Chord Energy 10Q 2022 Q1 Quarterly report

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 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 number: 001-31899


	WHITING PETROLEUM CORPORATION
	(Exact name of registrant as specified in its charter)


Delaware		20-0098515
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1700 Lincoln Street, Suite 4700 Denver, Colorado		80203-4547
(Address of principal executive offices)		(Zip code)

	(303) 837-1661
	(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:


Common Stock, $0.001 par value	WLL	New York Stock Exchange
(Title of each class)	(Trading symbol)	(Name of each exchange on which registered)

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	☒	Smaller reporting company	☐
Accelerated filer	☐	Emerging growth company	☐
Non-accelerated filer	☐

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 ☒

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13, or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☒ No ☐

Number of shares of the registrant’s common stock outstanding at April 29, 2022: 39,241,819 shares.

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GLOSSARY OF CERTAIN DEFINITIONS

Unless the context otherwise requires, the terms “we,” “us,” “our” or “ours” when used in this Quarterly Report on Form 10-Q refer to Whiting Petroleum Corporation, together with its consolidated subsidiaries. When the context requires, we refer to these entities separately.

We have included below the definitions for certain terms used in this report:

“ASC” Accounting Standards Codification.

“Bankruptcy Code” Title 11 of the United States Code.

“Bankruptcy Court” United States Bankruptcy Court for the Southern District of Texas.

“basis swap” or “differential swap” A derivative instrument that guarantees a fixed price differential to NYMEX at a specified delivery point. We receive the difference between the floating market price differential and the fixed price differential from the counterparty if the floating market differential is greater than the fixed price differential for the hedged commodity. We pay the difference between the floating market price differential and the fixed price differential to the counterparty if the fixed price differential is greater than the floating market differential for the hedged commodity.

“Bbl” One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to oil, NGLs and other liquid hydrocarbons.

“Bcf” One billion cubic feet, used in reference to natural gas.

“Board” The board of directors of Whiting Petroleum Corporation.

“BOE” One stock tank barrel of oil equivalent, computed on an approximate energy equivalent basis that one Bbl of crude oil equals six Mcf of natural gas and one Bbl of crude oil equals one Bbl of natural gas liquids.

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

“completion” The process of preparing an oil and gas wellbore for production through the installation of permanent production equipment, as well as perforation and fracture stimulation to optimize production.

“Credit Agreement” A reserves-based credit facility with a syndicate of banks that was entered into by Whiting Petroleum Corporation, as parent guarantor, and Whiting Oil and Gas Corporation, as borrower on September 1, 2020. Refer to the Long-Term Debt footnote in Item 1. “Condensed Consolidated Financial Statements” of this Quarterly Report on Form 10-Q for more information.

“deterministic method” The method of estimating reserves or resources using a single value for each parameter (from the geoscience, engineering or economic data) in the reserves calculation.

“development well” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

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

“FASB” Financial Accounting Standards Board.

“field” An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition”

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are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas of interest, etc.

“GAAP” Generally accepted accounting principles in the United States of America.

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

“ISDA” International Swaps and Derivatives Association, Inc.

“lease operating expense” or “LOE” The expenses of lifting oil or gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs and other expenses incidental to production, but not including lease acquisition or drilling or completion expenses.

“LIBOR” London interbank offered rate.

“MBbl” One thousand barrels of oil, NGLs or other liquid hydrocarbons.

“MBbl/d” One MBbl per day.

“MBOE” One thousand BOE.

“MBOE/d” One MBOE per day.

“Mcf” One thousand cubic feet, used in reference to natural gas.

“MMBbl” One million barrels of oil, NGLs or other liquid hydrocarbons.

“MMBOE” One million BOE.

“MMBtu” One million British Thermal Units, used in reference to natural gas.

“MMcf” One million cubic feet, used in reference to natural gas.

“MMcf/d” One MMcf per day.

“net acres” or “net wells” The sum of the fractional working interests owned in gross acres or wells, as the case may be.

“net production” The total production attributable to our fractional working interest owned.

“NGL” Natural gas liquid.

“NYMEX” The New York Mercantile Exchange.

“plugging and abandonment” Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of most states legally require plugging of abandoned wells.

“probabilistic method” The method of estimating reserves using the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) to generate a full range of possible outcomes and their associated probabilities of occurrence.

“proved developed reserves” Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

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“proved reserves” Those reserves which, by analysis of geoscience 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.

The area of the reservoir considered as proved includes all of the following:

The area identified by drilling and limited by fluid contacts, if any, and

Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid or carbon dioxide injection) are included in the proved classification when both of the following occur:

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

The project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period before 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 upon future conditions.

“proved undeveloped reserves” or “PUDs” Proved 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 recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. Under no circumstances shall estimates of proved undeveloped reserves 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 projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

“reasonable certainty” If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical and geochemical) engineering, and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.

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

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

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“resource play” An expansive contiguous geographical area with known accumulations of crude oil or natural gas reserves that has the potential to be developed uniformly with repeatable commercial success due to advancements in horizontal drilling and completion technologies.

“royalty” The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross income from crude oil or natural gas produced and sold, unencumbered by expenses relating to the drilling, completing or operating of the affected well.

“SEC” The United States Securities and Exchange Commission.

“SOFR” Secured overnight financing rate.

“turn-in-line” or “TIL” To turn a drilled and completed well online to begin sales.

“two-way collar” An option position where the proceeds from the sale of a call option at its inception fund the purchase of a put option at its inception.

“working interest” The interest in a crude oil and natural gas property (normally a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and to a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all associated risks.

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

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PART I – FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements

WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (unaudited)

(in thousands, except share and per share data)


	March 31,			December 31,
	2022			2021
ASSETS			��
Current assets:
Cash and cash equivalents	$	208		$	41,245
Accounts receivable trade, net		333,318			279,865
Prepaid expenses and other		13,626			17,158
Total current assets		347,152			338,268
Property and equipment:
Oil and gas properties, successful efforts method		2,642,670			2,274,908
Other property and equipment		63,351			61,624
Total property and equipment		2,706,021			2,336,532
Less accumulated depreciation, depletion and amortization		(301,516)			(254,237)
Total property and equipment, net		2,404,505			2,082,295
Other long-term assets		38,218			37,368
TOTAL ASSETS	$	2,789,875		$	2,457,931
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable trade	$	102,321		$	48,641
Revenues and royalties payable		212,892			258,527
Accrued capital expenditures		55,572			38,914
Accrued liabilities and other		44,077			30,726
Accrued lease operating expenses		28,547			32,408
Taxes payable		30,544			18,864
Derivative liabilities		506,868			209,653
Total current liabilities		980,821			637,733
Long-term debt		50,000			-
Asset retirement obligations		95,094			93,915
Operating lease obligations		14,067			14,710
Long-term derivative liabilities		33,454			46,720
Other long-term liabilities		706			1,228
Total liabilities		1,174,142			794,306
Commitments and contingencies
Equity:
Common stock, $0.001 par value, 500,000,000 shares authorized; 39,241,584 issued and outstanding as of March 31, 2022 and 39,133,637 issued and outstanding as of December 31, 2021		39			39
Additional paid-in capital		1,196,169			1,196,607
Accumulated earnings		419,525			466,979
Total equity		1,615,733			1,663,625
TOTAL LIABILITIES AND EQUITY	$	2,789,875		$	2,457,931

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

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WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)

(in thousands, except per share data)


	Three Months Ended March 31,
	2022		2021
OPERATING REVENUES
Oil, NGL and natural gas sales	$	520,216	$	304,679
Purchased gas sales		6,640		2,712
Total operating revenues		526,856		307,391
OPERATING EXPENSES
Lease operating expenses		72,505		59,339
Transportation, gathering, compression and other		6,760		7,028
Purchased gas expense		5,538		1,902
Production and ad valorem taxes		37,893		24,150
Depreciation, depletion and amortization		49,233		53,729
Exploration and impairment		2,200		2,622
General and administrative		18,585		10,291
Derivative loss, net		428,678		146,693
Total operating expenses		621,392		305,754
INCOME (LOSS) FROM OPERATIONS		(94,536)		1,637
OTHER INCOME (EXPENSE)
Interest expense		(2,278)		(5,103)
Bargain purchase gain		66,270		-
Other income		402		2,520
Total other income (expense)		64,394		(2,583)
LOSS BEFORE INCOME TAXES		(30,142)		(946)
INCOME TAX EXPENSE		7,287		-
NET LOSS	$	(37,429)	$	(946)
LOSS PER COMMON SHARE
Basic	$	(0.95)	$	(0.02)
Diluted	$	(0.95)	$	(0.02)
WEIGHTED AVERAGE SHARES OUTSTANDING
Basic		39,204		38,698
Diluted		39,204		38,698

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

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WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(in thousands)


	Three Months Ended March 31,
	2022		2021
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(37,429)	$	(946)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		49,233		53,729
Amortization of debt issuance costs		894		887
Stock-based compensation		4,038		2,309
Oil and gas property impairments		1,282		1,441
Bargain purchase gain		(66,270)		-
Non-cash derivative loss		287,140		107,399
Other, net		2,353		(973)
Changes in current assets and liabilities:
Accounts receivable trade, net		(53,880)		(58,032)
Prepaid expenses and other		159		3,906
Accounts payable trade and accrued liabilities		55,043		18,570
Revenues and royalties payable		(45,635)		20,699
Taxes payable		11,680		4,204
Net cash provided by operating activities		208,608		153,193
CASH FLOWS FROM INVESTING ACTIVITIES
Drilling and development capital expenditures		(72,811)		(35,728)
Acquisition of oil and gas properties		(213,964)		(470)
Other property and equipment		1,222		(2,597)
Proceeds from sale of properties		1,510		1,945
Net cash used in investing activities		(284,043)		(36,850)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under Credit Agreement		506,500		250,000
Repayments of borrowings under Credit Agreement		(456,500)		(365,000)
Dividends paid to shareholders		(9,810)		-
Principal payments on finance lease obligations		(373)		(1,249)
Restricted stock used for tax withholdings		(5,419)		(1,357)
Net cash provided by (used in) financing activities	$	34,398	$	(117,606)

				(Continued)

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WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(in thousands)


	Three Months Ended March 31,
	2022		2021
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH	$	(41,037)	$	(1,263)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH
Beginning of period		41,245		28,367
End of period	$	208	$	27,104
SUPPLEMENTAL CASH FLOW DISCLOSURES
Cash paid for reorganization items	$	-	$	396
NONCASH INVESTING ACTIVITIES
Accrued capital expenditures and accounts payable related to property additions	$	64,275	$	34,121

The accompanying notes are an integral part of these condensed consolidated financial statements.				(Concluded)

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WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (unaudited)

(in thousands)


				Additional
	Common Stock			Paid-in		Accumulated		Total
	Shares	Amount		Capital		Earnings		Equity
BALANCES - January 1, 2021	38,051	$	38	$	1,189,693	$	39,073	$	1,228,804
Net loss	-		-		-		(946)		(946)
Common stock issued in settlement of bankruptcy claims	949		1		(1)		-		-
Restricted stock issued	95		-		-		-		-
Restricted stock used for tax withholdings	(41)		-		(1,357)		-		(1,357)
Stock-based compensation	-		-		2,309		-		2,309
BALANCES - March 31, 2021	39,054	$	39	$	1,190,644	$	38,127	$	1,228,810


BALANCES - January 1, 2022	39,134	$	39	$	1,196,607	$	466,979	$	1,663,625
Net loss	-		-		-		(37,429)		(37,429)
Restricted stock issued	179		-		-		-		-
Restricted stock used for tax withholdings	(71)		-		(5,419)		-		(5,419)
Stock-based compensation	-		-		4,792		-		4,792
Dividends paid to shareholders and dividend equivalents payable to equity award holders	-		-		189		(10,025)		(9,836)
BALANCES - March 31, 2022	39,242	$	39	$	1,196,169	$	419,525	$	1,615,733

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

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WHITING PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. BASIS OF PRESENTATION

Description of Operations—Whiting Petroleum Corporation, a Delaware corporation, is an independent oil and gas company engaged in the development, production and acquisition of crude oil, NGLs and natural gas primarily in the Rocky Mountains region of the United States. Unless otherwise specified or the context otherwise requires, all references in these notes to “Whiting” or the “Company” are to Whiting Petroleum Corporation, together with its consolidated subsidiaries, Whiting Oil and Gas Corporation (“Whiting Oil and Gas” or “WOG”) and Whiting Programs, Inc. When the context requires, the Company refers to these entities separately.

Condensed Consolidated Financial Statements—The unaudited condensed consolidated financial statements include the accounts of Whiting Petroleum Corporation and its consolidated subsidiaries. Investments in entities which give Whiting significant influence, but not control, over the investee are accounted for using the equity method. Under the equity method, investments are stated at cost plus the Company’s equity in undistributed earnings and losses. All intercompany balances and transactions have been eliminated upon consolidation. These financial statements have been prepared in accordance with GAAP and the SEC rules and regulations for interim financial reporting. In the opinion of management, the accompanying financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim results. However, operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. The condensed consolidated financial statements and related notes included in this Quarterly Report on Form 10-Q should be read in conjunction with Whiting’s consolidated financial statements and related notes included in the Company’s Annual Report on Form 10-K for the period ended December 31, 2021, as amended. Except as disclosed herein, there have been no material changes to the information disclosed in the notes to consolidated financial statements included in the Company’s Annual Report on Form 10-K for the period ending December 31, 2021, as amended.

Cash and Cash Equivalents—Cash equivalents consist of demand deposits and highly liquid investments which have an original maturity of three months or less. Cash and cash equivalents potentially subject the Company to a concentration of credit risk as substantially all of its deposits held in financial institutions were in excess of the Federal Deposit Insurance Corporation insurance limits as of March 31, 2022 and December 31, 2021. The Company maintains its cash and cash equivalents in the form of money market and checking accounts with financial institutions that are also lenders under the Credit Agreement. The Company has not experienced any losses on its deposits of cash and cash equivalents.

Accounts Receivable Trade—Whiting’s accounts receivable trade consist mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates. The Company’s collection risk is inherently low based on the viability of its oil and gas purchasers as well as its general ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. The Company’s oil and gas receivables are generally collected within two months, and to date, the Company has not experienced material credit losses.

The Company routinely evaluates expected credit losses for all material trade and other receivables to determine if an allowance for credit losses is warranted. Expected credit losses are estimated based on (i) historic loss experience for pools of receivable balances with similar characteristics, (ii) the length of time balances have been outstanding and (iii) the economic status of each counterparty. These loss estimates are then adjusted for current and expected future economic conditions, which may include an assessment of the probability of non-payment, financial distress or expected future commodity prices and the impact that any current or future conditions could have on a counterparty’s credit quality and liquidity. As of December 31, 2021, the Company had an immaterial allowance for credit losses. There were no material changes in the estimate of expected credit losses at March 31, 2022.

Voluntary Reorganization under Chapter 11 of the Bankruptcy Code—On April 1, 2020, Whiting and certain of its subsidiaries (the “Debtors”) commenced voluntary cases (the “Chapter 11 Cases”) under chapter 11 of the Bankruptcy Code. On June 30, 2020, the Debtors filed the Joint Chapter 11 Plan of Reorganization of Whiting Petroleum Corporation and its Debtor affiliates (as amended, modified and supplemented, the “Plan”). On August 14, 2020 the Bankruptcy Court confirmed the Plan and on September 1, 2020, the Debtors satisfied all conditions required for Plan effectiveness and emerged from the Chapter 11 Cases.

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Proposed Merger with Oasis Petroleum Inc.—On March 7, 2022, Whiting entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Oasis Petroleum Inc., a Delaware corporation (“Oasis”), Ohm Merger Sub Inc., a Delaware corporation and a wholly owned subsidiary of Oasis (“Merger Sub”), and New Ohm LLC, a Delaware limited liability company and a wholly owned subsidiary of Oasis, pursuant to which, among other things, Whiting will merge with Merger Sub in a merger of equals (the “Merger”). The Merger is subject to customary closing conditions, including, among others, approval by Whiting and Oasis shareholders. The Company currently expects the Merger to close in the second half of 2022. Upon closing, Lynn A. Peterson, Whiting’s President and Chief Executive Officer, will serve as Executive Chair of the Board of Directors of the combined company, and Daniel E. Brown, Oasis’ Chief Executive Officer, will serve as President and Chief Executive Officer and as a member of the Board of Directors of the combined company.

2. OIL AND GAS PROPERTIES

Net capitalized costs related to the Company’s oil and gas producing activities at March 31, 2022 and December 31, 2021 are as follows (in thousands):


	March 31,		December 31,
	2022		2021
Proved oil and gas properties	$	2,368,052	$	2,034,533
Unproved leasehold costs		184,268		182,109
Wells and facilities in progress		90,350		58,266
Total oil and gas properties, successful efforts method		2,642,670		2,274,908
Accumulated depletion		(294,663)		(248,298)
Oil and gas properties, net	$	2,348,007	$	2,026,610

Impairment expense for unproved properties totaled $1 million for the three months ended March 31, 2022 and 2021, respectively, and is reported in exploration and impairment expense in the condensed consolidated statements of operations.

Refer to the “Acquisitions and Divestitures” and “Fair Value Measurements” footnotes for more information on recent property acquisitions.

3. ACQUISITIONS AND DIVESTITURES

2022 Acquisitions and Divestitures

On March 17, 2022, the Company completed the acquisition of additional interests in producing wells, drilled and uncompleted wells and undeveloped properties located in Mountrail County, North Dakota for an aggregate unadjusted purchase price of $240 million. The purchase and sales agreement had an effective date of November 1, 2021 and contained customary provisions for purchase price adjustments based on actual revenues and property costs relating to the properties occurring between the effective date and March 17, 2022. The transaction was funded with cash on hand and borrowings under the Credit Agreement. The revenue and earnings from these properties since the acquisition date are included in the Company’s condensed consolidated financial statements for the three months ended March 31, 2022 and are not material. Pro forma revenue and earnings for the acquired properties are not material to our condensed consolidated financial statements and have therefore not been presented.

The acquisition was accounted for as a business combination and was recorded using the acquisition method of accounting in accordance with FASB ASC Topic 805 – Business Combinations. The following table summarizes the preliminary allocation of the estimated $216 million adjusted purchase price (which remains subject to post-closing adjustments) to the assets acquired and liabilities assumed in this acquisition based on their respective fair values at the acquisition date, which resulted in the recognition of a bargain purchase gain. Refer to the “Fair Value Measurements” footnote for a detailed discussion of the fair value inputs used by the Company in determining the valuation of the significant assets acquired and liabilities assumed. As the purchase price is further adjusted for post-closing adjustments and as the oil and gas property valuation is completed, the final purchase price allocation may result in a different allocation than what is presented in the table below (in thousands):

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Cash consideration	$	240,000
Estimated purchase price adjustments		(24,314)
Adjusted purchase price	$	215,686

Fair Value of Assets Acquired:
Prepaid expenses and other	$	343
Oil and gas properties, successful efforts method:
Proved oil and gas properties		274,276
Unproved leasehold costs		9,730
Total fair value of assets acquired		284,349

Fair Value of Liabilities Assumed:
Asset retirement obligations		2,393

Total fair value of assets acquired and liabilities assumed		281,956

Bargain purchase gain		66,270

Total purchase price	$	215,686

As a result of comparing the adjusted purchase price to the respective fair values of the assets acquired and liabilities assumed in the acquisition, a $66 million bargain purchase gain was recognized. The bargain purchase gain is primarily the result of a significant increase in crude oil prices between when the Purchase and Sale Agreement was signed and the date Whiting completed the acquisition.

There were no significant divestitures during the three months ended March 31, 2022.

2021 Acquisitions and Divestitures

There were no significant acquisitions or divestitures during the three months ended March 31, 2021.

4. LONG-TERM DEBT

Long-term debt, consisting entirely of borrowings outstanding under the Credit Agreement, totaled $50 million at March 31, 2022. At December 31, 2021, the Company had 0 long-term debt.

Credit Agreement

Whiting Petroleum Corporation, as parent guarantor, and Whiting Oil and Gas, as borrower, have a Credit Agreement with a syndicate of banks. As of March 31, 2022, the Credit Agreement had a borrowing base and aggregate commitments of $750 million. As of March 31, 2022, the Company had $699 million of available borrowing capacity under the Credit Agreement, which was net of $50 million of borrowings outstanding and $1 million in letters of credit outstanding.

The borrowing base under the Credit Agreement is determined at the discretion of the lenders, based on the collateral value of the Company’s proved reserves that have been mortgaged to such lenders, and is subject to regular redeterminations on April 1 and October 1 of each year, as well as special redeterminations described in the Credit Agreement, in each case which may increase or decrease the amount of the borrowing base. Additionally, the Company can increase the aggregate commitments by up to an additional $750 million, subject to certain conditions. On April 1, 2022, the Company and the lenders under the Credit Agreement agreed to defer the regularly scheduled redetermination scheduled for such date until September 1, 2022.

Up to $50 million of the borrowing base may be used to issue letters of credit for the account of Whiting Oil and Gas or other designated subsidiaries of the Company. As of March 31, 2022, $49 million was available for additional letters of credit under the Credit Agreement.

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The Credit Agreement provides for interest only payments until maturity on April 1, 2024, when the agreement terminates and any outstanding borrowings are due. In addition, the Credit Agreement provides for certain mandatory prepayments, including a provision pursuant to which, if the Company’s cash balances are in excess of approximately $75 million during any given week, such excess must be utilized to repay any outstanding borrowings under the Credit Agreement. Interest under the Credit Agreement accrues at the Company’s option at either (i) a base rate for a base rate loan plus a margin between 1.75% and 2.75% based on the ratio of outstanding borrowings and letters of credit to the lower of the current borrowing base or total commitments, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.5% per annum, or an adjusted LIBOR plus 1.0% per annum, or (ii) an adjusted LIBOR for a eurodollar loan plus a margin between 2.75% and 3.75% based on the ratio of outstanding borrowings and letters of credit to the lower of the current borrowing base or total commitments. The Credit Agreement also provides that the administrative agent and the Company have the ability to amend the LIBOR rate with a benchmark replacement rate, which may be a SOFR-based rate, if LIBOR borrowings become unavailable. Additionally, the Company incurs commitment fees of 0.5% on the unused portion of the aggregate commitments of the lenders under the Credit Agreement, which are included as a component of interest expense. At March 31, 2022, the weighted average interest rate on the outstanding principal balance under the Credit Agreement was 4%.

The Credit Agreement contains restrictive covenants that may limit the Company’s ability to, among other things, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, enter into hedging contracts, incur liens and engage in certain other transactions without the prior consent of its lenders. The Credit Agreement also restricts the Company’s ability to make any dividend payments or distributions of cash on its common stock except to the extent that the Company has distributable free cash flow and (i) has at least 20% of available borrowing capacity, (ii) has a consolidated net leverage ratio of less than or equal to 2.0 to 1.0, (iii) does not have a borrowing base deficiency and (iv) is not in default under the Credit Agreement. These restrictions apply to all of the Company’s restricted subsidiaries and are calculated in accordance with definitions contained in the Credit Agreement. The Credit Agreement requires the Company, as of the last day of any quarter, to maintain commodity hedges covering a minimum of 50% of its projected production for the succeeding twelve months, as reflected in the reserves report most recently provided by the Company to the lenders under the Credit Agreement. If the Company’s consolidated net leverage ratio equals or exceeds 1.0 to 1.0 as of the last day of any fiscal quarter, the Company will also be required to hedge 35% of its projected production for the second succeeding twelve months. The Company is also limited to hedging a maximum of 85% of its production from proved reserves. The Credit Agreement requires the Company to maintain the following ratios (as defined in the Credit Agreement): (i) a consolidated current assets to consolidated current liabilities ratio of not less than 1.0 to 1.0 and (ii) a total debt to last four quarters’ EBITDAX ratio of not greater than 3.5 to 1.0. As of March 31, 2022, the Company was in compliance with the covenants under the Credit Agreement.

The obligations of Whiting Oil and Gas under the Credit Agreement are secured by a first lien on substantially all of the Company’s and certain of its subsidiaries’ properties. The Company has also guaranteed the obligations of Whiting Oil and Gas under the Credit Agreement and has pledged the stock of certain of its subsidiaries as security for its guarantee.

5. ASSET RETIREMENT OBLIGATIONS

The Company’s asset retirement obligations represent the present value of estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws and the terms of the Company’s lease agreements. The current portions as of March 31, 2022 and December 31, 2021 were $13 million and $10 million, respectively, and have been included in accrued liabilities and other in the condensed consolidated balance sheets. The following table provides a reconciliation of the Company’s asset retirement obligations for the three months ended March 31, 2022 (in thousands):


Asset retirement obligation at January 1, 2022	$	104,067
Additional liability incurred or assumed		3,301
Accretion expense		2,129
Liabilities settled		(1,311)
Asset retirement obligation at March 31, 2022	$	108,186

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6. DERIVATIVE FINANCIAL INSTRUMENTS

The Company is exposed to certain risks relating to its ongoing business operations, and it uses derivative instruments to manage its commodity price risk.

Commodity Derivative Contracts—Historically, prices received for crude oil, natural gas and natural gas liquids production have been volatile because of supply and demand factors, worldwide political factors, general economic conditions and seasonal weather patterns. Whiting primarily enters into derivative contracts such as crude oil, natural gas and NGL swaps, collars, basis swaps and differential swaps to achieve a more predictable cash flow by reducing its exposure to commodity price volatility, thereby ensuring adequate funding for the Company’s capital programs and facilitating the management of returns on drilling programs and acquisitions. The Company also enters into derivative contracts to maintain its compliance with certain minimum hedging requirements contained in the Credit Agreement. Refer to the “Long-Term Debt” footnote for a detailed discussion of the minimum and maximum hedging requirements of the Credit Agreement. The Company does not enter into derivative contracts for speculative or trading purposes.

Swaps, Collars, Basis Swaps and Differential Swaps. Swaps establish a fixed price for anticipated future oil, gas or NGL production, while collars are designed to establish floor and ceiling prices on anticipated future production. Basis and differential swaps mitigate risk associated with anticipated future production by establishing a fixed differential between NYMEX prices and the index price referenced in the contract. While the use of these derivative instruments limits the downside risk of adverse price movements, it may also limit future income from favorable price movements.

The table below details the Company’s swap and collar derivatives entered into to hedge forecasted crude oil, natural gas and NGL production revenues as of March 31, 2022.


					Weighted Average
Settlement Period	Index	Derivative Instrument	Total Volumes	Units	Swap Price	Floor	Ceiling
Crude Oil
2022	NYMEX WTI	Fixed Price Swaps	2,750,000	Bbl	$78.08	-	-
2022	NYMEX WTI	Two-way Collars	8,722,000	Bbl	-	$47.28	$57.72
Q1-Q2 2023	NYMEX WTI	Fixed Price Swaps	1,172,000	Bbl	$76.79	-	-
Q1-Q3 2023	NYMEX WTI	Two-way Collars	3,443,500	Bbl	-	$46.75	$58.87
		Total	16,087,500
Natural Gas
2022	NYMEX Henry Hub	Fixed Price Swaps	9,054,000	MMBtu	$3.59	-	-
2022	NYMEX Henry Hub	Two-way Collars	12,804,000	MMBtu	-	$2.60	$3.20
Q1 2023	NYMEX Henry Hub	Fixed Price Swaps	1,800,000	MMBtu	$4.25	-	-
Q1-Q3 2023	NYMEX Henry Hub	Two-way Collars	8,799,000	MMBtu	-	$2.85	$3.57
		Total	32,457,000
Natural Gas Basis ⁽¹⁾
2022	NNG Ventura to NYMEX	Fixed Price Swaps	1,985,000	MMBtu	$0.21	-	-
Q1-Q2 2023	NNG Ventura to NYMEX	Fixed Price Swaps	5,920,000	MMBtu	$0.40	-	-
		Total	7,905,000
NGL - Propane
2022	Mont Belvieu	Fixed Price Swaps	13,461,000	Gallons	$1.06	-	-
2022	Conway	Fixed Price Swaps	46,200,000	Gallons	$1.04	-	-
Q1 2023	Conway	Fixed Price Swaps	7,560,000	Gallons	$1.16	-	-
		Total	67,221,000

(1)

The weighted average price associated with the natural gas basis swaps shown in the table above represents the average fixed differential to NYMEX as stated in the related contracts, which is compared to the Northern Natural Gas Ventura Index (“NNG Ventura”) for each period. If NYMEX combined with the fixed differential as stated in each contract is higher than the NNG Ventura index price at any settlement date, the Company receives the difference. Conversely, if the NNG Ventura index price is higher than NYMEX combined with the fixed differential, the Company pays the difference.

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Derivative Instrument Reporting—All derivative instruments are recorded in the condensed consolidated financial statements at fair value, other than derivative instruments that meet the “normal purchase normal sale” exclusion. Fair value gains and losses on the Company’s derivative instruments are recognized immediately in earnings as derivatives (gain) loss, net in the condensed consolidated statements of operations.

Offsetting of Derivative Assets and Liabilities. The Company nets its financial derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The following tables summarize the location and fair value amounts of all the Company’s derivative instruments in the condensed consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the condensed consolidated balance sheets (in thousands):


		March 31, 2022⁽¹⁾
						Net
		Gross				Recognized
		Recognized		Gross		Fair Value
Not Designated as		Assets/		Amounts		Assets/
ASC 815 Hedges	Balance Sheet Classification	Liabilities		Offset		Liabilities
Derivative Assets
Commodity contracts - current	Prepaid expenses and other	$	14,038	$	(14,038)	$	-
Commodity contracts - non-current	Other long-term assets		4,295		(4,114)		181
Total derivative assets		$	18,333	$	(18,152)	$	181
Derivative Liabilities
Commodity contracts - current	Derivative liabilities	$	520,906	$	(14,038)	$	506,868
Commodity contracts - non-current	Long-term derivative liabilities		37,568		(4,114)		33,454
Total derivative liabilities		$	558,474	$	(18,152)	$	540,322


		December 31, 2021⁽¹⁾
						Net
		Gross				Recognized
		Recognized		Gross		Fair Value
Not Designated as		Assets/		Amounts		Assets/
ASC 815 Hedges	Balance Sheet Classification	Liabilities		Offset		Liabilities
Derivative Assets
Commodity contracts - current	Prepaid expenses and other	$	34,375	$	(31,002)	$	3,373
Commodity contracts - non-current	Other long-term assets		13,674		(13,674)		-
Total derivative assets		$	48,049	$	(44,676)	$	3,373
Derivative Liabilities
Commodity contracts - current	Derivative liabilities	$	240,655	$	(31,002)	$	209,653
Commodity contracts - non-current	Long-term derivative liabilities		60,394		(13,674)		46,720
Total derivative liabilities		$	301,049	$	(44,676)	$	256,373

(1)

All of the counterparties to the Company’s financial derivative contracts subject to master netting arrangements are lenders under the Credit Agreement, which eliminates the need to post or receive collateral associated with its derivative positions other than that already provided under the Credit Agreement. Therefore, columns for cash collateral pledged or received have not been presented in these tables.

Contingent Features in Financial Derivative Instruments. None of the Company’s derivative instruments contain credit-risk-related contingent features. Counterparties to the Company’s financial derivative contracts are high credit-quality financial institutions that are lenders under the Credit Agreement. The Company uses Credit Agreement participants as hedge counterparties since these institutions are secured equally with the holders of Whiting’s bank debt, which eliminates the potential need to post collateral when Whiting is in a derivative liability position. As a result, the Company is not required to post letters of credit or corporate guarantees for its derivative counterparties in order to secure contract performance obligations.

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7. FAIR VALUE MEASUREMENTS

Cash, cash equivalents, accounts receivable and accounts payable are carried at cost, which approximates their fair value because of the short-term maturity of these instruments. The Credit Agreement has a recorded value that approximates its fair value since its variable interest rate is tied to current market rates and the applicable margins represent market rates.

The Company’s derivative financial instruments are recorded at fair value and include a measure of the Company’s own nonperformance risk or that of its counterparty, as appropriate. The following tables present information about the Company’s financial assets and liabilities measured at fair value on a recurring basis as of March 31, 2022 and December 31, 2021, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values (in thousands):


							Total Fair Value
	Level 1		Level 2		Level 3		March 31, 2022
Financial Assets
Commodity derivatives – non-current	$	-	$	181	$	-	$	181
Total financial assets	$	-	$	181	$	-	$	181
Financial Liabilities
Commodity derivatives – current	$	-	$	506,868	$	-	$	506,868
Commodity derivatives – non-current		-		33,454		-		33,454
Total financial liabilities	$	-	$	540,322	$	-	$	540,322


							Total Fair Value
	Level 1		Level 2		Level 3		December 31, 2021
Financial Assets
Commodity derivatives – current	$	-	$	3,373	$	-	$	3,373
Total financial assets	$	-	$	3,373	$	-	$	3,373
Financial Liabilities
Commodity derivatives – current	$	-	$	209,653	$	-	$	209,653
Commodity derivatives – non-current		-		46,720		-		46,720
Total financial liabilities	$	-	$	256,373	$	-	$	256,373

The following methods and assumptions were used to estimate the fair values of the Company’s financial assets and liabilities that are measured on a recurring basis:

Commodity Derivatives. Commodity derivative instruments consist mainly of swaps, collars, basis swaps and differential swaps for crude oil, natural gas and NGLs. The Company’s swaps, collars and basis swaps are valued based on an income approach. Both the option and swap models consider various assumptions, such as quoted forward prices for commodities, time value and volatility factors. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace and are therefore designated as Level 2 within the valuation hierarchy. The discount rates used in the fair values of these instruments include a measure of either the Company’s or the counterparty’s nonperformance risk, as appropriate. The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations.

Non-recurring Fair Value Measurements—Nonfinancial assets and liabilities, such as the initial measurement of oil and natural gas properties and asset retirement obligations upon acquisition or the impairment of proved properties, are recognized at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. The Company did not recognize any impairment write-downs with respect to its proved property during the periods presented.

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Williston Basin Acquisition. On March 17, 2022, the Company acquired additional interests in oil and gas properties in the Williston Basin, as further described in the “Acquisitions and Divestitures” footnote above. The assets acquired and liabilities assumed were recorded at their fair values as of March 17, 2022. The inputs utilized in the valuation of the oil and gas properties and related assets acquired included mostly unobservable inputs which fall within Level 3 of the fair value hierarchy. Such inputs included estimates of future oil and gas production from the properties’ reserve reports, commodity prices based on forward strip price curves (adjusted for basis differentials) as of March 17, 2022, operating and development costs, expected future development plans for the properties and a discount rate of 13% based on a weighted-average cost of capital. The Company also recorded the asset retirement obligations assumed at fair value. The inputs utilized in valuing the asset retirement obligations were mostly Level 3 unobservable inputs, including estimated economic lives of oil and natural gas wells as of March 17, 2022, anticipated future plugging and abandonment costs and an appropriate credit-adjusted risk-free rate to discount such costs.

8. REVENUE RECOGNITION

The tables below present the disaggregation of revenue by product and transaction type for the periods presented (in thousands):


	Three Months Ended March 31,
OPERATING REVENUES	2022		2021
Oil sales	$	429,758	$	256,709
NGL and natural gas sales		90,458		47,970
Oil, NGL and natural gas sales		520,216		304,679
Purchased gas sales		6,640		2,712
Total operating revenues	$	526,856	$	307,391

Whiting receives payment for product sales 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 accounts receivable trade, net in the condensed consolidated balance sheets. As of March 31, 2022 and December 31, 2021, such receivable balances were $229 million and $178 million, respectively. Variances between the Company’s estimated revenue and actual payments are recorded in the month the payment is received, but differences have been and are insignificant. Accordingly, the variable consideration is not constrained.

9. SHAREHOLDERS’ EQUITY

Common Stock—The Company previously filed an amended and restated certificate of incorporation with the Delaware Secretary of State to provide for, among other things, the authority to issue a total of 550,000,000 shares of all classes of capital stock, of which 500,000,000 shares are common stock, par value $0.001 per share (the “Common Stock”) and 50,000,000 shares are preferred stock, par value $0.001 per share.

Warrants—The Company entered into warrant agreements on September 1, 2020 with Computershare Inc. and Computershare Trust Company, N.A., as warrant agent, which provide for (i) the Company’s issuance of up to an aggregate of 4,837,821 Series A warrants to acquire Common Stock (the “Series A Warrants”) and (ii) the Company’s issuance of up to an aggregate of 2,418,910 Series B warrants to acquire Common Stock (the “Series B Warrants” and together with the Series A Warrants, the “Warrants”).

The Series A Warrants are exercisable from the date of issuance until September 1, 2024, at which time all unexercised Series A Warrants will expire and the rights of the holders of such warrants to acquire Common Stock will terminate. The Series A Warrants are initially exercisable for 1 share of Common Stock per Series A Warrant at an initial exercise price of $73.44 per Series A Warrant (the “Series A Exercise Price”).

The Series B Warrants are exercisable from the date of issuance until September 1, 2025, at which time all unexercised Series B Warrants will expire and the rights of the holders of such warrants to acquire Common Stock will terminate. The Series B Warrants are initially exercisable for 1 share of Common Stock per Series B Warrant at an initial exercise price of $83.45 per Series B Warrant (the “Series B Exercise Price” and together with the Series A Exercise Price, the “Exercise Prices”).

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In the event that a holder of Warrants elects to exercise their option to acquire shares of Common Stock, the Company shall issue a net number of exercised shares of Common Stock. The net number of exercised shares is calculated as (i) the number of Warrants exercised multiplied by (ii) the difference between the 30 day daily volume weighted average price (“VWAP”) of the Common Stock leading up to the exercise date (the “Current Market Price”) and the relevant exercise price, calculated as a percentage of the Current Market Price on the exercise date.

During the three months ended March 31, 2022, Warrant holders exercised 264 Series A Warrants in exchange for 7 shares of Common Stock. As a result of these exchanges, 4,837,112 Series A Warrants remain outstanding as of March 31, 2022. 2,418,832 Series B Warrants remain outstanding as of March 31, 2022.

Pursuant to the warrant agreements, no holder of a Warrant, by virtue of holding or having a beneficial interest in a Warrant, will have the right to vote, receive dividends, receive notice as stockholders with respect to any meeting of stockholders for the election of Whiting’s directors or any other matter, or exercise any rights whatsoever as a stockholder of Whiting unless, until and only to the extent such holders become holders of record of shares of Common Stock issued upon settlement of the Warrants.

The number of shares of Common Stock for which a Warrant is exercisable and the Exercise Prices are subject to adjustment from time to time upon the occurrence of certain events, including stock splits, reverse stock splits or stock dividends to holders of Common Stock or a reclassification in respect of Common Stock.

Dividends—On February 8, 2022, the Company announced an inaugural quarterly dividend of $0.25 per share. The first dividend totaling approximately $10 million was paid on March 15, 2022 to shareholders of record as of February 21, 2022. On April 14, 2022 the Company declared another quarterly cash dividend of $0.25 per share payable June 1, 2022 to shareholders of record as of May 20, 2022.

Settlement of Bankruptcy Claims—Prior to the Chapter 11 Cases, WOG was party to various executory contracts with BNN Western, LLC, subsequently renamed Tallgrass Water Western, LLC (“Tallgrass”), including a Produced Water Gathering and Disposal Agreement (the “PWA”). In January 2021, WOG and Tallgrass entered into a settlement agreement to resolve all of the related claims before the Bankruptcy Court relating to such executory contracts, terminated the PWA and entered into a new Water Transport, Gathering and Disposal Agreement. In accordance with the settlement agreement, Whiting made a $2 million cash payment and issued 948,897 shares of Common Stock to a Tallgrass entity in February 2021.

An additional 2,121,304 shares of Common Stock remain reserved as of March 31, 2022 for potential future distribution to certain general unsecured claimants whose claim values are pending resolution in the Bankruptcy Court.

10. STOCK-BASED COMPENSATION

Equity Incentive Plan—On September 1, 2020, the Company’s board of directors adopted the Whiting Petroleum Corporation 2020 Equity Incentive Plan (the ��2020 Equity Plan”). The 2020 Equity Plan provides the authority to issue 4,035,885 shares of the Company’s common stock. Any shares forfeited under the 2020 Equity Plan will be available for future issuance under the 2020 Equity Plan. However, shares netted for tax withholding under the 2020 Equity Plan will be cancelled and will not be available for future issuance. Under the 2020 Equity Plan, during any calendar year no non-employee director participant may be granted awards having a grant date fair value in excess of $500,000. As of March 31, 2022, 2,788,280 shares of common stock remained available for grant under the 2020 Equity Plan.

Historically, the Company has granted restricted stock units (“RSUs”) to executive officers and employees, which generally vest ratably over a two, three or five-year service period. The Company has granted service-based RSUs to directors, which generally vest over a one-year service period. In addition, the Company has granted performance share units (“PSUs”) to executive officers that are subject to market-based vesting criteria, which generally vest over a three-year service period. Additionally, certain of the Company’s executive officers can receive shares for any short-term bonus award in excess of the targets set by the board of directors at the beginning of each year. The Company accounts for forfeitures of awards granted under these plans as they occur in determining compensation expense. The Company recognizes compensation expense for all awards subject to market-based vesting conditions regardless of whether it becomes probable that these conditions will be achieved or not, and compensation expense for share-settled awards is not reversed if vesting does not actually occur.

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The Company also grants dividend equivalents on any unvested awards when dividends are paid to shareholders of the Company’s Common Stock. Dividend equivalents are granted in an amount equal to what would have been paid to the award holder if the unvested shares were outstanding at the dividend record date. These dividend equivalents are deemed reinvested in additional restricted stock units that are subject to the same terms and conditions and shall vest and be settled or be forfeited at the same time as the awards to which they are attributable. Any fractional shares that result from dividend equivalents are settled in cash upon vesting.

Awards under the 2020 Equity Plan

In September 2020, 189,900 shares of market-based RSUs were granted to executive officers. The awards vest upon the Company’s common stock trading for 20 consecutive trading days above a certain daily VWAP as follows: 50% vested when the VWAP exceeded $32.57 per share, an additional 25% vested when the daily VWAP exceeded $48.86 per share and the final 25% vested when the daily VWAP exceeded $65.14 per share. The Company recognizes compensation expense based on the fair value as determined by a Monte Carlo valuation model (the “Monte Carlo Model”) over the expected vesting period, which was estimated to be between 1.8 and 3.8 years at the grant date. Upon vesting, any unrecognized compensation expense related to the shares is accelerated and recognized. The weighted average grant date fair value of these RSUs was $6.54 per share. More information on the inputs to the Monte Carlo Model are explained below. During 2021, the first 75% of these awards vested as the Company’s VWAP exceeded both $32.57 and $48.86 per share for 20 consecutive trading days during the period. During the first quarter of 2022, the remaining 25% of these awards vested as the Company’s VWAP exceeded $65.14 per share for 20 consecutive days during the period.

During the three months ended March 31, 2022 and 2021, 149,200 and 358,123 shares, respectively, of service-based RSUs were granted to executive officers and employees, which vest ratably over either a two or three-year service period. Additionally, during the three months ended March 31, 2021, 117,607 shares of service-based RSUs were granted to executive officers, which cliff vest on the fifth anniversary of the grant date. The Company determines compensation expense for these share-settled awards using their fair value at the grant date, which is based on the closing bid price of the Company’s common stock on such date. The weighted average grant date fair value of serviced-based RSUs was $73.97 per share and $22.46 per share, respectively, for the three months ended March 31, 2022 and 2021.

During the three months ended March 31, 2022 and 2021, 83,946 and 232,150 shares, respectively, of PSUs subject to certain market-based vesting criteria were granted to executive officers. These market-based awards vest at the end of a three-year performance period, which is December 31, 2024 for the 2022 awards and December 31, 2023 for the 2021 awards. The number of shares that vest at the end of the performance period is determined based on two performance goals: (i) half of the shares granted in each period vest based on the Company’s annualized absolute total stockholder return (“ATSR”) over the performance period as compared to certain preestablished target returns and (ii) half of the shares vest based on the Company’s relative total stockholder return (“RTSR”) compared to the stockholder returns of a preestablished peer group of companies over the performance period. The number of awards earned could range from 0 up to 2 times the number of shares initially granted, all of which will be settled in shares. The weighted average grant date fair value of the market-based awards granted during 2022 was $110.47 per share and $99.63 per share for the ATSR and RTSR awards, respectively, and the weighted average grant date fair value of the market-based awards granted in 2021 was $29.32 per share and $32.33 per share for the ATSR and RTSR awards, respectively.

For awards subject to market conditions, the grant date fair value is estimated using the Monte Carlo Model, which is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility for the market-based RSUs was calculated based on the observed volatility of peer public companies. Expected volatility for the market-based PSUs was calculated based on the historical and implied volatility of Whiting’s common shares (adjusted for the impacts of the Chapter 11 Cases). The risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with the vesting period for the relevant award. The key assumptions used in valuing these market-based awards were as follows:


	2022	2021	2020
	PSUs	PSUs	RSUs
Number of simulations	500,000	500,000	100,000
Expected volatility	69%	81%	40%
Risk-free interest rate	1.37%	0.17%	0.66%
Dividend yield	-	-	-

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During the three months ended March 31, 2022, certain executives received 11,787 shares of common stock as part of their incentive compensation package which represented the portion of their 2021 short-term bonus that was in excess of their target bonus established by the Board at the beginning of the year, in accordance with their employment agreements. As the bonus amount was determined prior to December 31, 2021, the Company recorded approximately $1 million in stock compensation expense related to these awards during the fourth quarter of 2021, which was recorded to accrued liabilities and other in the Company’s consolidated balance sheets as of December 31, 2021.

The following table shows a summary of the Company’s service-based and market-based awards activity for the three months ended March 31, 2022:


	Number of Awards			Weighted Average
	Service‑Based	Market-Based	Market-Based	Grant Date
	RSUs	RSUs	PSUs	Fair Value
Nonvested awards, January 1, 2022	516,256	47,475	232,150	$	24.67
Granted	160,987	-	83,946		84.75
Vested	(131,028)	(47,475)	-		22.05
Forfeited	(1,074)	-	-		41.82
Nonvested awards, March 31, 2022	545,141	-	316,096	$	42.28

The Company recognized $4 million and $2 million in stock-based compensation expense during the three months ended March 31, 2022 and 2021, respectively.

11. INCOME TAXES

Income tax expense during interim periods is generally determined by applying an estimated annual effective income tax rate to year-to-date income and adjusting for any significant unusual or infrequently occurring items which are recorded in the interim period. For the three months ended March 31, 2022, this resulted in an income tax benefit that was not recognized due to a full valuation allowance in effect on the Company’s U.S. deferred tax assets (“DTAs”). Therefore, income tax expense for the three months ended March 31, 2022 was determined based on estimated earnings for the interim period. The Company therefore incurred income tax expense of $7 million for the period after the utilization of the Company’s available Internal Revenue Code (“IRC”) Section 382 limited net operating loss carryforwards (“NOLs”). The net result is an effective U.S. income tax rate of (24.2%). This rate differs from the statutory U.S. federal income tax rate of 21.0% primarily due to share-based compensation, other permanent items and a full valuation allowance in effect on the Company’s DTAs, including the tax effects of unrealized losses on derivatives.

For the three months ended March 31, 2021, 0 U.S. income tax expense was recognized for an effective U.S. tax rate of 0%. The provisions for income taxes for the three months ended March 31, 2021 differ from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21.0% to pre-tax income primarily due to a full valuation allowance in effect on the Company’s DTAs.

In assessing the realizability of DTAs, management considers whether it is more likely than not that some portion, or all, of the Company’s DTAs will not be realized. In making such determination, the Company considers all available positive and negative evidence, including future reversals of temporary differences, tax-planning strategies and projected future taxable income and results of operations. If the Company concludes that it is more likely than not that some portion, or all, of its DTAs will not be realized, the tax asset is reduced by a valuation allowance. The Company assesses the appropriateness of its valuation allowance on a quarterly basis. At March 31, 2022 and December 31, 2021, the Company had a full valuation allowance on its DTAs.

The computation of the estimated annual effective tax rate at each interim period requires certain estimates and significant judgment including, but not limited to, the expected operating income for the year, projections of the proportion of income earned and taxed in various jurisdictions, permanent and temporary differences, and the likelihood of recovering DTAs generated in the current year. The accounting estimates used to compute the provision for income taxes may change as new events occur, more experience is obtained, additional information becomes known or as the tax environment changes.

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IRC Section 382 addresses tax impacts of an ownership change and specifically limits the utilization of NOLs and certain other deductions for tax periods following an ownership change. The Company previously experienced an ownership change within the meaning of IRC Section 382. This ownership change subjected certain of the Company’s tax attributes to an IRC Section 382 limitation. The ownership change and resulting annual limitation on the Company’s NOL usage will result in the expiration of certain NOLs and other tax attributes otherwise available, with a corresponding decrease in the Company’s valuation allowance.

As of December 31, 2021, the Company had federal NOLs of $3.3 billion which are subject to limitation under IRC Section 382. Due to the annual IRC Section 382 limitation, certain other attribute reductions and the carryforward period of NOLs, approximately $2.2 billion of these federal NOLs will expire before they are able to be used. The remaining non-expiring NOLs are subject to a full valuation allowance as of March 31, 2022 and December 31, 2021.

12. EARNINGS PER SHARE

The reconciliations between basic and diluted earnings (loss) per share are as follows (in thousands, except per share data):


	Three Months Ended March 31,
	2022		2021
Basic and diluted loss per share
Net loss	$	(37,429)	$	(946)
Weighted average shares outstanding, basic and diluted		39,204		38,698
Loss per common share, basic and diluted	$	(0.95)	$	(0.02)

During the three months ended March 31, 2022, the diluted earnings per share calculation excludes the effect of 381,460 shares of service-based awards, 313,303 shares of market-based awards and 128,333 outstanding Series A Warrants that were anti-dilutive as a result of the net loss incurred during the period. The calculation also excludes 2,121,304 contingently issuable shares related to the settlement of general unsecured claims associated with the Chapter 11 Cases, as all necessary conditions had not been met to be considered dilutive shares as of March 31, 2022. Finally, the calculation excludes the effect of common shares that may be issued pursuant to the Series B Warrants as such warrants were out-of-the-money as of March 31, 2022.

During the three months ended March 31, 2021, the diluted earnings per share calculation excludes the effect of 194,469 shares of service-based awards and 90,352 shares of market-based awards that were anti-dilutive as a result of the net loss incurred during the period and 94,950 shares of market-based awards that did not meet the market-based vesting criteria as of March 31, 2021. Further, the calculation excludes the effect of 2,121,304 contingently issuable shares related to the settlement of general unsecured claims associated with the Chapter 11 Cases, as all necessary conditions had not been met to be considered dilutive shares as of March 31, 2021. Finally, the calculation excludes the effect of common shares that may be issued pursuant to the Series A and Series B Warrants as such warrants were out-of-the-money as of March 31, 2021.

Refer to the “Stock-Based Compensation” footnote for more information on the Company’s service-based and market-based awards.

13. COMMITMENTS AND CONTINGENCIES

Chapter 11 Cases— On April 1, 2020, the Debtors filed the Chapter 11 Cases seeking relief under the Bankruptcy Code. The filing of the Chapter 11 Cases allowed the Company to, upon approval of the Bankruptcy Court, assume, assign or reject certain contractual commitments, including certain executory contracts. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such contract and, subject to certain exceptions, relieves the Company from performing future obligations under such contract but entitles the counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. The claims resolution process is ongoing and certain of these claims remain subject to the jurisdiction of the Bankruptcy Court. To the extent that these Bankruptcy Court proceedings result in unsecured claims being allowed against the Company, such claims may be satisfied through the issuance of shares of the Company’s common stock or other remedy or agreement under and pursuant to the Plan.

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Arguello Inc. and Freeport-McMoRan Oil & Gas LLC. WOG had interests in federal oil and gas leases in the Point Arguello Unit located offshore in California. While those interests have expired, pursuant to certain related agreements (the “Point Arguello Agreements”), WOG may be subject to abandonment and decommissioning obligations. WOG and Whiting Petroleum Corporation rejected the related contracts pursuant to the Plan. On October 1, 2020, Arguello Inc. and Freeport-McMoRan Oil & Gas LLC, individually and in its capacity as the designated Point Arguello Unit operator (collectively, the “FMOG Entities”) filed with the Bankruptcy Court an application for allowance of certain administrative claims arguing the FMOG Entities were entitled to recover Whiting’s proportionate share of decommissioning obligations owed to the U.S. government through subrogation to the U.S. government’s economic rights. The FMOG Entities’ application alleged administrative claims of approximately $25 million for estimated decommissioning costs owed to the U.S. government, at least $60 million of estimated decommissioning costs owed to the FMOG Entities and other insignificant amounts. On September 14, 2020, the FMOG Entities also filed with the Bankruptcy Court proofs of claim for rejection damages to serve as an alternative course of action in the event that a court should determine that the FMOG Entities do not hold any applicable administrative claims. The U.S. government may also be able to bring claims against WOG directly for decommissioning costs. On February 18, 2021, WOG entered into a stipulation and agreed order with the United States Department of the Interior, Bureau of Safety & Environmental Enforcement (the “BSEE”) pursuant to which the BSEE withdrew its proofs of claims against Whiting Petroleum Corporation and WOG and acknowledged their respective rights and obligations pursuant to the Plan. On March 26, 2021, the FMOG Entities withdrew their administrative claim for the recovery of Whiting’s proportionate share of costs incurred after August 31, 2020 to fulfill obligations owed to the U.S. Government on the basis of subrogation to the Government’s economic rights. The FMOG Entities continue to assert certain other administrative claims and have reserved the right to assert claims for the recovery of Whiting’s share of the decommissioning costs incurred after August 31, 2020 based on the theory of equitable subrogation. On September 14, 2021, Whiting Petroleum Corporation and WOG filed an objection in the Bankruptcy Court, seeking an order partially disallowing the FMOG Entities’ claims. The Bankruptcy Court has not issued a ruling on the damages for rejection of the Point Arguello Agreements and it is possible that a settlement with the FMOG Entities could be reached. Although WOG intends to vigorously pursue its objection in this legal proceeding, if the FMOG Entities were to prevail on certain of their respective claims (including the reserved claims) on the merits, the Company enters into a settlement agreement or the U.S. government were to bring claims against WOG, Whiting could be liable for claims that must be paid or otherwise satisfied under and pursuant to the Plan including through an equity issuance, cash payment or otherwise.

It is possible that as a result of the legal proceedings associated with the bankruptcy claims administration process or the matter detailed above, the Bankruptcy Court may rule that the claim should be afforded some treatment other than as a general unsecured claim. This outcome could require the Company to make cash payments to settle those claims instead of or in addition to issuing shares of the Company’s common stock, and such cash payments would result in losses in future periods. In addition, it is also reasonably possible that a settlement with respect to such legal proceedings could be reached, in which case the settlement consideration would be paid or otherwise satisfied under and pursuant to the Plan, including through an equity issuance, cash payment or otherwise. As of March 31, 2022, the Company had $55 million of outstanding offers to settle claims from the Chapter 11 Cases in cash, rather than through the issuance of shares of the Company’s common stock reserved under the Plan for potential distribution to general unsecured claimants. If accepted, these settlements would be paid with cash on hand or borrowings under the Credit Agreement and would not result in the Company issuing shares of common stock to resolve the claims. However, such claims remain subject to the jurisdiction of the Bankruptcy Court and it is reasonably possible that these claims could be resolved by the issuance of shares of the Company’s common stock. The ultimate amount of either a cash payment or number of shares of the Company’s common stock that may be issued to settle such claims is uncertain and cannot currently be reasonably estimated.

Litigation—The Company is subject to litigation, claims and governmental and regulatory proceedings arising in the ordinary course of business. The Company accrues a loss contingency for these lawsuits and claims when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. While the outcome of these lawsuits and claims cannot be predicted with certainty, it is the opinion of the Company’s management that the loss for any litigation matters and claims that are reasonably possible to occur will not have a material adverse effect, individually or in the aggregate, on its consolidated financial position, cash flows or results of operations unless separately disclosed. Accordingly, no material amounts for loss contingencies associated with litigation, claims or assessments have been accrued at March 31, 2022 or December 31, 2021.

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

Unless the context otherwise requires, the terms “Whiting,” “we,” “us,” “our” or “ours” when used in this Item refer to Whiting Petroleum Corporation, together with its consolidated subsidiaries, Whiting Oil and Gas Corporation (“Whiting Oil and Gas” or “WOG”) and Whiting Programs, Inc. When the context requires, we refer to these entities separately. This document contains forward-looking statements, which give our current expectations or forecasts of future events. Please refer to “Forward-Looking Statements” at the end of this Item for an explanation of these types of statements.

Proposed Merger with Oasis Petroleum Inc.

On March 7, 2022, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Oasis Petroleum Inc., a Delaware corporation (“Oasis”), Ohm Merger Sub Inc., a Delaware corporation and a wholly owned subsidiary of Oasis (“Merger Sub”), and New Ohm LLC, a Delaware limited liability company and a wholly owned subsidiary of Oasis, pursuant to which, among other things, we will merge with Merger Sub in a merger of equals (the “Merger”). The Merger is subject to customary closing conditions, including, among others, approval by Whiting and Oasis shareholders. We currently expect the Merger to close in the second half of 2022. Upon closing, Lynn A. Peterson, our President and Chief Executive Officer, will serve as Executive Chair of the Board of Directors of the combined company, and Daniel E. Brown, Oasis’ Chief Executive Officer, will serve as President and Chief Executive Officer and as a member of the Board of Directors of the combined company.

The foregoing summary of the Merger Agreement and the transactions contemplated thereby does not purport to be complete and is qualified in its entirety by reference to the terms and conditions of the Merger Agreement, a copy of which is attached as Exhibit 2.1 to the Company’s Current Report on Form 8-K, filed on March 8, 2022.

Overview

We are an independent oil and gas company engaged in development, production and acquisition activities primarily in the Rocky Mountains region of the United States where we are focused on developing our large resource play in the Williston Basin of North Dakota and Montana. Since our inception, we have built a strong asset base through a combination of property acquisitions, development of proved reserves and exploration activities. We are currently focusing our capital programs on drilling and workover opportunities that we believe provide attractive well-level returns in order to maintain consistent production levels and generate free cash flow. During 2022, we are focused on high-return projects in our asset portfolio that will generate significant cash flow from operations in order to maintain and expand our shareholder capital return program and minimize our borrowings under the Credit Agreement. We continually evaluate our property portfolio and sell properties when we believe that the sales price realized will provide an above average rate of return for the property or when the property no longer matches the profile of properties we desire to own. Refer to “Recent Developments” below for more information on our recent acquisition and divestiture activity.

We are committed to developing the energy resources the world needs in a safe and responsible way that allows us to protect our employees, our contractors, our vendors, the public and the environment while also meeting or exceeding regulatory requirements. We continually evolve our practices to better protect wildlife habitats and communities, to reduce freshwater use in our development process, to identify and reduce methane emissions of our operations, to encourage waste reduction programs and to promote worker safety. Additionally, we are committed to transparency in reporting our environmental, social and governance performance and to monitoring such performance through various measures, some of which are tied to our short-term incentive program for all employees. Refer to our Sustainability Report published on our website for sustainability performance highlights and additional information. Information contained in our Sustainability Report is not incorporated by reference into, and does not constitute a part of, this Quarterly Report on Form 10-Q. Concurrently, our oil and gas development and production operations are subject to stringent environmental regulations governing the release of certain materials into the environment which often require costly compliance measures that carry substantial penalties for noncompliance. However, we have not incurred any material penalties historically. Refer to “Government Regulation” in Item 1 of our Annual Report on Form 10-K, as amended, for more information.

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Our revenue, profitability, cash flows and future growth rate depend on many factors which are beyond our control, such as oil and gas prices; economic, political and regulatory developments; the financial condition of our industry partners; competition from other sources of energy; cost pressures as a result of inflation and the other items discussed under the caption “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the period ended December 31, 2021, as amended, and as supplemented by the additional risk factors described in Item 1A in this Quarterly Report on Form 10-Q for the three months ended March 31, 2022. Oil and gas prices historically have been volatile and may fluctuate widely in the future. The following table highlights the quarterly average NYMEX price trends for crude oil and natural gas prices since the first quarter of 2020:


	2020								2021								2022
	Q1		Q2		Q3		Q4		Q1		Q2		Q3		Q4		Q1
Crude oil	$	46.08	$	27.85	$	40.94	$	42.67	$	57.80	$	66.06	$	70.55	$	77.17	$	94.38
Natural gas	$	1.88	$	1.66	$	1.89	$	2.51	$	2.56	$	2.74	$	3.95	$	5.13	$	4.49

Oil prices continued to increase during the first quarter of 2022 compared to 2021, when prices were recovering from the economic effects of the coronavirus pandemic on the demand for oil and natural gas and uncertainty around output restraints on oil production agreed upon by the Organization of Petroleum Exporting Countries (“OPEC”) and other oil exporting nations. While oil, NGL and natural gas prices have increased significantly, uncertainties related to the demand for oil and natural gas products remain as (i) the Russian invasion of Ukraine has triggered significant economic sanctions and upended global commodity markets, (ii) the pandemic continues to impact the world economy, (iii) OPEC continues to negotiate appropriate production levels to balance the market and (iv) inflationary pressures in the economy disrupt commodity markets. Lower oil, NGL and natural gas prices decrease our revenues and reduce the amount of oil and natural gas that we can produce economically, which decreases our oil and gas reserve quantities. Substantial and extended declines in oil, NGL and natural gas prices have resulted, and may result, in impairments of our proved oil and gas properties or undeveloped acreage and may materially and adversely affect our future business, financial condition, cash flows, results of operations, liquidity or ability to fund planned capital expenditures. In addition, lower commodity prices may result in a reduction of the borrowing base under our Credit Agreement, which is determined at the discretion of our lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders. Upon a redetermination, if borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of the debt outstanding under our Credit Agreement. Alternatively, higher oil prices may result in significant mark-to-market losses being incurred on our commodity-based derivatives (such as the net derivative losses discussed below under “Results of Operations”).

Recent Developments

Return of Capital. On February 8, 2022, we announced an inaugural quarterly dividend of $0.25 per share. The first dividend totaling approximately $10 million was paid on March 15, 2022 to shareholders of record as of February 21, 2022. On April 14, 2022, we announced our second quarterly dividend of $0.25 per share to be paid on June 1, 2022 to shareholders of record as of May 20, 2022.

Williston Basin Acquisitions. On September 14, 2021, we completed the acquisition of interests in oil and gas properties located in Mountrail County, North Dakota for an aggregate purchase price of $271 million (before closing adjustments). This transaction was funded primarily with borrowings under our Credit Agreement, which have subsequently been repaid.

On December 16, 2021, we completed the acquisition of additional interests in oil and gas properties located in Mountrail County, North Dakota for an aggregate purchase price of $32 million (before closing adjustments). This transaction was funded with cash on hand and borrowings under our Credit Agreement, which have subsequently been repaid.

On March 17, 2022, we completed the acquisition of additional interests in oil and gas properties located in Mountrail County, North Dakota for an aggregate unadjusted purchase price of $240 million. This transaction was funded with cash on hand and borrowings under our Credit Agreement.

On a combined basis, our recent Williston Basin acquisitions included interests in 76 new gross producing oil and gas wells and increased interests in 527 existing gross producing wells. Overall, the acquisitions effectively added 136.2 net producing wells and included approximately 23,300 net undeveloped acres.

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2022 Highlights and Future Considerations

Operational Highlights

North Dakota and Montana – Williston Basin

Our properties in the Williston Basin of North Dakota and Montana target the Bakken and Three Forks formations. Net production from North Dakota and Montana averaged 86.6 MBOE/d for the first quarter of 2022, representing a 5% decrease from the fourth quarter of 2021. Across our acreage in the Williston Basin, we have implemented completion designs specifically tailored to unique reservoir conditions to increase well performance while reducing cost. We continued to focus on reducing time-on-location and total well cost while maximizing our lateral footage through drilling best practices including utilizing top tier drilling rigs, advanced downhole motor and drill bit technology and our custom drilling fluid system.

During the second half of 2021 and first quarter of 2022, we completed several acquisitions of additional oil and gas properties in the Williston Basin. Refer to “Recent Developments” above for additional details.

During the first quarter of 2022, we averaged two drilling rigs and one active completion crew in the Williston Basin. We plan to maintain this level of activity throughout the remainder of 2022. We drilled 17 gross (12.4 net) operated wells and TIL 11 gross (6.6 net) operated wells in this area during the quarter. As of March 31, 2022, we have 32 gross (22.8 net) operated drilled uncompleted wells. Under our current 2022 capital program, we expect to TIL approximately 68 gross (43.4 net) operated wells in this area during the year.

As discussed in “Proposed Merger with Oasis Petroleum Inc.” above, on March 7, 2022 we entered into a Merger Agreement that could result in significant changes to the current 2022 capital program should the transaction close during the year.

Financing Highlights

We entered into an agreement with the lenders of the Credit Agreement to defer the regularly scheduled April 1, 2022 borrowing base redetermination until September 1, 2022, which leaves the borrowing base under the Credit Agreement unchanged at $750 million until the next redetermination. Refer to the “Long-Term Debt” footnote in the notes to the condensed consolidated financial statements for more information.

Dakota Access Pipeline

In early 2020, the U.S. Army Corps of Engineers was ordered by the U.S. District Court for D.C. to prepare an environmental impact statement for the Dakota Access Pipeline (“DAPL”), the result of which could lead to future shutdowns of the pipeline. Refer to the Dakota Access Pipeline discussion in “Risk Factors” in Item 1A and “2021 Highlights and Future Considerations” in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2021, as amended, for more information. The potential disruption of transportation as a result of the DAPL being shut down or the anticipation of the DAPL being shut down could negatively impact our ability to achieve the most favorable prices for our crude oil production, which could have an adverse effect on our business, financial condition, results of operations and cash flows. To help mitigate the potential impact of an unfavorable outcome, we have coordinated with our midstream partners and downstream markets to source transportation alternatives.

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Results of Operations

Three Months Ended March 31, 2022 Compared to Three Months Ended December 31, 2021


	Three Months Ended
	March 31,		December 31,
	2022		2021
Net production
Oil (MMBbl)		4.7		4.9
NGLs (MMBbl)		1.7		1.9
Natural gas (Bcf)		9.6		10.3
Total production (MMBOE)		8.0		8.5
Net sales (in millions) ⁽¹⁾
Oil	$	429.7	$	369.0
NGLs		58.2		55.9
Natural gas		32.3		37.9
Total oil, NGL and natural gas sales	$	520.2	$	462.8
Average sales prices
Oil (per Bbl) ⁽¹⁾	$	91.05	$	75.75
Effect of oil hedges on average price (per Bbl)		(26.73)		(20.38)
Oil after the effect of hedging (per Bbl)	$	64.32	$	55.37
Weighted average NYMEX price (per Bbl) ⁽²⁾	$	94.52	$	77.00
NGLs (per Bbl) ⁽¹⁾	$	34.40	$	28.74
Effect of NGL hedges on average price (per Bbl)		(1.67)		(2.08)
NGLs after the effect of hedging (per Bbl)	$	32.73	$	26.66
Natural gas (per Mcf) ⁽¹⁾	$	3.37	$	3.68
Effect of natural gas hedges on average price (per Mcf)		(1.31)		(2.15)
Natural gas after the effect of hedging (per Mcf)	$	2.06	$	1.53
Weighted average NYMEX price (per MMBtu) ⁽²⁾	$	4.49	$	5.13
Costs and expenses (per BOE)
Lease operating expenses	$	9.05	$	7.31
Transportation, gathering, compression and other	$	0.84	$	0.80
Production and ad valorem taxes	$	4.73	$	3.74
Depreciation, depletion and amortization	$	6.15	$	5.76
General and administrative	$	2.32	$	1.79

(1)	Before consideration of hedging transactions.

(2)	Average NYMEX pricing weighted for monthly production volumes.

Oil, NGL and Natural Gas Sales. Our oil, NGL and natural gas sales revenue increased $57 million to $520 million when comparing the first quarter of 2022 to the fourth quarter of 2021. Changes in sales revenue between periods are due to changes in production sold and changes in average commodity prices realized (excluding the impacts of hedging). When comparing the first quarter of 2022 to the fourth quarter of 2021, increases in oil and NGL prices realized between periods accounted for a $82 million increase in revenue, which was partially offset by a decrease in total production and natural gas prices realized between periods that accounted for $22 million and $3 million decreases in revenue, respectively.

Our oil, NGL and natural gas volumes decreased by 3%, 13% and 7%, respectively, between periods. The overall volume decrease between periods was primarily driven by normal field production decline and fewer production days during the first quarter of 2022 compared to the fourth quarter of 2021, partially offset by new wells drilled and completed during the first quarter of 2022 in the Williston Basin. Additionally, NGL volumes decreased between periods due to lower NGL yields.

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Our average price for oil and NGLs (before the effects of hedging) increased 20% each between periods and our average price for natural gas (before the effects of hedging) decreased 8% between periods. Our average realized price for oil and NGLs primarily increased as a result of favorable movements in applicable benchmark indices between periods. The decrease in average price for natural gas was primarily a result of unfavorable movements in the applicable benchmark indices, partially offset by improved natural gas average realized price differentials to NYMEX as a result of stronger regional pricing in the Williston Basin during the first quarter of 2022.

Lease Operating Expenses. Our lease operating expenses (“LOE”) during the first quarter of 2022 were $73 million, a $10 million increase over the fourth quarter of 2021. This increase between periods was primarily due to a $4 million increase in well workover costs as a result of higher expenses per workover job completed, a $2 million increase in gas facility expenses, a $2 million increase in company and contract labor expenses and a $1 million increase in the cost of oil field goods and services.

Our lease operating expenses on a BOE basis also increased when comparing the first quarter of 2022 to the fourth quarter of 2021. LOE per BOE amounted to $9.05 during the first quarter of 2022, which represents an increase of $1.74 per BOE (or 24%) from the fourth quarter of 2021. This increase was mainly due to the overall increase in LOE discussed above as well as lower overall production volumes between periods.

Transportation, Gathering, Compression and Other. Our transportation, gathering, compression and other (“TGC”) expenses during the first quarter of 2022 were $7 million, which was consistent with the fourth quarter of 2021.

TGC per BOE, however, slightly increased when comparing the first quarter of 2022 to the fourth quarter of 2021. TGC per BOE amounted to $0.84 per BOE during the first quarter of 2022, which represents an increase of $0.04 per BOE (or 5%) from the fourth quarter of 2021. This increase was mainly due to the lower overall production volumes between periods discussed above.

Production and Ad Valorem Taxes. Our production and ad valorem taxes during the first quarter of 2022 totaled $38 million, a $6 million increase over the fourth quarter of 2021, which was primarily due to higher sales revenue between periods. Our production taxes, however, are generally calculated as a percentage of net oil, NGL and natural gas sales revenue before the effects of hedging, and this percentage on a company-wide basis was 7.4% and 6.8% for the first quarter of 2022 and the fourth quarter of 2021, respectively. This production tax percentage increase between periods is primarily due to severance tax refunds received in the fourth quarter of 2021.

Depreciation, Depletion and Amortization. The components of our depletion, depreciation and amortization (“DD&A”) expense were as follows (in thousands):


	Three Months Ended
	March 31,		December 31,
	2022		2021
Depletion	$	46,379	$	46,482
Accretion of asset retirement obligations		2,129		1,996
Depreciation		725		723
Total	$	49,233	$	49,201

DD&A expense was consistent between periods. On a BOE basis, our overall DD&A rate was $6.15 per BOE for the first quarter of 2022, which represents an increase of $0.39 per BOE (or 7%) from the fourth quarter of 2021. The primary factors contributing to this higher DD&A rate were our recent acquisitions in the Williston Basin as described in “Recent Developments” above, as well as increased drilling and completion activity between periods, partially offset by upward revisions to proved reserves due to higher commodity prices between periods.

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Exploration and Impairment Costs. The components of our exploration and impairment expense, which were consistent between periods, were as follows (in thousands):


	Three Months Ended
	March 31,		December 31,
	2022		2021
Impairment	$	1,282	$	1,577
Exploration		918		1,089
Total	$	2,200	$	2,666

General and Administrative Expenses. We report general and administrative (“G&A”) expenses net of third-party reimbursements and internal allocations. The components of our G&A expenses were as follows (in thousands):


	Three Months Ended
	March 31,		December 31,
	2022		2021
General and administrative expenses, other ⁽¹⁾	$	32,666	$	29,111
Stock-based compensation, non-cash		4,038		3,238
Reimbursements and allocations		(18,119)		(17,076)
General and administrative expenses, net (GAAP)		18,585		15,273
Less: Significant cost drivers ⁽²⁾		(6,140)		-
Non-GAAP general and administrative expenses less significant cost drivers⁽³⁾	$	12,445	$	15,273

(1)	General and administrative expenses, other excludes non-cash stock-based compensation expense and reimbursements and allocations. We believe general and administrative expenses, other provides useful information to compare our expenses between periods without the impact of the aforementioned items.

(2)	Includes advisory and other third-party fees directly attributable to the Merger. Additional fees will be incurred prior to the consummation of the Merger transaction.

(3)

We believe non-GAAP general and administrative expenses less significant cost drivers is a useful measure for investors to understand our general and administrative expenses incurred on a recurring basis. We further believe investors may utilize this non-GAAP measure to estimate future general and administrative expenses. However, this non-GAAP measure is not a substitute for general and administrative expenses, net (GAAP), and there can be no assurance that any of the significant cost drivers excluded from such metric will not be incurred again in the future.

G&A expenses, other increased $4 million between periods primarily due to $6 million of significant cost drivers incurred during the first quarter of 2022 for advisory and other third-party fees associated with the Merger transaction.

G&A expense per BOE amounted to $2.32 per BOE during the first quarter of 2022, which represents an increase of $0.53 per BOE (or 30%) from the fourth quarter of 2021. This increase was mainly due to the overall increase in G&A discussed above and lower overall production volumes between periods. G&A expense per BOE excluding significant cost drivers amounted to $1.55 per BOE during the first quarter of 2022.

Derivative (Gain) Loss, Net. Our commodity derivative contracts are marked to market each quarter with fair value gains and losses recognized immediately in earnings as derivative (gain) loss, net. Cash flow, however, is only impacted to the extent that settlements under these contracts result in us making or receiving a payment to or from the counterparty. Derivative (gain) loss, net, amounted to a loss of $429 million and a gain of $5 million for the three months ended March 31, 2022 and December 31, 2021, respectively. These gains and losses relate to our collar, swap, basis swap and differential swap commodity derivative contracts and resulted from the upward and downward shifts, respectively, in the futures curve of forecasted commodity prices for crude oil, natural gas and NGLs during those periods.

For more information on our outstanding derivatives refer to the “Derivative Financial Instruments” footnote in the notes to the condensed consolidated financial statements.

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Bargain Purchase Gain. During the first quarter of 2022, we acquired additional interests in oil and gas properties in the Williston Basin for an estimated adjusted purchase price of $216 million. The fair value of the assets acquired and liabilities assumed in the transaction exceeded the purchase price as a result of a significant increase in crude oil prices between the effective date of the contract and the closing date of the acquisition, which resulted in a bargain purchase gain of $66 million. The acquisition remains subject to a final settlement between Whiting and the sellers of the properties. Refer to the “Acquisitions and Divestitures” and “Fair Value Measurements” footnotes in the condensed consolidated financial statements for more information on this transaction.

Interest Expense. The components of our interest expense, which were consistent between periods, were as follows (in thousands):


	Three Months Ended
	March 31,		December 31,
	2022		2021
Credit agreement	$	1,468	$	1,702
Amortization of debt issue costs		894		894
Other		(84)		830
Total	$	2,278	$	3,426

Income Tax Expense. For the three months ended March 31, 2022 and December 31, 2021, $7 million and $1 million, respectively, of U.S. income tax expense was recognized. Our overall effective tax rate of (24.2%) for the three months ended March 31, 2022 is lower than the U.S. statutory income tax rate primarily due to share-based compensation, other permanent items and a full valuation allowance in effect on our U.S. deferred tax assets, including the tax effects of unrealized losses on derivatives. Our overall effective tax rate of 0.2% for the three months ended December 31, 2021 was lower than the U.S. statutory income tax rate primarily as a result of the full valuation allowance on our DTAs.

Liquidity and Capital Resources

Overview. At March 31, 2022, we had $0.2 million of cash on hand, $50 million of long-term debt and $1.6 billion of shareholders’ equity, while at December 31, 2021, we had $41 million of cash on hand, no long-term debt and $1.7 billion of equity. We expect that our liquidity going forward will be primarily derived from cash flows from operating activities, cash on hand and availability under the Credit Agreement and that these sources of liquidity will be sufficient to provide us the ability to fund our material cash requirements, as described below, as well as our operating and development activities, dividends paid to our shareholders and planned capital programs. We may need to fund acquisitions or other business opportunities that support our strategy through additional borrowings or the issuance of common stock or other forms of equity.

Cash Flows. During the first quarter of 2022, we generated $209 million of cash from operating activities, a decrease of $5 million from the fourth quarter of 2021. Cash provided by operating activities decreased between periods primarily due to an increase in cash settlements paid on our commodity derivative contracts, higher lease operating expenses, higher production taxes and higher cash G&A expenses between periods. These negative factors were partially offset by higher realized sales prices and lower cash interest expense between periods. Refer to “Results of Operations” for more information on the impact of volumes and prices on revenues and for more information on increases and decreases in certain expenses between periods. During the first quarter of 2022, cash flows from operating activities, $50 million of outstanding borrowings under the Credit Agreement and unrestricted cash on hand were used to fund the $216 million Williston Basin acquisition, $73 million of drilling and development expenditures and $10 million of dividends paid to shareholders.

One of the primary sources of variability in our cash flows from operating activities is commodity price volatility, which we partially mitigate through the use of commodity derivative contracts. As of April 29, 2022, we had crude oil derivative contracts (consisting of collars and swaps) covering the sale of 42,000 Bbl and 17,000 Bbl of oil per day for the remainder of 2022 and the first three quarters of 2023, respectively. As of April 29, 2022, we had natural gas derivative contracts (consisting of collars, swaps and basis swaps) covering the sale of 87,000 MMBtu and 61,000 MMBtu of natural gas per day through the remainder of 2022 and the first three quarters of 2023, respectively. As of April 29, 2022, we had NGL derivative contracts (consisting of swaps) covering the sale of 217,000 gallons and 84,000 gallons of NGLs per day for the remainder of 2022 and the first quarter of 2023, respectively. For more information on our outstanding derivatives refer to the “Derivative Financial Instruments” footnote in the notes to the condensed consolidated financial statements.

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Material Cash Requirements. Our material short-term cash requirements include dividend payments, tax payments, payments under our short-term lease agreements, recurring payroll and benefits obligations for our employees, capital and operating expenditures and other working capital needs. Working capital, defined as total current assets less total current liabilities, fluctuates depending on commodity pricing and effective management of payables to our vendors and receivables from our purchasers and working interest partners. As commodity prices improve, our working capital requirements may increase as we spend additional capital, maintain production and pay larger settlements on our outstanding commodity derivative contracts. Additionally, as discussed in “Proposed Merger with Oasis Petroleum Inc.” above, on March 7, 2022 we entered into a Merger Agreement that will result in a material short-term cash commitment of approximately $24 million as of March 31, 2022 for certain advisory and other third-party fees directly attributable to the Merger. The majority of these costs are contingent on closing and final amounts may differ significantly from this preliminary estimate.

Our long-term material cash requirements from currently known obligations include repayment of outstanding borrowings and interest payment obligations under our Credit Agreement, settlements on our outstanding commodity derivative contracts, future obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, operating and finance lease obligations and contracts to transport a minimum volume of crude oil and natural gas within specified time frames. The following table summarizes our estimated material cash requirements for known obligations as of March 31, 2022. This table does not include repayments of outstanding borrowings on our Credit Agreement, or the associated interest payments, as the timing and amount of borrowings and repayments cannot be forecasted with certainty and are based on working capital requirements, commodity prices and acquisition and divestiture activity, among other factors. As of March 31, 2022, our outstanding borrowings under our Credit Agreement were $50 million, with a weighted average interest rate on the outstanding principal balance of 4%. Refer to “Credit Agreement” below as well as the “Long-Term Debt” footnote in the notes to the condensed consolidated financial statements for more information. This table also does not include amounts payable under obligations where we cannot forecast with certainty the amount and timing of such payments, including any amounts we may be obligated to pay under our derivative contracts, as such payments are dependent on commodity prices in effect at the time of settlement. Refer to the “Derivative Financial Instruments” footnote in the notes to the condensed consolidated financial statements for further information on these contracts and their fair values as of March 31, 2022, which fair values represent the cash settlement amount required to terminate such instruments based on forward price curves for commodities as of that date. Refer to the “Commitments and Contingencies” footnote in the notes to the condensed consolidated financial statements for more information on other obligations that we may have where the timing and amount of any payments is uncertain.


	Payments due by period
		(in thousands)
			Less than 1						More than
Material Cash Requirements	Total		year		1-3 years		3-5 years		5 years
Asset retirement obligations ⁽¹⁾	$	108,186	$	13,092	$	14,218	$	12,779	$	68,097
Operating leases ⁽²⁾		20,139		3,601		5,759		3,860		6,919
Finance leases ⁽²⁾		1,853		1,232		563		58		-
Total	$	130,178	$	17,925	$	20,540	$	16,697	$	75,016

(1)	Asset retirement obligations represent the present value of estimated amounts expected to be incurred in the future to plug and abandon oil and gas wells, remediate oil and gas properties and dismantle their related plants and facilities.

(2)

We have operating and finance leases for corporate and field offices, midstream facilities, equipment and automobiles. The obligations reported above represent our minimum financial commitments pursuant to the terms of these contracts. Refer to the “Leases” footnote in the notes to the consolidated financial statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2021 (as amended) for more information on these leases.

Exploration and Development Expenditures. During the three months ended March 31, 2022 and 2021, we incurred accrual basis exploration and development (“E&D”) expenditures of $91 million and $56 million, respectively. Of these expenditures, 98% were incurred in the Williston Basin of North Dakota and Montana, where we have focused our current development activities. Capital expenditures reported in the condensed consolidated statements of cash flows are calculated on a cash basis, which differs from the accrual basis used to calculate the incurred capital expenditures as detailed in the table below:

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	Three Months Ended March 31,
	2022		2021
Capital expenditures, accrual basis	$	90,862	$	55,602
Decrease (increase) in accrued capital expenditures and other noncash capital activity		(18,051)		(19,874)
Capital expenditures, cash basis	$	72,811	$	35,728

We continually evaluate our capital needs and compare them to our capital resources. Our 2022 E&D budget is a range of $360 million to $400 million, which we expect to fund with net cash provided by operating activities and cash on hand. Our level of E&D expenditures is largely discretionary, although a portion of our E&D expenditures are for non-operated properties where we have limited control over the timing and amount of such expenditures, and the amount of funds we devote to any particular activity may increase or decrease significantly depending on commodity prices, cash flows, available opportunities and development results, among other factors. We believe that we have sufficient liquidity and capital resources to execute our development plan over the next 12 months. With our expected cash flow streams, commodity price hedging strategies, current liquidity levels (primarily consisting of availability under the Credit Agreement) and flexibility to modify future capital expenditure programs, we expect to fund all planned capital programs, comply with our debt covenants and meet other obligations that may arise from our oil and gas operations.

Dividends. On February 8, 2022, we announced an inaugural quarterly dividend of $0.25 per share. The first dividend totaling approximately $10 million was paid on March 15, 2022 to shareholders of record as of February 21, 2022. On April 14, 2022, we announced our second quarterly dividend of $0.25 per share to be paid on June 1, 2022 to shareholders of record as of May 20, 2022. While we believe that our future cash flows from operations can sustain this dividend, future dividends may change based on a variety of factors, including contractual restrictions, legal limitations, business developments and the judgment of our Board. There can be no guarantee that we will pay dividends or otherwise return capital to our shareholders in the future.

Credit Agreement. Whiting Petroleum Corporation, as parent guarantor, and Whiting Oil and Gas, as borrower, are parties to the Credit Agreement, a reserves-based credit facility with a syndicate of banks. The Credit Agreement had a borrowing base and aggregate commitments of $750 million as of March 31, 2022. As of March 31, 2022, we had $699 million of available borrowing capacity under the Credit Agreement, which was net of $50 million of borrowings outstanding and $1 million in letters of credit outstanding.

The borrowing base under the Credit Agreement is determined at the discretion of the lenders, based on the collateral value of our proved reserves that have been mortgaged to the lenders, and is subject to regular redeterminations on April 1 and October 1 of each year, as well as special redeterminations described in the Credit Agreement, which in each case may increase or decrease the borrowing base. Additionally, we can increase the aggregate commitments by up to an additional $750 million, subject to certain conditions. On April 1, 2022, we entered into an agreement with the lenders under the Credit Agreement to defer the regularly scheduled redetermination scheduled for such date until September 1, 2022.

Up to $50 million of the borrowing base may be used to issue letters of credit for the account of Whiting Oil and Gas or our other designated subsidiaries. As of March 31, 2022, $49 million was available for additional letters of credit under the Credit Agreement.

The Credit Agreement provides for interest only payments until maturity on April 1, 2024, when the agreement terminates and all outstanding borrowings are due. In addition, the Credit Agreement provides for certain mandatory prepayments, including a provision pursuant to which, if our cash balances are in excess of approximately $75 million during any given week, such excess must be utilized to repay borrowings under the Credit Agreement. Interest under the Credit Agreement accrues at our option at either (i) a base rate for a base rate loan plus a margin between 1.75% and 2.75% based on the ratio of outstanding borrowings and letters of credit to the lower of the current borrowing base or total commitments, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.5% per annum, or an adjusted LIBOR plus 1.0% per annum, or (ii) an adjusted LIBOR for a eurodollar loan plus a margin between 2.75% and 3.75% based on the ratio of outstanding borrowings and letters of credit to the lower of the current borrowing base or total commitments. The Credit Agreement also provides that the administrative agent and we have the ability to amend the LIBOR rate with a benchmark replacement rate, which may be a SOFR-based rate, if LIBOR borrowings become unavailable. Additionally, we incur commitment fees of 0.5% on the unused portion of the aggregate commitments of the lenders under the Credit Agreement, which are included as a component of interest expense.

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The Credit Agreement contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, enter into hedging contracts, incur liens and engage in certain other transactions without the prior consent of our lenders. The Credit Agreement also restricts our ability to make any dividend payments or cash distributions on our common stock except to the extent that we have distributable free cash flow and (i) have at least 20% of available borrowing capacity, (ii) have a consolidated net leverage ratio of less than or equal to 2.0 to 1.0, (iii) do not have a borrowing base deficiency and (iv) are not in default under the Credit Agreement. These restrictions apply to all of our restricted subsidiaries and are calculated in accordance with definitions contained in the Credit Agreement. The Credit Agreement requires us, as of the last day of any quarter, to maintain commodity hedges covering a minimum of 50% of our projected production for the succeeding twelve months, as reflected in the reserves report most recently provided by us to the lenders under the Credit Agreement. If our consolidated net leverage ratio equals or exceeds 1.0 to 1.0 as of the last day of any fiscal quarter, we will also be required to hedge 35% of our projected production for the next succeeding twelve months. We are also limited to hedging a maximum of 85% of our production from proved reserves. The Credit Agreement requires us to maintain the following ratios: (i) a consolidated current assets to consolidated current liabilities ratio of not less than 1.0 to 1.0 and (ii) a total debt to last four quarters’ EBITDAX ratio of not greater than 3.5 to 1.0.

For further information on the loan security related to the Credit Agreement, refer to the “Long-Term Debt” footnote in the notes to the condensed consolidated financial statements.

Critical Accounting Policies and Estimates

Information regarding critical accounting policies and estimates is contained in Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2021, as amended. No material updates were made to such critical accounting policies and estimates during the three months ended March 31, 2022.

Effects of Inflation and Pricing

The oil and gas industry is very cyclical, and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and not adjust downward in proportion to prices. Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, depletion expense, impairment assessments of oil and gas properties and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrow money and retain personnel. Higher demand in the industry could result in increases in the costs of materials, services and personnel. As commodity prices have risen substantially in 2021 and 2022, the cost of oil field goods and services have also risen materially in response to increased competition resulting from increased drilling and completion activity as well as inflationary cost pressures on the U.S. economy. We expect these inflationary pressures to continue throughout the remainder of 2022.

Forward-Looking Statements

This report contains statements that we believe to be “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than historical facts, including, without limitation, statements regarding the Merger, any statements regarding the expected timetable for completing the Merger, the results, effects, benefits and synergies of the Merger, future opportunities for the combined company, our future financial position, business strategy, dividends, cash flows and debt levels, acquisitions and divestitures, projected revenues, expenses, earnings, returns, costs and capital expenditures, and plans and objectives of management for future operations, are forward-looking statements. When used in this report, words such as “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe” or “should” or the negative thereof or variations thereon or similar terminology are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements.

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These risks and uncertainties include, but are not limited to, risks associated with:

●

declines in, or extended periods of low oil, NGL or natural gas prices;

●

the occurrence of epidemic or pandemic diseases, including the coronavirus pandemic;

●

any impact of the ongoing Russian-Ukrainian conflict on the global energy markets and geopolitical stability;

●

action or inaction of the Organization of Petroleum Exporting Countries and other oil exporting nations to set and maintain production levels;

●

hedging muting the impacts of improvements in commodity prices on our results;

●

regulatory developments, including the potential shutdown of the Dakota Access Pipeline and new or amended federal, state and local initiatives relating to the regulation of hydraulic fracturing, air emissions and other aspects of oil and gas operations that could have a negative effect on the oil and gas industry and/or increase costs of compliance;

●

the geographic concentration of our operations;

●

our inability to access oil and gas markets due to market conditions or operational impediments;

●

adequacy of midstream and downstream transportation capacity and infrastructure;

●

shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs and completion services;

●

adverse weather conditions that may negatively impact development or production activities;

●

potential losses and claims resulting from our oil and gas operations, including uninsured or underinsured losses;

●

lack of control over non-operated properties;

●

cybersecurity attacks or failures of our telecommunication and other information technology infrastructure;

●

revisions to reserve estimates as a result of changes in commodity prices, regulation and other factors;

●

inaccuracies of our reserve estimates or our assumptions underlying them;

●

impact of negative shifts in investor sentiment and public perception towards the oil and gas industry and corporate governance standards;

●

climate change issues;

●

litigation and other legal proceedings;

●

the anticipated impact of the Merger on the combined company’s results of operations, financial position, growth opportunities and competitive position;

●

the possibility that stockholders of Oasis may not approve the issuance of new shares of Oasis common stock in the Merger or that stockholders of Whiting may not approve the Merger Agreement; and

●

other risks described under the caption “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the period ended December 31, 2021, as amended, and as supplemented by the additional risk factors described in Item 1A in this Quarterly Report on Form 10-Q for the three months ended March 31, 2022.

We assume no obligation, and disclaim any duty, to update the forward-looking statements in this Quarterly Report on Form 10-Q.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

The price we receive for our oil, NGL and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Crude oil, NGL and natural gas are commodities, and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, NGLs and natural gas have been volatile, and these markets will likely continue to be volatile in the future.

We periodically enter into derivative contracts to achieve a more predictable cash flow by reducing our exposure to oil, NGL and natural gas price volatility. Our derivative contracts have traditionally been two-way collars, swaps, basis swaps and differential swaps although we evaluate and have entered into other forms of derivative instruments as well. We do not apply hedge accounting, and therefore all changes in commodity derivative fair values are recorded immediately to earnings.

Crude Oil, Natural Gas and NGL Collars, Swaps and Basis Swaps. Our hedging portfolio currently consists of crude oil, natural gas and NGL collars and swaps, as well as natural gas basis swaps. Refer to the “Derivative Financial Instruments” footnote in the notes to the condensed consolidated financial statements for a description and list of our outstanding derivative contracts at March 31, 2022.

Our collar contracts have the effect of providing a protective floor, while allowing us to share in upward pricing movements up to the ceiling price. Our fixed-price swap contracts entitle us to receive settlement from the counterparty in amounts, if any, by which the settlement price for the applicable calculation period is less than the fixed price, or require us to pay the counterparty if the settlement price for the applicable calculation period is more than the fixed price. Our basis swap contracts guarantee us a fixed price differential to NYMEX and the referenced index price, with settlement terms based on the difference between the floating market price differential and the fixed price differential.

The fair value of our oil derivative positions at March 31, 2022 was a net liability of $456 million. A hypothetical upward or downward shift of 10% per Bbl in the NYMEX forward curve for crude oil as of March 31, 2022 would cause an increase of $138 million or a decrease of $136 million, respectively, in this fair value liability. The fair value of our natural gas derivative positions was a net liability of $68 million. A hypothetical upward or downward shift of 10% per MMBtu in the NYMEX forward curve for natural gas as of March 31, 2022 would cause an increase of $10 million or a decrease of $21 million, respectively, in this fair value liability. The fair value of our NGL derivative positions was a net liability of $16 million. A hypothetical upward or downward shift of 10% per Bbl in the Mont Belvieu and Conway forward curves for propane as of March 31, 2022 would cause an increase or decrease, respectively, of $9 million in this fair value liability.

While these collars, fixed-price swaps and basis swaps are designed to decrease our exposure to downward price movements, they also have the effect of limiting the benefit of (i) price increases above the ceiling with respect to the collars, (ii) upward price movements generally with respect to the fixed-price swaps and (iii) decreasing floating market differentials relative to NYMEX with respect to the basis swaps and differential swaps.

Interest Rate Risk

Market risk is estimated as the change in fair value resulting from a hypothetical 100 basis point change in the interest rate on the outstanding balance under the Credit Agreement. The Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance for a period up to one month. To the extent that the interest rate is fixed, interest rate changes affect the instrument’s fair market value but do not impact results of operations or cash flows. Conversely, for the portion of the Credit Agreement that has a floating interest rate, interest rate changes will not affect the fair market value but will impact future results of operations and cash flows. At March 31, 2022, our outstanding principal balance under the Credit Agreement was $50 million, and the weighted average interest rate on the outstanding principal balance was 4%. At March 31, 2022, the carrying amount approximated fair market value. Assuming a constant debt level of $50 million, the cash flow impact resulting from a 100 basis point change in interest rates during periods when the interest rate is not fixed would be $0.5 million over a 12-month time period.

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Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures. In accordance with Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), our management evaluated, with the participation of our Chief Executive Officer and our Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of March 31, 2022. Based upon their evaluation of these disclosure controls and procedures, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures were effective as of March 31, 2022 to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure.

Changes in internal control over financial reporting. There was no change in our internal control over financial reporting that occurred during the quarter ended March 31, 2022 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

The information contained in the “Commitments and Contingencies” footnote in the notes to the condensed consolidated financial statements under the headings “Chapter 11 Cases” and “Litigation” are incorporated herein by reference.

Item 1A. Risk Factors

Risk factors relating to us are contained in Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2021, as amended, and are supplemented by the additional risk factors described below under “Risks Relating to the Merger” in this Quarterly Report on Form 10-Q for the three months ended March 31, 2022.

Risks Relating to the Merger

The Merger is subject to a number of conditions, which may delay the Merger, result in additional expenditures of money and resources or reduce the anticipated benefits or result in termination of the Merger Agreement.

Our obligations and the obligations of Oasis to consummate the Merger are subject to the satisfaction (or waiver by all parties, to the extent permissible under applicable laws) of a number of conditions described in the Merger Agreement, including the approval by Oasis’ stockholders of issuance of shares of Oasis common stock to Whiting stockholders in connection with the Merger and the approval and adoption of the Merger Agreement and the transactions contemplated therein, including the Merger, by the Whiting stockholders. Many of the conditions to completion of the Merger are not within our control and we cannot predict when, or if, these conditions will be satisfied. If any of these conditions are not satisfied or waived prior to the Outside Date (as such term is defined in the Merger Agreement), it is possible that the Merger Agreement may be terminated.

Although the parties have agreed to use reasonable best efforts, subject to certain limitations, to complete the Merger promptly, these and other conditions may fail to be satisfied. In addition, completion of the Merger may take longer, and could cost more, than we expect. The requirements for obtaining the required clearances and approvals could delay the completion of the Merger for a significant period of time or prevent them from occurring. Any delay in completing the Merger may adversely affect the cost savings and other benefits that we expect to achieve if the Merger and the integration of businesses are completed within the expected timeframe.

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The Merger Agreement subjects us to restrictions on our business activities prior to closing the Merger.

The Merger Agreement subjects us to restrictions on our business activities prior to closing the Merger. The Merger Agreement obligates us to generally conduct our businesses in the ordinary course until the closing and to, among other things, use our reasonable best efforts to (i) preserve substantially intact our present business organization, goodwill and assets, (ii) keep available the services of our current officers and employees and (iii) preserve our existing relationships with governmental entities and significant customers, suppliers, licensors, licensees, distributors, lessors and others having significant business dealings with us. These restrictions could prevent us from pursuing certain business opportunities that arise prior to the closing and are outside the ordinary course of business.

The combined company may be unable to integrate the business of Oasis and Whiting successfully or realize the anticipated benefits of the Merger.

The Merger involves the combination of two companies that currently operate as independent public companies. The combination of two independent businesses is complex, costly and time consuming, and each of Oasis and Whiting will be required to devote significant management attention and resources to integrating the business practices and operations of Whiting into Oasis. Potential difficulties that Oasis and Whiting may encounter as part of the integration process include the following:

●

the inability to successfully combine the business of Oasis and Whiting in a manner that permits the combined company to achieve, on a timely basis, or at all, the enhanced revenue opportunities and cost savings and other benefits anticipated to result from the Merger;

●

complexities associated with managing the combined businesses, including difficulty addressing possible differences in operational philosophies and the challenge of integrating complex systems, technology, networks and other assets of each of the companies in a seamless manner that minimizes any adverse impact on customers, suppliers, employees and other constituencies;

●

the assumption of contractual obligations with less favorable or more restrictive terms; and

●

potential unknown liabilities and unforeseen increased expenses or delays associated with the Merger.

In addition, Oasis and Whiting have operated and, until the completion of the Merger, will continue to operate, independently. It is possible that the integration process could result in:

●

diversion of the attention of each company’s management and

●

the disruption of, or the loss of momentum in, each company’s ongoing businesses or inconsistencies in standards, controls, procedures and policies.

Any of these issues could adversely affect each company’s ability to maintain relationships with customers, suppliers, employees and other constituencies or achieve the anticipated benefits of the Merger, or could reduce each company’s earnings or otherwise adversely affect the business and financial results of the combined company following the Merger.

Our stockholders and Oasis’ shareholders, in each case as of immediately prior to the Merger, will have reduced ownership in the combined company.

We anticipate Oasis will issue 0.5774 shares of the Oasis common stock to Whiting stockholders in exchange for each share of Whiting common stock, pursuant to the Merger Agreement. The issuance of these new shares could have the effect of depressing the market price of the combined company’s common stock, through dilution of earnings per share or otherwise. Any dilution of, or delay of any accretion to, the combined company’s earnings per share could cause the price of its common stock to decline or increase at a reduced rate.

Following the completion of the Merger, it is anticipated that persons who were Whiting stockholders and Oasis shareholders immediately prior to the Merger will own approximately 53% and 47% of the combined company, respectively. As a result, our current stockholders will have less influence on the policies of the combined company than they currently have on our policies.

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Failure to complete the Merger could negatively impact Whiting’s stock price and have a material adverse effect on our results of operations, cash flows and financial position.

If the Merger is not completed for any reason, including if the Oasis stockholders or Whiting stockholders fail to approve the applicable proposals, the ongoing businesses of Whiting may be materially adversely affected and, without realizing any of the benefits of having completed the Merger, Whiting would be subject to a number of risks, including the following:

●

Whiting may experience negative reactions from the financial markets, including negative impacts on our stock price;

●

Whiting and our subsidiaries may experience negative reactions from their customers, distributors, suppliers, vendors, landlords, joint venture partners and other business partners;

●

Whiting will still be required to pay certain significant costs relating to the merger, such as legal, accounting, financial advisor and printing fees;

●

Whiting will be required to pay a termination fee if the Merger Agreement is terminated in certain circumstances;

●

the Merger Agreement places certain restrictions on the conduct of Whiting’s business pursuant to the terms of the Merger Agreement, which may delay or prevent us from undertaking business opportunities that, absent the Merger Agreement, we may have pursued;

●

matters relating to the Merger (including integration planning) require substantial commitments of time and resources by our management, which may have resulted in the distraction of our management from ongoing business operations and pursuing other opportunities that could have been beneficial to Whiting; and

●

litigation related to any failure to complete the Merger or related to any enforcement proceeding commenced against Whiting to perform any obligations pursuant to the Merger Agreement.

If the Merger is not completed, the risks described above may materialize and they may have a material adverse effect on Whiting’s results of operations, cash flows, financial position and stock price.

Item 6. Exhibits

The exhibits listed in the accompanying index to exhibits are filed as part of this Quarterly Report on Form 10-Q.

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EXHIBIT INDEX

Exhibit Number		Exhibit Description
(2)		Joint Chapter 11 Plan of Reorganization of Whiting Petroleum Corporation and its Debtor Affiliates [Incorporated by reference to Exhibit A of the Order Confirming the Joint Chapter 11 Plan of Reorganization, filed as Exhibit 2 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on August 17, 2020 (File No. 001-31899)].
(2.1)*		Agreement and Plan of Merger, dated as of March 7, 2022, by and among Oasis Petroleum Inc., Ohm Merger Sub Inc., New Ohm LLC and Whiting Petroleum Corporation [Incorporated by reference to Exhibit 2.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on March 8, 2022 (File No. 001-31899)].
(3.1)		Amended and Restated Certificate of Incorporation of Whiting Petroleum Corporation [Incorporated by reference to Exhibit 3.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on September 1, 2020 (File No. 001-31899)].
(3.2)		Second Amended and Restated By-laws of Whiting Petroleum Corporation [Incorporated by reference to Exhibit 3.2 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on September 1, 2020 (File No. 001-31899)].
(10.1)		First Amendment to Executive Employment and Severance Agreement, dated March 3, 2022, by and between Whiting Petroleum Corporation and M. Scott Regan.
(10.2)		First Addendum to Executive Employment and Severance Agreement, dated April 13, 2022, by and between Whiting Petroleum Corporation and Charles J. Rimer [Incorporated by reference to Exhibit 10.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on April 15, 2022 (File No. 001-31899)].
(10.3)		First Addendum to Employment Agreement and Severance Agreement, dated April 13, 2022, by and between Whiting Petroleum Corporation and James P. Henderson [Incorporated by reference to Exhibit 10.2 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on April 15, 2022 (File No. 001-31899)].
(10.4)		First Addendum to Executive Employment and Severance Agreement, dated April 13, 2022, by and between Whiting Petroleum Corporation and Sirikka Lohoefener [Incorporated by reference to Exhibit 10.2 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on April 15, 2022 (File No. 001-31899)].
(10.5)		First Addendum to Executive Employment and Severance Agreement, dated April 13, 2022, by and between Whiting Petroleum Corporation and M. Scott Regan [Incorporated by reference to Exhibit 10.2 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on April 15, 2022 (File No. 001-31899)].
(31.1)		Certification by the President and Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
(31.2)		Certification by the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
(32.1)		Written Statement of the President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.
(32.2)		Written Statement of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
(99)		Order Confirming Joint Chapter 11 Plan of Reorganization of Whiting Petroleum Corporation [Incorporated by reference to Exhibit 99.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on August 17, 2020 (File No. 001-31899)].
(101)		The following materials from Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2022 are filed herewith, formatted in iXBRL (Inline Extensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Operations, (iii) the Condensed Consolidated Statements of Cash Flows, (iv) the Condensed Consolidated Statements of Equity and (v) Notes to Condensed Consolidated Financial Statements. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the iXBRL document.
(104)		Cover Page Interactive Data File (formatted as Inline XBRL) – The cover page interactive data file does not appear in the interactive data file because its XBRL tags are embedded within the iXBRL document.

* Schedules and similar attachments have been omitted pursuant to Item 601(a)(5) of Regulation S-K. Whiting agrees to furnish a supplemental copy of any omitted schedule or attachment to the SEC upon request.

Table of Contents

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on this 4^th day of May, 2022.


		WHITING PETROLEUM CORPORATION


	By	/s/ Lynn A. Peterson
		Lynn A. Peterson
		President and Chief Executive Officer


	By	/s/ James P. Henderson
		James P. Henderson
		Executive Vice President Finance and Chief Financial Officer


	By	/s/ Sirikka R. Lohoefener
		Sirikka R. Lohoefener
		Vice President, Accounting and Controller

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Chord Energy (WLLBW) 10-Q2022 Q1 Quarterly report

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