NORTHERN OIL & GAS, INC. [NOG] Filings

10-Q 1 nog-20220331.htm 10-Q nog-20220331

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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, 2022

☐ 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)

N/A

(Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report)

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 4, 2022, there were 77,333,290 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 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 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 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.

“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.

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“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.

(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 (“LKH”) 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 (“HKO”) 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.

“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, 2022

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	26

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	36

Item 4.	Controls and Procedures	38

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	39

Item 1A.	Risk Factors	39

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39

Item 3.	Defaults Upon Senior Securities	39

Item 4.	Mine Safety Disclosures	39

Item 5.	Other Information	39

Item 6.	Exhibits	40

Signatures		42

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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, 2022		December 31, 2021
Assets	(Unaudited)
Current Assets:
Cash and Cash Equivalents	$	3,335	$	9,519
Accounts Receivable, Net	297,754		193,554
Advances to Operators	18,536		6,319
Prepaid Expenses and Other	2,111		3,417
Derivative Instruments	1,720		2,519

Total Current Assets	323,456		215,328

Property and Equipment:
Oil and Natural Gas Properties, Full Cost Method of Accounting
Proved	5,492,966		5,034,769
Unproved	55,606		24,998
Other Property and Equipment	2,732		2,616
Total Property and Equipment	5,551,304		5,062,383
Less – Accumulated Depreciation, Depletion and Impairment	(3,861,759)		(3,809,041)
Total Property and Equipment, Net	1,689,545		1,253,342

Derivative Instruments	483		1,863

Acquisition Deposit	—		40,650
Other Noncurrent Assets, Net	10,985		11,683

Total Assets	$	2,024,469	$	1,522,866

Liabilities and Stockholders' Equity (Deficit)
Current Liabilities:
Accounts Payable	$	101,696	$	65,464
Accrued Liabilities	137,593		105,590
Accrued Interest	5,519		20,498

Derivative Instruments	378,180		134,283




Other Current Liabilities	2,541		1,722
Total Current Liabilities	625,529		327,557

Long-term Debt, Net	1,119,500		803,437

Derivative Instruments	284,623		147,762


Asset Retirement Obligations	27,815		25,865
Other Noncurrent Liabilities	2,304		3,110

Total Liabilities	$	2,059,771	$	1,307,731

Commitments and Contingencies (Note 8)

Stockholders’ Equity (Deficit)
Preferred Stock, Par Value $.001; 5,000,000 Shares Authorized; 1,856,061 Series A Shares Outstanding at 3/31/2022 2,218,732 Series A Shares Outstanding at 12/31/2021	2		2

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Common Stock, Par Value $.001; 135,000,000 Shares Authorized; 77,266,137 Shares Outstanding at 3/31/2022 77,341,921 Shares Outstanding at 12/31/2021	479		479
Additional Paid-In Capital	1,944,773		1,988,649
Retained Deficit	(1,980,556)		(1,773,996)
Total Stockholders’ Equity (Deficit)	(35,302)		215,135
Total Liabilities and Stockholders’ Equity (Deficit)	$	2,024,469	$	1,522,866

______________

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)	2022		2021
Revenues
Oil and Gas Sales	$	456,458	$	157,332
Gain (Loss) on Commodity Derivatives, Net	(489,388)		(135,935)

Total Revenues	(32,930)		21,397

Operating Expenses
Production Expenses	54,540		34,312
Production Taxes	34,616		13,453
General and Administrative Expense	13,813		6,782
Depletion, Depreciation, Amortization and Accretion	53,185		31,221


Total Operating Expenses	156,154		85,768

Income (Loss) From Operations	(189,084)		(64,371)

Other Income (Expense)
Interest Expense, Net of Capitalization	(17,977)		(13,510)

Gain on Unsettled Interest Rate Derivatives, Net	1,290		240
Loss on Extinguishment of Debt, Net	—		(12,594)

Contingent Consideration Gain (Loss)	—		(125)

Other Income (Expense)	—		3
Total Other Income (Expense)	(16,687)		(25,986)

Income (Loss) Before Income Taxes	(205,771)		(90,357)

Income Tax Provision (Benefit)	789		—

Net Loss	$	(206,560)	$	(90,357)

Cumulative Preferred Stock Dividend	(3,016)		(3,830)

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

Net Loss Attributable to Common Stockholders	$	(224,533)	$	(94,188)

Net Loss Per Common Share – Basic	$	(2.92)	$	(1.73)
Net Loss Per Common Share – Diluted	$	(2.92)	$	(1.73)
Weighted Average Common Shares Outstanding – Basic	76,922,543		54,538,099
Weighted Average Common Shares Outstanding – Diluted	76,922,543		54,538,099

______________

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)	2022		2021
Cash Flows from Operating Activities
Net Income (Loss)	$	(206,560)	$	(90,357)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
Depletion, Depreciation, Amortization and Accretion	53,185		31,221
Amortization of Debt Issuance Costs	1,078		1,014

Loss on Extinguishment of Debt	—		12,594
Amortization of Bond Premium on Long-term Debt	(531)		(122)
Deferred Income Taxes	789		—
Unrealized (Gain) Loss of Derivative Instruments	382,937		128,398

Loss on Contingent Consideration	—		125


Stock-Based Compensation Expense	1,447		769


Other	2,675		61
Changes in Working Capital and Other Items:
Accounts Receivable, Net	(102,033)		(23,694)
Prepaid and Other Expenses	(698)		(1,037)
Accounts Payable	33,243		5,057
Accrued Interest	(14,488)		(2,588)
Accrued Liabilities and Expenses	2,991		1,447

Net Cash Provided by Operating Activities	154,034		62,766

Cash Flows from Investing Activities
Drilling and Development Capital Expenditures	(55,941)		(33,331)
Acquisition of Oil and Natural Gas Properties	(361,541)		(1,790)
Acquisition Deposit	—		(17,500)


Purchases of Other Property and Equipment	(117)		(51)
Net Cash Used for Investing Activities	(417,599)		(52,672)

Cash Flows from Financing Activities
Advances on Revolving Credit Facility	434,000		109,000
Repayments on Revolving Credit Facility	(118,000)		(378,000)




Repurchases of Second Lien Notes due 2023	—		(280,249)
Repayment of Unsecured VEN Bakken Note due 2022	—		(130,000)
Debt Issuance Costs Paid	(13)		(11,607)


Issuance of Common Stock	—		132,900
Issuance of Unsecured Notes due 2028	—		550,000


Repurchases of Preferred Stock	(50,225)		—
Restricted Stock Surrenders - Tax Obligations	(2,206)		(837)

Common Dividends Paid	(6,176)		—
Net Cash Provided (Used) for Financing Activities	257,380		(8,793)

Net Increase (Decrease) in Cash and Cash Equivalents	(6,185)		1,301

Cash and Cash Equivalents - Beginning of Period	9,519		1,428

Cash and Cash Equivalents - End of Period	3,335		2,729

______________

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, 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)




Acquisition 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)


(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, 2020	45,908,779	$	448	2,218,732	$	2	$	1,556,602	$	(1,780,357)	$	(223,304)

Issuance of Common Stock	138,297	—		—	—		—		—		—

Share Based Compensation	—	—		—	—		916		—		916
Restricted Stock Surrenders - Tax Obligations	(60,529)	—		—	—		(837)		—		(837)


Equity Offerings, Net of Issuance Costs	14,375,000	14		—	—		132,885		—		132,900




Net Loss	—	—		—	—		—		(90,357)		(90,357)

March 31, 2021	60,361,547	$	462	2,218,732	$	2	$	1,689,567	$	(1,870,714)	$	(180,682)

______________

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

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NOTES TO CONDENSED FINANCIAL STATEMENTS

MARCH 31, 2022

(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”.

Northern’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, 2021 has been derived from the Company’s audited financial statements for the year ended December 31, 2021. 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, 2021, which were included in the Company’s 2021 Annual Report on Form 10-K for the fiscal year ended December 31, 2021.

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. Actual results may differ from those estimates.

The Company considered the impact of the novel coronavirus 2019 (“COVID-19”) pandemic on the assumptions and estimates used by management in the unaudited condensed financial statements for the reporting periods presented. Management’s estimates and assumptions were based on historical data and consideration of future market conditions. Given the uncertainty inherent in any projection, which is heightened by the possibility of unforeseen additional impacts from the COVID-19 pandemic, 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 in the near term.

Adopted and Recently Issued Accounting Pronouncements

In March 2020, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”) followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021 to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. Generally, the guidance is to be applied as of any date from the beginning of an interim period that includes or is subsequent to March 12,

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2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. ASU 2020-04 and ASU 2021-01 are effective for all entities through December 31, 2022. The Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01 and the impact the new standard will have on its financial statements and related disclosure.

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 in accordance with FASB ASC Topic 606, Revenue from Contracts with Customers (“ASC 606”). The exemption, as described in ASC 606-10-50-14(a), 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, 2022 and 2021, 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, 2022 and 2021.


	Three Months Ended March 31, 2022								Three Months Ended March 31, 2021
(In thousands)	Williston		Permian		Appalachian		Total		Williston		Permian		Appalachian		Total
Oil Revenues	$	268,010	$	80,816	$	—	$	348,826	$	133,840	$	1,807	$	—	$	135,647
Natural Gas and NGL Revenues	62,620		18,214		26,797		107,632		21,569		116		—		21,685
Total	$	330,631	$	99,030	$	26,797	$	456,458	$	155,410	$	1,922	$	—	$	157,332

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, economic disruptions resulting from the COVID-19 pandemic, 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 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, 2022, the Company’s top four operators made up 43% of total oil and natural gas sales, compared to 55% for the three months ended March 31, 2021.

The Company faces concentration risk due to the fact that a substantial majority of its oil and natural gas revenue is sourced from North Dakota. Recent acquisitions 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 Series A Preferred Stock (see Note 5). The number of potential common shares outstanding are calculated using the treasury stock or if-converted method. For the three months ended March 31, 2022 the Company repurchased certain preferred stock at a premium over the carrying value, which increased the net loss attributable to common shareholders.

The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three months ended March 31, 2022 and 2021 are as follows:

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	Three Months Ended March 31,
(In thousands, except share and per share data)	2022		2021
Net Loss	$	(206,560)	$	(90,357)
Less: Cumulative Dividends on Preferred Stock	(3,016)		(3,830)
Less: Premium on Repurchase of Preferred Stock	(14,957)		—
Net Loss Attributable to Common Stockholders	(224,533)		$	(94,188)

Weighted Average Common Shares Outstanding:
Weighted Average Common Shares Outstanding – Basic	76,922,543		54,538,099
Plus: Dilutive Effect of Stock Options, Restricted Stock and Preferred Shares	—		—

Weighted Average Common Shares Outstanding – Diluted	76,922,543		54,538,099

Net Income (Loss) per Common Share:
Basic	$	(2.92)	$	(1.73)
Diluted	$	(2.92)	$	(1.73)

Shares Excluded from EPS Due to Anti-Dilutive Effect:
Restricted Stock	239,033		120,039

Supplemental Cash Flow Information

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


	Three Months Ended March 31,
(In thousands)	2022		2021
Supplemental Cash Items:
Cash Paid During the Period for Interest, Net of Amount Capitalized	$	29,147	$	12,525
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	139,799		91,072
Capitalized Asset Retirement Obligations	1,586		205

Compensation Capitalized on Oil and Gas Properties	53		147
Acquisition of Property Financed in Part by Issuance of Warrants	17,870		—



Non-cash Financing Activities:




Issuance of Common Stock Warrants - Acquisitions of Oil and Natural Gas Properties	17,870		—
Common Stock Dividends Declared	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, 2022 and 2021, 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.

2022 Acquisitions

In addition to the closing of the Veritas Acquisition (defined below), the Company acquired oil and natural gas properties, through a number of independent transactions, for a total of $11.6 million during the three months ended March 31, 2022.

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 estimated consideration included $390.9 million in cash (which includes a $40.7 million cash deposit previously paid by the Company upon the execution of the purchase agreement and customary purchase price adjustments) 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. The Veritas Acquisition was accounted for using the acquisition method under ASC Topic 805, Business Combinations, which requires all assets acquired and liabilities assumed to be recorded at fair value at the acquisition date.

The results of operations from the acquisition from the January 27, 2022 closing date through March 31, 2022, represented approximately $45.4 million of revenue and $31.7 million of income from operations. The Company incurred $6.8 million of transaction costs in connection with the acquisition, which are included in general and administrative expense in the condensed 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	$	382,536
Unproved oil and natural gas properties	26,262
Asset retirement cost	1,219
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

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2021 Acquisitions

CM Resources Acquisition

On August 2, 2021, the Company completed the acquisition of certain non-operated oil and gas properties from CM Resources, LLC, effective as of April 1, 2021 (the “CM Resources Acquisition”), for total estimated consideration of $101.7 million in cash. At closing, the acquired assets included approximately 6.5 net producing wells and 3.0 net wells in progress, as well as approximately 2,285 net acres in the Permian Basin. The CM Resources Acquisition was accounted for using the acquisition method under ASC Topic 805, Business Combinations, which requires all assets acquired and liabilities assumed to be recorded at fair value at the acquisition date.

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	$	101,858

Total assets acquired	101,858
Asset retirement obligations	(179)
Net assets acquired	$	101,679

Fair value of consideration paid for net assets:
Cash consideration	$	101,679
Total fair value of consideration transferred	$	101,679

Reliance Acquisition

On April 1, 2021, the Company completed the acquisition of certain oil and gas properties, interests and related net assets from Reliance Marcellus, LLC (the “Reliance Acquisition”), effective July 1, 2020. At closing, the acquired assets included approximately 95.3 net producing wells and 24.9 net wells in progress, as well as approximately 61,712 net acres in the Appalachian Basin in Pennsylvania. In addition, the Company assumed minimum volume commitment contracts. The Reliance Acquisition was completed pursuant to the purchase and sale agreement between the Company and Reliance Marcellus, LLC (“Reliance”), dated February 3, 2021.

The total consideration paid by the Company was $140.6 million, consisting of (i) warrants to purchase 3,250,000 shares of the Company’s common stock with an exercise price equal to $14.00 per share and a total estimated fair value of $30.5 million and (ii) cash purchase consideration of $110.1 million. The Reliance Acquisition was accounted for using the acquisition method under ASC Topic 805, Business Combinations, which requires all assets acquired and liabilities assumed to be recorded at fair value at the acquisition date.

The following table reflects the fair values of the net assets and liabilities as of the date of acquisition:

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	(In thousands)
Fair value of net assets:
Proved oil and natural gas properties	$	139,644
Unproved oil and natural gas properties	10,912
Total assets acquired	150,556
Asset retirement obligations	(6,549)
Minimum volume commitment liability	(3,443)
Net assets acquired	$	140,564

Fair value of consideration paid for net assets:
Cash consideration	$	110,052
Issuance of Common Stock Warrants (3.2 million shares at $14.00 per share)	30,512
Total fair value of consideration transferred	$	140,564

Pro Forma Information

The following summarized unaudited pro forma condensed statement of operations information for the three months ended March 31, 2022 and 2021 assumes that each of the Veritas Acquisition, CM Resources Acquisition and Reliance Acquisition occurred as of January 1, 2021. 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, 2021, or that would be attained in the future.


	Three Months Ended		Three Months Ended
(In thousands)	March 31, 2022		March 31, 2021
Total Revenues	$	(13,101)	$	53,086
Net Income (Loss)	(193,227)		(105,212)

Comstock Acquisition

On November 16, 2021, the Company completed the acquisition of certain oil and gas properties, interests and related assets from Comstock Oil & Gas, LLC (“Comstock”), effective as of October 1, 2021 (the “Comstock Acquisition”), for total estimated consideration of $150.5 million in cash. The acquisition was accounted for as an asset acquisition under ASC Topic 805, Business Combinations, and the acquired assets consisted of approximately 65.9 net producing wells located primarily in Williams, McKenzie, Mountrail and Dunn Counties, North Dakota. Of the purchase price, 100% was allocated to proved properties and the Company recognized approximately $1.7 million of asset retirement obligations. The Comstock Acquisition was completed pursuant to the purchase and sale agreement between the Company and Comstock, dated October 6, 2021.

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

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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 abandoned. 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, 2022 and 2021, unproved properties of $1.3 million and $0.2 million, respectively, were impaired.

NOTE 4 LONG-TERM DEBT

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


(In thousands)	March 31, 2022		December 31, 2021
Revolving Credit Facility	$	371,000	$	55,000
Unsecured Notes due 2028	750,000		750,000


Total principal	1,121,000		805,000
Unamortized debt premiums	12,686		13,217
Unamortized debt issuance costs(1)	(14,186)		(14,780)
Total debt	$	1,119,500	$	803,437

________________

(1)Debt issuance costs related to the Company’s revolving credit facility of $5.2 million and $5.7 million as of March 31, 2022 and December 31, 2021, respectively, are recorded in “Other Noncurrent Assets, Net” on the balance sheets.

Revolving Credit Facility

On November 22, 2019, the Company entered into a Second Amended and Restated Credit Agreement (the “Revolving Credit Facility”) with Wells Fargo Bank, National Association, as administrative 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 October 5, 2018. The Revolving Credit Facility is scheduled to mature on November 22, 2024.

The Revolving Credit Facility 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, 2022, the borrowing base was $850.0 million and the aggregate elected commitment amount was $750.0 million. In order to borrow in excess of the elected commitment amount, the Company would need to find new or existing lenders willing to provide the additional commitments. The borrowing base will be redetermined semiannually on or around April 1st and October 1st, with one interim “wildcard” redetermination available between scheduled redeterminations. The first scheduled redetermination each year is based on a January 1st engineering report audited by a third party (reasonably acceptable by the Agent). The aggregate elected commitment amount may be increased semi-annually upon each scheduled borrowing base redetermination, and up to two times between each scheduled redetermination.

At the Company’s option, borrowings under the Revolving Credit Facility shall bear interest at the base rate or LIBOR plus an applicable margin. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the Agents’s prime rate; (ii) the federal funds effective rate plus 50 basis points; and (iii) the adjusted LIBOR rate for a one-month interest period plus 100 basis points. The applicable margin for base rate loans ranges from 100 to 200 basis points, and the applicable margin for LIBOR loans ranges from 200 to 300 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, maintain excess cash liquidity, sell assets, enter into certain derivatives contracts, change the nature of its business or 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

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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 pro forma 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 Topic 815, Derivatives and Hedging (“ASC 815”), divided by consolidated current liabilities excluding current non-cash obligations under ASC 815 and current maturities under the Revolving Credit Facility) shall not be less than 1.00 to 1.00. The Company is in compliance with these financial covenants as of March 31, 2022.

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 us or the Company’s 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 proved 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.

Unsecured Notes due 2028

On February 18, 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 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 “2028 Notes”). The proceeds of the 2028 Notes were used primarily to refinance existing indebtedness, and for general corporate purposes. The 2028 Notes will mature on March 1, 2028. Interest on the 2028 Notes is payable semi-annually in arrears on each March 1 and September 1, commencing September 1, 2021, to holders of record on the February 15 and August 15 immediately preceding the related interest payment date, at a rate of 8.125% per annum.

Prior to March 1, 2024, the Company may redeem all or a part of the 2028 Notes at a redemption price equal to 100% of the principal amount of the 2028 Notes redeemed, plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On or after March 1, 2024, the Company may redeem all or a part of the 2028 Notes at redemption prices (expressed as percentages of principal amount) equal to 104.063% for the twelve-month period beginning on March 1, 2024, 102.031% for the twelve-month period beginning on March 1, 2025, and 100% beginning on March 1, 2026, plus accrued and unpaid interest to the redemption date.

The 2028 Notes Indenture contains covenants that, among other things, limit the Company’s ability and the ability of its restricted subsidiaries, if any, to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends or distributions in respect of equity interests or redeem, repurchase or retire equity securities or subordinated indebtedness; (iii) transfer or sell certain assets; (iv) make investments; (v) create liens to secure indebtedness; (vi) enter into agreements that restrict dividends or other payments from any non-guarantor subsidiary to the Company; (vii) consolidate with or merge with or into, or sell substantially all of the Company’s assets to, another person; (viii) enter into transactions with affiliates; and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications, and many of these covenants will be terminated if the 2028 Notes achieve an investment grade rating from either Moody’s Investors Services, Inc. or S&P Global Ratings.

The 2028 Notes Indenture contains customary events of default, including, but not limited to: (i) default for 30 days in the payment when due of interest on the 2028 Notes; (ii) default in payment when due of the principal of, or premium, if any, on the 2028 Notes; (iii) failure by the Company or certain of its subsidiaries, if any, to comply with certain of their respective obligations, covenants or agreements contained in the 2028 Notes or the 2028 Notes Indenture, subject to certain notice and grace periods; (iv) failure by the Company or any of its restricted subsidiaries to pay indebtedness within any applicable grace period or the acceleration of any such indebtedness if the total amount of such indebtedness exceeds $35.0 million; (v) failure by the Company or any of its restricted subsidiaries that is a Significant Subsidiary (as defined in the 2028 Notes Indenture) to pay final non-appealable judgments aggregating in excess of $35.0 million, which judgments are not paid, discharged or stayed for a period of 60 days; (vi) except as permitted by the 2028 Notes Indenture, any guarantee of the 2028 Notes is held in any judicial proceeding to be unenforceable or invalid, or ceases for any reason to be in full force and effect, or is denied or disaffirmed by a Guarantor (as defined in the 2028 Notes Indenture); and (vii) certain events of bankruptcy or insolvency

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described in the 2028 Notes Indenture with respect to the Company and its restricted subsidiaries that are Significant Subsidiaries.

NOTE 5 COMMON AND PREFERRED STOCK

Common Stock

The Company is authorized to issue up to 135,000,000 shares of common stock, par value $0.001 per share. As of March 31, 2022, the Company had 77,266,137 shares of common stock issued and outstanding.

In January 2022, the Company’s Board of Directors declared a cash dividend on the Company’s common stock in the amount of $0.14 per share. The dividend was paid on April 29, 2022 to stockholders of record as of the close of business on March 30, 2022.

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 Board of Directors. As of March 31, 2022, the Company had 1,856,061 shares of preferred stock issued and outstanding, all of which were shares of 6.500% Series A Perpetual Cumulative Convertible Preferred Stock (the “Series A Preferred Stock”).

The terms of the Series A Preferred Stock are set forth in the Certificate of Designations for the Series A Preferred Stock (the “Certificate of Designations”), as originally filed with the Delaware Secretary of State on November 22, 2019, and as amended thereafter. The Series A Preferred Stock ranks senior to the Company’s common stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding-up. Holders of the Series A Preferred Stock are entitled to receive, when, as and if declared by the board of directors of the Company, cumulative dividends in cash, at a rate of 6.500% per annum on the sum of (i) the $100 liquidation preference per share of Series A Preferred Stock (the “Liquidation Preference”) and (ii) all accumulated and unpaid dividends (if any), payable semi-annually in arrears on May 15 and November 15 of each year, commencing on May 15, 2020. As of March 31, 2022, the Company was current in the payment of dividends with $4.6 million of undeclared accumulated dividends remaining on the Series A Preferred Stock.

The Series A Preferred Stock is convertible at the holders’ option (an “Optional Conversion”) into common stock at a conversion rate set forth in the Certificate of Designations, subject to customary adjustments as provided for therein. As of March 31, 2022, the conversion rate was 4.4214 shares of common stock for each share of Series A Preferred Stock (which is equivalent to a conversion price of $22.6173. Holders may be entitled to additional shares of common stock or cash in connection with a conversion that occurs in connection with a Fundamental Change (as defined in the Certificate of Designations). The Series A Preferred Stock is convertible at the Company’s option (a “Mandatory Conversion”) if the closing sale price of the Company’s common stock equals or exceeds 145% of the conversion price for at least 20 trading days (whether or not consecutive) in a period of 30 consecutive trading days. A Mandatory Conversion would also entitle the holder to a cash payment equal to eight semi-annual dividend payments, less an amount equal to all cash dividend payments made in respect of such holder’s shares of Series A Preferred Stock prior to such Mandatory Conversion. The occurrence of any Optional Conversion or Mandatory Conversion is subject to various terms and limitations set forth in the Certificate of Designations. The Certificate of Designations also sets forth additional information relating to the payment of dividends, voting, conversion rights, consent rights, liquidation rights, the ranking of the Series A Preferred Stock in comparison with the Company’s other securities, and other matters.

2022 Activity

Common Stock

During the three months ended March 31, 2022, 89,620 shares of common stock were surrendered by certain employees of the Company to cover tax obligations in connection with their restricted stock awards. The total value of these shares was approximately $2.2 million, which is based on the market prices on the dates the shares were surrendered.

Preferred Stock

During the three months ended March 31, 2022, the Company repurchased 362,671 shares of Series A Preferred Stock in a number of independent transactions for an aggregate of $50.2 million in cash.

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Stock Repurchase Program

In May 2011, 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. The stock repurchase program allows the Company to repurchase its shares from time to time in the open market, block transactions and in negotiated transactions.

During the three months ended March 31, 2022 and March 31, 2021, respectively, the Company did not repurchase shares of its common stock under the stock repurchase program. 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 now included in the Company’s pool of authorized but unissued shares.

NOTE 6 STOCK-BASED COMPENSATION AND WARRANTS

The Company maintains its 2018 Equity Incentive Plan (the “2018 Plan”), which replaced the Company’s prior 2013 Incentive Plan (the “2013 Plan”), for making equity-based awards to employees, directors and other eligible persons. No future awards will be made under the 2013 Plan. The 2013 Plan continues to govern awards that were made thereunder, which remain in effect pursuant to their terms. As of March 31, 2022, there were 568,918 shares available for future 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 unaudited 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 unaudited balance sheets.

The 2018 Plan and 2013 Plan award types are summarized as follows:

Restricted Stock Awards

The Company issues restricted stock awards (“RSAs”) subject to various vesting conditions as compensation to executive officers, employees and directors of the Company. RSAs issued to employees and executive officers generally vest over three years, provided that any performance and/or market conditions are also met. RSAs issued to directors generally vest over one year, provided that any performance and/or market conditions are also met. For RSAs 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 with both service and performance conditions is recognized on a graded basis only 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 whether it becomes probable that these conditions will be achieved or not, and stock-based compensation expense for any such awards is not reversed if vesting does not actually occur. 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.

The following table reflects the outstanding RSAs and activity related thereto for the three months ended March 31, 2022:

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	Service-based Awards			Service, Performance, and Market-based Awards
	Number of Shares	Weighted-average Grant Date Fair Value			Number of Shares	Weighted-average Grant Date Fair Value
Outstanding at December 31, 2021	420,122	$	13.68		18,600	$	9.80
Shares granted	15,651	28.19			—	—
Shares forfeited	(1,815)	11.64			—	—
Shares vested	(184,403)	14.38			(18,600)	9.80
Outstanding at March 31, 2022	249,555	$	14.08		—	$	—

At March 31, 2022, there was $3.4 million of total unrecognized compensation expense related to unvested RSAs. That cost is expected to be recognized over a weighted average period of 0.89 years. For the three months ended March 31, 2022 and 2021, the total fair value of the Company’s restricted stock awards vested was $4.6 million and $1.8 million, respectively.

Warrants

In April 2021, the Company issued common stock warrants as a part of the Reliance Acquisition as purchase consideration. The common stock warrants issued grant holders the right to purchase 3,250,000 shares of the Company’s common stock at an exercise price equal to $14.00 per share (subject to certain anti-dilution adjustments), have a total fair value of $30.5 million, and are generally exercisable from June 30, 2021 until April 1, 2028. The fair value of the common stock warrants consideration was determined by utilizing an Option Pricing Model, which used the market value of the Company’s common stock based on the issue date, an exercise price of $14.00, an implied volatility of 80% and a risk-free rate of 1.34%.

In January 2022, the Company issued common stock warrants as a part of the Veritas Acquisition as purchase consideration. The common stock warrants issued grant holders the right to purchase 1,939,998 shares of the Company’s common stock at an exercise price equal to $28.30 per share (subject to certain anti-dilution adjustments), have a total fair value of $17.9 million, and are generally exercisable from April 27, 2022 until January 27, 2029. The fair value of the common stock warrants consideration was determined by utilizing an Option Pricing Model, which used the market value of the Company’s common stock based on the issue date, an exercise price of $28.30, an implied volatility of 60%, a risk-free rate of 2.14% and an implied dividend yield of 3.00%.

The following table reflects the outstanding warrants and activity related thereto for the three months ended March 31, 2022:


	Reliance			Veritas
	Warrants	Weighted-average Exercise Price		Warrants	Weighted-average Exercise Price
Outstanding at December 31, 2021	3,276,582	$	13.89	—	$	—
Issued	—	—		1,939,998	28.30
Anti-Dilution Adjustments for Common Stock Dividends	17,510	13.81		10,367	28.15
Exercised	—	—		—	—
Expired	—	—		—