more detail below). As a result of customary post-closing adjustments, the Company reduced its proved oil and natural gas properties and total consideration by $6.6 million subsequent to closing.

The results of operations from the acquisition from the August 15, 2022 closing date through December 31, 2022, represented approximately $25.3 million of revenue and $17.0 million of income from operations. The Company incurred $1.1 million of transaction costs in connection with the acquisition, which are included in general and administrative expense in the Company’s statement of operations. The following table reflects the fair values of the net assets and liabilities as of the closing date of the acquisition:

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	(In thousands)
Fair value of net assets:
Proved oil and natural gas properties	$	160,155


Total assets acquired	160,155
Asset retirement obligations	(319)
Net assets acquired	$	159,836

Fair value of consideration paid for net assets:
Cash consideration	$	157,977
Contingent consideration	1,850
Total fair value of consideration transferred	$	159,827

A contingent consideration liability arising from potential additional consideration in connection with the Incline Acquisition was recognized at its fair value. The seller had the potential to earn up to $5.0 million of additional cash consideration dependent upon NYMEX WTI oil pricing at the end of 2022. This contingent consideration was not earned, and there was no remaining associated liability as of December 31, 2022. The acquisition date fair value of the potential additional consideration, totaling $1.8 million, was recorded within contingent consideration liabilities on the Company’s balance sheets. Changes in the fair value of the liability (that were not accounted for as revisions of the acquisition date fair value) are recorded in other income (expense) on the Company’s statement of operations.

Laredo Acquisition

On October 3, 2022, the Company completed the acquisition of certain non-operated oil and gas properties, interests and related assets in the Permian Midland Basin from Laredo Petroleum, Inc., effective as of August 1, 2022 (the “Laredo Acquisition”).

The total consideration at closing was $110.1 million in cash. As a result of customary post-closing adjustments, the Company reduced its proved oil and natural gas properties and total consideration by $3.2 million subsequent to closing.

The results of operations from the acquisition from the October 3, 2022 closing date through December 31, 2022, represented approximately $9.4 million of revenue and $6.8 million of income from operations. The Company incurred $0.8 million of transaction costs in connection with the acquisition, which are included in general and administrative expense in the Company’s statement of operations. The following table reflects the fair values 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	$	110,258

Total assets acquired	110,258
Asset retirement obligations	(187)
Net assets acquired	$	110,071

Fair value of consideration paid for net assets:
Cash consideration	$	110,071

Total fair value of consideration transferred	$	110,071

Alpha Acquisition

On December 1, 2022, the Company completed the acquisition of certain non-operated oil and gas properties, interests and related assets in the Permian Midland Basin from Alpha Energy Partners, effective as of September 1, 2022 (the “Alpha Acquisition”).

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The total consideration at closing was $164.0 million, which includes $153.9 million in cash and $10.1 million in value attributable to potential additional contingent consideration (described in more detail below). As a result of customary post-closing adjustments, the Company increased its proved oil and natural gas properties and total consideration by $0.3 million subsequent to closing.

The results of operations from the acquisition from the December 1, 2022 closing date through December 31, 2022, represented approximately $2.6 million of revenue and $1.5 million of income from operations. The Company incurred $1.3 million of transaction costs in connection with the acquisition, which are included in general and administrative expense in the Company’s statement of operations. The following table reflects the fair values 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	$	164,300

Total assets acquired	164,300
Asset retirement obligations	(278)
Net assets acquired	$	164,023

Fair value of consideration paid for net assets:
Cash consideration	$	153,916
Contingent consideration	10,107
Total fair value of consideration transferred	$	164,023

A contingent consideration liability arising from potential additional consideration in connection with the Alpha Acquisition was recognized at its fair value. The seller has the potential to earn additional cash consideration dependent upon average front month NYMEX WTI oil pricing during the first six months of 2023. The amount will be determined on a sliding scale from zero additional consideration if such pricing is below $75.00 per barrel, up to $22.5 million of additional consideration if such pricing is at least $87.85 per barrel. The acquisition date fair value of the potential additional consideration, totaling $10.1 million, was recorded within contingent consideration liabilities on the Company’s condensed balance sheets. Changes in the fair value of the liability are recorded in other income (expense) on the Company’s condensed statement of operations. For the three months ended March 31, 2023 we recorded a $6.2 million contingent consideration gain relating to the change in fair value of the liability.

Delaware Acquisition

On December 16, 2022, the Company completed the acquisition of certain non-operated oil and gas properties, interests and related assets in the Permian Delaware Basin from a private seller, effective as of November 1, 2022 (the “Delaware Acquisition”).

The total consideration at closing was $131.6 million in cash. As a result of customary post-closing adjustments, the Company increased its proved oil and natural gas properties and total consideration by $0.1 million subsequent to closing.

The results of operations from the acquisition from the December 16, 2022 closing date through December 31, 2022, represented approximately $1.2 million of revenue and $0.7 million of income from operations. The Company incurred $1.3 million of transaction costs in connection with the acquisition, which are included in general and administrative expense in the Company’s statement of operations. The following table reflects the fair values of the net assets and liabilities as of the closing date of the acquisition:

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	(In thousands)
Fair value of net assets:
Proved oil and natural gas properties	$	131,773


Total assets acquired	131,773
Asset retirement obligations	(155)
Net assets acquired	$	131,618

Fair value of consideration paid for net assets:
Cash consideration	$	131,618

Total fair value of consideration transferred	$	131,618

Pro Forma Information

The following summarized unaudited pro forma condensed statement of operations information for the three months ended March 31, 2022, assumes that the MPDC Acquisition and each of the 2022 Bolt-on Acquisitions occurred as of January 1, 2022. There is no pro forma information included for the three months ended March 31, 2023, because the Company’s actual financial results for such period fully reflect all such acquisitions. 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, 2022, or that would be attained in the future.

Three Months Ended

(In thousands)

March 31, 2022

Total Revenues

107,005

Net Income (Loss)

(103,782)

Unproved Properties

All 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. Once a property is classified as proved, 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 costs will become subject to depletion within the next five years by proving up reserves relating to the acreage through exploration and development activities, by impairing the acreage that will expire before the Company can explore or develop it further or by determining that further exploration and development activity will not occur. The timing by which all other 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 impaired unproved properties, 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 on 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 as they are either developed or impaired. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion and full cost ceiling calculations. For the three months ended March 31, 2023 and 2022, unproved properties of $0.6 million and $1.3 million, respectively, were impaired.

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NOTE 4 LONG-TERM DEBT

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


	March 31, 2023
(In thousands)	Principal Balance		Unamortized Premium		Debt Issuance Costs, Net		Long-term Debt, Net
Revolving Credit Facility (1)	$	569,000	$	—	$	—	$	569,000
Senior Notes	705,108		9,901		(11,072)		703,937
Convertible Notes	500,000		—		(15,988)		484,012
Total	$	1,774,108	$	9,901	$	(27,060)	$	1,756,949

	December 31, 2022
	Principal Balance		Unamortized Net Premium		Debt Issuance Costs, Net		Long-term Debt, Net
Revolving Credit Facility (1)	$	319,000	$	—	$	—	$	319,000
Senior Notes	724,235		10,682		(11,946)		722,972
Convertible Notes	500,000		—		(16,558)		483,442
Total	$	1,543,235	$	10,682	$	(28,504)	$	1,525,413

________________

(1)Debt issuance costs related to the Company’s Revolving Credit Facility of $10.4 million and $10.9 million as of March 31, 2023 and December 31, 2022, are recorded in “Other Noncurrent Assets, Net” in the balance sheets.

Revolving Credit Facility

On June 7, 2022, the Company entered into a Third Amended and Restated Credit Agreement (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 on November 22, 2019. The Revolving Credit Facility is scheduled to mature on June 7, 2027.

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 gas properties. As of March 31, 2023, the borrowing base was $1.6 billion and the aggregate elected commitment amount was $1.0 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 1st and October 1st, 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 gas properties with an aggregate value exceeding 5% of the borrowing base, the Company may request an additional redetermination. The scheduled redetermination are based on a December 31st or June 30th reserve report, as applicable, prepared under the supervision of the Company’s chief engineer and, in the case of the December 31st reserve report, audited by an approved petroleum engineer (reasonably acceptable to the Agent). The Company has the option to seek commitments for term loans, which such term loans (if obtained) are capped at the least of (1) the borrowing base minus the aggregate elected commitment amount minus the then-outstanding principal amount of term loans, (ii) the aggregate elected commitment amount minus the then-outstanding principal amount of term loans and (iii) $500.0 million. Such term loans are subject to certain other terms of the Revolving Credit Facility.

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 125 to 225 basis points, and the applicable margin for SOFR loans ranges from 225 to 325 basis points, in each case depending on the percentage of the borrowing base utilized.

The Revolving Credit Facility contains negative covenants that limit the Company’s ability, among other things, to pay dividends, incur additional indebtedness, sell assets, enter into certain derivatives contracts, change the nature of its business or

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operations, merge, consolidate, or make certain types of investments. In addition, the Revolving Credit Facility requires that the Company comply with the following financial covenants: (i) as of the date of determination, the ratio of total net debt to EBITDAX (as defined in the Revolving Credit Facility) shall be no more than 3.50 to 1.00, measured on a rolling four quarter basis, and (ii) the current ratio (defined as consolidated current assets including unused amounts of the total commitments, but excluding non-cash assets under FASB ASC 815, divided by consolidated current liabilities excluding current non-cash obligations under FASB ASC 815, current maturities under the Revolving Credit Facility and current maturities of any long-term debt) shall not be less than 1.00 to 1.00. The Company is in compliance with these financial covenants as of March 31, 2023.

The Company’s obligations under the Revolving Credit Facility may be accelerated, subject to customary grace and cure periods, upon the occurrence of certain Events of Default (as defined in the Revolving Credit Facility). Such Events of Default include customary events for a financing agreement of this type, including, without limitation, payment defaults, the inaccuracy of representations and warranties, defaults in the performance of affirmative or negative covenants, defaults on other indebtedness of the Company or its subsidiaries, defaults related to judgments and the occurrence of a Change in Control (as defined in the Revolving Credit Facility).

The Company’s obligations under the Revolving Credit Facility are secured by mortgages on not less than 90% of the value of proven reserves associated with the oil and 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

On February 18, 2021, the Company and Wilmington Trust, National Association, as trustee, entered into an indenture (the “Senior Notes Indenture”), pursuant to which the Company issued $550.0 million in aggregate principal amount of 8.125% senior unsecured notes due 2028 (the “Original 2028 Notes”). On November 15, 2021, the Company issued an additional $200.0 million aggregate principal amount of 8.125% senior notes due 2028 (the “Additional 2028 Notes” and, together with the Original 2028 Notes, the “Senior Notes”). The proceeds of the Senior Notes were used primarily to refinance existing indebtedness, and for general corporate purposes.

During the three months ended March 31, 2023, the Company repurchased and retired $