Amended Annual Report (10-k/a)

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combined

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

AMENDMENT NO. 1

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2021

☐ 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)

Securities registered pursuant to Section 12(g) of the Act: None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ☐ No ☒

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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

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 ☐

Aggregate market value of the voting common stock held by non-affiliates of the registrant at June 30, 2021: $2,126,000,000.

Number of shares of the registrant’s common stock outstanding at February 17, 2022: 39,240,791 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the 2022 Annual Meeting of Stockholders are incorporated by reference into Part III.

EXPLANATORY NOTE

This Amendment No. 1 on Form 10-K/A (the “Amendment”) amends the Annual Report on Form 10-K of Whiting Petroleum Corporation (the “Company,” “we” or “our”) for the fiscal year ended December 31, 2021, as filed with the Securities and Exchange Commission (the “SEC”) on February 23, 2022 (the “Original 10-K”).

In Item 8 of Part II of the Original 10-K, the Company corrected certain errors in its Supplemental Disclosures About Oil and Gas Producing Activities (Unaudited) (the “Supplemental Disclosures”) for the years ended December 31, 2020 and 2019. The Company originally concluded that such errors were immaterial and classified the correction of such errors as revisions to previously reported amounts. Subsequent to the filing of the Original 10-K, it was determined that such errors were material, and the Amendment is being filed to amend and restate Item 8 of the Original 10-K to recharacterize the correction of these errors as a restatement of the Company’s Supplemental Disclosures for the years ended December 31, 2020 and 2019. There are no changes to any amounts previously reported within Item 8 of the Original 10-K. As a result of the Company’s conclusion that our Supplemental Disclosures for the years ended December 31, 2020 and 2019 contained material errors, we also concluded that our disclosure controls and procedures were ineffective as of December 31, 2020, as discussed in Item 9A of this Amendment. This does not affect our conclusion that our disclosure controls and procedures for the year ended December 31, 2021 were effective.

In addition, pursuant to the rules of the SEC, the exhibit list included in Item 15 of Part IV of the Original 10-K has been amended and restated to include updates to applicable exhibits, consisting of currently-dated consents of the independent registered public accounting firm and certified independent petroleum engineers and current certifications from the Company's Chief Executive Officer and Chief Financial Officer, as required by Sections 302 and 906 of the Sarbanes-Oxley Act of 2002.

Except as described above, no other information included in the Original 10-K is being amended, updated, changed or restated by the Amendment and the Amendment does not purport to reflect any information or events subsequent to the Original 10-K. The Amendment continues to describe the conditions as of the date of the Original 10-K and, except as expressly contained herein, this Amendment is not intended to update, modify, or supplement the disclosures contained in the Original 10-K. Accordingly, this Amendment should be read in conjunction with the Original 10-K and our other filings with the SEC.

PART II

Item 8. Financial Statements and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)	4
Consolidated Balance Sheets	6
Consolidated Statements of Operations	7
Consolidated Statements of Cash Flows	8
Consolidated Statements of Equity	10
Notes to Consolidated Financial Statements	11

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Whiting Petroleum Corporation

Denver, Colorado

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Whiting Petroleum Corporation and subsidiaries (the "Company") as of December 31, 2021 and 2020, the related consolidated statements of operations, stockholders’ equity, and cash flows for the year ended December 31, 2021 and the period from September 1, 2020 to December 31, 2020 (Successor Company operations), and the periods from January 1, 2020 to August 31, 2020 and January 1, 2019 to December 31, 2019 (Predecessor Company operations), and the related notes (collectively referred to as the “financial statements”). In our opinion, the Successor financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for the year ended December 31, 2021 and for the period of September 1, 2020 to December 31, 2020, in conformity with accounting principles generally accepted in the United States of America. Further, in our opinion, the Predecessor financial statements present fairly, in all material respects, the results of its operations and cash flows for the periods from January 1, 2020 to August 31, 2020 and January 1, 2019 to December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2022, expressed an unqualified opinion on the Company's internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of this critical audit matter does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Proved Oil and Natural Gas Property and Depletion — Oil and Natural Gas Reserve Quantities — Refer to Note 1 to the financial statements

Critical Audit Matter Description

The Company’s proved oil and natural gas properties are depleted using the units of production method based on the Company’s oil and natural gas reserves. The development of the Company’s oil and natural gas reserve quantities required management to make significant estimates and assumptions, including those related to management’s five-year property development plan. The Company engaged a third-party engineering firm to estimate oil and natural gas quantities using generally accepted methods, calculation procedures and engineering data. Changes in these estimates or engineering data could have a significant impact on the amount of depletion. The proved oil and natural gas properties balance was $1.8 billion as of December 31, 2021, net of accumulated depreciation, depletion, and amortization. Depreciation, depletion and amortization expense was $0.2 billion for the year ended December 31, 2021.

Given the significant judgments made by management, performing audit procedures to evaluate the Company’s oil and natural gas reserve quantities, including management’s estimates related to its five-year property development plan, requires a high degree of auditor judgment and an increased extent of effort.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to management’s significant judgments and estimates related to oil and natural gas reserves quantities and converting proved undeveloped oil and natural gas reserves to proved developed properties within five years included the following, among others:

●

We tested the operating effectiveness of controls related to the Company’s estimation of oil and natural gas reserve quantities, including controls relating to management’s five-year property development plan.

●

We evaluated the Company’s estimated proved reserve quantities and reasonableness of management’s five-year property development plan by comparing the forecasts to:

-

Historical conversions of proved undeveloped oil and natural gas reserves into proved developed oil and natural gas reserves.

-

Working capital and future cash flows to support development of proved undeveloped reserves into proved developed oil and natural gas reserves.

-

Internal communications to management and the Board of Directors.

-

Permits and approval for expenditures.

-

Forecasted information included in Company press releases as well as in analyst and industry reports for the Company and certain of its peer companies.

●

We evaluated the Company’s estimates of future production volumes by completing a retrospective comparison to historical production.

●

We evaluated the experience, qualifications and objectivity of management’s expert, a third-party engineering firm, including the methodologies and calculation procedures used to estimate oil and natural gas reserves and performed analytical procedures on the reserve quantities.

/s/ Deloitte & Touche LLP

Denver, Colorado

February 23, 2022

We have served as the Company’s auditor since 2003.

WHITING PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(in thousands, except share and per share data)


	Successor
	December 31,		December 31,
	2021		2020
ASSETS
Current assets:
Cash, cash equivalents and restricted cash	$	41,245	$	28,367
Accounts receivable trade, net		279,865		142,830
Prepaid expenses and other		17,158		19,224
Total current assets		338,268		190,421
Property and equipment:
Oil and gas properties, successful efforts method		2,274,908		1,812,601
Other property and equipment		61,624		74,064
Total property and equipment		2,336,532		1,886,665
Less accumulated depreciation, depletion and amortization		(254,237)		(73,869)
Total property and equipment, net		2,082,295		1,812,796
Other long-term assets		37,368		40,723
TOTAL ASSETS	$	2,457,931	$	2,043,940
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable trade	$	48,641	$	23,697
Revenues and royalties payable		258,527		151,196
Accrued capital expenditures		38,914		20,155
Accrued liabilities and other		30,726		42,007
Accrued lease operating expenses		32,408		23,457
Taxes payable		18,864		11,997
Derivative liabilities		209,653		49,485
Total current liabilities		637,733		321,994
Long-term debt		-		360,000
Asset retirement obligations		93,915		91,864
Operating lease obligations		14,710		17,415
Long-term derivative liabilities		46,720		9,750
Other long-term liabilities		1,228		14,113
Total liabilities		794,306		815,136
Commitments and contingencies
Equity:
Common stock, $0.001 par value, 500,000,000 shares authorized; 39,133,637 issued and outstanding as of December 31, 2021 and 38,051,125 issued and outstanding as of December 31, 2020		39		38
Additional paid-in capital		1,196,607		1,189,693
Accumulated earnings		466,979		39,073
Total equity		1,663,625		1,228,804
TOTAL LIABILITIES AND EQUITY	$	2,457,931	$	2,043,940

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

WHITING PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)


	Successor				Predecessor
	Year Ended December 31, 2021		Four Months Ended December 31, 2020		Eight Months Ended August 31, 2020		Year Ended December 31, 2019
OPERATING REVENUES
Oil, NGL and natural gas sales	$	1,511,837	$	273,358	$	459,004	$	1,572,245
Purchased gas sales		21,644		-		-		-
Total operating revenues		1,533,481		273,358		459,004		1,572,245
OPERATING EXPENSES
Lease operating expenses		242,476		73,981		158,228		328,427
Transportation, gathering, compression and other		30,107		8,038		22,266		42,438
Purchased gas expense		17,572		-		-		-
Production and ad valorem taxes		110,416		24,150		41,204		138,212
Depreciation, depletion and amortization		206,475		77,502		338,757		816,488
Exploration and impairment		10,781		7,865		4,184,830		54,738
General and administrative		49,520		21,734		91,816		132,609
Derivative (gain) loss, net		520,131		24,714		(181,614)		53,769
(Gain) loss on sale of properties		(95,611)		395		927		1,964
Amortization of deferred gain on sale		-		-		(5,116)		(9,069)
Total operating expenses		1,091,867		238,379		4,651,298		1,559,576
INCOME (LOSS) FROM OPERATIONS		441,614		34,979		(4,192,294)		12,669
OTHER INCOME (EXPENSE)
Interest expense		(16,381)		(8,080)		(73,054)		(191,047)
Gain on extinguishment of debt		-		-		25,883		7,830
Interest income and other		3,583		136		211		1,602
Reorganization items, net		-		-		217,419		-
Total other income (expense)		(12,798)		(7,944)		170,459		(181,615)
INCOME (LOSS) BEFORE INCOME TAXES		428,816		27,035		(4,021,835)		(168,946)
INCOME TAX EXPENSE (BENEFIT)
Current		910		2,463		2,718		-
Deferred		-		(14,501)		(59,092)		72,220
Total income tax expense (benefit)		910		(12,038)		(56,374)		72,220
NET INCOME (LOSS)	$	427,906	$	39,073	$	(3,965,461)	$	(241,166)
INCOME (LOSS) PER COMMON SHARE
Basic	$	10.97	$	1.03	$	(43.37)	$	(2.64)
Diluted	$	10.78	$	1.03	$	(43.37)	$	(2.64)
WEIGHTED AVERAGE SHARES OUTSTANDING
Basic		39,006		38,080		91,423		91,285
Diluted		39,692		38,119		91,423		91,285

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

WHITING PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


	Successor				Predecessor
	Year Ended December 31, 2021		Four Months Ended December 31, 2020		Eight Months Ended August 31, 2020		Year Ended December 31, 2019
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	427,906	$	39,073	$	(3,965,461)	$	(241,166)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		206,475		77,502		338,757		816,488
Deferred income tax benefit		-		(14,501)		(59,092)		72,220
Amortization of debt issuance costs, debt discount and debt premium		3,554		1,258		13,535		28,340
Stock-based compensation		10,745		515		4,188		7,721
Amortization of deferred gain on sale		-		-		(5,116)		(9,069)
(Gain) loss on sale of properties		(95,611)		395		927		1,964
Oil and gas property impairments		6,707		3,233		4,161,885		17,866
Gain on extinguishment of debt		-		-		(25,883)		(7,830)
Non-cash derivative (gain) loss		196,439		20,772		(136,131)		78,626
Non-cash reorganization items, net		-		-		(274,588)		-
Other, net		(5,464)		(1,761)		(223)		(1,352)
Changes in current assets and liabilities:
Accounts receivable trade, net		(140,102)		(7,100)		181,416		(24,343)
Prepaid expenses and other		4,891		1,989		(5,491)		7,165
Accounts payable trade and accrued liabilities		17,096		(42,922)		(46,734)		40,117
Revenues and royalties payable		100,505		5,690		(56,504)		(26,274)
Taxes payable		7,102		(1,975)		(12,872)		(4,513)
Net cash provided by operating activities		740,243		82,168		112,613		755,960
CASH FLOWS FROM INVESTING ACTIVITIES
Drilling and development capital expenditures		(234,437)		(33,987)		(238,456)		(793,365)
Acquisition of oil and gas properties		(306,487)		(166)		(493)		(6,031)
Other property and equipment		457		(2,486)		(1,072)		(6,451)
Proceeds from sale of properties		180,271		532		29,273		72,000
Net cash used in investing activities		(360,196)		(36,107)		(210,748)		(733,847)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under Credit Agreement		1,831,000		272,500		425,328		-
Repayments of borrowings under Credit Agreement		(2,191,000)		(337,828)		-		-
Borrowings under Predecessor Credit Agreement		-		-		1,185,000		2,650,000
Repayments of borrowings under Predecessor Credit Agreement		-		-		(1,402,259)		(2,275,000)
Repurchase of 1.25% Convertible Senior Notes due 2020		-		-		(52,890)		(297,000)
Repurchase of 5.75% Senior Notes due 2021		-		-		-		(95,279)
Debt issuance and extinguishment costs		(73)		-		(12,784)		(819)
Principal payments on finance lease obligations		(4,020)		(1,773)		(3,198)		(5,140)
Restricted stock used for tax withholdings		(3,076)		-		(307)		(3,830)
Net cash provided by (used in) financing activities	$	(367,169)	$	(67,101)	$	138,890	$	(27,068)

								(Continued)

WHITING PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


	Successor				Predecessor
	Year Ended December 31, 2021		Four Months Ended December 31, 2020		Eight Months Ended August 31, 2020		Year Ended December 31, 2019
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH	$	12,878	$	(21,040)	$	40,755	$	(4,955)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH
Beginning of period		28,367		49,407		8,652		13,607
End of period	$	41,245	$	28,367	$	49,407	$	8,652
SUPPLEMENTAL CASH FLOW DISCLOSURES
Income taxes paid (refunded), net	$	-	$	6,209	$	(1,028)	$	(7,508)
Interest paid, net of amounts capitalized	$	12,134	$	6,322	$	80,220	$	163,859
Cash paid for reorganization items	$	396	$	22,248	$	33,238	$	-
NONCASH INVESTING ACTIVITIES
Accrued capital expenditures and accounts payable related to property additions	$	42,335	$	21,531	$	26,796	$	86,088
Leasehold improvements paid for by third party lessor under office lease agreement	$	375	$	99	$	49	$	10,422
NONCASH FINANCING ACTIVITIES ⁽¹⁾
Derivative termination settlement payments used to repay borrowings under Predecessor Credit Agreement	$	-	$	-	$	157,741	$	-

								(Concluded)

(1)	Refer to the “Leases” footnote in the notes to the consolidated financial statements for discussion of right-of-use assets obtained in exchange for finance lease liabilities.

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

WHITING PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY

(in thousands)


				Additional
	Common Stock			Paid-in		Accumulated		Total
	Shares	Amount		Capital		Earnings (Deficit)		Equity
BALANCES - January 1, 2019 (Predecessor)	92,067	$	92	$	6,414,170	$	(2,143,946)	$	4,270,316
Net loss	-		-		-		(241,166)		(241,166)
Adjustment to equity component of Convertible Senior Notes upon partial extinguishment	-		-		(8,070)		-		(8,070)
Restricted stock issued	113		-		-		-		-
Restricted stock forfeited	(286)		-		-		-		-
Restricted stock used for tax withholdings	(150)		-		(3,830)		-		(3,830)
Stock-based compensation	-		-		7,721		-		7,721
BALANCES - December 31, 2019 (Predecessor)	91,744		92		6,409,991		(2,385,112)		4,024,971
Net loss	-		-		-		(3,965,461)		(3,965,461)
Adjustment to equity component of Convertible Senior Notes upon partial extinguishment	-		-		(3,461)		-		(3,461)
Restricted stock issued	194		-		-		-		-
Restricted stock forfeited	(238)		-		-		-		-
Restricted stock used for tax withholdings	(58)		-		(308)		-		(308)
Stock-based compensation	-		-		4,188		-		4,188
Cancellation of Predecessor stock	(91,642)		(92)		(6,410,410)		6,350,573		(59,929)
BALANCES - August 31, 2020 (Predecessor)	-	$	-	$	-	$	-	$	-


Issuance of Successor equity	38,051	$	38	$	1,159,818	$	-	$	1,159,856
Issuance of Successor warrants	-		-		29,360		-		29,360
BALANCES - September 1, 2020 (Successor)	38,051		38		1,189,178		-		1,189,216
Net income	-		-		-		39,073		39,073
Stock-based compensation	-		-		515		-		515
BALANCES - December 31, 2020 (Successor)	38,051		38		1,189,693		39,073		1,228,804
Net income	-		-		-		427,906		427,906
Common stock issued in settlement of bankruptcy claims	949		1		(1)		-		-
Restricted stock issued	206		-		-		-		-
Restricted stock used for tax withholdings	(72)		-		(3,076)		-		(3,076)
Stock-based compensation	-		-		9,991		-		9,991
BALANCES - December 31, 2021 (Successor)	39,134	$	39	$	1,196,607	$	466,979	$	1,663,625

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

WHITING PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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”), Whiting US Holding Company, Whiting Canadian Holding Company ULC, Whiting Resources LLC (“WRC,” formerly Whiting Resources Corporation) and Whiting Programs, Inc. In September 2020, Whiting US Holding Company merged with and into WOG with WOG surviving, and WRC transferred all of its operating assets to WOG. In November 2020, WRC, over a series of steps, was amalgamated with Whiting Canadian Holding Company ULC and subsequently dissolved. When the context requires, the Company refers to these entities separately.

Voluntary Reorganization under Chapter 11 of the Bankruptcy Code—On April 1, 2020 (the “Petition Date”), Whiting Petroleum Corporation, Whiting Oil and Gas, Whiting US Holding Company, Whiting Canadian Holding Company ULC and Whiting Resources Corporation (collectively, 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 “Emergence Date”), the Debtors satisfied all conditions required for Plan effectiveness and emerged from the Chapter 11 Cases.

Upon emergence, the Company adopted fresh start accounting in accordance with FASB ASC Topic 852 – Reorganizations (“ASC 852”), which specifies the accounting and financial reporting requirements for entities reorganizing through chapter 11 bankruptcy proceedings. The application of fresh start accounting resulted in a new basis of accounting and the Company becoming a new entity for financial reporting purposes. As a result of the implementation of the Plan and the application of fresh start accounting, the consolidated financial statements after the Emergence Date are not comparable to the consolidated financial statements before that date and the historical financial statements on or before the Emergence Date are not a reliable indicator of the Company’s financial condition and results of operations for any period after its adoption of fresh start accounting. Refer to the “Fresh Start Accounting” footnote for more information. References to “Successor” refer to the Company and its financial position and results of operations after the Emergence Date. References to “Predecessor” refer to the Company and its financial position and results of operations on or before the Emergence Date. References to “2020 Successor Period” relate to the period of September 1, 2020 through December 31, 2020. References to “2020 Predecessor Period” relate to the period of January 1, 2020 through August 31, 2020. The Company previously evaluated the events between August 31, 2020 and September 1, 2020 and concluded that the use of an accounting convenience date of August 31, 2020 did not have a material impact on the Company’s financial position or results of operations.

During the 2020 Predecessor Period, the Company applied ASC 852 in preparing the consolidated financial statements, which requires distinguishing transactions associated with the reorganization separate from activities related to the ongoing operations of the business. Accordingly, pre-petition liabilities that could have been impacted by the chapter 11 proceedings were classified as liabilities subject to compromise. Additionally, certain expenses, realized gains and losses and provisions for losses that were realized or incurred during the Chapter 11 Cases, including adjustments to the carrying value of certain assets and indebtedness were recorded as reorganization items, net in the consolidated statements of operations for the relevant Predecessor periods. Refer to the “Chapter 11 Emergence” footnote for more information on the events of the bankruptcy proceedings as well as the accounting and reporting impacts of the reorganization during the 2020 Predecessor Period.

Basis of Presentation of Consolidated Financial Statements—The consolidated financial statements have been prepared in accordance with GAAP and SEC rules and regulations and 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.

Reclassifications—Certain prior period balances in the consolidated balance sheets have been combined or reclassified to conform to current period presentation. Such reclassifications had no impact on net income (loss), cash flows or shareholders’ equity previously reported.

Use of Estimates—The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Items subject to such estimates and assumptions include (i) oil and natural gas reserves; (ii) impairment tests of long-lived assets; (iii) depreciation, depletion and amortization; (iv) asset retirement obligations; (v) assignment of fair value and allocation of purchase price in connection with business combinations, including the determination of any resulting goodwill; (vi) income taxes; (vii) accrued liabilities; (viii) valuation of derivative instruments; and (ix) accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ from these estimates. Further, these estimates and other factors, including those outside of the Company’s control, such as the impact of lower commodity prices, may have a significant negative impact to the Company’s business, financial condition, results of operations and cash flows.

Fair Value Measurements—The Company follows FASB ASC Topic 820 – Fair Value Measurement (“ASC 820”) which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

●	Level 1: Quoted Prices in Active Markets for Identical Assets – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

●

Level 2: Significant Other Observable Inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

●	Level 3: Significant Unobservable Inputs – inputs to the valuation methodology are unobservable and significant to the fair value measurement.

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability.

Cash, Cash Equivalents and Restricted Cash—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 (“FDIC”) insurance limits as of December 31, 2021 and 2020. 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.

Restricted cash as of December 31, 2020 consists of funds remaining in a professional fee escrow account that were reserved to pay certain professional fees upon emergence from the Chapter 11 Cases (the “Professional Fee Escrow Account”).

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance sheets and statements of cash flows (in thousands):


	Successor
	December 31,		December 31,
	2021		2020
Cash and cash equivalents	$	41,245	$	25,607
Restricted cash		-		2,760
Total cash, cash equivalents and restricted cash	$	41,245	$	28,367

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, 2020 (Successor), the Company had an immaterial allowance for credit losses due to the application of fresh start accounting. There were no material changes in the estimate of expected credit losses at December 31, 2021.

Inventories—Materials and supplies inventories consist primarily of tubular goods and production equipment, carried at weighted-average cost. Materials and supplies are included in other property and equipment and totaled $33 million and $29 million as of December 31, 2021 and 2020 (Successor), respectively. Crude oil in tanks inventory is carried at the lower of the estimated cost to produce or net realizable value. Oil in tanks is included in prepaid expenses and other and totaled $4 million and $6 million as of December 31, 2021 and 2020 (Successor), respectively.

Oil and Gas Properties

Proved. The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a unit-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively. Costs of drilling exploratory wells are initially capitalized but are charged to expense if the well is determined to be unsuccessful.

The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. Such events include, but are not limited to, declines in commodity prices, increases in operating costs, unfavorable reserve revisions, poor well performance, changes in development plans and potential property divestitures. The impairment test compares undiscounted future net cash flows to the assets’ net book value. These undiscounted cash flows are driven by significant assumptions, including the Company’s expected future development activity, reserve estimates, forecasted pricing, future operating costs, capital expenditures and severance taxes. If the net capitalized costs exceed undiscounted future net cash flows, then the cost of the property is written down to fair value utilizing a discounted future net cash flow analysis.

Impairment expense for proved properties totaled $4 billion for the 2020 Predecessor Period, which is reported in exploration and impairment expense in the consolidated statements of operations.

Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income. Gains or losses from the disposal of complete units of depreciable property are recognized to earnings.

Unproved. Unproved properties consist of costs to acquire undeveloped leases as well as purchases of unproved reserves. Undeveloped lease costs and unproved reserve acquisitions are capitalized, and individually insignificant unproved properties are amortized on a composite basis, based on average remaining lease-term and the historical experience of developing acreage in a particular prospect. The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis.

Exploratory. Geological and geophysical costs, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense.

Costs of drilling exploratory wells are initially capitalized, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, the costs of drilling the well and other associated costs are charged to expense. Costs incurred for exploratory wells that find reserves, which cannot yet be classified as proved, continue to be capitalized if (i) the well has found a sufficient quantity of reserves to justify completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met, or if the Company obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well costs, net of any salvage value, are expensed.

Leases—The Company accounts for leases in accordance with FASB ASC Topic 842 – Leases (“ASC 842”). The Company has elected certain practical expedients available under ASC 842 including the short-term lease recognition exemption for all classes of underlying assets. Accordingly, leases with a term of one year or less have not and will not be recognized in the consolidated balance sheets. The Company has also elected the practical expedient to not separate lease and non-lease components contained within a single agreement for all classes of underlying assets.

Other Property and Equipment—Other property and equipment consists of materials and supplies inventories, carried at weighted-average cost, and furniture and fixtures, buildings and leasehold improvements, which are stated at cost and depreciated using the straight-line method over their estimated useful lives ranging from 4 to 30 years. Additionally, other property and equipment includes finance lease right-of-use assets for automobiles, which are depreciated using the straight-line method over the shorter of (i) their lease term or (ii) their estimated useful lives of 5 years. Refer to the “Leases” footnote for additional information on these lease assets.

Debt Issuance Costs—Debt issuance costs related to the Credit Agreement are included in other long-term assets and are amortized to interest expense on a straight-line basis over the term of the agreement. As a result of the Chapter 11 Cases and the adoption of ASC 852, the Company wrote off all unamortized issuance costs related to its senior notes on the Petition Date. Refer to the “Chapter 11 Emergence” and “Fresh Start Accounting” footnotes for more information.

Debt Discounts and Premiums—Debt discounts and premiums related to the Company’s senior notes and convertible senior notes were previously included as a deduction from or addition to the carrying amount of the long-term debt and were amortized to interest expense using the effective interest method over the term of the related notes. As a result of the Chapter 11 Cases and the adoption of ASC 852, the Company wrote off all unamortized premium balances related to its notes on the Petition Date. Refer to the “Chapter 11 Emergence” and “Fresh Start Accounting” footnotes for more information.

Derivative Instruments—The Company enters into derivative contracts, primarily collars and swaps, to manage its exposure to commodity price risk. Whiting follows FASB ASC Topic 815 – Derivatives and Hedging (“ASC 815”), to account for its derivative financial instruments. All derivative instruments, other than those that meet the “normal purchase normal sale” exclusion, are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. Gains and losses from changes in the fair value of derivative instruments are recognized immediately in earnings, unless the derivative meets specific hedge accounting criteria and the derivative has been designated as a hedge. The Company does not currently apply hedge accounting to any of its outstanding derivative instruments, and as a result, all changes in derivative fair values are recognized currently in earnings.

Cash flows from derivatives used to manage commodity price risk are classified in operating activities along with the cash flows of the underlying hedged transactions. The Company does not enter into derivative instruments for speculative or trading purposes. Refer to the “Derivative Financial Instruments” footnote for further information.

Asset Retirement Obligations and Environmental Costs—Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The Company follows FASB ASC Topic 410 – Asset Retirement and Environmental Obligations, to determine its asset retirement obligation amounts by calculating the present value of the estimated future cash outflows associated with its plugging and abandonment obligations. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred (typically when a well is completed or acquired or when an asset is installed at the production location), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a unit-of-production basis over the proved developed reserves of the related asset. Revisions typically occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells, and such revisions result in adjustments to the related capitalized asset and corresponding liability.

Deferred Gain on Sale—The Company recorded a deferred gain on sale related to the sale of 18,400,000 Whiting USA Trust II (“Trust II”) units, which was being amortized to income based on the unit-of-production method. As a result of the Chapter 11 Cases and the adoption of ASC 852, the Company wrote off the remaining deferred gain to “Reorganization items, net” in the consolidated statements of operations during the 2020 Predecessor Period. Refer to the “Chapter 11 Emergence” and “Fresh Start Accounting” footnotes for more information.

Revenue Recognition—Revenues are predominantly derived from the sale of produced oil, NGLs and natural gas. The Company accounts for revenues in accordance with FASB ASC Topic 606 – Revenue from Contracts with Customers (“ASC 606”), and thus oil and gas revenues are recognized at the point in time at which the Company’s performance obligation to deliver the product is met and control is transferred to the customer. The Company has determined that its contracts for the sale of crude oil, unprocessed natural gas, residue gas and NGLs contain monthly performance obligations to deliver product at locations specified in the contract. Control is transferred at the delivery location, at which point the performance obligation has been satisfied and revenue is recognized. Fees included in the contract that are incurred prior to control transfer are classified as transportation, gathering, compression and other, and fees incurred after control transfers are included as a reduction to the transaction price. The transaction price at which revenue is recognized consists entirely of variable consideration based on quoted market prices less various fees and the quantity of volumes delivered.

Payments for product sales are received one to three months after delivery. At the end of each month when the performance obligation is satisfied and the amount of production delivered and the price received can be reasonably estimated, amounts due from customers are accrued in accounts receivable trade, net in the consolidated balance sheets.

The Company has elected to utilize the practical expedient in ASC 606 that states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company’s contracts, each monthly delivery of product represents a separate performance obligation, therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

Taxes collected and remitted to governmental agencies on behalf of customers are not included in revenues or costs and expenses.

General and Administrative Expenses—General and administrative expenses are reported net of reimbursements of overhead costs that are allocated to the working interest owners that participate in oil and gas properties operated by Whiting.

Stock-based Compensation Expense—The Company has a share-based employee compensation plan that provides for the issuance of various types of stock-based awards, including shares of restricted stock, restricted stock units, performance shares, performance share units and stock options, to employees and non-employee directors. The Company determines compensation expense for share-settled awards granted under these plans based on the grant date fair value, and such expense is recognized on a straight-line basis over the requisite service period of the award. The Company determines compensation expense for cash-settled awards granted under these plans based on the fair value of such awards at the end of each reporting period. Cash-settled awards are recorded as a liability in the consolidated balance sheets, and gains and losses from changes in fair value are recognized immediately in earnings. The Company accounts for forfeitures of share-based awards as they occur. Refer to the “Stock-Based Compensation” footnote for further information.

401(k) Plan—The Company has a defined contribution retirement plan for all employees. The plan is funded by employee contributions and discretionary Company contributions. The Company’s contributions for 2021, the 2020 Successor Period, the 2020 Predecessor Period and the year ended December 31, 2019 (Predecessor) were $3 million, $1 million, $4 million and $7 million, respectively. Non-executive employees become 100% vested in employer contributions immediately. Executives vest in employer contributions at 20% per year of completed service up to five years.

Income Taxes—Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are accounted for using the liability method. Under this method, deferred tax assets and liabilities are determined by applying the enacted statutory tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the Company’s financial statements. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance for deferred tax assets is established when it is more likely than not that some portion of the benefit from deferred tax assets will not be realized. The Company’s uncertain tax positions must meet a more-likely-than-not realization threshold to be recognized, and any potential accrued interest and penalties related to unrecognized tax benefits are recognized within income tax expense.

Earnings Per Share—Basic earnings per common share is calculated by dividing net income by the weighted average number of common shares outstanding during each period. Diluted earnings per common share is calculated by dividing adjusted net income by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted earnings per share calculations for the Successor periods consist of unvested restricted and performance stock units, outstanding warrants and contingently issuable shares related to settlement of outstanding claims related to the Chapter 11 Cases, all using the treasury stock method. Potentially dilutive securities for the diluted earnings per share calculations for the Predecessor periods consist of unvested restricted and performance stock awards and units, stock options and contingently issuable shares of convertible debt to be settled in cash, all using the treasury stock method. When a loss from continuing operations exists, all dilutive securities and potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share.

Industry Segment and Geographic Information—The Company has evaluated how it is organized and managed and has identified only one operating segment, which is the exploration and production of crude oil, NGLs and natural gas. The Company considers its gathering, processing and marketing functions as ancillary to its oil and gas producing activities. All of the Company’s operations and assets are located in the United States, and substantially all of its revenues are attributable to United States customers.

Concentration of Credit Risk—Whiting is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries. The creditworthiness of customers and other counterparties is subject to continuing review. The following tables present the percentages by purchaser that accounted for 10% or more of the Company’s total oil, NGL and natural gas sales for the periods presented.


Year Ended December 31, 2021
Shell Trading (US) Company	23	%
Marathon Oil Company	11	%


Year Ended December 31, 2020
Shell Trading (US) Company	14	%
Tesoro Crude Oil Co	13	%


Year Ended December 31, 2019
Tesoro Crude Oil Co	14	%
Philips 66 Company	12	%

Commodity derivative contracts held by the Company are with nine counterparties, all of which are participants in Whiting’s credit facility and all of which have investment-grade ratings from Moody’s and Standard & Poor’s. As of December 31, 2021, outstanding derivative contracts with JP Morgan Chase Bank, Wells Fargo Bank, N.A., Capital One, N.A and Canadian Imperial Bank of Commerce represented 30%, 25%, 10% and 10%, respectively, of total volumes hedged.

2. CHAPTER 11 EMERGENCE

Plan of Reorganization under Chapter 11 of the Bankruptcy Code—On April 1, 2020, the Debtors commenced the Chapter 11 Cases as described in the “Summary of Significant Accounting Policies” footnote above. On April 23, 2020, the Debtors entered into a restructuring support agreement with certain holders of the Company’s senior notes to support a restructuring in accordance with the terms set forth in the Plan. On August 14, 2020, the Bankruptcy Court confirmed the Plan. On September 1, 2020 the Debtors satisfied all conditions required for Plan effectiveness and emerged from the Chapter 11 Cases.

On the Emergence Date and pursuant to the Plan:

(1)	The Company amended and restated its certificate of incorporation and bylaws.

(2)	The Company constituted a new Successor Board.

(3)	The Company appointed a new Chief Executive Officer and a new Chief Financial Officer.

(4)	The Company issued:

●

36,817,630 shares of the Successor’s common stock pro rata to holders of the Predecessor’s senior notes,

●

1,233,495 shares of the Successor’s common stock pro rata to holders of the Predecessor’s common stock,

●

4,837,387 Series A Warrants to purchase the same number of shares of the Successor’s common stock pro rata to holders of the Predecessor’s common stock and

●

2,418,840 Series B Warrants to purchase the same number of shares of the Successor’s common stock pro rata to holders of the Predecessor’s common stock.

The Company also reserved 3,070,201 shares of the Successor’s common stock for potential future distribution to certain general unsecured claimants whose claim values were pending resolution in the Bankruptcy Court. In February 2021, the Company issued 948,897 shares out of this reserve to a general unsecured claimant in full settlement of such claimant’s claims pending before the Bankruptcy Court and for rejection damages relating to an executory contract. Any remaining reserved shares that are not distributed to resolve pending claims will be cancelled. In addition, 4,035,885 shares were reserved for distribution under the Company’s 2020 equity incentive plan, as further detailed in the “Stock-Based Compensation” footnote below.

(5)

Whiting Petroleum Corporation, as parent guarantor, and Whiting Oil and Gas, as borrower, entered into the Credit Agreement with a syndicate of banks with initial aggregate commitments in the amount of $750 million, with the ability to increase the aggregate commitments by up to an additional $750 million, subject to certain conditions. Refer to the “Long-Term Debt” footnote for more information on the Credit Agreement. The Company utilized borrowings from the Credit Agreement and cash on hand to repay all borrowings and accrued interest outstanding on its pre-emergence credit facility (the “Predecessor Credit Agreement”) as of the Emergence Date, which terminated on that date.

(6)	The holders of trade claims, administrative expense claims, other secured claims and other priority claims received payment in full in cash upon emergence or through the ordinary course of business after the Emergence Date.

Executory Contracts—Subject to certain exceptions, under the Bankruptcy Code the Debtors were entitled to assume, assign or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and fulfillment of certain other conditions. Generally, the rejection of an executory contract or unexpired lease was treated as a pre-petition breach of such contract and, subject to certain exceptions, relieved the Debtors from performing future obligations under such contract but entitled the counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Alternatively, the assumption of an executory contract or unexpired lease required the Debtors to cure existing monetary defaults under such executory contract or unexpired lease, if any. Accordingly, any description of an executory contract or unexpired lease with the Debtors in this document, including where applicable quantification of the Company’s obligations under such executory or unexpired lease of the Debtors, is qualified by any overriding rejection rights the Company has under the Bankruptcy Code unless an order settling the claims has been issued by the Bankruptcy Court. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the Debtors expressly reserve all of their rights in that regard. Refer to the “Commitments and Contingencies” footnote for more information on potential future rejection damages related to general unsecured claims.

Interest Expense—The Company discontinued recording interest on its senior notes as of the Petition Date. The contractual interest expense not accrued in the consolidated statements of operations was approximately $57 million for the period from the Petition Date through the Emergence Date.

Claims Resolution Process—Pursuant to the Plan, the Debtors have the sole authority to (1) file and prosecute objections to claims asserted by third parties and governmental entities and (2) settle, compromise, withdraw, litigate to judgment or otherwise resolve objections to such claims. The claims resolutions process is ongoing and certain of these claims remain subject to the jurisdiction of the Bankruptcy Court.

3. FRESH START ACCOUNTING

Fresh Start—In connection with the Company’s emergence from bankruptcy and in accordance with ASC 852, the Company qualified for and adopted fresh start accounting on the Emergence Date. The Company was required to adopt fresh start accounting because (i) the holders of existing voting shares of the Predecessor received less than 50% of the voting shares of the Successor and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the total of post-petition liabilities and allowed claims.

In accordance with ASC 852, with the application of fresh start accounting, the Company allocated its reorganization value to its individual assets based on their estimated fair values in conformity with ASC 820 and FASB ASC Topic 805 – Business Combinations (“ASC 805”). The reorganization value represents the fair value of the Successor’s assets before considering certain liabilities and is intended to represent the approximate amount a willing buyer would pay for the Company’s assets immediately after reorganization.

Reorganization Value—As set forth in the Plan and related disclosure statement, the enterprise value of the Successor was estimated to be between $1.35 billion and $1.75 billion. At the Emergence Date, the Successor’s estimated enterprise value was $1.59 billion before the consideration of cash and cash equivalents on hand, which falls slightly above the midpoint of this range. The enterprise value was derived primarily from an independent valuation using an income approach to derive the fair value of the Company’s assets as of the fresh start reporting date of September 1, 2020.

The Company’s principal assets are its oil and natural gas properties. The fair value of proved reserves was estimated using an income approach, which was based on the anticipated future cash flows associated with those proved reserves, risked by reserve category and discounted using a weighted average cost of capital rate of 14%. The proved reserve locations included in this analysis were limited to wells included in the Company's five-year development plan. Future prices for the income approach were based on forward strip price curves (adjusted for basis differentials). The fair value of the Company’s unproved reserves was estimated using a combination of income and market approaches. Refer to further discussion below in “Fresh Start Accounting Adjustments.”

The following table reconciles the Company’s enterprise value to the implied value of the Successor’s common stock as of September 1, 2020 (in thousands):


Enterprise value	$	1,591,887
Plus: Cash and cash equivalents		22,657
Less: Fair value of debt		(425,328)
Implied value of Successor common stock	$	1,189,216

The following table reconciles the Company’s enterprise value to its reorganization value as of September 1, 2020 (in thousands):


Enterprise value	$	1,591,887
Plus:
Cash and cash equivalents		22,657
Accounts payable trade		56,432
Revenues and royalties payable		145,506
Other current liabilities		143,790
Asset retirement obligations		121,343
Operating lease obligations		17,839
Deferred income taxes		14,501
Other long-term liabilities		28,773
Reorganization value	$	2,142,728

Although the Company believes the assumptions and estimates used to develop enterprise value and reorganization value are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating these values are inherently uncertain and require judgment. Refer to the caption “Fresh Start Adjustments” below for additional information regarding assumptions used in the valuation of the Company’s significant assets and liabilities.

Condensed Consolidated Balance Sheet at Emergence (in thousands)—The adjustments set forth in the following condensed consolidated balance sheet as of September 1, 2020 reflect the consummation of transactions contemplated by the Plan (the “Reorganization Adjustments”) and the fair value adjustments as a result of applying fresh start accounting (the “Fresh Start Adjustments”). The explanatory notes highlight methods used to determine fair values or other amounts of the corresponding assets or liabilities, as well as significant assumptions.


	As of September 1, 2020
			Reorganization			Fresh Start
	Predecessor		Adjustments			Adjustments			Successor
ASSETS
Current assets:
Cash and cash equivalents	$	547,354	$	(524,697)	^(a)	$	-		$	22,657
Restricted cash		28,955		(2,205)	^(b)		-			26,750
Accounts receivable trade, net		136,881		-			81	^(o)		136,962
Prepaid expenses and other		18,722		231	^(c)		2,260	^(p)		21,213
Total current assets		731,912		(526,671)			2,341			207,582
Property and equipment:
Oil and gas properties, successful efforts method		4,885,013		-			(3,058,899)	^(q)		1,826,114
Other property and equipment		159,866		(909)	^(d)		(87,642)	^(o)(r)		71,315
Total property and equipment		5,044,879		(909)			(3,146,541)			1,897,429
Less accumulated depreciation, depletion and amortization		(2,085,266)		-			2,085,266	^(o)(q)(r)		-
Total property and equipment, net		2,959,613		(909)			(1,061,275)			1,897,429
Debt issuance costs		1,834		10,950	^(e)		-			12,784
Other long-term assets		37,010		(8,760)	^(d)		(3,317)	^(o)(s)		24,933
TOTAL ASSETS	$	3,730,369	$	(525,390)		$	(1,062,251)		$	2,142,728
LIABILITIES AND EQUITY (DEFICIT)
Current liabilities:
Current portion of long-term debt	$	912,259	$	(912,259)	^(f)	$	-		$	-
Accounts payable trade		47,168		9,264	^(g)(h)		-			56,432
Revenues and royalties payable		145,506		-			-			145,506
Accrued capital expenditures		14,037		1,305	^(g)		-			15,342
Accrued liabilities and other		46,327		21,942	^(g)(i)		(6,529)	^(o)(t)		61,740
Accrued lease operating expenses		25,344		1,394	^(g)		-			26,738
Accrued interest		3,459		(3,332)	^(g)(j)		(127)	^(o)		-
Taxes payable		13,972		-			-			13,972
Derivative liabilities		25,998		-			-			25,998
Total current liabilities		1,234,070		(881,686)			(6,656)			345,728
Long-term debt		-		425,328	^(k)		-			425,328
Asset retirement obligations		150,925		-			(29,582)	^(u)		121,343
Operating lease obligations		-		17,652	^(d)(g)		187	^(o)		17,839
Deferred income taxes		69,847		-			(55,346)	^(v)		14,501
Other long-term liabilities		18,160		11,071	^(g)		(458)	^(o)(t)		28,773
Total liabilities not subject to compromise		1,473,002		(427,635)			(91,855)			953,512
Liabilities subject to compromise		2,526,925		(2,526,925)	^(g)		-			-
Total liabilities		3,999,927		(2,954,560)			(91,855)			953,512
Commitments and contingencies
Equity (deficit):
Predecessor common stock		92		(92)	^(l)		-			-
Successor common stock		-		38	^(m)		-			38
Predecessor additional paid-in capital		6,410,410		(6,410,410)	^(l)		-			-
Successor additional paid-in capital		-		1,189,178	^(m)		-			1,189,178
Accumulated earnings (deficit)		(6,680,060)		7,650,456	⁽ⁿ⁾		(970,396)	^(w)		-
Total equity (deficit)		(269,558)		2,429,170			(970,396)			1,189,216
TOTAL LIABILITIES AND EQUITY (DEFICIT)	$	3,730,369	$	(525,390)		$	(1,062,251)		$	2,142,728

Reorganization Adjustments

(a)	The table below reflects the sources and uses of cash on the Emergence Date pursuant to the terms of the Plan (in thousands):


Sources:
Release of restricted cash upon bankruptcy emergence	$	28,205
Borrowings under the Credit Agreement		425,328
Total sources of cash		453,533
Uses:
Payment of outstanding borrowings under the Predecessor Credit Agreement		(912,259)
Payment of accrued interest on the Predecessor Credit Agreement		(3,437)
Payment of debt issuance costs related to the Credit Agreement		(10,950)
Funding of the Professional Fee Escrow Account		(26,000)
Payment of professional fees upon emergence		(14,470)
Payment of contract cure amounts		(11,114)
Total uses of cash		(978,230)

Net uses of cash	$	(524,697)

(b)	The table below reflects the net reclassification of cash balances to and from restricted cash on the Emergence Date pursuant to terms of the Plan (in thousands):


Funding of the Professional Fee Escrow Account	$	26,000
Release of restricted cash upon bankruptcy emergence ⁽¹⁾		(28,205)
Net reclassifications from restricted cash	$	(2,205)

(1)

Includes $23 million of funds related to derivative termination settlements that were directed by the counterparty to be held in a segregated account until the Company emerged from bankruptcy, as well as $5 million of amounts set aside as adequate assurance for utility providers that were restricted until emergence.

(c)	Reflects the payment of professional fee retainers upon emergence.

(d)

The Company amended a corporate office lease agreement and terminated the lease of certain floors within that agreement, which amendment was effective upon emergence from the Chapter 11 Cases. As a result of the lease modification and terminations, the Company reduced the associated right-of-use assets and operating lease obligations by $10 million and $15 million, respectively, resulting in a $5 million gain on settlement of liabilities subject to compromise, which was recorded to reorganization items, net in the consolidated statements of operations. The corporate office lease was classified as an operating lease and the modification did not result in a change to the lease’s classification. Additionally, $18 million of long-term operating lease obligations in liabilities subject to compromise were reinstated to be satisfied in the ordinary course of business.

(e)	Represents $11 million of financing costs related to the Credit Agreement which were capitalized as debt issuance costs and will be amortized to interest expense through the maturity date of April 1, 2024.

(f)	Reflects the payment in full of the borrowings outstanding under the Predecessor Credit Agreement on the Emergence Date.

(g)

As part of the Plan, the Bankruptcy Court approved the settlement of certain claims reported within liabilities subject to compromise in the Company's consolidated balance sheet at their respective allowed claim amounts. The table below indicates the reinstatement or disposition of liabilities subject to compromise (in thousands):


Liabilities subject to compromise pre-emergence	$	2,526,925
Amounts reinstated on the Emergence Date:
Accounts payable trade		(10,866)
Accrued capital expenditures		(1,305)
Accrued lease operating expenses		(1,394)
Accrued liabilities and other		(13,961)
Accrued interest		(105)
Operating lease obligations		(17,652)
Other long-term liabilities		(11,071)
Total liabilities reinstated		(56,354)
Less: Amounts settled per the Plan
Issuance of common stock to general unsecured claim holders		(1,125,062)
Payment of contract cure amounts		(10,836)
Operating lease modification and terminations		(9,669)
Issuance of Successor common stock to holders of unvested cash-settled equity awards ⁽¹⁾		(64)
Total amounts settled		(1,145,631)
Gain on settlement of liabilities subject to compromise	$	1,324,940

(1)

Holders of unvested cash-settled restricted stock awards were included as existing equity interests in the Plan and thus received Successor common stock on a pro rata basis based on the amount of unvested awards held. This amount represents the gain on the liability related to those awards, which was included in liabilities subject to compromise prior to emergence.

(h)	Reflects the reinstatement of $11 million of accounts payable included in liabilities subject to compromise to be satisfied in the ordinary course of business, partially offset by $2 million of professional fees paid on the Emergence Date.

(i)

Represents the accrual of success fees payable upon emergence as well as certain other expenses, the payment of certain professional fees that were accrued for prior to emergence and the reinstatement of certain accrued liabilities included in liabilities subject to compromise to be satisfied in the ordinary course of business, as detailed in the following table (in thousands):


Reinstatement of accrued expenses from liabilities subject to compromise	$	13,961
Recognition of success fee payable upon emergence		11,500
Other expenses accrued at emergence		3,315
Payment of certain professional fees accrued prior to emergence		(6,834)
Net impact to accrued liabilities and other	$	21,942

(j)	Represents a $3 million payment of accrued interest on the Predecessor Credit Agreement and reinstated accrued interest that was included within liabilities subject to compromise to be satisfied in the ordinary course of business.

(k)	Reflects borrowings drawn under the Credit Agreement upon emergence. Refer to the "Long-Term Debt" footnote for more information on the Credit Agreement.

(l)

Pursuant to the terms of the Plan, on the Emergence Date, all Predecessor common stock interests were cancelled. As a result of the cancellation, the Company accelerated the recognition of $4 million in compensation expense related to the unrecognized portion of share-based compensation as of the Emergence Date, which was recorded to reorganization items, net in the consolidated statements of operations.

(m)

Reflects the issuance of Successor equity, including the issuance of 38,051,125 shares of common stock at a par value of $0.001 per share and warrants to purchase 7,256,227 shares of common stock in exchange for claims against or interests in the Debtors pursuant to the Plan. Equity issued to each class of claims is detailed in the table below (in thousands):


Issuance of common stock to general unsecured claim holders	$	1,125,062
Issuance of common stock to Predecessor common stockholders and holders of unvested cash-settled equity awards		34,794
Issuance of warrants to Predecessor common stockholders and holders of unvested cash-settled equity awards		29,360
Fair value of Successor equity	$	1,189,216

(n)	The table below reflects the cumulative impact of the reorganization adjustments discussed above (in thousands):


Gain on settlement of liabilities subject to compromise	$	1,324,940
Cancellation of Predecessor equity ⁽¹⁾		6,414,541
Fair value of equity issued to Predecessor common stockholders and holders of unvested cash-settled equity awards		(34,794)
Fair value of warrants issued to Predecessor common stockholders and holders of unvested cash-settled equity awards		(29,360)
Success fees incurred upon emergence		(17,303)
Acceleration of unvested stock-based compensation awards		(4,161)
Other expenses incurred upon emergence		(3,407)
Net impact on accumulated earnings (deficit)	$	7,650,456

(1)

This value is reflective of Predecessor common stock, Predecessor additional paid in capital and the recognition of $4 million in compensation expense related to the unrecognized portion of share-based compensation.

Fresh Start Adjustments

(o)

Reflects the adjustments to fair value made to operating and finance lease assets and liabilities. Upon adoption of fresh start accounting, the Company's remaining lease obligations were recalculated using the incremental borrowing rate applicable to the Company upon emergence and commensurate with the Successor's capital structure. The fair value adjustments related to leases are summarized in the table below (in thousands):


Lease Asset/Liability	Emergence Balance Sheet Classification	Fair Value Adjustment
Accounts receivable, net	Accounts receivable, net	$	81
Operating lease assets, net	Other long-term assets		(1,480)
Finance lease assets	Other property and equipment		(10,765)
Accumulated depreciation - finance leases	Less accumulated depreciation, depletion and amortization		15,099
Accrued interest - finance leases	Accrued interest		127
Short-term finance lease obligation	Accrued liabilities and other		(576)
Short-term operating lease obligation	Accrued liabilities and other		319
Long-term finance lease obligation	Other long-term liabilities		(1,174)
Long-term operating lease obligation	Operating lease obligations		(187)
		$	1,444

(p)	Reflects the adjustment to fair value of the Company's oil in tank inventory based on market prices as of the Emergence Date.

(q)	Reflects the adjustments to fair value of the Company's oil and natural gas properties and undeveloped properties, as well as the elimination of accumulated depletion, depreciation and amortization.

For purposes of estimating the fair value of the Company's proved oil and gas properties, an income approach was used which estimated the fair value based on the anticipated future cash flows associated with the Company's proved reserves, risked by reserve category and discounted using a weighted average cost of capital rate of 14%. The proved reserve locations included in this analysis were limited to wells included in the Company's five-year development plan. Future prices for the income approach were based on forward strip price curves (adjusted for basis differentials) as of the Emergence Date.

In estimating the fair value of the Company's unproved properties, a combination of income and market approaches were utilized. The income approach consistent with that utilized for proved properties was utilized for properties which had positive future cash flows associated with reserve locations that did not qualify as proved reserves. A market approach was used to value the remainder of the Company’s unproved properties.

(r)

Reflects the fair value adjustment to recognize the Company’s land, buildings and other property, plant and equipment as of the Emergence Date based on the fair values of such land, buildings and other property, plant and equipment as well as the elimination of related historical depletion, depreciation and amortization balances. Land and buildings were valued using a market approach. Other property, plant and equipment were valued using a cost approach based on the current replacement costs of the assets, less depreciation based on the estimated economic useful lives of the assets and the age of the assets. The fair value adjustments consisted of a decrease of $16 million in land and buildings, a decrease of $61 million in other property, plant and equipment and a corresponding write-off of $66 million in accumulated depletion, depreciation and amortization.

(s)	Reflects the adjustment to fair value of the Company's other long-term assets, including line fill and pipeline imbalances, based on the commodity market prices as of the Emergence Date, which resulted in a $2 million decrease to other long-term assets.

(t)

Represents the write-off of a deferred gain balance associated with the Predecessor. The deferred gain does not relate to the Successor and therefore the unamortized balance was written off in full in the Predecessor's consolidated statements of operations. Of the total $9 million write off, $7 million related to the short-term portion of the deferred gain (included in accrued liabilities and other in the consolidated balance sheets at emergence) and $2 million related to the long-term portion (included in other long-term liabilities in the consolidated balance sheets at emergence).

(u)	Reflects the adjustment to fair value of the Company's asset retirement obligations including using a credit-adjusted risk-free rate as of the Emergence Date.

(v)	Reflects the adjustment to fair value of the Company's deferred tax liability related to Whiting Canadian Holding Company ULC's outside basis difference in its ownership of a portion of Whiting's U.S. assets obtained through the acquisition of Kodiak Oil and Gas Corporation in 2014.

(w)	Reflects the cumulative impact of the fresh start adjustments discussed above.

Reorganization Items, Net—Any expenses, gains and losses that were realized or incurred between the Petition Date and the Emergence Date and as a direct result of the Chapter 11 Cases were recorded in reorganization items, net in the Company’s consolidated statements of operations. The following table summarizes the components of reorganization items, net for the periods presented (in thousands):


	Successor		Predecessor
	Four Months Ended December 31, 2020		Eight Months Ended August 31, 2020
Legal and professional advisory fees	$	-	$	57,170
Net gain on liabilities subject to compromise		-		(1,324,940)
Fresh start adjustments, net		-		1,025,742
Write-off of unamortized debt issuance costs and premium⁽¹⁾		-		15,145
Other items, net		-		9,464
Total reorganization items, net	$	-	$	(217,419)

(1)	As a result of the Chapter 11 Cases and the adoption of ASC 852, the Company wrote off all unamortized premium and issuance cost balances related to its senior notes on the Petition Date.

4. OIL AND GAS PROPERTIES

Net capitalized costs related to the Company’s oil and gas producing activities at December 31, 2021 and 2020 are as follows (in thousands):


	Successor
	December 31,		December 31,
	2021		2020
Proved oil and gas properties	$	2,034,533	$	1,701,163
Unproved leasehold costs		182,109		105,073
Wells and facilities in progress		58,266		6,365
Total oil and gas properties, successful efforts method		2,274,908		1,812,601
Accumulated depletion		(248,298)		(71,064)
Oil and gas properties, net	$	2,026,610	$	1,741,537

The following tables present impairment expense for unproved properties for the periods presented, which is reported in exploration and impairment expense in the consolidated statements of operations (in thousands):


	Successor				Predecessor
	Year Ended December 31, 2021		Four Months Ended December 31, 2020		Eight Months Ended August 31, 2020		Year Ended December 31, 2019
Impairment expense for unproved properties	$	3,093	$	1,396	$	12,566	$	9,450

5. ACQUISITIONS AND DIVESTITURES

2021 Acquisitions and Divestitures

On September 14, 2021, the Company 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). The revenue and earnings from these properties since the acquisition date are included in the Company’s consolidated financial statements for the year ended December 31, 2021. Pro forma revenue and earnings for the acquired properties are not material to the Company’s 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 ASC 805. The following table summarizes the preliminary allocation of the $268 million adjusted purchase price (which is still 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 did not result in the recognition of goodwill or 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-close 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):


Cash consideration	$	270,800
Purchase price adjustments		(2,553)
Adjusted purchase price	$	268,247

Fair Value of Assets Acquired:
Prepaid expenses and other	$	730
Oil and gas properties, successful efforts method:
Proved oil and gas properties		167,435
Unproved leasehold costs		103,397
Total fair value of assets acquired		271,562

Fair Value of Liabilities Assumed:
Asset retirement obligations		2,242
Revenue and royalties payable		1,073
Total fair value of liabilities assumed		3,315

Total fair value of assets acquired and liabilities assumed	$	268,247

On September 23, 2021, the Company completed the sale of all of its interests in producing assets and undeveloped acreage, including the associated midstream assets, of its Redtail field located in the Denver-Julesburg Basin of Weld County, Colorado for aggregate net sales proceeds of $171 million. The sale was effective June 1, 2021 and resulted in a pre-tax gain on sale of $86 million. The divestiture remains subject to a final settlement between Whiting and the buyer of the properties, which could impact the ultimate proceeds received and the gain recognized as a result of the transaction. The Company used the net proceeds from the sale to repay a portion of the borrowings outstanding under the Credit Agreement. This transaction included the removal of approximately $20 million in asset retirement obligations as well as certain finance leases for a pipeline and vehicles, which resulted in the termination of approximately $16 million of finance lease right-of-use assets, $3 million of accumulated depreciation and $12 million of long-term finance lease obligations.

On December 16, 2021, the Company 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). The acquisition was accounted for as a business combination and was recorded using the acquisition method of accounting in accordance with ASC 805. The preliminary allocation of the $32 million purchase price resulted in $31 million of proved oil and gas properties acquired, $1 million of unproved leasehold costs acquired and $1 million of asset retirement obligations assumed. As the purchase price is further adjusted for post-close adjustments and as the oil and gas property valuation is completed, the final purchase price allocation may result in a different allocation.

2020 Acquisitions and Divestitures

On January 9, 2020, the Predecessor completed the divestiture of its interests in 30 non-operated, producing oil and gas wells and related undeveloped acreage located in McKenzie County, North Dakota for aggregate sales proceeds of $25 million (before closing adjustments).

There were no significant acquisitions during the year ended December 31, 2020.

2019 Acquisitions and Divestitures

On July 29, 2019, the Predecessor completed the divestiture of its interests in 137 non-operated, producing oil and gas wells located in the McKenzie, Mountrail and Williams counties of North Dakota for aggregate sales proceeds of $27 million (before closing adjustments).

On August 15, 2019, the Predecessor completed the divestiture of its interests in 58 non-operated, producing oil and gas wells located in Richland County, Montana and Mountrail and Williams counties of North Dakota for aggregate sales proceeds of $26 million (before closing adjustments).

There were no significant acquisitions during the year ended December 31, 2019.

6. LEASES

The Company has operating and finance leases for corporate and field offices, equipment, pipeline and midstream facilities and automobiles. Right-of-use (“ROU”) assets and liabilities associated with these leases are recognized at the lease commencement date based on the present value of the lease payments over the lease term. ROU assets represent the Company’s right to use an underlying asset for the lease term, and lease liabilities represent the Company’s obligation to make lease payments.

Supplemental balance sheet information for the Company’s leases as of December 31, 2021 and 2020 consisted of the following (in thousands):


		Successor
Leases	Balance Sheet Classification	December 31, 2021		December 31, 2020

Operating Leases
Operating lease ROU assets	Other long-term assets	$	21,962	$	21,962
Accumulated depreciation	Other long-term assets		(4,499)		(1,096)
Operating lease ROU assets, net		$	17,463	$	20,866

Short-term operating lease obligations	Accrued liabilities and other	$	3,086	$	4,031
Long-term operating lease obligations	Operating lease obligations		14,710		17,415
Total operating lease obligations		$	17,796	$	21,446

Finance Leases
Finance lease ROU assets	Other property and equipment	$	4,023	$	19,706
Accumulated depreciation	Accumulated depreciation, depletion and amortization		(2,025)		(1,797)
Finance lease ROU assets, net		$	1,998	$	17,909

Short-term finance lease obligations	Accrued liabilities and other	$	1,321	$	4,830
Long-term finance lease obligations	Other long-term liabilities		721		13,138
Total finance lease obligations		$	2,042	$	17,968

The Company’s leases have remaining terms of up to 10 years. Most of the Company’s leases do not state or imply a discount rate. Accordingly, the Company uses its incremental borrowing rate based on information available at lease commencement to determine the present value of the lease payments. Information regarding the Company’s lease terms and discount rates as of December 31, 2021 and 2020 is as follows:


	Successor
	December 31, 2021		December 31, 2020
Weighted Average Remaining Lease Term
Operating leases		7 years		7 years
Finance leases		2 years		4 years

Weighted Average Discount Rate
Operating leases		4.4%		4.4%
Finance leases		4.1%		4.2%

Operating lease cost is recognized on a straight-line basis over the lease term. Finance lease cost is recognized based on the effective interest method for the lease liability and straight-line amortization of the ROU asset, resulting in more cost being recognized in earlier lease periods. All payments for short-term leases, including leases with a term of one month or less, are recognized in income or capitalized to the cost of oil and gas properties on a straight-line basis over the lease term. Additionally, any variable payments, which are generally related to the corresponding utilization of the asset, are recognized in the period in which the obligation was incurred. Lease cost for the periods presented consisted of the following (in thousands):


	Successor				Predecessor
	Year Ended		Four Months Ended		Eight Months Ended		Year Ended
	December 31, 2021		December 31, 2020		August 31, 2020		December 31, 2019
Operating lease cost	$	4,251	$	1,462	$	4,691	$	11,512

Finance lease cost:
Amortization of ROU assets	$	4,202	$	1,842	$	3,347	$	5,661
Interest on lease liabilities		513		260		1,131		1,996
Total finance lease cost	$	4,715	$	2,102	$	4,478	$	7,657

Short-term lease payments	$	224,711	$	26,430	$	164,815	$	676,850
Variable lease payments	$	10,637	$	99	$	23,307	$	31,812

Total lease cost represents the total financial obligations of the Company, a portion of which has been or will be reimbursed by the Company’s working interest partners. Lease cost is included in various line items in the consolidated statements of operations or capitalized to oil and gas properties and is recorded at the Company’s net working interest.

Supplemental cash flow information related to leases for the periods presented consisted of the following (in thousands):


	Successor				Predecessor
	Year Ended		Four Months Ended		Eight Months Ended		Year Ended
	December 31, 2021		December 31, 2020		August 31, 2020		December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	4,500	$	2,174	$	5,813	$	11,978
Operating cash flows from finance leases	$	536	$	197	$	1,156	$	2,006
Financing cash flows from finance leases	$	4,020	$	1,773	$	3,198	$	5,140

ROU assets obtained in exchange for new operating lease obligations	$	-	$	6,368	$	3,252	$	18,658
ROU assets obtained in exchange for new finance lease obligations	$	357	$	-	$	170	$	4,158

The Company’s lease obligations as of December 31, 2021 will mature as follows (in thousands):


Year ending December 31,	Operating Leases		Finance Leases
2022	$	3,572	$	1,378
2023		3,255		637
2024		2,950		76
2025		1,904		23
2026		1,940		4
Remaining		7,356		-
Total lease payments		20,977		2,118
Less imputed interest		(3,181)		(76)
Total discounted lease payments	$	17,796	$	2,042

7. LONG-TERM DEBT

Long-term debt, consisting entirely of borrowings outstanding under the Credit Agreement, totaled $360 million at December 31, 2020. At December 31, 2021, the Company had no long-term debt.

Credit Agreement (Successor)

On the Emergence Date, Whiting Petroleum Corporation, as parent guarantor, and Whiting Oil and Gas, as borrower, entered into the Credit Agreement, a reserves-based credit facility, with a syndicate of banks. As of December 31, 2021, the Credit Agreement had a borrowing base and aggregate commitments of $750 million. As of December 31, 2021, the Company had no borrowings outstanding under the Credit Agreement with $749 million of available borrowing capacity, which was net of $1 million in letters of credit outstanding. On September 15, 2021, the Company entered into an amendment to its existing Credit Agreement in connection with the October 1, 2021 regular borrowing base redetermination that (i) reaffirmed the $750 million borrowing base with such redetermination contemplating the closing of the Company’s recent divestiture described in the “Acquisitions and Divestitures” footnote, (ii) reduced the Company’s requirement to maintain commodity hedges covering its projected production for the succeeding twelve months from a minimum of 65% to a minimum of 50% and (iii) eliminated the Company’s requirement to maintain commodity hedges covering its projected production for the second succeeding twelve-month period, provided that the Company maintains a consolidated net leverage ratio of less than 1.0 to 1.0 as of the last day of any fiscal quarter. 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-month period.

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.

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 December 31, 2021, $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 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.

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 amended 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 December 31, 2021, 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.

Predecessor Senior Notes and Convertible Senior Notes

Prior to the Emergence Date, the Company had outstanding notes consisting of $774 million of 5.75% Senior Notes due 2021 (the “2021 Senior Notes”), $408 million of 6.25% Senior Notes due 2023 and $1.0 billion of 6.625% Senior Notes due 2026 (collectively with the 2021 Senior Notes, the “Senior Notes”) and $187 million of 1.25% Convertible Senior Notes due 2020 (the “Convertible Senior Notes”). On the Emergence Date, through implementation of the Plan, all outstanding obligations under the Senior Notes and the Convertible Senior Notes were cancelled and 36,817,630 shares of Successor common stock were issued to the holders of those cancelled notes. In addition, the remaining unamortized debt issuance costs and debt premium were written off to reorganization items, net in the consolidated statements of operations. Refer to the “Chapter 11 Emergence” and “Fresh Start Accounting” footnotes for more information.

In September 2019, the Predecessor paid $299 million to complete a cash tender offer for $300 million aggregate principal amount of the Convertible Senior Notes, which payment consisted of the 99.0% purchase price plus all accrued and unpaid interest on the notes, which were allocated to the liability and equity components based on their relative fair values. The Company financed the tender offer with borrowings under the Predecessor Credit Agreement. As a result of the tender offer, the Company recognized a $4 million gain on extinguishment of debt, which was net of a $7 million charge for the non-cash write-off of unamortized debt issuance costs and debt discount and a $1 million charge for transaction costs.

In March 2020, the Company paid $53 million to repurchase $73 million aggregate principal amount of the Convertible Senior Notes, which payment consisted of the average 72.5% purchase price plus all accrued and unpaid interest on the notes, which were allocated to the liability and equity components based on their relative fair values. The Company financed the repurchases with borrowings under the Predecessor Credit Agreement. As a result of these repurchases, the Company recognized a $23 million gain on extinguishment of debt during the 2020 Predecessor Period, which was net of a $0.2 million charge for the non-cash write-off of unamortized debt issuance costs and debt discount. In addition, the Company recorded a $3 million reduction to the equity component of the Convertible Senior Notes. There was no deferred tax impact associated with this reduction due to the full valuation allowance in effect as of March 31, 2020.

Interest expense recognized on the Convertible Senior Notes related to the stated interest rate and amortization of the debt discount totaled $1 million and $26 million for the 2020 Predecessor Period and the year ended December 31, 2019, respectively.

Repurchases of 2021 Senior Notes. In September and October 2019, the Predecessor paid $96 million to repurchase $100 million aggregate principal amount of the 2021 Senior Notes, which payment consisted of the average 95.279% purchase price plus all accrued and unpaid interest on the notes. The Company financed the repurchases with borrowings under the Predecessor Credit Agreement. As a result of the repurchases, the Company recognized a $1 million gain on extinguishment of debt during the year ended December 31, 2019, which included a non-cash charge for the acceleration of unamortized debt issuance costs and debt premium on the notes.

8. 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 December 31, 2021 and 2020 were $10 million and $6 million, respectively, and have been included in accrued liabilities and other in the consolidated balance sheets. The following table provides a reconciliation of the Company’s asset retirement obligations for the periods presented (in thousands):


Asset retirement obligation at January 1, 2020 (Predecessor)	$	134,893
Additional liability incurred		76
Revisions to estimated cash flows		56,702
Accretion expense		8,199
Obligations on sold properties		(693)
Liabilities settled ⁽¹⁾		(42,854)
Asset retirement obligation at August 31, 2020 (Predecessor)		156,323

Fresh start adjustment ⁽²⁾		(29,582)


Asset retirement obligation at September 1, 2020 (Successor)		126,741
Additional liability incurred		20
Revisions to estimated cash flows		(30,623)
Accretion expense		3,801
Liabilities settled		(1,809)
Asset retirement obligation at December 31, 2020 (Successor)		98,130
Additional liability incurred or assumed		4,348
Revisions to estimated cash flows		26,605
Accretion expense		8,237
Obligations on sold properties		(29,251)
Liabilities settled		(4,002)
Asset retirement obligation at December 31, 2021 (Successor)	$	104,067

(1)

A portion of the Predecessor’s asset retirement obligations related to a contractual obligation to remove certain offshore facilities in California. The Company included the related contract in its schedule of rejected contracts as part of the Plan, and the related amounts of the obligations were included in liabilities subject to compromise in the consolidated balance sheets of the Predecessor as of August 31, 2020. A final ruling from the Bankruptcy Court on the rejection of this contract has not yet been issued. Refer to the “Fresh Start Accounting” and “Commitments and Contingencies” footnotes under the heading “Chapter 11 Cases—Arguello Inc. and Freeport-McMoRan Oil & Gas LLC” for additional information.

(2)	Refer to the “Fresh Start Accounting” footnote for more information on fresh start adjustments.

9. 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 Successor’s swap and collar derivatives entered into to hedge forecasted crude oil, natural gas and NGL production revenues as of December 31, 2021.


					Weighted Average
Settlement Period	Index	Derivative Instrument	Total Volumes	Units	Swap Price	Floor	Ceiling
Crude Oil
2022	NYMEX WTI	Fixed Price Swaps	2,275,000	Bbl	$69.29	-	-
2022	NYMEX WTI	Two-way Collars	11,204,000	Bbl	-	$47.07	$57.59
Q1-Q3 2023	NYMEX WTI	Two-way Collars	3,443,500	Bbl	-	$46.75	$58.87
		Total	16,922,500
Natural Gas
2022	NYMEX Henry Hub	Fixed Price Swaps	8,009,000	MMBtu	$3.24	-	-
2022	NYMEX Henry Hub	Two-way Collars	17,304,000	MMBtu	-	$2.70	$3.32
Q1-Q3 2023	NYMEX Henry Hub	Two-way Collars	6,999,000	MMBtu	-	$2.42	$2.94
		Total	32,312,000
Natural Gas Basis ⁽¹⁾
Q1-Q2 2022	NNG Ventura to NYMEX	Fixed Price Swaps	6,230,000	MMBtu	$0.51	-	-
Q1-Q2 2023	NNG Ventura to NYMEX	Fixed Price Swaps	4,740,000	MMBtu	$0.20	-	-
		Total	10,970,000
NGL - Propane
2022	Mont Belvieu	Fixed Price Swaps	19,110,000	Gallons	$1.08	-	-
2022	Conway	Fixed Price Swaps	19,110,000	Gallons	$1.17	-	-
		Total	38,220,000

(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.

Subsequent to December 31, 2021, the Company entered into additional crude oil, natural gas, natural gas basis and NGL swaps for 2022 and the first quarter of 2023. The table below details the Company’s additional derivative contracts entered into through February 17, 2022.


					Weighted Average
Settlement Period	Index	Derivative Instrument	Total Volumes	Units	Swap Price	Floor	Ceiling
Crude Oil
2022	NYMEX WTI	Fixed Price Swaps	796,000	Bbl	$72.14	-	-
Q1 2023	NYMEX WTI	Fixed Price Swaps	810,000	Bbl	$75.14	-	-
		Total	1,606,000
Natural Gas
Q2-Q4 2022	NYMEX Henry Hub	Fixed Price Swaps	3,660,000	MMBtu	$4.03	-	-
Q1 2023	NYMEX Henry Hub	Fixed Price Swaps	1,800,000	MMBtu	$4.25	-	-
		Total	5,460,000
Natural Gas Basis
Q4 2022	NNG Ventura to NYMEX	Fixed Price Swaps	620,000	MMBtu	$1.17	-	-
Q1 2023	NNG Ventura to NYMEX	Fixed Price Swaps	1,180,000	MMBtu	$1.17	-	-
		Total	1,800,000
NGL - Propane
Q2 2022	Mont Belvieu	Fixed Price Swaps	1,911,000	Gallons	$1.03	-	-
2022	Conway	Fixed Price Swaps	39,606,000	Gallons	$1.04	-	-
		Total	41,517,000

Effect of Chapter 11 Cases—The commencement of the Chapter 11 Cases constituted a termination event with respect to the Predecessor’s then outstanding derivative instruments, which permitted the counterparties of such derivative instruments to terminate those derivatives. Such termination events were not stayed under the Bankruptcy Code. During April 2020, certain of the lenders under the Predecessor Credit Agreement elected to terminate their master ISDA agreements and outstanding derivatives with the Company

for aggregate settlement proceeds to the Company of $145 million. The proceeds from these terminations along with $13 million of March 2020 hedge settlement proceeds received in April 2020 were applied to the outstanding borrowings under the Predecessor Credit Agreement. An additional $23 million of settlement proceeds from terminated derivative positions were held in escrow until the completion of the Chapter 11 Cases. On the Emergence Date, these funds were released from restrictions and the proceeds were used to pay down a portion of the borrowings outstanding on the Predecessor Credit Agreement.

Derivative Instrument Reporting—All derivative instruments are recorded in the 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 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 Successor’s derivative instruments in the consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheets (in thousands):


		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


		December 31, 2020⁽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	$	14,287	$	(14,287)	$	-
Commodity contracts - non-current	Other long-term assets		19,991		(19,991)		-
Total derivative assets		$	34,278	$	(34,278)	$	-
Derivative Liabilities
Commodity contracts - current	Derivative liabilities	$	63,772	$	(14,287)	$	49,485
Commodity contracts - non-current	Long-term derivative liabilities		29,741		(19,991)		9,750
Total derivative liabilities		$	93,513	$	(34,278)	$	59,235

(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 credit facility, which eliminates the potential need to post additional 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.

10. FAIR VALUE MEASUREMENTS

Cash, cash equivalents, restricted cash, 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 December 31, 2021 and 2020 (Successor), 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		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


							Total Fair Value
	Level 1		Level 2		Level 3		December 31, 2020
Financial Liabilities
Commodity derivatives – current	$	-	$	49,485	$	-	$	49,485
Commodity derivatives – non-current		-		9,750		-		9,750
Total financial liabilities	$	-	$	59,235	$	-	$	59,235

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 oil and natural gas properties and asset retirement obligations, 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, such as the initial measurement or when an impairment occurs. The Company did not recognize any impairment write-downs with respect to its proved properties during 2021, the 2020 Successor Period or the year ended December 31, 2019 (Predecessor). The following tables present information about the Company’s non-financial assets measured at fair value on a non-recurring basis during the 2020 Predecessor Period, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values (in thousands):


	Predecessor
	Net Carrying
	Value as of								Loss (Before Tax)
	March 31,		Fair Value Measurements Using						Three Months Ended
	2020		Level 1		Level 2		Level 3		March 31, 2020
Proved property ⁽¹⁾	$	816,234	$	-	$	-	$	816,234	$	3,732,096

(1)

During the first quarter of 2020, certain proved oil and gas properties across the Company’s Williston Basin resource play with a previous carrying amount of $4.5 billion were written down to their fair value as of March 31, 2020 of $816 million, resulting in a non-cash impairment charge of $3.7 billion, which was recorded within exploration and impairment expense. These impaired

properties were written down due to a reduction in anticipated future cash flows primarily driven by an expectation of sustained depressed oil prices and a resultant decline in future development plans for the properties assessed as of March 31, 2020.


	Predecessor
	Net Carrying
	Value as of								Loss (Before Tax)
	June 30,		Fair Value Measurements Using						Six Months Ended
	2020		Level 1		Level 2		Level 3		June 30, 2020
Proved property ⁽²⁾	$	85,418	$	-	$	-	$	85,418	$	409,079

(2)

During the second quarter of 2020, other proved oil and gas properties in the Company’s Williston Basin resource play with a previous carrying amount of $494 million were written down to their fair value as of June 30, 2020 of $85 million, resulting in a non-cash impairment charge of $409 million, which was recorded within exploration and impairment expense. These impaired properties were written down due to a reduction in anticipated future cash flows primarily driven by an expectation of sustained depressed oil prices and a resultant decline in future development plans for the properties assessed as of June 30, 2020.

Predecessor Proved Property Impairments. The Company tests proved property for impairment whenever events or changes in circumstances indicate that the fair value of these assets may be reduced below their carrying value. As a result of the significant decrease in the forward price curves for crude oil and natural gas during the first and second quarters of 2020, the associated decline in anticipated future cash flows and the resultant decline in future development plans for the properties, the Company performed proved property impairment tests as of March 31, 2020 and June 30, 2020. The fair value was ascribed using an income approach based on the net discounted future cash flows from the producing properties and related assets. The discounted cash flows were based on management’s expectations for the future. Unobservable inputs included estimates of future oil and gas production from the Company’s reserve reports, commodity prices based on forward strip price curves (adjusted for basis differentials) as of March 31, 2020 and June 30, 2020, operating and development costs, expected future development plans for the properties and a discount rate of 16% and 17% as of March 31, 2020 and June 30, 2020, respectively, based on a weighted-average cost of capital (all of which were designated as Level 3 inputs within the fair value hierarchy). The impairment tests indicated that proved property impairments had occurred, and the Company therefore recorded non-cash impairment charges to reduce the carrying value of the impaired properties to their fair value at March 31, 2020 and June 30, 2020.

Chapter 11 Emergence and Fresh Start Accounting. On the Emergence Date, the Company emerged from the Chapter 11 Cases and adopted fresh start accounting, which resulted in the Company becoming a new entity for financial reporting purposes. Upon the adoption of fresh start accounting, the Company’s assets and liabilities were recorded at their fair values as of September 1, 2020. The inputs utilized in the valuation of the Company’s most significant asset, its oil and gas properties and related assets, 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 Company’s reserve reports, commodity prices based on forward strip price curves (adjusted for basis differentials) as of September 1, 2020, operating and development costs, expected future development plans for the properties and a discount rate of 14% based on a weighted-average cost of capital. The Company also recorded its asset retirement obligations at fair value as a result of fresh start accounting. 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 the Emergence Date, anticipated future plugging and abandonment costs and an appropriate credit-adjusted risk free rate to discount such costs. Refer to the “Fresh Start Accounting” footnote for a detailed discussion of the fair value approaches used by the Company.

Williston Basin Acquisition. On September 14, 2021, the Company acquired interests in producing assets and undeveloped acreage 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 September 14, 2021. 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 September 14, 2021, operating and development costs, expected future development plans for the properties and a discount rate of 11% 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 September 14, 2021, anticipated future plugging and abandonment costs and an appropriate credit-adjusted risk-free rate to discount such costs.

11. REVENUE RECOGNITION

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


	Successor				Predecessor
OPERATING REVENUES	Year Ended December 31, 2021		Four Months Ended December 31, 2020		Eight Months Ended August 31, 2020		Year Ended December 31, 2019
Oil sales	$	1,251,015	$	254,024	$	440,820	$	1,492,218
NGL and natural gas sales		260,822		19,334		18,184		80,027
Oil, NGL and natural gas sales		1,511,837		273,358		459,004		1,572,245
Purchased gas sales		21,644		-		-		-
Total operating revenues	$	1,533,481	$	273,358	$	459,004		1,572,245

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 consolidated balance sheets. As of December 31, 2021 and 2020 (Successor), such receivable balances were $178 million and $88 million, respectively. Variances between the Company’s estimated revenue and actual payments are recorded in the month the payment is received, however, differences have been and are insignificant. Accordingly, the variable consideration is not constrained.

12. SHAREHOLDERS’ EQUITY

Common Stock—On the Emergence Date, the Successor 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 “New Common Stock”) and 50,000,000 shares are preferred stock, par value $0.001 per share.

Upon emergence from the Chapter 11 Cases on the Emergence Date all existing shares of the Predecessor’s common stock were cancelled and the Successor issued 38,051,125 shares of New Common Stock. Refer to the “Chapter 11 Emergence” and “Fresh Start Accounting” footnotes for more information.

Warrants—On the Emergence Date and pursuant to the Plan, the Successor entered into warrant agreements with Computershare Inc. and Computershare Trust Company, N.A., as warrant agent, which provide for (i) the Successor’s issuance of up to an aggregate of 4,837,821 Series A warrants to acquire the New Common Stock (the “Series A Warrants”) to certain former holders of the Predecessor’s common stock and (ii) the Successor’s issuance of up to an aggregate of 2,418,910 Series B warrants to acquire New Common Stock (the “Series B Warrants” and together with the Series A Warrants, the “Warrants”) to certain former holders of the Predecessor’s common stock. The Warrants were recorded at fair value in additional paid-in capital upon issuance on the Emergence Date, as further detailed in the “Fresh Start Accounting” footnote.

The Series A Warrants are exercisable from the date of issuance until the fourth anniversary of the Emergence Date, at which time all unexercised Series A Warrants will expire and the rights of the holders of such warrants to acquire New Common Stock will terminate. The Series A Warrants are initially exercisable for one share of New 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 the fifth anniversary of the Emergence Date, at which time all unexercised Series B Warrants will expire and the rights of the holders of such warrants to acquire New Common Stock will terminate. The Series B Warrants are initially exercisable for one share of New 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”).

In the event that a holder of Warrants elects to exercise their option to acquire shares of New Common Stock, the Company shall issue a net number of exercised shares of New 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 New 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.

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 New Common Stock issued upon settlement of the Warrants.

The number of shares of New 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 New Common Stock or a reclassification in respect of New Common Stock.

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 New Common Stock pursuant to the confirmed Plan to a Tallgrass entity in February 2021.

As discussed in the “Chapter 11 Emergence” footnote, an additional 2,121,304 shares of New Common Stock remain reserved as of December 31, 2021 for potential future distribution to certain general unsecured claimants whose claim values are pending resolution in the Bankruptcy Court.

13. STOCK-BASED COMPENSATION

Equity Incentive Plan—As discussed in the “Chapter 11 Emergence” and “Fresh Start Accounting” footnotes, on the Emergence Date and pursuant to the terms of the Plan, all of the Predecessor’s common stock and any unvested awards based on such common stock were cancelled and holders were issued an aggregate of 1,233,495 shares of Successor common stock on a pro rata basis. On September 1, 2020, the Successor’s Board adopted the Whiting Petroleum Corporation 2020 Equity Incentive Plan (the “2020 Equity Plan”), which replaced the Predecessor’s equity plan (the “Predecessor Equity Plan”). The 2020 Equity Plan provides the authority to issue 4,035,885 shares of the Successor’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 December 31, 2021, 3,034,539 shares of common stock remained available for grant under the 2020 Equity Plan.

Historically, the Company has granted service-based restricted stock awards (“RSAs”) and 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 RSAs and RSUs to directors, which generally vest over a one-year service period. In addition, the Company has granted performance share awards (“PSAs”) and 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 awarded in excess of the targets set by the Board 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.

Successor Awards under 2020 Equity Plan

During September and October 2020, 89,021 shares of service-based RSUs were granted to executive officers and directors. The Company determines compensation expense for these share-settled awards using their fair value at the grant date based on the closing bid price of the Company’s common stock on such date. The weighted average grant date fair value of these RSUs was $17.47 per share.

In September 2020, 189,900 shares of market-based RSUs were granted to executive officers. The awards vest upon the Successor’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 the year ended December 31, 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. On January 31, 2022, the remaining 25% of these awards vested as the Company’s VWAP exceeded $65.14 per share for 20 consecutive days as of that date.

During the year ended December 31, 2021, (i) 362,056 shares of service-based RSUs were granted to executive officers and employees, which vest ratably over either a two or three-year service period, (ii) 117,607 shares of service-based RSUs were granted to executive officers, which cliff vest on the fifth anniversary of the grant date and (iii) 23,730 shares of service-based RSUs were granted to the Board, which vest over a one-year period. 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 $24.00 per share for the year ended December 31, 2021.

During the year ended December 31, 2021, 232,150 shares of PSUs subject to certain market-based vesting criteria were granted to executive officers. These market-based awards vest at the end of the performance period, which is December 31, 2023, and the number of shares that vest at the end of the performance period is determined based on two performance goals: (i) 116,075 shares 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) 116,075 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 zero up to two 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 was $29.32 per share and $32.33 per share for the ATSR and RTSR awards, respectively, as determined by the Monte Carlo Model, which is described further below.

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:


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

The following table shows a summary of the Company’s service-based and market-based awards activity for the year ended December 31, 2021:


	Number of Awards			Weighted Average
	Service‑Based	Market-Based	Market-Based	Grant Date
	RSUs	RSUs	PSUs	Fair Value
Nonvested awards, December 31, 2020	89,021	189,900	-	$	10.03
Granted	503,393	-	232,150		26.15
Vested	(63,040)	(142,425)	-		10.11
Forfeited	(13,118)	-	-		24.39
Nonvested awards, December 31, 2021	516,256	47,475	232,150	$	24.67

During January 2022, certain executives received 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 year ended December 31, 2021, which was recorded to accrued liabilities and other in the Company’s consolidated balance sheets as of December 31, 2021.

The Company recognized $11 million and $1 million in stock-based compensation expense during the year ended December 31, 2021 and the 2020 Successor Period, respectively. As of December 31, 2021, there was $11 million of unrecognized compensation cost related to unvested awards granted under the 2020 Equity Plan. That cost is expected to be recognized over a weighted average period of 2.3 years.

For the year ended December 31, 2021, the total fair value of the Company’s service-based and market-based awards vested was $9 million.

Predecessor Awards under Predecessor Equity Plan

During the eight months ended August 31, 2020 and the year ended December 31, 2019, 53,198 and 467,055 shares, respectively, of share-settled service-based RSAs and RSUs were granted to executive officers and directors. The Company determined compensation expense for these awards using their fair value at the grant date, which was based on the closing bid price of the Company’s common stock on such date. The weighted average grant date fair value of these service-based RSAs and RSUs was $4.94 per share and $24.65 per share for the eight months ended August 31, 2020 and the year ended December 31, 2019, respectively. On March 31, 2020, all of the RSAs issued to executive officers in 2020 were forfeited and concurrently replaced with cash incentives. Refer to “2020 Compensation Adjustments” below for more information.

During the eight months ended August 31, 2020 and the year ended December 31, 2019, 1,616,504 and 774,665 shares, respectively, of cash-settled, service-based RSUs were granted to executive officers and employees. The Company determined compensation expense for these awards using the fair value at the end of each reporting period, which was based on the closing bid price of the Company’s common stock on such date. On March 31, 2020, all of the RSUs issued to executive officers in 2020 were forfeited and concurrently replaced with cash incentives. Refer to “2020 Compensation Adjustments” below for more information.

During the eight months ended August 31, 2020 and the year ended December 31, 2019, 1,665,153 and 347,493 shares, respectively, of PSAs and PSUs subject to certain market-based vesting criteria were granted to executive officers. These market-based awards were to cliff vest on the third anniversary of the grant date, however, on March 31, 2020, all of the PSAs and PSUs issued to executive officers in 2020 were forfeited and concurrently replaced with cash incentives. Refer to “2020 Compensation Adjustments” below for more information.

The grant date fair value of these PSAs and PSUs was estimated using the Monte Carlo Model. Expected volatility was calculated based on the historical volatility and implied volatility of Whiting’s common stock, and the risk-free interest rate was based on U.S. Treasury yield curve rates with maturities consistent with the three-year vesting period. The key assumptions used in valuing these market-based awards were as follows:


	2020	2019
Number of simulations	2,500,000	2,500,000
Expected volatility	76.52%	72.95%
Risk-free interest rate	1.51%	2.60%
Dividend yield	—	—

The weighted average grant date fair value of the market-based awards that were to be settled in shares as determined by the Monte Carlo valuation model was $4.31 per share and $25.97 per share in the 2020 Predecessor Period and 2019, respectively.

For the eight months ended August 31, 2020 and the year ended December 31, 2019, the total fair value of the Company’s service-based and market-based awards vested was $1 million and $12 million, respectively.

Total stock-based compensation expense for Predecessor restricted stock awards for the eight months ended August 31, 2020 and the year ended December 31, 2019 was $3 million and $8 million, respectively. As a result of the implementation of the Plan, the Company accelerated $4 million of expense related to unvested awards, which was recorded to reorganization items, net in the consolidated statements of operations during the 2020 Predecessor Period. Refer to the “Fresh Start Accounting” footnote for more information.

2020 Compensation Adjustments. All of the RSAs, RSUs, PSAs and PSUs granted to executive officers in 2020 under the Predecessor Equity Plan were forfeited on March 31, 2020 and were replaced with cash retention incentives. The cash retention incentives were subject to a service period and were subject to claw back provisions if an executive officer terminated employment for any reason other than a qualifying termination prior to the earlier of (i) the effective date of a plan of reorganization approved under chapter 11 of the Bankruptcy Code or (ii) March 30, 2021. The transactions were considered concurrent replacements of the stock compensation awards previously issued. As such, the $12 million fair value of the awards, consisting of the after-tax value of the cash incentives, was capitalized and amortized over the period from the Petition Date to the Emergence Date, which amortization is included in general and administrative expenses in the consolidated statements of operations for the 2020 Predecessor Period. The difference between the cash and after-tax value of the cash retention incentives of approximately $9 million, which was not subject to the claw back provisions contained within the agreements, was expensed to general and administrative expenses in the 2020 Predecessor Period.

14. INCOME TAXES

Income tax expense (benefit) consists of the following (in thousands):


	Successor				Predecessor
	Year Ended December 31, 2021		Four Months Ended December 31, 2020		Eight Months Ended August 31, 2020		Year Ended December 31, 2019
Current Income Tax Expense (Benefit)
Federal	$	878	$	-	$	(1,028)	$	-
State		32		-		-		-
Foreign		-		2,463		3,746		-
Total current income tax expense		910		2,463		2,718		-
Deferred Income Tax Expense (Benefit)
Federal		-		-		-		2,140
State		-		-		-		(3,513)
Foreign		-		(14,501)		(59,092)		73,593
Total deferred income tax expense (benefit)		-		(14,501)		(59,092)		72,220
Total	$	910	$	(12,038)	$	(56,374)	$	72,220

Income tax expense (benefit) differed from amounts that would result from applying the U.S. statutory income tax rate of 21% to income before income taxes as follows (in thousands):


	Successor				Predecessor
	Year Ended December 31, 2021		Four Months Ended December 31, 2020		Eight Months Ended August 31, 2020		Year Ended December 31, 2019
Federal and State Tax Expense (Benefit)
U.S. statutory income tax expense (benefit)	$	90,051	$	5,676	$	(844,471)	$	(35,479)
State income taxes, net of federal benefit		13,883		724		(148,305)		(8,288)
Executive compensation		1,757		(765)		2,182		-
Reorganization costs		-		-		10,584		-
IRC Section 382 and other restructuring adjustments		(4,824)		549,323		5,433		-
State net operating loss adjustments due to subsidiary restructuring		-		25,864		-		-
Market-based equity awards		(1,442)		415		441		910
Other		(3,032)		(1,105)		(4,040)		1,812
Valuation allowance		(95,483)		(580,132)		977,148		39,672
Total federal and state tax expense (benefit)		910		-		(1,028)		(1,373)
Foreign Tax Expense (Benefit)
Foreign tax expense (benefit)		-		2,463		3,746		(147)
ASC 740-30-25-19 outside basis difference recognition		-		(14,501)		(59,092)		73,740
Total foreign tax expense (benefit)		-		(12,038)		(55,346)		73,593
Total	$	910	$	(12,038)	$	(56,374)	$	72,220

The principal components of the Company’s deferred income tax assets and liabilities at December 31, 2021 and 2020 were as follows (in thousands):


	Successor
	December 31,		December 31,
	2021		2020
Deferred Income Tax Assets
Net operating loss carryforward	$	301,532	$	248,835
Derivative instruments		59,678		14,119
Asset retirement obligations		24,548		23,390
Restricted stock compensation		1,988		123
EOR credit carryforwards		7,946		7,946
Lease obligations		4,681		9,409
Oil and gas properties		93,896		291,698
Other		1,459		5,011
Total deferred income tax assets		495,728		600,531
Less valuation allowance		(489,812)		(585,296)
Net deferred income tax assets		5,916		15,235
Deferred Income Tax Liabilities
Trust distributions		1,439		6,061
Lease assets		4,477		9,174
Total deferred income tax liabilities		5,916		15,235
Total net deferred income tax liabilities	$	-	$	-

Internal Revenue Code (“IRC”) Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. As a result of the chapter 11 reorganization and related transactions, the Successor experienced an ownership change within the meaning of IRC Section 382 on the Emergence Date. This ownership change subjected certain of the Company’s tax attributes to an IRC Section 382 limitation. The ownership changes and resulting annual limitation will result in the expiration of net operating loss carryforwards (“NOLs”) or other tax attributes otherwise available, with a corresponding decrease in the Company’s valuation allowance.

As of December 31, 2021, the Company had federal NOL carryforwards of $3.3 billion, which are subject to IRC Section 382 limitations due to the Company incurring a Section 382 ownership event at the time of emergence from the Chapter 11 Cases. The Company currently estimates that approximately $2.2 billion of these federal NOLs will expire before they are able to be used. The determination of the state NOL carryforwards is dependent upon apportionment percentages and state laws that can change from year to year and that can thereby impact the amount of such carryforwards. If unutilized, the majority of the federal and state NOLs will expire between 2022 and 2037. Any federal NOLs generated in 2018 or subsequent do not expire.

EOR credits are a credit against federal income taxes for certain costs related to extracting high-cost oil, utilizing certain prescribed enhanced tertiary recovery methods. As of December 31, 2021, the Company had recognized aggregate EOR credits of $8 million. As a result of a IRC Section 382 limitation in July 2016, the Company recorded a full valuation allowance on these credits.

In assessing the realizability of deferred tax assets (“DTAs”), management considers whether it is more likely than not that some portion, or all, of the Company’s DTAs will not be realized. In making such determination, the Company considers all available positive and negative evidence, including 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. At December 31, 2021, the Company had a valuation allowance totaling $490 million.

During the fourth quarter of 2019, the Company determined it no longer had the ability to indefinitely prevent the reversal of the outside basis difference related to Whiting Canadian Holding Company ULC, Whiting’s wholly owned subsidiary, which at that time owned a portion of Whiting’s U.S. assets obtained through the acquisition of Kodiak Oil and Gas Corporation during 2014. Accordingly, the Company revised its assessment related to noncurrent Canadian deferred taxes pursuant to ASC 740-30-25-17 and recognized a $74 million deferred tax liability as well as the same amount of deferred income tax expense as of and for the year ended December 31, 2019 (Predecessor) associated with the outside basis difference related to Whiting Canadian Holding Company ULC. During the third quarter of 2020, the Company partially executed a legal entity restructuring plan to reduce administrative expenses and burden with a simplified corporate structure. The final steps of the legal entity restructuring were completed during the fourth quarter of 2020, ultimately resulting with Whiting Oil & Gas, under its parent Whiting Petroleum Corporation, holding all of the Company’s oil and gas operations. As a result of impacts from fresh start accounting, the Company reduced its deferred tax liability for its outside basis difference related to Whiting Canadian Holding Company ULC and recorded a tax benefit of $55 million during the 2020 Predecessor Period. As a result

of the restructuring, the Company reduced its deferred tax liability and recorded a tax benefit of $12 million during the 2020 Successor Period. The Company paid Canadian cash taxes of $6 million during the fourth quarter of 2020.

As of December 31, 2021 and 2020, the Company did not have any uncertain tax positions. For the periods presented, the Company did not recognize any interest or penalties with respect to unrecognized tax benefits, nor did the Company have any such interest or penalties previously accrued.

The Company files income tax returns in the U.S. federal jurisdiction and in various states, each with varying statutes of limitations. The 2018 through 2020 tax years generally remain subject to examination by federal and state tax authorities. Additionally, the Company has Canadian income tax filings which remain subject to examination by the related tax authorities for the 2017 through 2020 tax years.

15. EARNINGS PER SHARE

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


	Successor				Predecessor
	Year Ended December 31, 2021		Four Months Ended December 31, 2020		Eight Months Ended August 31, 2020		Year Ended December 31, 2019
Basic Earnings (Loss) Per Share
Net income (loss)	$	427,906	$	39,073	$	(3,965,461)	$	(241,166)
Weighted average shares outstanding, basic		39,006		38,080		91,423		91,285
Earnings (loss) per common share, basic	$	10.97	$	1.03	$	(43.37)	$	(2.64)

Diluted Earnings (Loss) Per Share
Net income (loss)	$	427,906	$	39,073	$	(3,965,461)	$	(241,166)
Weighted average shares outstanding, basic		39,006		38,080		91,423		91,285
Service-based awards and market-based awards		686		39		-		-
Weighted average shares outstanding, diluted		39,692		38,119		91,423		91,285
Earnings (loss) per common share, diluted	$	10.78	$	1.03	$	(43.37)	$	(2.64)

Successor

During 2021 and the 2020 Successor Period, the diluted earnings per share calculations exclude the effect of common shares that may be issued pursuant to the Series A Warrants and Series B Warrants, as such Warrants were out-of-the-money as of December 31, 2021 and 2020. During 2021, the diluted earnings per share calculation also excludes the effect of 47,475 shares of market-based awards that did not meet the market-based vesting criteria as of December 31, 2021 and 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 December 31, 2021. During the 2020 Successor Period, the diluted earnings per share calculation also excludes the effect of 189,900 shares of market-based awards that did not meet the market-based vesting criteria as of December 31, 2020 and 3,021,304 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 December 31, 2020. However, subsequent to December 31, 2020 the Company issued 948,897 of such contingently issuable shares. The basic weighted average shares outstanding calculation for the 2020 Successor Period includes 48,897 of these shares as all necessary conditions to be included in the calculation had been satisfied during the period. Refer to the “Shareholders’ Equity” footnote for more information on this share issuance.

Predecessor

For the eight months ended August 31, 2020, the Company had a net loss and therefore the diluted earnings per share calculation excludes the antidilutive effect of 314,896 shares of service-based awards. In addition, the diluted earnings per share calculation for the eight months ended August 31, 2020 excludes the effect of 29,465 common shares for stock options that were out of the money as of August 31, 2020. All outstanding stock options were canceled upon emergence from bankruptcy on the Emergence Date.

For the year ended December 31, 2019 the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes the anti-dilutive effect of 344,671 shares of service-based awards and 3,511 shares of market-based awards. In addition, the diluted earnings per share calculation for the year ended December 31, 2019 excludes the effect of 45,588 common shares for stock options that were out of the money as of December 31, 2019. All outstanding stock options were canceled upon emergence from bankruptcy on the Emergence Date.

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

The Company had the option to settle conversions of the Convertible Senior Notes with cash, shares of common stock or any combination thereof. As the conversion value of the Convertible Senior Notes did not exceed the principal amount of the notes for any time during the conversion period ending April 1, 2020, there was no impact to diluted earnings per share or the related disclosures for any of the periods presented.

16. COMMITMENTS AND CONTINGENCIES

Pipeline Transportation Agreements—The Company has an agreement through January 2022 with a third-party to facilitate the delivery of its produced oil, gas and NGLs to market. As of December 31, 2021, the Company estimated the minimum future commitments under this transportation agreement to be approximately $0.4 million through January 2022.

Previously, the Company had an agreement with a third-party to facilitate the delivery of its produced oil, gas and NGLs to market for production related to its Redtail field. Under this contract, the Company had committed to pay fixed monthly reservation fees on dedicated pipelines for natural gas and NGL transportation capacity, plus additional variable charges based on actual transportation volumes. As a result of the divestiture of all the Company’s interests in its Redtail field in September 2021, this contract was transferred to the buyer. Refer to the “Acquisitions and Divestitures” footnote for more information.

During 2021, the 2020 Successor Period, the 2020 Predecessor Period and the year ended December 31, 2019, the cost of transportation of crude oil, natural gas and NGLs under these contracts amounted to $4 million, $1 million, $1 million and $2 million, respectively.

Delivery Commitments—The Company has one physical delivery contract which requires the Company to deliver fixed volumes of crude oil. This delivery commitment became effective in April 2020 and is tied to crude oil production from Whiting’s Sanish field in Mountrail County, North Dakota. Under the terms of the agreement, Whiting has committed to deliver 15 MBbl/d for a term of 4.1 years. The Company believes its production and reserves at the Sanish field are sufficient to fulfill this delivery commitment, and therefore expects to avoid any payments for deficiencies under this contract.

The Company has another physical delivery contract effective through June 30, 2024 which is tied to oil production in North Dakota and Montana. Under the terms of the contract, the Company is required to deliver 5 MBbl/d during the delivery term. If the Company fails to deliver any of the committed volumes during the term of the contract, the Company will be in immediate default under the contract and will be required to pay liquidated damages for the remaining term of the contract. The Company believes its production and reserves are sufficient to fulfill this delivery commitment, and therefore expects to avoid any payments for deficiencies under this contract.

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. Refer to the “Chapter 11 Emergence” footnote for more information. 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 Successor’s common stock or other remedy or agreement under and pursuant to the Plan.

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 Successor’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 December 31, 2021, 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 Successor 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 the Successor’s 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 Successor’s common stock. The ultimate amount of either a cash payment or number of shares of Successor 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.

During 2020, the Company was involved in litigation related to a payment arrangement with a third party. In June 2020, the Company and the third party reached a settlement agreement resulting in the Company paying the third party a settlement amount of $14 million. The Company recognized $11 million in general and administrative expenses in the consolidated statements of operations for the year ended December 31, 2019 (Predecessor). The Company recorded $3 million of additional general and administrative expense in the consolidated statements of operations during the 2020 Predecessor Period upon settling this litigation. Upon settlement, the Company agreed to indemnify a party involved in the litigation for any further claims resulting from these matters up to $25 million. This indemnity will terminate on the date on which the statute of limitations for the relevant claims expires. The Company does not expect to pay additional amounts to this party as a result of this indemnity and thus has not recorded any liability related to the indemnity as of December 31, 2021 (Successor).

17. COMPANY RESTRUCTURINGS

During September 2020 and August 2019, the Company executed workforce reductions as part of an organizational redesign and cost reduction strategy to better align its business with the current operating environment and drive long-term value. For each of these workforce reductions, the Company incurred $8 million in net restructuring costs associated with one-time employee termination benefits. These charges were recorded to general and administrative expenses during the relevant periods in the consolidated statements of operations.

18. SUBSEQUENT EVENTS

Williston Basin Acquisition—On February 1, 2022, the Company entered into a purchase and sale agreement to acquire additional interests in oil and gas properties located in Mountrail County, North Dakota for an aggregate purchase price of $240 million (before closing adjustments). Upon executing the agreement, the Company tendered a $12 million deposit which will be held in escrow until closing of the transaction. The transaction is anticipated to close in March 2022 and the Company plans to account for the transaction using the acquisition method of accounting.

Dividends—On February 8, 2022, the Company announced an inaugural quarterly dividend of $0.25 per share with the first dividend to be paid on March 15, 2022 to shareholders of record as of February 21, 2022.

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (AS RESTATED)

Oil and Gas Producing Activities

Net capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):


	Successor
	December 31,		December 31,
	2021		2020
Proved oil and gas properties	$	2,034,533	$	1,701,163
Unproved oil and gas properties		240,375		111,438
Accumulated depletion		(248,298)		(71,064)
Oil and gas properties, net	$	2,026,610	$	1,741,537

The Company’s oil and gas activities for the periods presented were entirely within the United States. Costs incurred in oil and gas producing activities were as follows (in thousands):


	Successor				Predecessor
	Year Ended December 31, 2021		Four Months Ended December 31, 2020		Eight Months Ended August 31, 2020		Year Ended December 31, 2019
Development ⁽¹⁾	$	278,370	$	(6,773)	$	241,795	$	763,395
Proved property acquisition		197,104		4		146		-
Unproved property acquisition		104,198		163		346		6,281
Exploration		4,074		4,632		22,945		36,872
Total	$	583,746	$	(1,974)	$	265,232	$	806,548

(1)

Development costs include non-cash upward adjustments to oil and gas properties of $27 million and $57 million for 2021 and the 2020 Predecessor Period, respectively, which related to estimated future plugging and abandonment costs of the Company’s oil and gas wells. Additionally, the 2020 Successor Period and the year ended December 31, 2019 (Predecessor) include non-cash downward adjustments of $31 million and $9 million, respectively, which related to estimated future plugging and abandonment costs of the Company’s oil and gas wells.

Oil and Gas Reserve Quantities

For all years presented, the Company’s independent petroleum engineers independently estimated all of the proved reserve quantities included in this Annual Report on Form 10-K. In connection with the external petroleum engineers performing their independent reserve estimations, Whiting furnishes them with the following information for their use in their evaluation: (i) technical support data, (ii) technical analysis of geologic and engineering support information, (iii) economic and production data, (iv) the Company’s well ownership interests and (v) expected future development activity. The independent petroleum engineers, Netherland, Sewell & Associates, Inc., evaluated 100% of the Company’s estimated proved reserve quantities and their related pre-tax future net cash flows as of December 31, 2021. Proved reserve estimates included herein conform to the definitions prescribed by the SEC. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

As of December 31, 2021, all of the Company’s oil and gas reserves are attributable to properties within the United States. A summary of the Company’s changes in quantities of proved oil and gas reserves for the periods presented are as follows:


	Oil	NGLs	Natural Gas	Total
	(MBbl)	(MBbl)	(MMcf)	(MBOE)
Proved reserves
Balance—January 1, 2019 (Predecessor)	286,964	111,284	731,084	520,095
Extensions and discoveries	20,103	6,056	46,808	33,960
Purchases of minerals in place	(3,175)	(855)	(5,253)	(4,906)
Production	(29,811)	(7,596)	(50,483)	(45,820)
Revisions to previous estimates	(5,828)	(15,048)	17,886	(17,894)
Balance—December 31, 2019 (Predecessor)	268,253	93,841	740,042	485,435
Extensions and discoveries	12,616	2,627	17,306	18,127
Sales of minerals in place	(957)	(121)	(1,082)	(1,258)
Production	(22,130)	(6,626)	(44,007)	(36,091)
Revisions to previous estimates	(94,513)	(43,354)	(408,642)	(205,974)
Balance—December 31, 2020 (Successor)	163,269	46,367	303,617	260,239
Extensions and discoveries	12,720	3,898	22,001	20,285
Purchases of minerals in place	10,007	2,702	18,861	15,851
Sales of minerals in place	(6,434)	(1,551)	(16,113)	(10,670)
Production	(19,316)	(7,218)	(41,964)	(33,528)
Revisions to previous estimates	28,358	22,167	139,647	73,800
Balance—December 31, 2021 (Successor)	188,604	66,365	426,049	325,977

Proved developed reserves
December 31, 2018 (Predecessor)	194,869	82,725	529,154	365,786
December 31, 2019 (Predecessor)	190,725	72,102	576,213	358,863
December 31, 2020 (Successor)	128,227	37,961	251,316	208,074
December 31, 2021 (Successor)	148,317	55,006	351,914	261,975

Proved undeveloped reserves
December 31, 2018 (Predecessor)	92,095	28,559	201,930	154,309
December 31, 2019 (Predecessor)	77,528	21,739	163,829	126,572
December 31, 2020 (Successor)	35,042	8,406	52,301	52,165
December 31, 2021 (Successor)	40,287	11,359	74,135	64,002

Notable changes in proved reserves for the year ended December 31, 2021 included the following:

●	Extensions and discoveries. In 2021, total extensions and discoveries of 20.3 MMBOE were primarily attributable to successful drilling in the Williston Basin. New wells drilled in this area as well as the PUD locations added as a result of drilling increased the Company’s proved reserves.

●

Purchases of minerals in place. Purchases of minerals in place totaled 15.9 MMBOE during 2021 and were primarily attributable to two acquisitions in the Williston Basin as further described in the “Acquisitions and Divestitures” footnote in the notes to the consolidated financial statements within Item 8 of this Annual Report on Form 10-K.

●

Sales of minerals in place. Sales of minerals in place totaled 10.7 MMBOE during 2021 and were primarily attributable to the disposition of all of the Company’s interests in producing assets and undeveloped acreage of the Company’s Redtail field located in the Denver-Julesburg Basin of Weld County, Colorado as further described in the “Acquisitions and Divestitures” footnote in the notes to the consolidated financial statements within Item 8 of this Annual Report on Form 10-K.

●

Revisions to previous estimates. In 2021, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 73.8 MMBOE. Included in these revisions were (i) 70.1 MMBOE of upward adjustments resulting from higher crude oil, NGL and natural gas prices incorporated into the Company’s reserve estimates at December 31, 2021 as compared to December 31, 2020, (ii) 12.8 MMBOE of upward adjustments primarily attributable to reservoir and engineering analysis and well performance across the Company’s North Dakota and Montana assets, and (iii) 0.8 MMBOE of upward adjustments attributable to narrower differentials and stronger NGL yields. These upward adjustments were partially offset by 9.9 MMBOE of downward adjustments due to increased operating expenses.

Notable changes in proved reserves for the year ended December 31, 2020 included the following:

●

Extensions and discoveries. In 2020, total extensions and discoveries of 18.1 MMBOE were primarily attributable to successful drilling in the Williston Basin. Both the new wells drilled in this area as well as the PUD locations added as a result of drilling increased the Company’s proved reserves.

●

Sales of minerals in place. Sales of minerals in place totaled 1.3 MMBOE during 2020 and were primarily attributable to the disposition of certain non-operated properties in North Dakota as further described in the “Acquisitions and Divestitures” footnote in the notes to the consolidated financial statements within Item 8 of this Annual Report on Form 10-K.

●

Revisions to previous estimates. In 2020, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 206.0 MMBOE. Included in these revisions were 41.3 MMBOE of proved undeveloped reserve reductions due to changes in the Company’s development plan. Of this 41.3 MMBOE, 34.8 MMBOE represents proved undeveloped reserves no longer expected to be developed within five years from their initial recognition and 6.5 MMBOE represents other development timing changes. As a result of the significant declines in commodity pricing the Company experienced in 2020 as well as its chapter 11 reorganization, the Company has moved toward a more disciplined capital development program focused on the highest-return projects and the generation of free cash flow, which resulted in a change in the timing of the Company’s development plans related to PUD reserves in certain areas. These revisions do not represent the elimination of recoverable hydrocarbons physically in place, as they may be developed in the future. In addition, there were 114.3 MMBOE of downward adjustments primarily attributable to reservoir and engineering analysis and well performance across Whiting’s assets in North Dakota, Montana and Colorado assets including: (i) 64.7 MMBOE of performance adjustments related to changes in gas-oil ratio estimates and oil estimates based on 2020 well performance data and subsequent reservoir and engineering analysis, (ii) 43.7 MMBOE of changes to lease operating cost estimates related to a change in the Company’s process for modeling certain operating costs and higher operating costs experienced in 2020, and (iii) 5.9 MMBOE of other various revisions. Finally, there were 50.5 MMBOE of negative adjustments resulting from lower crude oil, NGL and natural gas prices incorporated into the Company’s reserve estimates at December 31, 2020 as compared to December 31, 2019.

Notable changes in proved reserves for the year ended December 31, 2019 included the following:

●

Extensions and discoveries. In 2019, total extensions and discoveries of 34.0 MMBOE were primarily attributable to successful drilling in the Williston Basin. Both the new wells drilled in this area as well as the PUD locations added as a result of drilling increased the Company’s proved reserves.

●

Sales of minerals in place. Sales of minerals in place totaled 4.9 MMBOE during 2019 and were primarily attributable to the disposition of certain non-operated properties in North Dakota as further described in the “Acquisitions and Divestitures” footnote in the notes to the consolidated financial statements within Item 8 of this Annual Report on Form 10-K.

●

Revisions to previous estimates. In 2019, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 17.9 MMBOE. Included in this change were upward revisions of 48.0 MMBOE to proved undeveloped reserves primarily located in the Williston Basin in locations where the Company has significant development activity and past drilling success. Offsetting these upward revisions were: (i) 32.9 MMBOE of downward adjustments caused by lower crude oil, NGL and natural gas prices incorporated into the Company’s reserve estimates at December 31, 2019 as compared to December 31, 2018, (ii) 19.3 MMBOE of downward adjustments primarily attributable to reservoir analysis and well performance across the Company’s assets in North Dakota, Montana and Colorado and (iii) 13.7 MMBOE of proved undeveloped reserves no longer expected to be developed within five years from their initial recognition.

Restatement of 2019 and 2020 Standardized Measure of Discounted Future Net Cash Flows

The Company has corrected certain errors in the unaudited Standardized Measure calculations previously reported in the supplemental disclosures to the Company’s financial statements for the years ended December 31, 2020 and 2019. The Company has restated the line item for future development costs to include estimated costs related to property abandonment in accordance with FASB ASC 932-235-50-30, 50-31 and 55-6. This change also impacts the calculation of future income taxes and discount for each respective period. The tables below set forth the effect of these errors on the Standardized Measure calculations previously disclosed in the supplemental disclosures to the Company’s financial statements for the years ended December 31, 2020 and 2019 (in thousands).


	December 31, 2020						December 31, 2019
	As Previously Reported		Change		As Restated		As Previously Reported		Change		As Restated
Future cash flows	$	5,628,620	$	-	$	5,628,620	$	14,700,974	$	-	$	14,700,974
Future production costs		(3,074,138)		-		(3,074,138)		(6,983,878)		-		(6,983,878)
Future development costs		(508,969)		(303,385)		(812,354)		(1,451,487)		(317,650)		(1,769,137)
Future income tax expense		(13,879)		13,879		-		(88,960)		10,680		(78,280)
Future net cash flows		2,031,634		(289,506)		1,742,128		6,176,649		(306,970)		5,869,679
10% annual discount for estimated timing of cash flows		(840,855)		170,704		(670,151)		(2,474,320)		253,375		(2,220,945)
Standardized measure of discounted future net cash flows	$	1,190,779	$	(118,802)	$	1,071,977	$	3,702,329	$	(53,595)	$	3,648,734


	Year Ended December 31, 2020						Year Ended December 31, 2019
	As Previously Reported		Change		As Restated		As Previously Reported		Change		As Restated
Beginning of year	$	3,702,329	$	(53,595)	$	3,648,734	$	5,206,110	$	(53,361)	$	5,152,749
Sale of oil and gas produced, net of production costs		(404,495)		-		(404,495)		(1,063,167)		-		(1,063,167)
Sales of minerals in place		(8,539)		-		(8,539)		(52,456)		-		(52,456)
Net changes in prices and production costs		(2,061,696)		-		(2,061,696)		(1,681,530)		-		(1,681,530)
Extensions, discoveries and improved recoveries		123,073		-		123,073		234,782		-		234,782
Previously estimated development costs incurred during the period		197,960		-		197,960		455,236		-		455,236
Changes in estimated future development costs		632,468		(66,268)		566,200		(12,964)		20,910		7,946
Purchases of minerals in place		-		-		-		-		-		-
Revisions of previous quantity estimates		(1,398,437)		-		(1,398,437)		(191,329)		-		(191,329)
Net change in income taxes		37,883		6,420		44,303		287,036		(15,808)		271,228
Accretion of discount		370,233		(5,359)		364,874		520,611		(5,336)		515,275
End of year	$	1,190,779	$	(118,802)	$	1,071,977	$	3,702,329	$	(53,595)	$	3,648,734

The Company has assessed the materiality of these errors in accordance with the guidelines provided by the SEC under Staff Accounting Bulletin Topic 1M: Materiality and Staff Accounting Bulletin Topic 1N: Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in the Current Year Financial Statements. Based on this analysis, the Company has determined that these errors were material to each of the years ended December 31, 2020 and 2019.

Standardized Measure of Discounted Future Net Cash Flows

The Standardized Measure relating to proved oil and gas reserves and changes in the Standardized Measure relating to proved oil and natural gas reserves were prepared in accordance with the provisions of FASB ASC Topic 932, Extractive Activities—Oil and Gas. Future cash inflows as of December 31, 2021, 2020 and 2019 were computed by applying average fiscal-year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period ended December 31, 2021, 2020 and 2019, respectively) to estimated future production. Future production and development costs (which include future costs related to property abandonment) are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on year-end costs and assuming the continuation of existing economic conditions.

Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the Standardized Measure. This calculation does not necessarily result in an estimate of the fair value of the Company’s oil and gas properties.

The Standardized Measure relating to proved oil and natural gas reserves is as follows (in thousands):


	December 31,
	2021		2020 ⁽¹⁾		2019 ⁽¹⁾
Future cash flows	$	13,554,387	$	5,628,620	$	14,700,974
Future production costs		(5,040,334)		(3,074,138)		(6,983,878)
Future development costs		(864,049)		(812,354)		(1,769,137)
Future income tax expense		(1,241,224)		-		(78,280)
Future net cash flows		6,408,780		1,742,128		5,869,679
10% annual discount for estimated timing of cash flows		(2,729,490)		(670,151)		(2,220,945)
Standardized measure of discounted future net cash flows	$	3,679,290	$	1,071,977	$	3,648,734

(1)	As restated.

Future cash flows as shown above are reported without consideration for the effects of open hedge contracts at each period end. If the effects of hedging transactions were included in the computation, then undiscounted future cash inflows would have decreased by $151 million in 2021 and increased by $34 million in 2020, respectively. The effects of hedging transactions had no significant impact on undiscounted future cash inflows in 2019.

The changes in the Standardized Measure relating to proved oil and natural gas reserves are as follows (in thousands):


	Year Ended December 31,
	2021		2020 ⁽¹⁾		2019 ⁽¹⁾
Beginning of year	$	1,071,977	$	3,648,734	$	5,152,749
Sale of oil and gas produced, net of production costs		(1,128,837)		(404,495)		(1,063,167)
Sales of minerals in place		(150,660)		(8,539)		(52,456)
Net changes in prices and production costs		2,877,747		(2,061,696)		(1,681,530)
Extensions, discoveries and improved recoveries		286,422		123,073		234,782
Previously estimated development costs incurred during the period		163,740		197,960		455,236
Changes in estimated future development costs		(112,230)		566,200		7,946
Purchases of minerals in place		223,819		-		-
Revisions of previous quantity estimates		1,042,079		(1,398,437)		(191,329)
Net change in income taxes		(701,965)		44,303		271,228
Accretion of discount		107,198		364,874		515,275
End of year	$	3,679,290	$	1,071,977	$	3,648,734

(1)	As restated.

Future net revenues included in the Standardized Measure relating to proved oil and natural gas reserves incorporate calculated weighted average sales prices (inclusive of adjustments for quality and location) in effect at December 31, 2021, 2020 and 2019 as follows:


	Successor				Predecessor
	2021		2020		2019
Oil (per Bbl)	$	61.94	$	33.07	$	50.89
NGLs (per Bbl)	$	16.99	$	5.10	$	8.72
Natural Gas (per Mcf)	$	1.75	$	(0.03)	$	0.31

******

Item 9A. 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 President and 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 the end of the year ended December 31, 2021. Based upon their evaluation of these disclosure controls and procedures, the President and Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures were effective as of December 31, 2021 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.

As a result of the correction of certain errors in the Supplemental Disclosures About Oil and Gas Producing Activities (Unaudited) (as Restated) as discussed in Item 8 of this Amendment No. 1 on Form 10-K/A, our management reevaluated, with the participation of our President and Chief Executive Officer and our Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the year ended December 31, 2020 and the President and Chief Executive Officer and the Chief Financial Officer concluded that such disclosure controls and procedures were not effective as of December 31, 2020. This does not affect our conclusion that our disclosure controls and procedures as of December 31, 2021 were effective as set forth in the immediately preceding paragraph.

Management’s Annual Report on Internal Control over Financial Reporting. The management of Whiting Petroleum Corporation and subsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of the inherent limitations of internal control over financial reporting, misstatements may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2021 using the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, our management believes that, as of December 31, 2021, our internal control over financial reporting was effective based on those criteria.

The effectiveness of our internal control over financial reporting as of December 31, 2021 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein on the following page.

Changes in internal control over financial reporting. There was no change in our internal control over financial reporting that occurred during the quarter ended December 31, 2021 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Whiting Petroleum Corporation

Denver, Colorado

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Whiting Petroleum Corporation and subsidiaries (the “Company”) as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2021, of the Company and our report dated February 23, 2022, expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Deloitte & Touche LLP

Denver, Colorado

February 23, 2022

PART IV

Item 15. Exhibits and Financial Statement Schedules


(a)	1. Financial statements – Refer to the Index to Consolidated Financial Statements included in Item 8 of this Form 10-K/A for a list of all financial statements filed as part of this report.

	2. Financial statement schedules – All schedules are omitted since the required information is not present, or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements or the notes thereto.

	3. Exhibits – The exhibits listed in the accompanying index to exhibits are filed as part of this Annual Report on Form 10-K/A.

(b)	Exhibits

	The exhibits listed in the accompanying exhibit index are filed (except where otherwise indicated) as part of this report.

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)]
(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)].
(4.1)		Description of Securities [Incorporated by reference to Exhibit 4.1 to Whiting Petroleum Corporation’s Annual Report on Form 10-K filed on February 23, 2022 (File No. 001-31899)].
(10.1)		Credit Agreement dated as of September 1, 2020, by and among Whiting Petroleum Corporation, as parent guarantor, Whiting Oil and Gas Corporation, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders and other parties party thereto [Incorporated by reference to Exhibit 10.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on September 1, 2020 (File No. 001-31899)].
(10.2)		First Amendment to Credit Agreement, dated as of June 7, 2021, among Whiting Oil and Gas Corporation as Borrower, its Parent Guarantor Whiting Petroleum Corporation, JPMorgan Chase Bank, N.A. as Administrative Agent and the lenders signatory thereto [Incorporated by reference to Exhibit 10.1 to Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q filed on August 4, 2021 (File No. 001-31899)].
(10.3)		Second Amendment and Waiver to Credit Agreement, dated as of September 15, 2021, among Whiting Oil and Gas Corporation as Borrower, its Parent Guarantor Whiting Petroleum Corporation, JPMorgan Chase Bank, N.A. as Administrative Agent and the lenders signatory thereto [Incorporated by reference to Exhibit 10.2 to Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q filed on November 3, 2021 (File No. 001-31899)].
(10.4)*		Form of Indemnification Agreement for directors and officers of Whiting Petroleum Corporation [Incorporated by reference to Exhibit 10.1 to Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 (File No. 001-31899)].
(10.5)		Specimen Common Stock Certificate [Incorporated by reference to Exhibit 4 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on September 1, 2020 (File No. 001-31899)].
(10.6)		Series A Warrant Agreement dated as of September 1, 2020, by and among Whiting Petroleum Corporation, Computershare Inc. and Computershare Trust Company, N.A. [Incorporated by reference to Exhibit 10.2 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on September 1, 2020 (File No. 001-31899)].
(10.7)		Series B Warrant Agreement dated as of September 1, 2020, by and among Whiting Petroleum Corporation, Computershare Inc. and Computershare Trust Company, N.A. [Incorporated by reference to Exhibit 10.3 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on September 1, 2020 (File No. 001-31899)].
(10.8)*		Executive Employment and Severance Agreement, dated February 2, 2021, by and between Whiting Petroleum Corporation and Lynn A. Peterson [Incorporated by reference to Exhibit 10.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on February 4, 2021 (File No. 001-31899)].
(10.9)*		Executive Employment and Severance Agreement, dated February 2, 2021, 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 February 4, 2021 (File No. 001-31899)].
(10.10)*		Executive Employment Agreement and Severance Agreement, dated February 2, 2021, by and between Whiting Petroleum Corporation and Charles J. Rimer [Incorporated by reference to Exhibit 10.3 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on February 4, 2021 (File No. 001-31899)].
(10.11)*		Form of Executive Employment Agreement and Severance Agreement for executive officers of Whiting Petroleum Corporation other than Lynn A. Peterson, James P. Henderson and Charles J. Rimer [Incorporated by reference to Exhibit 10.20 to Whiting Petroleum Corporation’s Annual Report on Form 10-K filed on February 24, 2021 (File No. 001-31899)].
(10.12)*		Whiting Petroleum Corporation 2020 Equity Incentive Plan [Incorporated by reference to Exhibit 10.4 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on September 1, 2020 (File No. 001-31899)].
(10.13)*		Form of Restricted Stock Unit Award Agreement (Officer Time Vesting - grants prior to February 2, 2021) pursuant to the Whiting Petroleum Corporation 2020 Equity Incentive Plan [Incorporated by reference to Exhibit 10.13 to Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q filed on November 5, 2020 (File No. 001-31899)].
(10.14)*		Form of Restricted Stock Unit Award Agreement (Officer Stock Price Performance Vesting) pursuant to the Whiting Petroleum Corporation 2020 Equity Incentive Plan [Incorporated by reference to Exhibit 10.14 to Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q filed on November 5, 2020 (File No. 001-31899)].
(10.15)*		Form of Restricted Stock Unit Award Agreement (Non-Employee Director) pursuant to the Whiting Petroleum Corporation 2020 Equity Incentive Plan [Incorporated by reference to Exhibit 10.15 to Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q filed on November 5, 2020 (File No. 001-31899)].


Exhibit
Number		Exhibit Description
(10.16)*		Form of Performance Stock Unit Award Agreement pursuant to the Whiting Petroleum Corporation 2020 Equity Incentive Plan [Incorporated by reference to Exhibit 10.4 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed February 4, 2021 (File No. 001-31899)].
(10.17)*		Form of Restricted Stock Award Agreement (Extended Vesting) pursuant to the Whiting Petroleum Corporation 2020 Equity Incentive Plan [Incorporated by reference to Exhibit 10.5 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed February 4, 2021 (File No. 001-31899)].
(10.18)*		Form of Restricted Stock Unit Award Agreement (Officer Time Vesting – grants on or after February 2, 2021) pursuant to the Whiting Petroleum Corporation 2020 Equity Incentive Plan [Incorporated by reference to Exhibit 10.6 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed February 4, 2021 (File No. 001-31899)].
(21)		Significant Subsidiaries of Whiting Petroleum Corporation [Incorporated by reference to Exhibit 21 to Whiting Petroleum Corporation’s Annual Report on Form 10-K filed on February 23, 2022 (File No. 001-31899)].
(23.1)**		Consent of Deloitte & Touche LLP.
(23.2)**		Consent of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers.
(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.
(99.1)		Report of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers relating to Total Proved Reserves, dated January 28, 2022 [Incorporated by reference to Exhibit 99.1 to Whiting Petroleum Corporation’s Annual Report on Form 10-K filed on February 23, 2022 (File No. 001-31899)].
(99.2)		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 Annual Report on Form 10-K/A for the year ended December 31, 2021 are filed herewith, formatted in iXBRL (Inline Extensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Statements of Equity, and (v) Notes to 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.

* A management contract or compensatory plan or arrangement.

** Updated with this Form 10-K/A.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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 4th day of March, 2022.

		WHITING PETROLEUM CORPORATION


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

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