UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended ~~September~~June 30, ~~2020~~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)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

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

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


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

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

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

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

Number of shares of the registrant’s common stock outstanding at ~~October 30, 2020: 38,051,210~~July 28, 2021: 39,117,950 shares.

Table of Contents

GLOSSARY OF CERTAIN DEFINITIONS

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

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

“ASC” Accounting Standards Codification.

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

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

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

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

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

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

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

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

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

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

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

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

“FASB” Financial Accounting Standards Board.

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

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

Table of Contents

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

“ISDA” International Swaps and Derivatives Association, Inc.

“lease operating expense” or “LOE” The expenses of lifting oil or gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets,

~~Table of Contents~~

maintenance, allocated overhead costs and other expenses incidental to production, but not including lease acquisition or drilling or completion expenses.

“LIBOR” London interbank offered rate.

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

“MBbl/d” One MBbl per day.

“MBOE” One thousand BOE.

“MBOE/d” One MBOE per day.

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

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

“MMBOE” One million BOE.

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

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

“MMcf/d” One MMcf per day.

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

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

“NGL” Natural gas liquid.

“NYMEX” The New York Mercantile Exchange.

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

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

“~~prospect”~~ ~~A property on which indications of oil or gas have been identified based on available seismic and geological information.~~

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

Table of Contents

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

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

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

~~Table of Contents~~

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

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

Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based, and

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

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“proved undeveloped reserves” or “PUDs” Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. Under no circumstances shall estimates of proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

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

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

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

Table of Contents

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

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

“SEC” The United States Securities and Exchange Commission.

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

~~Table of Contents~~

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

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

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements

WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (unaudited)

(in thousands, except share and per share data)


	Successor		Predecessor		Successor
	September 30,		December 31,		June 30,		December 31,
	2020		2019		2021		2020
ASSETS
Current assets:
Cash and cash equivalents	$	13,702	$	8,652
Restricted cash		13,233		-
Cash, cash equivalents and restricted cash					$	19,053	$	28,367
Accounts receivable trade, net		128,577		308,249		214,223		142,830
Prepaid expenses and other		22,056		14,082		14,740		19,224
Total current assets		177,568		330,983		248,016		190,421
Property and equipment:
Oil and gas properties, successful efforts method		1,829,472		12,812,007		1,929,550		1,812,601
Other property and equipment		72,856		178,689		68,443		74,064
Total property and equipment		1,902,328		12,990,696		1,997,993		1,886,665
Less accumulated depreciation, depletion and amortization		(19,447)		(5,735,239)		(177,084)		(73,869)
Total property and equipment, net		1,882,881		7,255,457		1,820,909		1,812,796
Other long-term assets		38,007		50,281		39,189		40,723
TOTAL ASSETS	$	2,098,456	$	7,636,721	$	2,108,114	$	2,043,940
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable trade	$	44,171	$	80,100	$	51,786	$	23,697
Revenues and royalties payable		146,767		202,010		191,248		151,196
Accrued capital expenditures		14,809		64,263		22,877		20,155
Accrued liabilities and other		63,987		85,007		35,143		42,007
Accrued lease operating expenses		23,757		38,262		28,642		23,457
Accrued interest		1,432		53,928
Taxes payable		16,985		26,844		16,712		11,997
Derivative liabilities						265,130		49,485
Total current liabilities		311,908		550,414		611,538		321,994
Long-term debt		400,328		2,799,885		115,000		360,000
Asset retirement obligations		119,262		131,208		93,276		91,864
Operating lease obligations		17,749		31,722		16,265		17,415
Deferred income taxes		-		73,593
Long-term derivative liabilities						89,354		9,750
Other long-term liabilities		19,723		24,928		12,909		14,113
Total liabilities		868,970		3,611,750		938,342		815,136
Commitments and contingencies
Equity:
Predecessor common stock, $0.001 par value, 225,000,000 shares authorized; 91,743,571 issued and 91,326,469 outstanding as of December 31, 2019		-		92
Successor common stock, $0.001 par value, 500,000,000 shares authorized; 38,051,210 issued and outstanding as of September 30, 2020		38		-
Successor common stock, $0.001 par value, 500,000,000 shares authorized; 39,091,073 issued and outstanding as June 30, 2021 and 38,051,125 issued and outstanding as of December 31, 2020						39		38
Additional paid-in capital		1,189,178		6,409,991		1,193,095		1,189,693
Accumulated earnings (deficit)		40,270		(2,385,112)		(23,362)		39,073
Total equity		1,229,486		4,024,971		1,169,772		1,228,804
TOTAL LIABILITIES AND EQUITY	$	2,098,456	$	7,636,721	$	2,108,114	$	2,043,940

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

Table of Contents

WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)

(in thousands, except per share data)


	Successor		Predecessor
	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020
OPERATING REVENUES
Oil, NGL and natural gas sales	$	349,983	$	91,600
Purchased gas sales		1,663		-
Total operating revenues		351,646		91,600
OPERATING EXPENSES
Lease operating expenses		64,182		53,242
Transportation, gathering, compression and other		7,443		9,044
Purchased gas expense		1,178		-
Production and ad valorem taxes		25,669		8,419
Depreciation, depletion and amortization		51,618		83,549
Exploration and impairment		2,047		421,156
General and administrative		11,995		28,136
Derivative loss, net		255,409		6,632
(Gain) loss on sale of properties		(10,110)		511
Amortization of deferred gain on sale		-		(1,908)
Total operating expenses		409,431		608,781
LOSS FROM OPERATIONS		(57,785)		(517,181)
OTHER INCOME (EXPENSE)
Interest expense		(3,981)		(16,425)
Other income		277		76
Reorganization items, net		-		(41,813)
Total other expense		(3,704)		(58,162)
LOSS BEFORE INCOME TAXES		(61,489)		(575,343)
INCOME TAX BENEFIT
Current		-		(1,028)
Total income tax benefit		-		(1,028)
NET LOSS	$	(61,489)	$	(574,315)
LOSS PER COMMON SHARE
Basic	$	(1.57)	$	(6.28)
Diluted	$	(1.57)	$	(6.28)
WEIGHTED AVERAGE SHARES OUTSTANDING
Basic		39,067		91,429
Diluted		39,067		91,429

(Continued)

Table of Contents

WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)

(in thousands, except per share data)


	Successor		Predecessor					Successor		Predecessor
	One Month Ended September 30, 2020		Two Months Ended August 31, 2020		Three Months Ended September 30, 2019			Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
OPERATING REVENUES
Oil, NGL and natural gas sales	$	61,084	$	122,558	$	375,891		$	654,662	$	336,446
Purchased gas sales									4,375		-
Total operating revenues									659,037		336,446
OPERATING EXPENSES
Lease operating expenses		18,526		32,646		85,320			123,521		125,582
Transportation, gathering, compression and other		1,980		4,259		11,176			14,471		18,007
Purchased gas expense									3,080		-
Production and ad valorem taxes		5,908		10,362		35,220			49,819		30,842
Depreciation, depletion and amortization		20,110		71,240		211,025			105,347		267,517
Exploration and impairment		4,207		10,217		10,890			4,669		4,174,613
General and administrative		10,345		16,513		29,890			22,286		75,303
Derivative (gain) loss, net		(30,594)		43,125		(30,597)			402,102		(224,739)
Loss on sale of properties		395		1,280		595
Gain on sale of properties									(10,110)		(353)
Amortization of deferred gain on sale		-		(1,171)		(2,266)			-		(3,945)
Total operating expenses		30,877		188,471		351,253			715,185		4,462,827
INCOME (LOSS) FROM OPERATIONS		30,207		(65,913)		24,638
LOSS FROM OPERATIONS									(56,148)		(4,126,381)
OTHER INCOME (EXPENSE)
Interest expense		(2,128)		(11,379)		(48,447)			(9,084)		(61,675)
Gain on extinguishment of debt		-		-		4,598			-		25,883
Interest income and other		6		139		144
Other income									2,797		72
Reorganization items, net		-		259,232		-			-		(41,813)
Total other income (expense)		(2,122)		247,992		(43,705)
INCOME (LOSS) BEFORE INCOME TAXES		28,085		182,079		(19,067)
Total other expense									(6,287)		(77,533)
LOSS BEFORE INCOME TAXES									(62,435)		(4,203,914)
INCOME TAX EXPENSE (BENEFIT)
Current		2,316		-		-			-		2,718
Deferred		(14,501)		(55,346)		-			-		(3,746)
Total income tax benefit		(12,185)		(55,346)		-			-		(1,028)
NET INCOME (LOSS)	$	40,270	$	237,425	$	(19,067)
INCOME (LOSS) PER COMMON SHARE
NET LOSS								$	(62,435)	$	(4,202,886)
LOSS PER COMMON SHARE
Basic	$	1.06	$	2.60	$	(0.21)		$	(1.61)	$	(45.98)
Diluted	$	1.06	$	2.60	$	(0.21)		$	(1.61)	$	(45.98)
WEIGHTED AVERAGE SHARES OUTSTANDING
Basic		38,051		91,464		91,299			38,883		91,409
Diluted		38,051		91,464		91,299			38,883		91,409

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

~~(Continued)~~

~~Table of Contents~~

~~WHITING PETROLEUM CORPORATION~~

~~CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)~~

~~(in thousands, except per share data)~~

Successor

Predecessor

One Month Ended September 30, 2020

Eight Months Ended August 31, 2020

Nine Months Ended September 30, 2019
OPERATING REVENUES

Oil, NGL and natural gas sales

$
61,084

$
459,004

$
1,191,644
OPERATING EXPENSES

Lease operating expenses

18,526

158,228

256,384
Transportation, gathering, compression and other

1,980

22,266

32,145
Production and ad valorem taxes

5,908

41,204

102,796
Depreciation, depletion and amortization

20,110

338,757

612,166
Exploration and impairment

4,207

4,184,830

44,045
General and administrative

10,345

91,816

97,437
Derivative (gain) loss, net

(30,594)

(181,614)

7,431
Loss on sale of properties

395

927

1,681
Amortization of deferred gain on sale

-

(5,116)

(6,963)
Total operating expenses

30,877

4,651,298

1,147,122
INCOME (LOSS) FROM OPERATIONS

30,207

(4,192,294)

44,522
OTHER INCOME (EXPENSE)

Interest expense

(2,128)

(73,054)

(145,274)
Gain on extinguishment of debt

-

25,883

4,598
Interest income and other

6

211

1,102
Reorganization items, net

-

217,419

-
Total other income (expense)

(2,122)

170,459

(139,574)
INCOME (LOSS) BEFORE INCOME TAXES

28,085

(4,021,835)

(95,052)
INCOME TAX EXPENSE (BENEFIT)

Current

2,316

2,718

-
Deferred

(14,501)

(59,092)

(1,373)
Total income tax benefit

(12,185)

(56,374)

(1,373)
NET INCOME (LOSS)

$
40,270

$
(3,965,461)

$
(93,679)
INCOME (LOSS) PER COMMON SHARE

Basic

$
1.06

$
(43.37)

$
(1.03)
Diluted

$
1.06

$
(43.37)

$
(1.03)
WEIGHTED AVERAGE SHARES OUTSTANDING

Basic

38,051

91,423

91,274
Diluted

38,051

91,423

91,274

~~(Concluded)~~

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

Table of Contents

WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(in thousands)


	Successor		Predecessor				Successor		Predecessor
	One Month Ended September 30, 2020		Eight Months Ended August 31, 2020		Nine Months Ended September 30, 2019		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	40,270	$	(3,965,461)	$	(93,679)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net loss							$	(62,435)	$	(4,202,886)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		20,110		338,757		612,166		105,347		267,517
Deferred income tax benefit		(14,501)		(59,092)		(1,373)		-		(3,746)
Amortization of debt issuance costs, debt discount and debt premium		371		13,535		23,707		1,773		9,786
Stock-based compensation		-		4,188		5,086		4,764		3,401
Amortization of deferred gain on sale		-		(5,116)		(6,963)		-		(3,945)
Loss on sale of properties		395		927		1,681
Gain on sale of properties								(10,110)		(353)
Oil and gas property impairments		-		4,161,885		15,729		2,691		4,154,369
Gain on extinguishment of debt		-		(25,883)		(4,598)		-		(25,883)
Non-cash derivative (gain) loss		(29,563)		(136,131)		22,228		295,249		(178,525)
Non-cash reorganization items, net		-		(274,588)		-		-		38,145
Other, net		(438)		(223)		1,141		(3,670)		829
Changes in current assets and liabilities:
Accounts receivable trade, net		7,752		181,416		(4,076)		(69,957)		152,560
Prepaid expenses and other		1,133		(5,491)		4,998		4,484		(12,036)
Accounts payable trade and accrued liabilities		(18,163)		(46,734)		(18,397)		23,536		(51,783)
Revenues and royalties payable		1,261		(56,504)		(28,110)		40,052		(65,609)
Taxes payable		3,013		(12,872)		(8,615)		4,715		(14,579)
Net cash provided by operating activities		11,640		112,613		520,925		336,439		67,262
CASH FLOWS FROM INVESTING ACTIVITIES
Drilling and development capital expenditures		(9,040)		(238,456)		(624,707)		(103,379)		(223,905)
Acquisition of oil and gas properties		(162)		(493)		(5,955)		(509)		(351)
Other property and equipment		56		(1,072)		(7,525)		490		(423)
Proceeds from sale of properties		532		29,273		66,738		6,442		28,243
Net cash used in investing activities		(8,614)		(210,748)		(571,449)		(96,956)		(196,436)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under Credit Agreement								590,000		-
Repayments of borrowings under Credit Agreement								(835,000)		-
Borrowings under Predecessor Credit Agreement		-		1,185,000		1,980,000		-		1,185,000
Repayments of borrowings under Predecessor Credit Agreement		-		(1,402,259)		(1,615,000)		-		(490,000)
Borrowings under Exit Credit Agreement		75,000		425,328		-
Repayments of borrowings under Exit Credit Agreement		(100,000)		-		-
Repurchase of 1.25% Convertible Senior Notes due 2020		-		(52,890)		(297,000)		-		(52,890)
Repurchase of 5.75% Senior Notes due 2021		-		-		(23,461)
Debt issuance and extinguishment costs		-		(12,784)		(36)
Principal payments on finance lease obligations								(2,436)		(2,409)
Restricted stock used for tax withholdings		-		(307)		(3,696)		(1,361)		(304)
Principal payments on finance lease obligations		(498)		(3,198)		(3,890)
Net cash provided by (used in) financing activities	$	(25,498)	$	138,890	$	36,917	$	(248,797)	$	639,397

						(Continued)				(Continued)

Table of Contents

WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(in thousands)


		Successor		Predecessor					Successor		Predecessor
		One Month Ended September 30, 2020		Eight Months Ended August 31, 2020		Nine Months Ended September 30, 2019			Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH		$	(22,472)	$	40,755	$	(13,607)		$	(9,314)	$	510,223
CASH, CASH EQUIVALENTS AND RESTRICTED CASH
Beginning of period			49,407		8,652		13,607			28,367		8,652
End of period		$	26,935	$	49,407	$	-		$	19,053	$	518,875
SUPPLEMENTAL CASH FLOW DISCLOSURES
Interest paid, net of amounts capitalized		$	301	$	80,220	$	156,664		$	6,189	$	72,199
Cash paid for reorganization items		$	14,353	$	33,238	$	-		$	396	$	3,668
NONCASH INVESTING ACTIVITIES
Accrued capital expenditures and accounts payable related to property additions		$	23,245	$	26,796	$	147,295		$	26,935	$	38,504
NONCASH FINANCING ACTIVITIES
Derivative termination settlement payments used to repay borrowings under Predecessor Credit Agreement		$	-	$	157,741	$	-		$	-	$	157,741

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

Table of Contents

WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY ~~(DEFICIT)~~ (unaudited)

(in thousands)


													Additional		Accumulated
				Additional						Common Stock			Paid-in		Earnings		Total
	Common Stock			Paid-in		Accumulated		Total
	Shares	Amount		Capital		Earnings (Deficit)		Equity (Deficit)
BALANCES - January 1, 2019 (Predecessor)	92,067	$	92	$	6,414,170	$	(2,143,946)	$	4,270,316
Net loss	-		-		-		(68,925)		(68,925)
Restricted stock forfeited	(106)		-		-		-		-
Restricted stock used for tax withholdings	(130)		-		(3,693)		-		(3,693)
Stock-based compensation	-		-		4,651		-		4,651
BALANCES - March 31, 2019 (Predecessor)	91,831		92		6,415,128		(2,212,871)		4,202,349
Net loss	-		-		-		(5,687)		(5,687)
Restricted stock issued	63		-		-		-		-
Restricted stock forfeited	(3)		-		-		-		-
Stock-based compensation	-		-		3,965		-		3,965
BALANCES - June 30, 2019 (Predecessor)	91,891		92		6,419,093		(2,218,558)		4,200,627
Net loss	-		-		-		(19,067)		(19,067)
Adjustment to equity component of Convertible Senior Notes upon extinguishment	-		-		(8,070)		-		(8,070)
Restricted stock issued	45		-		-		-		-
Restricted stock forfeited	(175)		-		-		-		-
Restricted stock used for tax withholdings	-		-		(3)		-		(3)
Stock-based compensation	-		-		(3,530)		-		(3,530)
BALANCES - September 30, 2019 (Predecessor)	91,761	$	92	$	6,407,490	$	(2,237,625)	$	4,169,957
										Shares	Amount		Capital		(Deficit)		Equity
BALANCES - January 1, 2020 (Predecessor)	91,744	$	92	$	6,409,991	$	(2,385,112)	$	4,024,971	91,744	$	92	$	6,409,991	$	(2,385,112)	$	4,024,971
Net loss	-		-		-		(3,628,571)		(3,628,571)	-		-		-		(3,628,571)		(3,628,571)
Adjustment to equity component of Convertible Senior Notes upon extinguishment	-		-		(3,461)		-		(3,461)	-		-		(3,461)		-		(3,461)
Restricted stock issued	185		-		-		-		-	185		-		-		-		-
Restricted stock forfeited	(238)		-		-		-		-	(238)		-		-		-		-
Restricted stock used for tax withholdings	(54)		-		(304)		-		(304)	(54)		-		(304)		-		(304)
Stock-based compensation	-		-		2,068		-		2,068	-		-		2,068		-		2,068
BALANCES - March 31, 2020 (Predecessor)	91,637		92		6,408,294		(6,013,683)		394,703	91,637		92		6,408,294		(6,013,683)		394,703
Net loss	-		-		-		(574,315)		(574,315)	-		-		-		(574,315)		(574,315)
Stock-based compensation	-		-		1,333		-		1,333	-		-		1,333		-		1,333
BALANCES - June 30, 2020 (Predecessor)	91,637		92		6,409,627		(6,587,998)		(178,279)	91,637	$	92	$	6,409,627	$	(6,587,998)	$	(178,279)
Net income	-		-		-		237,425		237,425


BALANCES - January 1, 2021 (Successor)										38,051	$	38	$	1,189,693	$	39,073	$	1,228,804
Net loss										-		-		-		(946)		(946)
Common stock issued in settlement of bankruptcy claims										949		1		(1)		-		-
Restricted stock issued	9		-		-		-		-	95		-		-		-		-
Restricted stock used for tax withholdings	(4)		-		(4)		-		(4)	(41)		-		(1,357)		-		(1,357)
Stock-based compensation	-		-		787		-		787	-		-		2,309		-		2,309
Cancellation of Predecessor equity	(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	-		-		-		40,270		40,270
BALANCES - September 30, 2020 (Successor)	38,051	$	38	$	1,189,178	$	40,270	$	1,229,486
BALANCES - March 31, 2021 (Successor)										39,054		39		1,190,644		38,127		1,228,810
Net loss										-		-		-		(61,489)		(61,489)
Restricted stock issued										37		-		-		-		-
Restricted stock used for tax withholdings										-		-		(4)		-		(4)
Stock-based compensation										-		-		2,455		-		2,455
BALANCES - June 30, 2021 (Successor)										39,091	$	39	$	1,193,095	$	(23,362)	$	1,169,772

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

Table of Contents

WHITING PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. BASIS OF PRESENTATION

Description of Operations—Whiting Petroleum Corporation, a Delaware corporation, is an independent oil and gas company engaged in the development, production and acquisition of crude oil, NGLs and natural gas primarily in the Rocky Mountains region of the United States. Unless otherwise specified or the context otherwise requires, all references in these notes to “Whiting” or the “Company” are to Whiting Petroleum Corporation, ~~and~~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.~~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 ~~its~~the Company’s financial condition and results of operations for any period after ~~the Company’s~~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 “Successor Period” ~~relate to the period of September 1, 2020 through September 30, 2020. References to “Current Predecessor Quarter”~~ and ~~“Current Predecessor~~“Successor YTD Period” relate to the periods of July 1, 2020 through August 31, 2020 and January 1, 2020 through August 31, 2020, respectively. References to “Prior Predecessor Quarter” and “Prior Predecessor YTD Period” relaterefer to the three and ~~nine~~six months ended ~~September~~June 30, ~~2019,~~2021, respectively. ~~The Company evaluated~~References to “Predecessor Period” and “Predecessor YTD Period” refer to the ~~events between August 31,~~three and six months ended June 30, 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.~~respectively.

During the ~~Current~~ Predecessor YTD Period, the Company applied ASC 852 in preparing the condensed 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 indebtedness, were recorded as reorganization items, net in the condensed 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 ~~Current~~ Predecessor YTD Period.

~~Ability to Continue as a Going Concern~~—The accompanying condensed consolidated financial statements have been prepared assuming the Company will continue as a going concern and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business. During the Chapter 11 Cases, the Company’s ability to continue as a going concern was subject to a high degree of risk and uncertainty until the Plan was confirmed and the Company emerged from the Chapter 11 Cases. As a result of implementing the Plan, there is no longer substantial doubt about the Company’s ability to continue as a going concern.

Condensed Consolidated Financial Statements—The unaudited condensed consolidated financial statements include the accounts of Whiting Petroleum Corporation and its consolidated subsidiaries. Investments in entities which give Whiting significant influence, but

~~Table of Contents~~

not control, over the investee are accounted for using the equity method. Under the equity method, investments are stated at cost plus the Company’s equity in undistributed earnings and losses. All intercompany balances and transactions have been eliminated upon consolidation. These financial statements have been prepared in accordance with GAAP and the SEC rules and regulations for interim financial reporting. In the opinion of management, the accompanying financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim results. However, operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. The condensed consolidated financial statements and related notes included in this Quarterly Report on Form 10-Q should be read in conjunction with Whiting’s consolidated financial statements and related notes included in the Company’s Annual Report on Form 10-K

Table of Contents

for the period ended December 31, ~~2019.~~2020. Except as disclosed herein, there have been no material changes to the information disclosed in the notes to consolidated financial statements included in the Company’s ~~2019~~ Annual Report on Form ~~10-K.~~10-K for the period ending December 31, 2020.

Reclassifications—Certain prior period balances in the condensed consolidated balance sheets have been combined or reclassified to conform to current period presentation pursuant to Rule 10-01(a)(2) of Regulation S-X of the SEC. Such reclassifications had no impact on net loss, cash flows or shareholders’ equity previously reported.

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 ~~September~~June 30, ~~2020 (Successor)~~2021 and December 31, ~~2019 (Predecessor).~~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 Successor’s credit agreement. The Company has not experienced any losses on its deposits of cash and cash equivalents.

Restricted cash as of ~~September~~June 30, 2021 and December 31, 2020 ~~(Successor) includes $13 million~~consist 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”).~~Cases.

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


	Successor		Predecessor		Successor
	September 30,		December 31,		June 30,		December 31,
	2020		2019		2021		2020
Cash and cash equivalents	$	13,702	$	8,652	$	16,652	$	25,607
Restricted cash		13,233		-		2,401		2,760
Total cash, cash equivalents and restricted cash	$	26,935	$	8,652	$	19,053	$	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 June 30, 2021 and December 31, ~~2019 (Predecessor)~~2020 (Successor), the Company had ~~an allowance~~immaterial allowances for credit ~~losses of $9 million.~~losses.

Table of Contents

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 “Basis of Presentation” footnote above. On April 23, 2020, the Debtors entered into ~~the RSA~~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 of directors.

(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,

●

~~1,233,580~~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 ~~are currently~~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 ~~these~~pending claims will be cancelled. In addition, 4,035,885 shares have been 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 a reserves-based credit agreement with a syndicate of banks (the ~~“Exit Credit~~“Credit Agreement”) 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 ~~Exit~~ Credit Agreement. The Company utilized borrowings from the ~~Exit~~ 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~~and the Predecessor Credit Agreement 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, and provide adequate assurance of future performance.~~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.~~Code unless an order settling the claims

Table of Contents

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

~~Table of Contents~~

from the rejection of any executory contract or unexpired lease and the Debtors expressly ~~preserve~~reserve all of their rights ~~thereto.~~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~~between the Petition ~~Date.~~Date and the Emergence Date in accordance with ASC 852. The contractual interest expense not accrued in the condensed consolidated statements of operations was approximately ~~$57~~$34 million for the period from the Petition Date through June 30, 2020 (Predecessor).

Claims Resolution Process—Pursuant to the ~~Emergence Date.~~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~~Upon application of fresh start accounting, the Company allocated its reorganization value to its individual assets based on their estimated fair values in conformity with FASB ASC Topic 820 – Fair Value Measurement (“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~~For further information on the ~~Plan~~Company’s reorganization value and ~~related disclosure statement,~~ the ~~enterprise value of the Successor was estimated to be between $1.35 billion and $1.75 billion. At~~resulting fresh start adjustments made on the Emergence Date, refer to 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 our 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“Fresh Start Accounting” footnote in the ~~Company's five-year development plan. Future prices for~~notes to the ~~income approach were based on forward strip price curves (adjusted for basis differentials). The fair value~~consolidated financial statements in Item 8 of the Company’s ~~unproved reserves was estimated using~~Annual Report on Form 10-K for the period ending December 31, 2020.

Reorganization Items, Net—Any expenses, gains and losses that were realized or incurred between the Petition Date and the Emergence Date and as a ~~combination~~direct result of ~~income and market approaches. See further discussion below~~the Chapter 11 Cases were recorded in ~~“Fresh Start Accounting Adjustments.”~~

reorganization items, net in the Company’s condensed consolidated statements of operations. The following table ~~reconciles~~summarizes the ~~Company’s enterprise value to~~components of reorganization items, net for the ~~implied value of the Successor’s common stock as of September 1,~~three and six months ended June 30, 2020 (in ~~thousands, except per share data)~~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


	Predecessor
	Three and Six Months Ended
	June 30, 2020
Legal and professional advisory fees	$	26,668
Write-off of unamortized debt issuance costs and premium⁽¹⁾		15,145
Total reorganization items, net	$	41,813

(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.

Table of Contents

4. OIL AND GAS PROPERTIES

Net capitalized costs related to the Company’s oil and gas producing activities at June 30, 2021 and December 31, 2020 are as follows (in thousands):


	Successor
	June 30,		December 31,
	2021		2020
Proved oil and gas properties	$	1,781,723	$	1,701,163
Unproved leasehold costs		101,477		105,073
Wells and facilities in progress		46,350		6,365
Total oil and gas properties, successful efforts method		1,929,550		1,812,601
Accumulated depletion		(170,435)		(71,064)
Oil and gas properties, net	$	1,759,115	$	1,741,537

Impairment expense for unproved properties was $1 million and $2 million for the three and six months ended June 30, 2021 (Successor), respectively. Impairment expense for unproved properties was immaterial for the three months ended June 30, 2020 (Predecessor) and $12 million for the six months ended June 30, 2020 (Predecessor). Impairment expense for unproved properties is reported in exploration and impairment expense in the condensed consolidated statements of operations.

Refer to the “Fair Value Measurements” footnote for more information on proved property impairments recorded during the three and six months ended June 30, 2020.

5. ACQUISITIONS AND DIVESTITURES

2021 Acquisitions and Divestitures

There were no significant acquisitions or divestitures during the six months ended June 30, 2021.

Refer to the “Subsequent Events” footnote for information on acquisition and divestiture activity subsequent to June 30, 2021.

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 six months ended June 30, 2020.

6. LONG-TERM DEBT

Long-term debt, consisting entirely of borrowings outstanding under the Company’s Credit Agreement, totaled $115 million and $360 million at June 30, 2021 and December 31, 2020, respectively.

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 June 30, 2021, the Credit Agreement had a borrowing base and aggregate commitments of $750 million. As of June 30, 2021, the Company had $633 million of available borrowing capacity under the Credit Agreement, which was net of $115 million of borrowings outstanding and $2 million in letters of credit outstanding.

The borrowing base under the Credit Agreement is determined at the discretion of the lenders, based on the collateral value of the Company’s proved reserves that have been mortgaged to such lenders, and is subject to regular redeterminations on April 1 and October 1 of each year, as well as special redeterminations described in the Credit Agreement, in each case which may increase or

Table of Contents

decrease the amount of the borrowing base. In April 2021, the Company’s borrowing base and aggregate commitments of $750 million were reaffirmed in connection with our regular borrowing base redetermination. Asset sales that materially impact the value of the Company’s proved reserves may result in a reduction of the borrowing base. However, the Company can increase the aggregate commitments by up to an additional $750 million, subject to certain conditions.

A portion of the borrowing base in an aggregate amount not to exceed $50 million 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 June 30, 2021, $48 million was available for additional letters of credit under the Credit Agreement.

The Credit Agreement provides for interest only payments until maturity on April 1, 2024, when the agreement terminates and all outstanding borrowings are due. In addition, the Credit Agreement provides for certain mandatory prepayments, including a provision pursuant to which, if the Company’s cash balances are in excess of approximately $75 million during any given week, such excess must be utilized to repay borrowings under the Credit Agreement. Interest under the Credit Agreement accrues at 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. Additionally, the Company incurs commitment fees of 0.5% on the unused portion of the aggregate commitments of the lenders under the Credit Agreement, which are included as a component of interest expense. At June 30, 2021, the weighted average interest rate on the outstanding principal balance under the Credit Agreement was 4.1%.

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. Except for limited exceptions, the Credit Agreement also restricts the Company’s ability to make any dividend payments or distributions on its common stock prior to September 1, 2021, and thereafter only to the extent that the Company has distributable free cash flow and (i) has at least 20% of available borrowing capacity, (ii) has a consolidated net leverage ratio of less than or equal to 2.0 to 1.0, (iii) does not have a borrowing base deficiency and (iv) is not in default under the Credit Agreement. These restrictions apply to all of the Company’s restricted subsidiaries and are calculated in accordance with definitions contained in the Credit Agreement. The Credit Agreement requires the Company, as of the last day of any quarter, to maintain commodity hedges covering a minimum of 65% of its projected production for the succeeding twelve months, and 35% of its projected production for the next succeeding twelve months, both as reflected in the reserves report most recently provided by the Company to the lenders under the Credit Agreement. 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: (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 June 30, 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 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.

Senior Notes and Convertible Senior Notes (Predecessor)

Prior to the Emergence Date, the Company had outstanding notes consisting of $774 million 5.75% Senior Notes due 2021, $408 million 6.25% Senior Notes due 2023 and $1.0 billion 6.625% Senior Notes due 2026 (collectively, 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 outstanding notes. In addition, the remaining unamortized debt issuance costs and debt premium were written off to reorganization items, net in the condensed consolidated statements of operations. Refer to the “Chapter 11 Emergence” and “Fresh Start Accounting” footnotes for more information.

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 Predecessor Period, which was net of a $0.2 million charge for the non-cash write-off of unamortized debt issuance costs

Table of Contents

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.

7. 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 June 30, 2021 and December 31, 2020 (Successor) were $6 million, and have been included in accrued liabilities and other in the condensed consolidated balance sheets. The following table ~~reconciles~~provides a reconciliation of the Company’s ~~enterprise value to its reorganization value as of September 1, 2020~~asset retirement obligations for the six months ended June 30, 2021 (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


Asset retirement obligation at January 1, 2021 (Successor)	$	98,130
Additional liability incurred		773
Revisions to estimated cash flows		8,354
Accretion expense		4,412
Obligations on sold properties		(9,654)
Liabilities settled		(2,492)
Asset retirement obligation at June 30, 2021 (Successor)	$	99,523

~~Although~~

8. 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 natural gas liquids 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 ~~believes the assumptions and estimates used~~also enters into derivative contracts 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. See below under the caption “Fresh Start Adjustments” for additional information regarding assumptions usedmaintain its compliance with certain minimum hedging requirements contained in the ~~valuation~~Credit Agreement. Refer to the “Long-Term Debt” footnote for a detailed discussion of the ~~Company’s significant assets~~minimum and ~~liabilities.~~maximum hedging requirements of the Credit Agreement. The Company does not enter into derivative contracts for speculative or trading purposes.

~~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~~Crude Oil, Natural Gas and Natural Gas Liquids Swaps and Collars, Natural Gas Basis Swaps and Crude Oil 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 oil or gas production. Natural gas basis swaps and crude oil differential swaps mitigate risk associated with anticipated future production by ~~the Plan (the “Reorganization Adjustments”)~~establishing a fixed differential between NYMEX prices and the ~~fair value adjustments as a result~~referenced index price. While the use of ~~applying fresh start accounting (the “Fresh Start Adjustments”). The explanatory notes highlight methods used to determine fair values or other amounts~~these derivative instruments limits the downside risk of ~~the corresponding assets or liabilities, as well as significant assumptions.~~

adverse price movements, it may also limit future income from favorable price movements.

1517

Table of Contents

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

~~Table of Contents~~

~~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 Exit 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 Exit 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 condensed 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 Exit 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.~~

~~Table of Contents~~

~~(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 condensed 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 Exit Credit Agreement upon emergence. Refer to the "Long-Term Debt" footnote for more information on the Exit 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 condensed consolidated statements of operations.

~~Table of Contents~~

~~(m)~~

Reflects the issuance of Successor equity, including the issuance of 38,051,210 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

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

~~Table of Contents~~

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 condensed consolidated statements of operations. $7 million of the write-off related to the short-term portion of the deferred gain (included in accrued liabilities and other in the condensed consolidated balance sheets at emergence) and the remaining $2 million related to the long-term portion of the deferred gain (included in other long-term liabilities in the condensed 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.~~

~~Table of Contents~~

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

Successor

Predecessor

One Month Ended September 30, 2020

Two Months Ended August 31, 2020

Eight Months Ended August 31, 2020
Legal and professional advisory fees ⁽¹⁾

$
-

$
30,502

$
57,170
Net gain on liabilities subject to compromise

-

(1,324,940)

(1,324,940)
Fresh start adjustments, net

-

1,025,742

1,025,742
Write-off of unamortized debt issuance costs and premium⁽²⁾

-

-

15,145
Other items, net

-

9,464

9,464
Total reorganization items, net

$
-

$
(259,232)

$
(217,419)

~~(1)~~

As of September 30, 2020, $10 million of these fees are accrued and unpaid and are presented in accounts payable and accrued liabilities and other in the condensed consolidated balance sheets. These amounts will be paid in the ordinary course of business.

~~(2)~~

~~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 September 30, 2020 and December 31, 2019 are as follows (in thousands):~~

Successor

Predecessor

September 30,

December 31,

2020

2019
Proved oil and gas properties

$
1,693,217

$
12,549,395
Unproved leasehold costs

124,838

103,278
Wells and facilities in progress

11,417

159,334
Total oil and gas properties, successful efforts method

1,829,472

12,812,007
Accumulated depletion

(18,735)

(5,656,929)
Oil and gas properties, net

$
1,810,737

$
7,155,078

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

Successor

Predecessor

One Month Ended September 30, 2020

Two Months Ended August 31, 2020

Three Months Ended September 30, 2019
Impairment expense for unproved properties

$
-

$
83

$
2,233

Successor

Predecessor

One Month Ended September 30, 2020

Eight Months Ended August 31, 2020

Nine Months Ended September 30, 2019
Impairment expense for unproved properties

$
-

$
12,566

$
8,063

~~Table of Contents~~

~~Refer to the “Fair Value Measurements” footnote for more information on proved property measurements recorded during the periods presented.~~

~~5. ACQUISITIONS AND DIVESTITURES~~

~~2020 Acquisitions and Divestitures~~

~~There were no significant acquisitions during the nine months ended September 30, 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 nine months ended September 30, 2019.~~

~~6. LONG-TERM DEBT~~

~~Long-term debt consisted of the following at September 30, 2020 and December 31, 2019 (in thousands):~~

Successor

Predecessor

September 30,

December 31,

2020

2019
Exit Credit Agreement

$
400,328

$
-
Predecessor Credit Agreement

-

375,000
1.25% Convertible Senior Notes due 2020

-

262,075
5.75% Senior Notes due 2021

-

773,609
6.25% Senior Notes due 2023

-

408,296
6.625% Senior Notes due 2026

-

1,000,000
Total principal

400,328

2,818,980
Unamortized debt discounts and premiums

-

(2,575)
Unamortized debt issuance costs on notes

-

(16,520)
Total long-term debt

$
400,328

$
2,799,885

~~Exit Credit Agreement~~

On the Emergence Date, Whiting Petroleum Corporation, as parent guarantor, and Whiting Oil and Gas, as borrower, entered into the Exit Credit Agreement, a reserves-based credit facility, with a syndicate of banks. As of September 30, 2020, the Exit Credit Agreement had a borrowing base and aggregate commitments of $750 million. As of September 30, 2020, the Company had $348 million of available borrowing capacity under the Exit Credit Agreement, which was net of $400 million of borrowings outstanding and $2 ~~million in letters of credit outstanding.~~

The borrowing base under the Exit 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 initial redetermination on April 1, 2021, regular

~~Table of Contents~~

redeterminations on April 1 and October 1 of each year thereafter, as well as special redeterminations described in the Exit 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.~~

A portion of the revolving credit facility in an aggregate amount not to exceed $50 million 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 September 30, 2020, $48 million was available for additional letters of credit under the Exit Credit Agreement.

The Exit Credit Agreement provides for interest only payments until maturity on April 1, 2024, when the agreement terminates and all outstanding borrowings are due. In addition, the Exit Credit Agreement provides for certain mandatory prepayments, including if the Company’s cash balances are in excess of approximately $75 million on any given week, such excess must be utilized to repay borrowings under the Exit Credit Agreement. Interest under the Exit 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 rate plus 1.0% per annum, or (ii) an adjusted LIBOR rate 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. Additionally, the Company incurs commitment fees of 0.5% on the unused portion of the aggregate commitments of the lenders under the Exit Credit Agreement, which are included as a component of interest expense. At September 30, 2020, the weighted average interest rate on the outstanding principal balance under the Exit Credit Agreement was 4.3%.

The Exit 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. Except for limited exceptions, the Exit Credit Agreement also restricts the Company’s ability to make any dividend payments or distributions on its common stock prior to September 1, 2021, and thereafter only to the extent that the Company has distributable free cash flow and (i) at least 20% of available borrowing capacity, (ii) 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 Exit Credit Agreement. These restrictions apply to all of the Company’s restricted subsidiaries (as defined in the Exit Credit Agreement). The Exit Credit Agreement requires the Company, as of the last day of any quarter to maintain commodity hedges covering a minimum of 65% of its projected production for the succeeding twelve months, and 35% of its projected production for the next succeeding twelve months. The Exit Credit Agreement requires the Company, as of the last day of any quarter beginning with the quarter ending December 31, 2020, to maintain the following ratios: (i) a consolidated current assets to consolidated current liabilities ratio of not less than 1.0 to 1.0 and (ii) a total debt to last four quarters’ EBITDAX ratio of not greater than 3.5 to 1.0.

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

~~Predecessor Credit Agreement~~

Whiting Oil and Gas, the Company’s wholly owned subsidiary, had the Predecessor Credit Agreement that had a borrowing base of $2.05 billion and aggregate commitments of $1.75 billion prior to the Predecessor filing the Chapter 11 Cases.

On the Emergence Date, the Predecessor Credit Agreement was terminated and the outstanding borrowings of $912 million and accrued interest of $3 million were paid in full. These payments were funded with cash on hand and proceeds from the Exit Credit Agreement.

~~Predecessor Senior Notes and Convertible Senior Notes~~

Prior to the Emergence Date, the Company had outstanding notes consisting of $774 million 5.75% Senior Notes due 2021, $408 million 6.25% Senior Notes due 2023 and $1.0 billion 6.625% Senior Notes due 2026 (the “Senior Notes”) and $187 million of 1.25% Convertible Senior Notes due 2020 (the “Convertible Senior Notes”). These notes were unsecured obligations of Whiting Petroleum Corporation in the Chapter 11 Cases and were therefore included in liabilities subject to compromise on the condensed consolidated balance sheets of the Predecessor as of August 31, 2020. 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 outstanding notes. In addition, the remaining unamortized debt issuance costs and debt premium

~~Table of Contents~~

were written off to reorganization items, net in the condensed consolidated statements of operations. Refer to the “Chapter 11 Emergence” and “Fresh Start Accounting” footnotes for more information.

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 Current Predecessor YTD 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.

~~7. 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. The current portions as of September 30, 2020 (Successor), September 1, 2020 (Successor) and December 31, 2019 (Predecessor) were $8 million, $5 million and $4 million, respectively, and have been included in accrued liabilities and other in the condensed consolidated balance sheets. The following table provides a reconciliation of the Company’s asset retirement obligations for the 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)
Ending balance as of 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
Accretion expense

929
Asset retirement obligation at September 30, 2020 (Successor)

$
127,690

~~(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 on the condensed 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 for additional information.

~~(2)~~

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

8~~. 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 and natural gas 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 and natural gas swaps and collars 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

~~Table of Contents~~

~~management of returns on drilling programs and acquisitions. The Company does not enter into derivative contracts for speculative or trading purposes.~~

~~Crude Oil and Natural Gas Swaps and Collars.~~ Swaps establish a fixed price for anticipated future oil or gas production, while collars are designed to establish floor and ceiling prices on anticipated future oil or gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, it may also limit future income from favorable price movements.

The table below details the ~~Company’s~~Successor’s swap and collar derivatives entered into to hedge forecasted crude oil, NGL and natural gas production revenues as of ~~September~~June 30, ~~2020~~2021 (Successor).


												Weighted Average
Settlement Period	Index	Derivative Instrument	Total Volumes ⁽¹⁾	Units	Weighted Average Swap Price	Weighted Average Floor	Weighted Average Ceiling	Index	Derivative Instrument	Total Volumes	Units	Swap Price	Floor	Ceiling
Crude Oil
2020	NYMEX WTI	Fixed Price Swaps	1,058,000	Bbl	$41.01	-	-
2020	NYMEX WTI	Two-way Collars	1,794,000	Bbl	-	$37.63	$45.36
2021	NYMEX WTI	Fixed Price Swaps	2,737,500	Bbl	$40.05	-	-	NYMEX WTI	Fixed Price Swaps	3,588,000	Bbl	$45.40	-	-
2021	NYMEX WTI	Two-way Collars	6,043,500	Bbl	-	$38.11	$46.61	NYMEX WTI	Two-way Collars	3,162,000	Bbl	-	$41.64	$50.50
2022 ⁽²⁾	NYMEX WTI	Two-way Collars	3,518,000	Bbl	-	$38.36	$49.16
Q1 2022								NYMEX WTI	Fixed Price Swaps	630,000	Bbl	$54.30	-	-
2022								NYMEX WTI	Two-way Collars	9,559,000	Bbl	-	$43.22	$53.70
Q1-Q2 2023								NYMEX WTI	Two-way Collars	3,259,500	Bbl	-	$46.79	$59.37
									Total	20,198,500
Crude Oil Differentials ⁽¹⁾
2021								UHC Clearbrook to NYMEX	Fixed Price Swaps	76,500	Bbl	-$1.95	-	-
		Total	15,151,000	Bbl					Total	76,500
Natural Gas
2020	NYMEX Henry Hub	Fixed Price Swaps	2,440,000	MMBtu	$2.50	-	-
2020	NYMEX Henry Hub	Two-way Collars	1,830,000	MMBtu	-	$2.17	$2.36
2021	NYMEX Henry Hub	Fixed Price Swaps	11,840,000	MMBtu	$2.66	-	-	NYMEX Henry Hub	Fixed Price Swaps	8,970,000	MMBtu	$2.81	-	-
2021	NYMEX Henry Hub	Two-way Collars	10,950,000	MMBtu	-	$2.60	$2.79	NYMEX Henry Hub	Two-way Collars	5,520,000	MMBtu	-	$2.60	$2.79
Q1-Q3 2022								NYMEX Henry Hub	Fixed Price Swaps	5,259,000	MMBtu	$2.68	-	-
2022	NYMEX Henry Hub	Fixed Price Swaps	1,365,000	MMBtu	$2.60	-	-	NYMEX Henry Hub	Two-way Collars	10,720,000	MMBtu	-	$2.35	$2.85
2022	NYMEX Henry Hub	Two-way Collars	8,190,000	MMBtu	-	$2.30	$2.80
Q1-Q2 2023								NYMEX Henry Hub	Two-way Collars	4,975,000	MMBtu	-	$2.37	$2.91
		Total	36,615,000	MMBtu					Total	35,444,000
Natural Gas Basis ⁽²⁾
2021								NNG Ventura to NYMEX	Fixed Price Swaps	3,680,000	MMBtu	-$0.18	-	-
Q1-Q2 2022								NNG Ventura to NYMEX	Fixed Price Swaps	3,530,000	MMBtu	$0.14	-	-
Q1-Q2 2023								NNG Ventura to NYMEX	Fixed Price Swaps	4,740,000	MMBtu	$0.07	-	-
									Total	11,950,000
NGL - Propane
2021								Mont Belvieu	Fixed Price Swaps	19,320,000	Gallons	$0.78	-	-
Q1 2022								Mont Belvieu	Fixed Price Swaps	3,780,000	Gallons	$0.81	-	-
									Total	23,100,000

(1)

~~Subsequent~~The weighted average price associated with the crude oil differential swaps shown in the table above represents the average fixed differential to ~~September 30, 2020,~~NYMEX as stated in the related contracts, which is compared to the NE2 Canadian Monthly Index for UHC Clearbrook (“UHC Clearbrook”) for each period. If NYMEX combined with the fixed differential as stated in each contract is higher than the UHC Clearbrook index price at any settlement date, the Company ~~entered into additional swap contracts for 690,000 MMBtu of natural gas volumes for~~receives the ~~last three months of 2021 and additional collar contracts for 2,530,000 MMBtu of natural gas volumes for~~difference. Conversely, if the ~~last three months of 2022.~~UHC Clearbrook index price is higher than NYMEX combined with the fixed differential, the Company pays the difference.

(2)

The ~~Company’s crude oil~~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 ~~terms cover only~~is higher than the ~~first nine months of 2022.~~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.

Effect of Chapter 11 Cases—The commencement of the Chapter 11 Cases constituted a termination event with respect to the Company’s ~~then outstanding~~ derivative instruments, which permitted the counterparties of such derivative instruments to terminate ~~those~~their outstanding hedges. Such termination events ~~were~~are 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 hedges with the Company for aggregate settlement proceeds 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.~~

2518

Table of Contents

Derivative Instrument Reporting—All derivative instruments are recorded in the condensed consolidated financial statements at fair value, other than derivative instruments that meet the “normal purchase normal sale” ~~exclusion or other derivative scope exceptions. The following tables summarize~~exclusion. Fair value gains and losses on the ~~effects of~~Company’s derivative instruments onare recognized immediately in earnings as derivatives (gain) loss, net in the condensed consolidated statements of ~~operations for the periods presented (in thousands):~~

(Gain) Loss Recognized in Income

Successor

Predecessor
Not Designated as ASC 815 Hedges

Statements of Operations Classification

One Month Ended September 30, 2020

Two Months Ended August 31, 2020

Three Months Ended September 30, 2019
Commodity contracts

Derivative (gain) loss, net

$
(30,594)

$
43,125

$
(30,597)
Total

$
(30,594)

$
43,125

$
(30,597)

(Gain) Loss Recognized in Income

Successor

Predecessor
Not Designated as ASC 815 Hedges

Statements of Operations Classification

One Month Ended September 30, 2020

Eight Months Ended August 31, 2020

Nine Months Ended September 30, 2019
Commodity contracts

Derivative (gain) loss, net

$
(30,594)

$
(181,614)

$
7,431
Total

$
(30,594)

$
(181,614)

$
7,431

operations.

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


		June 30, 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	$	7,001	$	(7,001)	$	-
Commodity contracts - non-current	Other long-term assets		21,324		(21,324)		-
Total derivative assets		$	28,325	$	(28,325)	$	-
Derivative liabilities
Commodity contracts - current	Derivative liabilities	$	272,131	$	(7,001)	$	265,130
Commodity contracts - non-current	Long-term derivative liabilities		110,678		(21,324)		89,354
Total derivative liabilities		$	382,809	$	(28,325)	$	354,484

Successor

September 30, 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

$
23,607

$
(21,631)

$
1,976
Commodity contracts - non-current

Other long-term assets

22,817

(22,368)

449
Total derivative assets

$
46,424

$
(43,999)

$
2,425
Derivative liabilities

Commodity contracts - current

Accrued liabilities and other

$
29,298

$
(21,631)

$
7,667
Commodity contracts - non-current

Other long-term liabilities

26,027

(22,368)

3,659
Total derivative liabilities

$
55,325

$
(43,999)

$
11,326

~~Table of Contents~~


		Predecessor
		December 31, 2019 ⁽¹⁾							December 31, 2020⁽¹⁾
						Net							Net
		Gross				Recognized			Gross				Recognized
		Recognized		Gross		Fair Value			Recognized		Gross		Fair Value
Not Designated as		Assets/		Amounts		Assets/			Assets/		Amounts		Assets/
ASC 815 Hedges	Balance Sheet Classification	Liabilities		Offset		Liabilities		Balance Sheet Classification	Liabilities		Offset		Liabilities
Derivative assets
Commodity contracts - current	Prepaid expenses and other	$	75,654	$	(74,768)	$	886	Prepaid expenses and other	$	14,287	$	(14,287)	$	-
Commodity contracts - non-current	Other long-term assets		5,648		(5,648)		-	Other long-term assets		19,991		(19,991)		-
Total derivative assets		$	81,302	$	(80,416)	$	886		$	34,278	$	(34,278)	$	-
Derivative liabilities
Commodity contracts - current	Accrued liabilities and other	$	85,053	$	(74,768)	$	10,285	Derivative liabilities	$	63,772	$	(14,287)	$	49,485
Commodity contracts - non-current	Other long-term liabilities		6,534		(5,648)		886	Long-term derivative liabilities		29,741		(19,991)		9,750
Total derivative liabilities		$	91,587	$	(80,416)	$	11,171		$	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 ~~both~~ the ~~Exit Credit Agreement and the Predecessor~~ Credit Agreement, which eliminates the need to post or receive collateral associated with its derivative positions. 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 ~~Exit~~ Credit Agreement. The Company uses ~~Exit~~ Credit Agreement participants toas hedge ~~with,~~counterparties since these institutions are secured equally with the holders of Whiting’s bank debt, which eliminates the potential need to post collateral when Whiting is in a derivative liability position. As a result, the Company is not required to post letters of credit or corporate guarantees for its derivative counterparties in order to secure contract performance obligations.

Table of Contents

9. FAIR VALUE MEASUREMENTS

The Company follows 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, 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 Company’s ~~Exit~~ Credit Agreement ~~and Predecessor Credit Agreement have~~has a recorded value that approximates ~~their~~its fair ~~values~~value since ~~their~~its variable interest ~~rates are~~rate is tied to current market rates and the applicable margins represent market rates.

~~Table of Contents~~

The Predecessor’s Senior Notes were recorded at cost and the Predecessor’s Convertible Senior Notes were recorded at fair value at the date of issuance. The following table summarizes the fair values and carrying values of these instruments as of December 31, 2019 (in thousands):

Predecessor

December 31, 2019

Fair

Carrying

Value ⁽¹⁾

Value ⁽²⁾
1.25% Convertible Senior Notes due 2020

$
260,214

$
259,026
5.75% Senior Notes due 2021

732,995

772,080
6.25% Senior Notes due 2023

343,989

405,392
6.625% Senior Notes due 2026

681,250

988,387
Total

$
2,018,448

$
2,424,885

~~(1)~~

~~Fair values are based on quoted market prices for these debt securities, and such fair values are therefore designated as Level 1 within the valuation hierarchy.~~

~~(2)~~

~~Carrying values are presented net of unamortized debt issuance costs and debt discounts or premiums.~~

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 ~~September~~June 30, ~~2020 (Successor)~~2021 and December 31, ~~2019 (Predecessor)~~2020 (Successor), and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values (in thousands):


	Successor														Total Fair Value
							Total Fair Value		Level 1		Level 2		Level 3		June 30, 2021
	Level 1		Level 2		Level 3		September 30, 2020
Financial Assets
Commodity derivatives – current	$	-	$	1,976	$	-	$	1,976
Commodity derivatives – non-current		-		449		-		449
Total financial assets	$	-	$	2,425	$	-	$	2,425
Financial Liabilities
Commodity derivatives – current	$	-	$	7,667	$	-	$	7,667	$	-	$	265,130	$	-	$	265,130
Commodity derivatives – non-current		-		3,659		-		3,659		-		89,354		-		89,354
Total financial liabilities	$	-	$	11,326	$	-	$	11,326	$	-	$	354,484	$	-	$	354,484


	Predecessor														Total Fair Value
							Total Fair Value		Level 1		Level 2		Level 3		December 31, 2020
	Level 1		Level 2		Level 3		December 31, 2019
Financial Assets
Commodity derivatives – current	$	-	$	886	$	-	$	886
Total financial assets	$	-	$	886	$	-	$	886
Financial Liabilities
Commodity derivatives – current	$	-	$	10,285	$	-	$	10,285	$	-	$	49,485	$	-	$	49,485
Commodity derivatives – non-current		-		886		-		886		-		9,750		-		9,750
Total financial liabilities	$	-	$	11,171	$	-	$	11,171	$	-	$	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 natural ~~gas.~~gas liquids. The Company’s swaps, collars, basis swaps and differential swaps are valued based on an income approach. Both the option and ~~the~~ swap models consider various

~~Table of Contents~~

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.

Table of Contents

Non-recurring Fair Value Measurements—The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including proved property. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. The Company did not recognize any impairment write-downs with respect to its proved property during the Successor ~~Period or during the Prior Predecessor Quarter or Prior Predecessor~~ YTD Period. The following tables present information about the Company’s non-financial assets measured at fair value on a non-recurring basis during the ~~Current~~ Predecessor YTD Period and ~~indicate~~indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values (in thousands):


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


	Predecessor
									Loss (Before		Predecessor
	Net Carrying								Tax) During the		Net Carrying
	Value as of								Current		Value as of								Loss (Before Tax)
	June 30,		Fair Value Measurements Using						Predecessor YTD		June 30,		Fair Value Measurements Using						Six Months Ended
	2020		Level 1		Level 2		Level 3		Period		2020		Level 1		Level 2		Level 3		June 30, 2020
Proved property ⁽²⁾	$	85,418	$	-	$	-	$	85,418	$	409,079	$	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 during the second quarter~~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

~~Table of Contents~~

Level 3 inputs within the fair value hierarchy). The impairment tests indicated that a proved property ~~impairment~~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. ~~Additional impairments may be recorded in future periods if commodity prices deteriorate or further reductions to the development plans~~

Table of ~~the properties are indicated by market conditions.~~Contents

~~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.

10. REVENUE RECOGNITION

The Company recognizes revenue in accordance with FASB ASC Topic 606 – Revenue from Contracts with Customers (“ASC 606”). Revenue is recognized at the point in time at which the Company’s performance obligations under its commodity sales contracts are satisfied and control of the commodity 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. Purchased gas sales revenue relates to the sale of natural gas from Whiting facilities that was not produced from the Company’s properties. The tables below present the disaggregation of revenue by product and transaction type for the periods presented (in thousands):

Successor

Predecessor
OPERATING REVENUES

One Month Ended September 30, 2020

Two Months Ended August 31, 2020

Three Months Ended September 30, 2019
Oil sales

$
60,392

$
116,971

$
369,940
NGL and natural gas sales

692

5,587

5,951
Oil, NGL and natural gas sales

$
61,084

$
122,558

$
375,891

Successor

Predecessor
OPERATING REVENUES

One Month Ended September 30, 2020

Eight Months Ended August 31, 2020

Nine Months Ended September 30, 2019
Oil sales

$
60,392

$
440,820

$
1,133,264
NGL and natural gas sales

692

18,184

58,380
Oil, NGL and natural gas sales

$
61,084

$
459,004

$
1,191,644


	Successor		Predecessor
OPERATING REVENUES	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020
Oil sales	$	308,417	$	91,904
NGL and natural gas sales ⁽¹⁾		41,566		(304)
Oil, NGL and natural gas sales		349,983		91,600
Purchased gas sales		1,663		-
Total operating revenues	$	351,646	$	91,600

(1)	Negative NGL and natural gas sales revenue during the three months ended June 30, 2020 was a result of third-party transportation, gathering and processing costs exceeding the average price realized for certain NGL and natural gas volumes sold during the period.


	Successor		Predecessor
	Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
OPERATING REVENUES
Oil sales	$	565,126	$	323,849
NGL and natural gas sales		89,536		12,597
Oil, NGL and natural gas sales		654,662		336,446
Purchased gas sales		4,375		-
Total operating revenues	$	659,037	$	336,446

Whiting receives payment for product sales from one to three months after delivery. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in accounts receivable trade, net in the condensed consolidated balance sheets. As of ~~September~~June 30, ~~2020 (Successor)~~2021 and December 31, ~~2019~~

~~Table of Contents~~

~~(Predecessor)~~2020 (Successor), such receivable balances were ~~$70~~$132 million and ~~$161~~$88 million, respectively. Variances between the Company’s estimated revenue and actual payments are recorded in the month the payment is received, ~~however,~~but differences have been and are insignificant. Accordingly, the variable consideration is not constrained.

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.

Table of Contents

11. 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.

~~On the Emergence Date, upon~~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 ~~38,051,210~~38,051,125 shares of New Common Stock. Refer to the “Chapter 11 Emergence” ~~and “Fresh Start Accounting” footnotes~~footnote 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 purchase 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 purchase 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.

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 purchase 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 purchase 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”).

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 June 30, 2021 for potential future distribution to certain general unsecured claimants whose claim values were pending resolution in the Bankruptcy Court.

Table of Contents

12. STOCK-BASED COMPENSATION

Equity Incentive Plan—As discussed in the “Chapter 11 Emergence” ~~and “Fresh Start Accounting” footnotes,~~footnote, 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 ~~1,233,580~~1,233,495 shares of Successor common stock on a pro rata basis. On ~~August 31,~~September 1, 2020, the Successor’s board of directors 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

~~Table of Contents~~

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 ~~September~~June 30, ~~2020, 3,758,814~~2021, 3,029,358 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 ~~three-year~~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. 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

OnDuring September ~~29,~~and October 2020, ~~87,171~~89,021 shares of service-based RSUs were granted to executive officers and directors under the 2020 Equity Plan. 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.

OnIn September ~~29,~~ 2020, 189,900 shares of market-based RSUs were granted to executive officers under the 2020 Equity Plan. The awards will vest upon the Successor’s common stock trading for 20 consecutive trading days above a certain daily volume weighted average price (“VWAP”) as follows: 50% will vest if the VWAP exceeds $32.57 per share, an additional 25% if the daily VWAP exceeds $48.86 per share and the final 25% if the daily VWAP exceeds $65.14 per share. The ~~grant date fair value of these awards was estimated using a Monte Carlo valuation model (the “Monte Carlo Model”).~~ The Monte Carlo Model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility was calculated based on the observed volatility of peer public companies. The key assumptions used in valuing these market-based awards were as follows:


~~Number of simulations~~		~~100,000~~
~~Expected volatility~~		~~40%~~
~~Risk-free interest rate~~		~~0.66%~~
~~Dividend yield~~		0

~~The~~ Company ~~will recognize~~recognizes compensation expense based on the fair value as determined by ~~the~~a Monte Carlo ~~Model~~valuation model (the “Monte Carlo Model”) over the expected vesting period, which is estimated to be between 1.8 and 3.8 years. The weighted average grant date fair value of these RSUs was $6.54 per share. More information on the inputs of the Monte Carlo Model are explained below. During the six months ended June 30, 2021, the first 50% of these awards vested as the Company’s VWAP exceeded $32.57 per share for 20 consecutive trading days during the period. Subsequent to June 30, 2021, an additional 25% of these awards vested as the Company’s VWAP exceeded $48.86 per share for 20 consecutive trading days.

During the six months ended June 30, 2021, 358,123 shares of service-based RSUs were granted to executive officers and employees under the 2020 Equity Plan, which vest ratably over either a two or three-year service period. Additionally, during the six months ended June 30, 2021, 117,607 shares of service-based RSUs were granted to executive officers under the 2020 Equity Plan, which cliff vest on the fifth anniversary of the grant date. Finally, during the six months ended June 30, 2021, 23,730 shares of service-based RSUs were granted to directors under the 2020 Equity Plan, which vest ratably 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 $23.74 per share for the six months ended June 30, 2021.

During the six months ended June 30, 2021, 232,150 shares of PSUs subject to certain market-based vesting criteria were granted to executive officers under the 2020 Equity Plan. 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

Table of Contents

of awards earned could range from 0 up to 2 times the number of shares initially granted, all of which will be settled in shares. The weighted average grant date fair value of the market-based awards 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:


	2020	2021
	RSUs	PSUs
Number of simulations	100,000	500,000
Expected volatility	40%	81%
Risk-free interest rate	0.66%	0.17%
Dividend yield	0	0

The following table shows a summary of the Company’s service-based and market-based awards activity for the six months ended June 30, 2021:


	Number of Awards			Weighted Average
	Service‑Based	Market-Based	Market-Based	Grant Date
	RSUs	RSUs	PSUs	Fair Value
Nonvested awards, January 1	89,021	189,900	-	$	10.03
Granted	499,460	-	232,150		25.99
Vested	(36,959)	(94,950)	-		9.61
Forfeited	(4,004)	-	-		22.46
Nonvested awards, June 30	547,518	94,950	232,150	$	23.38

The Company recognized $2 million and $5 million in stock-based compensation expense during the three and six months ended June 30, 2021, respectively.

Predecessor Awards

During the ~~eight~~six months ended ~~August 31,~~June 30, 2020, ~~and the nine months ended September 30, 2019,~~ 53,198 ~~and 464,140~~ shares ~~respectively,~~ of share-settled, service-based RSAs and RSUs were granted to executive officers and directors under the Predecessor Equity Plan. 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 $24.76 per share~~ for the ~~eight~~six months ended ~~August 31, 2020 and the nine months ended September~~June 30, ~~2019, respectively.~~2020. 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~~six months ended ~~August 31,~~June 30, 2020, ~~and the nine months ended September 30, 2019,~~ 1,616,504 ~~and 774,665~~ shares ~~respectively,~~ of cash-settled, service-based RSUs were granted to executive officers and employees under the Predecessor Equity Plan. The ~~Company~~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

~~Table of Contents~~

officers in 2020 were forfeited and concurrently replaced with cash incentives. Refer to “2020 Compensation Adjustments” below for more information.

During the ~~eight~~six months ended ~~August 31,~~June 30, 2020, ~~and the nine months ended September 30, 2019,~~ 1,665,153 ~~and 347,493, respectively,~~shares of PSAs and PSUs subject to certain market-based vesting criteria were granted to executive officers under the Predecessor Equity Plan. These market-based awards were to cliff vest on the third anniversary of the grant date, ~~and the number of shares that would vest at the end of that three-year performance period was determined based~~however, on ~~the rank of Whiting’s cumulative stockholder return compared to the stockholder return of a peer group of companies on each anniversary~~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 weighted average grant date ~~over~~fair value of the ~~three-year performance period. The number of~~market-based awards ~~earned could range from 0 up~~that were to ~~2 times the number of shares initially granted. However, awards earned up to the target shares granted (or 100%) would have been~~be settled in shares, ~~while awards earned~~as determined by the Monte Carlo valuation

Table of Contents

model, was $4.31 per share in ~~excess of the target shares granted would have been settled in cash.~~2020. The cash-settled component of such awards was recorded as a liability in the consolidated balance sheets and was remeasured at fair value using a Monte Carlo valuation model at the end of each reporting period. 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.

For the PSAs and PSUs subject to market conditions, the grant date fair value 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

0

0

The ~~weighted average grant date fair value of~~Company recognized $1 million and $2 million in total stock-based compensation expense during the ~~market-based awards that were to be settled in shares, as determined by the Monte Carlo valuation model, was $4.31 per share~~three and ~~$25.97 per share in~~six months ended June 30, 2020, ~~and 2019,~~ respectively.

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 to prepaid expenses and other in the condensed consolidated balance sheets as of March 31, 2020 and was~~ amortized over the period from the Petition Date to the Emergence ~~Date, which amortization~~Date. Amortization of the fair value of these cash incentives totaled $7 million during the three and six months ended June 30, 2020 and is included in general and administrative expenses in the Predecessor’s condensed consolidated statements of ~~operations for the Current Predecessor YTD Period.~~operations. The difference between the cash and after-tax value of the cash retention incentives of approximately $9 million, which iswas not subject to the claw back provisions contained within the agreements, was expensed to general and administrative expenses in the ~~Predecessor~~Predecessor’s condensed consolidated statements of operations during the first quarter of 2020.

Total stock compensation expense recognized for restricted stock was expense of $1 million for Current Predecessor Quarter, a benefit of $5 million for the Prior Predecessor Quarter, expense of $3 million for the Current Predecessor YTD Period and expense of $6 million for the Prior Predecessor YTD Period. 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 condensed consolidated statements of operations during the Current Predecessor Quarter and Current Predecessor YTD Period. Refer to the “Fresh Start Accounting” footnote for more information.

13. INCOME TAXES

Income tax expense during interim periods is based on applying an estimated annual effective income tax rate to year-to-date income, plus any significant unusual or infrequently occurring items which are recorded in the interim period. The provisions for income taxes for the ~~month~~three and six months ended ~~September~~June 30, 2021 (Successor) and June 30, 2020 ~~and eight months ended August 31, 2020~~(Predecessor) differ from the ~~amount that would be provided by~~

~~Table of Contents~~

applying the statutory U.S. federal income tax rate of 21% to pre-tax income primarily as a result of a full valuation allowance on the Company’s U.S. deferred tax assets (“DTAs”) and the revision of the Company’s Canadian deferred tax liability (“DTL”) related to its outside basis difference in Whiting Canadian Holding Company ULC. The Company also recognized a $1 million U.S. income tax benefit during the eight months ended August 31, 2020 related to an alternative minimum tax refund received. As a result of the full valuation on the Company’s DTAs as of September 30, 2020 (Successor) and August 31, 2020 (Predecessor), no additional U.S. tax benefit or expense was recognized during the periods presented.

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 owns a portion of Whiting’s U.S. assets obtained through the acquisition of Kodiak Oil and Gas Corporation in 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). During the Successor Period, the Company partially executed a legal entity restructuring plan to reduce administrative expenses and burden with a simplified corporate structure. Several steps of the restructuring plan were executed during the Successor Period, with the remaining steps expected to be completed in the fourth quarter of 2020. As part of the completed steps to date, Whiting US Holding Company merged into Whiting Oil and Gas Corporation. Additionally, as a result of fresh start accounting and the legal entity restructuring, the Company reduced its deferred tax liability for its outside basis difference related to Whiting Canadian Holding Company ULC and recorded tax benefits of $15 million and $55 million during the Successor Period and Current Predecessor Quarter, respectively. The Company’s total Canadian tax liability is $6 million as of September 30, 2020 (Successor), which is expected to be payable in the fourth quarter of 2020.

The Company’s overall effective tax rates for the month ended September 30, 2020 (Successor) and the eight months ended August 31, 2020 (Predecessor) of (43.4)% and 1.4%, respectively, were lower than the U.S. statutory income tax rate as a result of the full valuation on the Company’s DTAs and the reduction of the overall Canadian DTL as discussed above.

~~The provision for income taxes for the nine months ended September 30, 2019 (Predecessor) differs from the amount~~amounts that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax income primarily due to ~~the~~a full valuation allowance in effect on the Company’s U.S. ~~DTAs.~~ deferred tax assets (“DTAs”), resulting in 0 U.S. income tax expense recognized for the periods presented, outside of a $1 million alternative minimum tax refund received during the first quarter of 2020, and an effective U.S. tax rate of 0%. Additionally, during the second quarter of 2020, $4 million of Canadian deferred tax expense became current.

In assessing the realizability of DTAs, management considers whether it is more likely than not that some portion, or all, of the Company’s DTAs will not be realized. In making such determination, the Company considers all available positive and negative evidence, including future reversals of temporary differences, tax-planning strategies and projected future taxable income and results of operations. If the Company concludes that it is more likely than not that some portion, or all, of its DTAs will not be realized, the tax asset is reduced by a valuation allowance. The Company assesses the appropriateness of its valuation allowance on a quarterly basis. At ~~September~~June 30, 2021 and December 31, 2020 (Successor), the Company had a full valuation allowance on its ~~U.S.~~ DTAs.

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

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~~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. ~~This limitation has not resulted in a current tax liability for the Successor Period, or any intervening period since the Emergence Date.~~ The ownership changes and resulting annual limitation ~~may~~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.

The Company estimates that it has federal NOLs of ~~$3.5~~$3.1 billion as of ~~the Emergence Date,~~December 31, 2020, which are subject to limitation under IRC Section 382. The Company currently estimates that approximately ~~$2.6~~$2.3 billion of these federal NOLs will expire before they are able to be used. The remaining non-expiring NOLs remain subject to a full valuation allowance. These estimates are subject to revision through the filing of the tax return for the year ending December 31, 2020.

3426

Table of Contents

14. EARNINGS PER SHARE

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

Successor

Predecessor

One Month Ended September 30, 2020

Two Months Ended August 31, 2020

Three Months Ended September 30, 2019
Basic Earnings (Loss) Per Share

Net income (loss)

$
40,270

$
237,425

$
(19,067)
Weighted average shares outstanding

38,051

91,464

91,299
Earnings (loss) per common share

$
1.06

$
2.60

$
(0.21)

Diluted Earnings (Loss) Per Share

Net income (loss)

$
40,270

$
237,425

$
(19,067)
Weighted average shares outstanding

38,051

91,464

91,299
Earnings (loss) per common share

$
1.06

$
2.60

$
(0.21)


	Successor		Predecessor
	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020
Basic and diluted loss per share
Net loss	$	(61,489)	$	(574,315)
Weighted average shares outstanding, basic and diluted		39,067		91,429
Loss per common share, basic and diluted	$	(1.57)	$	(6.28)

Successor

Predecessor

One Month Ended September 30, 2020

Eight Months Ended August 31, 2020

Nine Months Ended September 30, 2019
Basic Earnings (Loss) Per Share

Net income (loss)

$
40,270

$
(3,965,461)

$
(93,679)
Weighted average shares outstanding

38,051

91,423

91,274
Earnings (loss) per common share

$
1.06

$
(43.37)

$
(1.03)

Diluted Earnings (Loss) Per Share

Net income (loss)

$
40,270

$
(3,965,461)

$
(93,679)
Weighted average shares outstanding

38,051

91,423

91,274
Earnings (loss) per common share

$
1.06

$
(43.37)

$
(1.03)


	Successor		Predecessor
	Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
Basic and diluted loss per share
Net loss	$	(62,435)	$	(4,202,886)
Weighted average shares outstanding, basic and diluted		38,883		91,409
Loss per common share, basic and diluted	$	(1.61)	$	(45.98)

Successor

During the Successor Period, the diluted earnings per share ~~calculation excludes~~calculations exclude the effect of ~~4,837,387~~4,837,376 common shares for Series A Warrants and ~~2,418,840~~2,418,832 common shares for Series B ~~warrants~~Warrants that were out-of-the-money as of ~~September~~June 30, ~~2020,~~2021, as well as ~~3,070,201~~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 ~~September~~June 30, ~~2020.~~2021. Further, during the ~~calculation excludes~~three and six months ended June 30, 2021, the Company had net losses and therefore the diluted earnings per share calculations for those periods exclude the anti-dilutive effect of ~~87,171~~(i) 345,272 shares of service-based awards ~~that were anti-dilutive~~ and ~~189,900~~195,854 shares of market-based awards for the three months ended June 30, 2021 and (ii) 314,524 shares of service-based awards and 202,643 shares of market-based awards for the six months ended June 30, 2021. Finally, the diluted earnings per share calculations for the three and six months ended June 30, 2021 also exclude 94,950 shares of market-based awards that did not meet the market-based vesting criteria as of ~~September~~June 30, ~~2020.~~

~~Predecessor~~

During the Current Predecessor Quarter, although the Company had net income, the treasury stock method resulted in a larger number of shares assumed to be reacquired by the Company than weighted average unvested awards outstanding. Thus, the diluted earnings per share calculation excludes the anti-dilutive effect of 239,186 shares of service-based awards.

During the Current Predecessor YTD Period, Prior Predecessor Quarter and Prior Predecessor YTD Period, the Company had a net loss and therefore the diluted earnings per share calculations exclude the anti-dilutive effect of (i) 314,896 shares of service-based awards for the Current Predecessor YTD Period, (ii) 35,433 shares of service-based awards and 7,159 shares of market-based awards for the Prior Predecessor Quarter and (iii) 344,419 shares of service-based awards and 64,407 market-based awards for Prior Predecessor YTD Period.

~~Table of Contents~~

In addition, the diluted earnings per share calculations exclude the effect of (i) 18,310 and 29,465 common shares for the Current Predecessor Quarter and Current Predecessor YTD Period, respectively, for stock options that were out-of-the-money as of August 31, 2020 and (ii) 43,367 and 46,095 common shares for the Prior Predecessor Quarter and Prior Predecessor YTD Period, respectively, for stock options that were out-of-the-money as of September 30, 2019.2021.

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

Predecessor

During the three and six months ended June 30, 2020, the Company had net losses and therefore the diluted earnings per share calculations for those periods exclude the anti-dilutive effect of 270,058 and 342,299 shares, respectively, of service-based awards. In addition, the diluted earnings per share calculations for the three and six months ended June 30, 2020 exclude the effect of 28,505 and 31,805 common shares, respectively, for stock ~~options.~~options that were out-of-the-money as of June 30, 2020.

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,~~Predecessor Period, there was no impact to diluted earnings per share or the related disclosures for the Predecessor periods presented.

15. COMMITMENTS AND CONTINGENCIES

Chapter 11 Cases—On April 1, 2020, the Debtors filed the Chapter 11 Cases seeking relief under the Bankruptcy Code. The filing of the Chapter 11 Cases allowed the Company to, upon approval of the Bankruptcy Court, assume, assign or reject certain contractual commitments, including certain executory contracts. 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 ~~resolutions~~resolution process is ongoing and certain of

Table of Contents

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 will be satisfied through the issuance of shares of the Successor’s common stock. As a result, the Company has not established material liabilities in connection with these claims.

However, it is reasonably possible that as a result of the legal proceedings associated with the ~~two counterparties~~bankruptcy claims administration process or the matter detailed below, the Bankruptcy Court may rule, or it may be determined, that (i) the applicable contracts cannot be rejected, or ~~allow the~~(ii) a claim ~~amounts as administrative claims. Either~~is not a general unsecured claim. Any of these outcomes 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.

~~BNN Western, LLC.~~ Whiting Oil and Gas is a party to a Produced Water Gathering and Disposal Agreement (the “PWA”) with BNN Western, LLC (“BNN”). On June 22, 2020, WOG filed with the Bankruptcy Court a motion for entry of an order authorizing rejection of certain executory contracts with BNN and an adversary complaint and motion for summary judgment against BNN seeking a declaratory judgment that the PWA did not create a covenant running with the land and could be rejected. On September 22, 2020, the Bankruptcy Court issued an order that did not grant either party’s motion for summary judgment on whether the PWA created a covenant running with the land, but found that WOG defaulted under the PWA and ruled that BNN’s sole remedy under the terms of the PWA is termination of the PWA and the damages set forth in the PWA. On September 28, 2020, WOG filed an amended complaint for declaratory judgment that (i) WOG has defaulted under the PWA, (ii) BNN’s sole remedy for default is termination of the PWA and damages set forth in the PWA, (iii) any payments by WOG after the events of default under the PWA are not and will not be deemed a renewal of the PWA and (iv) the PWA is terminated and BNN is entitled to damages of no more than approximately $60 million or other amount proved by the parties in accordance with the PWA. The Bankruptcy Court has not issued a ruling on WOG’s amended complaint and the Bankruptcy Court’s September 22 order is subject to appeal by BNN. Although WOG is vigorously defending this legal proceeding, if BNN were to prevail on the merits of its claims, WOG may not be able to reject the PWA and could be required to perform the remainder of the term of the PWA. At this time, the Company is not able to determine the likelihood or range of amounts attributable to BNN’s claims with respect to the PWA due to uncertainties with respect to, among other things, the nature of the claims and defenses and the ultimate potential outcomes of the claims.

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 ~~(collectively, “Whiting”)~~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~~operator (collectively, the “FMOG Entities”) filed with the Bankruptcy Court an application for allowance of certain administrative claims arguing the FMOG Entities ~~are~~were entitled to recover Whiting’s proportionate share of decommissioning obligations owed to the U.S. government through subrogation to the U.S.

~~Table of Contents~~

government’s economic rights. The FMOG Entities’ application ~~alleges~~alleged administrative claims of approximately $25 million for estimated decommissioning costs owed to the U.S. government, at least ~~$60~~$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 (“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. The Bankruptcy Court has not issued a ruling on the damages for rejection of the Point Arguello ~~Agreements or the FMOG Entities’ application for administrative claims.~~Agreements. Although WOG intends to vigorously defend this legal proceeding, if the FMOG Entities were to prevail on certain of their respective claims (including the reserved claims) on the merits or the U.S. government were to bring claims against WOG, Whiting could be liable for ~~administrative~~ claims that must be paid ~~in cash~~or otherwise satisfied, including through an equity issuance, under and pursuant to the Plan. At this time, the Company is not able to determine the likelihood or range of amounts attributable to the FMOG Entities’ claims or any potential claims by the U.S. government due to uncertainties with respect to, among other things, the nature of the claims and defenses and the ultimate potential outcomes of the claims.

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.

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. Certain amounts were recognized in accrued liabilities and other in the consolidated balance sheets as of December 31, 2019 and general and administrative expenses in the consolidated statements of operations for the year ended December 31, 2019 as it was determined that a loss as a result of this litigation was probable. The Company recorded $3 million of additional litigation settlement expense in general and administrative expenses in the condensed consolidated statements of operations for the ~~Current Predecessor YTD Period~~three and six months ended June 30, 2020 (Predecessor) 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 later of: (i) June 1, 2021 or (ii)~~ 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 ~~September~~June 30, ~~2020~~2021 (Successor).

~~Delivery Commitments~~—The Company had a delivery contract tied to its oil production in the Williston Basin. The effective date of this contract was contingent upon the completion of certain related pipelines, the construction of which has not yet commenced. Under the terms of the agreement, Whiting was committed to deliver 10 MBbl/d for a term of seven years. In July 2020, the Company elected to terminate the agreement and is 0 longer required to deliver the committed volumes.

~~16. 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. The Company incurred one-time net charges related to these restructurings of $7 million and $8 million, respectively, 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 condensed consolidated statement of operations.

3728

Table of Contents

16. SUBSEQUENT EVENTS

Williston Basin Acquisition—On July 19, 2021, the Company entered into a purchase and sale agreement to acquire interests in approximately 8,750 net acres in the Williston Basin, including interests in 76 gross (50.2 net) producing wells, 5 gross (2.3 net) drilled and uncompleted oil and gas wells and undeveloped acreage located in Mountrail County, North Dakota for an aggregate purchase price of $271 million (before closing adjustments). Upon executing the agreement, the company tendered a $23 million deposit which will be held in escrow until closing of the transaction. The transaction is anticipated to close in September 2021 and the Company plans to account for the transaction using the acquisition method of accounting.

Denver-Julesburg Basin Divestiture—On July 21, 2021, the Company entered into a purchase and sale agreement for the divestiture 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 sales proceeds of $187 million (before closing adjustments). Additionally during July 2021, the Company executed derivative contracts that will be novated to the purchaser upon closing of the transaction. As of July 28, 2021, these derivative contracts covered the sale of 321,000 Bbl and 844,500 Bbl of oil and 870,000 MMBtu and 3,125,000 MMBtu of natural gas for the remainder of 2021 and the full year 2022, respectively. The transaction is anticipated to close in September 2021.

Table of Contents

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

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

Overview

We are an independent oil and gas company engaged in development, production and acquisition activities primarily in the Rocky Mountains region of the United States where we are focused on developing our ~~largest~~large resource play in the Williston Basin of North Dakota and Montana. As a result of the sharp decline in commodity prices during the first nine months of 2020 as well as our chapter 11 reorganization, we have significantly decreased our level of capital spending to more closely align with our reduced cash flows from operating activities. We ~~have concentrated~~are currently focusing our capital ~~program~~programs on drilling and workover opportunities that we believe provide the greatest well-level returns in order to maintain consistent production levels and generate free cash flow, and we are selectively pursuing acquisitions that complement our existing core properties. During 2021, we are focused on high-return projects in our asset portfolio that ~~are expected to~~will generate ~~acceptable rates of return in the current price environment.~~significant cash flow from operations. We continually evaluate our property portfolio and sell properties when we believe that the sales price realized will provide an above average rate of return for the property or when the property no longer matches the profile of properties we desire to own. Refer to ~~the “Acquisitions and Divestitures” footnote in the notes to condensed consolidated financial statements~~“Recent Developments” below for more information on our recent acquisition and divestiture activity.

Our revenue, profitability, future growth rate and cash flows depend on many factors which are beyond our control, such as oil and gas ~~prices,~~prices; economic, political and regulatory ~~developments,~~developments; the financial condition of our industry ~~partners,~~partners; competition from other sources of ~~energy,~~energy; and the other items discussed under the caption “Risk Factors” in Item 1A of ~~this Quarterly Report on Form 10-Q and~~ our Annual Report on Form 10-K for the period ended December 31, ~~2019.~~2020. Oil and gas prices historically have been volatile and may fluctuate widely in the future. The following table highlights the quarterly average NYMEX price trends for crude oil and natural gas prices since the first quarter of ~~2018:~~2019:

2018

2019

2020


Q1

Q2

Q3

Q4

Q1

Q2

Q3

Q4

Q1

Q2

Q3
Crude oil

$
62.89

$
67.90

$
69.50

$
58.83

$
54.90

$
59.83

$
56.45

$
56.96

$
46.08

$
27.85

$
40.94
Natural gas

$
3.13

$
2.77

$
2.88

$
3.62

$
3.00

$
2.58

$
2.29

$
2.44

$
1.88

$
1.66

$
1.89


	2019								2020								2021
	Q1		Q2		Q3		Q4		Q1		Q2		Q3		Q4		Q1		Q2
Crude oil	$	54.90	$	59.83	$	56.45	$	56.96	$	46.08	$	27.85	$	40.94	$	42.67	$	57.80	$	66.06
Natural gas	$	3.00	$	2.58	$	2.29	$	2.44	$	1.88	$	1.66	$	1.89	$	2.51	$	2.56	$	2.74

Oil prices ~~declined sharply~~improved during the first half of 2021 compared to the lows experienced during 2020, when prices were depressed primarily ~~in response~~due to ~~Saudi Arabia’s announcement of plans to abandon previously agreed upon output restraints and~~ the economic effects of the coronavirus ~~(“COVID-19”)~~ pandemic on the demand for oil and natural ~~gas.~~gas and uncertainty around output restraints on oil production agreed upon by the Organization of Petroleum Exporting Countries (the “OPEC”) and other oil exporting nations. While oil, NGL and natural gas prices ~~began to recover in the third quarter of 2020,~~have recovered significantly, uncertainties related to the demand for oil and natural gas products remain as the pandemic continues to impact the world ~~economy.~~economy and the OPEC continues to negotiate appropriate restraint levels to balance the market. Lower oil, NGL and natural gas prices decrease our revenues and reduce the amount of oil and natural gas that we can produce economically which decreases our oil and gas reserve quantities. Substantial and extended declines in oil, NGL and natural gas prices have resulted, and may result, in impairments of our proved oil and gas properties or undeveloped acreage (such as the impairments discussed below under ~~the~~ “Results of Operations”) and may materially and adversely affect our future business, financial condition, cash flows, results of operations, liquidity or ability to ~~finance~~fund planned capital expenditures. In addition, lower commodity prices may reduce the amount of our borrowing base under our credit agreement, which is determined at the discretion of our lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders. Upon a redetermination, if borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of the debt outstanding under our credit agreement. Alternatively, higher oil prices may result in significant mark-to-market losses being incurred on our commodity-based ~~derivatives.~~derivatives (such as the net derivative losses discussed below under “Results of Operations”).

3830

Table of Contents

Recent Developments

Williston Basin Acquisition. On July 19, 2021, we entered into a purchase and sale agreement for the acquisition of approximately 8,750 net acres and 4,200 BOE per day (80% oil) of net daily production in the Williston Basin, including interests in 76 gross (50.2 net) producing wells, 5 gross (2.3 net) drilled and uncompleted oil and gas wells and undeveloped acreage located in Mountrail County, North Dakota for an aggregate purchase price of $271 million (before closing adjustments). We expect this transaction to close in September 2021. We intend to finance this acquisition with proceeds from the Denver-Julesburg Basin divestiture discussed below and borrowings under our Credit Agreement.

Denver-Julesburg Basin Divestiture. On July 21, 2021, we entered into a purchase and sale agreement to divest all of our interests in producing assets with net daily production of approximately 7,100 BOE per day (51% oil) and undeveloped acreage, including the associated midstream assets, of our Redtail field located in the Denver-Julesburg Basin of Weld County, Colorado for aggregate sales proceeds of $187 million (before closing adjustments). We expect this transaction to close in September 2021. These properties represent 4% of our estimated proved reserves as of June 30, 2021. We intend to use the sales proceeds from this divestiture to fund the Williston Basin acquisition discussed above.

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

Beginning on the Emergence Date, we applied fresh start accounting, which resulted in a new basis of accounting and we became a new entity for financial reporting purposes. As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the consolidated financial statements after September 1, 2020 are not comparable with the consolidated financial statements on or prior to that ~~date. Refer to~~date and the ~~“Fresh Start Accounting” footnote in the condensed consolidated~~historical financial statements on or before the Emergence Date are not a reliable indicator of our financial condition and results of operations for ~~more information.~~any period after the adoption of fresh start accounting. References to “Successor” refer to ~~the~~ Whiting ~~entity~~and its financial position and results of operations after ~~our emergence from bankruptcy on~~ the Emergence Date. References to “Predecessor” refer to Whiting and its financial position and results of operations on or before the ~~Whiting entity prior to our emergence from bankruptcy.~~Emergence Date. References to “Successor YTD Period” ~~refer~~relate to the ~~period from September 1, 2020 through September~~six months ended June 30, 2021. References to “Predecessor YTD Period” relate to the six months ended June 30, 2020. ~~References to “Current Predecessor Quarter” and “Current Predecessor YTD Period” refer~~

Settlement of Bankruptcy Claims. Prior to the ~~periods from July 1, 2020 through August 31, 2020~~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 ~~1, 2020 through August 31, 2020, respectively. References~~2021, WOG and Tallgrass entered into a settlement agreement to “Prior Predecessor Quarter” and “Prior Predecessor YTD Period” refer to the three and nine months ended September 30, 2019, respectively. Although GAAP requires that we report on our results for the Successor Period and the Current Predecessor Quarter and Current Predecessor YTD Period separately, in certain circumstances management views our operating results for the three and nine months ended September 30, 2020 by combining the resultsresolve all of the ~~applicable Predecessor~~related claims before the Bankruptcy Court relating to such executory contracts, terminated the PWA and ~~Successor periods in order to provide~~entered into a new Water Transport, Gathering and Disposal Agreement. In accordance with the ~~most meaningful comparison of our current results to prior periods. Accordingly, references to “Combined Current Quarter”~~settlement agreement, we made a $2 million cash payment and ~~“Combined Current YTD Period” refer to the three and nine months ended September 30, 2020, respectively.~~

~~On the Emergence Date and pursuant to the Plan, we:~~

~~(1)~~

~~amended and restated our certificate of incorporation and bylaws;~~

~~(2)~~

~~constituted a new Successor board of directors;~~

~~(3)~~

~~appointed a new Chief Executive Officer and a new Chief Financial Officer;~~

~~(4)~~

~~issued:~~

●

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

●

~~1,233,580 shares of the Successor’s common stock pro rata to holders of the Predecessor’s common stock,~~

●

~~4,837,387 Series A Warrants to purchasethe 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; and~~

~~We also reserved 3,070,201~~issued 948,897 shares of the Successor’s common stock for potential future distribution to certain general unsecured claimants whose claim values are currently pending resolution in the Bankruptcy Court. Any remaining reserved shares that are not distributed to resolve these claims will be cancelled. In addition, 4,035,885 shares have been reserved for distribution under our 2020 equity incentive plan, as further detailed in the “Stock-Based Compensation” footnote in the notespursuant to the ~~condensed consolidated financial statements for more information.~~

~~(5)~~

~~entered into a reserves-based credit agreement with a syndicate of banks~~ ~~(the “Exit Credit Agreement”) with initial aggregate commitments and borrowing base of $750 million and the ability~~confirmed Plan to ~~increase the aggregate commitments by up to an additional $750 million, subject to certain conditions.~~

~~Table of Contents~~

~~(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.

~~Proved Reserves.~~ As a ~~result of lower crude oil, NGL and natural gas prices and a substantial reduction~~Tallgrass entity in our capital plan incorporated into our reserve estimates at September 30, 2020, our proved developed reserves decreased from 358.9 MMBOE as of December 31, 2019 to 218.5 MMBOE as of September 30, 2020, which represents a 39% reduction between periods. Additionally, our proved undeveloped reserves decreased from 126.6 MMBOE as of December 31, 2019 to 40.2 MMBOE as of September 30, 2020, which represents a 68% reduction between periods. Approximately 86% of this decrease in our proved undeveloped reserve volumes was the result of a change in the planned timing of the drilling and completion of PUD reserve locations outside of the SEC five-year window. February 2021.

~~Exploration and Development Expenditures.~~ The changes in our capital plan have also resulted in reductions to our 2020 Exploration and Development (“E&D”) budget from a previous midpoint of $418 million to $215 million in order to preserve our liquidity and maximize value to our shareholders in the current crude oil price environment. Refer to “2020 Highlights and Future Considerations” and “Liquidity and Capital Resources” for more information on our reduced activity levels and planned capital expenditures.

~~2020~~2021 Highlights and Future Considerations

Operational Highlights

~~Operational Response to Market Conditions~~

As a result of the significant decline in crude oil prices in the first nine months of 2020, we suspended all drilling and completion activity and terminated our drilling rig contracts in April 2020, incurring insignificant early termination and demobilization fees. Additionally, we curtailed production from certain of our producing wells, reduced the number of workover rigs operating on our properties, deferred the completion of certain wells and delayed placing some of our completed wells online during the second quarter. Substantial and extended declines in crude oil prices may result in our decision to voluntarily curtail production, reduce workover activity or change the timing of when wells are placed online in the future.

~~Northern Rocky Mountains~~North Dakota & Montana – Williston Basin

Our properties in the Williston Basin of North Dakota and Montana target the Bakken and Three Forks formations. Net production from ~~the Williston Basin~~North Dakota and Montana averaged ~~84.5~~85.2 MBOE/d for the ~~third~~second quarter of ~~2020, representing~~2021, which represents a ~~5% decrease~~4% increase from ~~89.3 MBOE/d~~the first quarter of 2021 and is in line with our production exit rate for the fourth quarter of 2020. Across our acreage in the Williston Basin, we have implemented custom, right-sized completion designs to increase well performance while reducing cost. We continue to focus on reducing time-on-location and total well cost while maximizing our lateral footage through drilling best practices including utilizing top tier drilling rigs, advanced downhole motor and drill bit technology and our custom drilling fluid system.

During portions of the second quarter of ~~2020. We turned 7~~2021, we had one active completion crew in this area, and we plan to continue with this crew intermittently for the remainder of 2021. In addition, we resumed drilling in the Williston Basin in February with one rig, and we plan to add a second rig in September 2021. During the second quarter of 2021, we drilled 9 gross (5.6 net) wells ~~online~~and TIL 9 gross (5.4 net) wells in this area, and as of June 30, 2021, we have 21 gross (15.3 net) drilled uncompleted wells. Under our current 2021 capital program, we expect to TIL approximately 55 gross (35.4 net) wells in this area during the ~~third quarter~~year.

Table of ~~2020.~~ Contents

On July 19, 2021, we entered into a purchase and sale agreement to acquire additional oil and gas properties in the Williston Basin for an aggregate purchase price of $271 million (before closing adjustments). Refer to “Recent Developments” above for additional details.

~~Central Rocky Mountains~~Colorado – Denver-Julesburg Basin

Our properties in the Denver-Julesburg Basin ~~(“DJ Basin”)~~ in Weld County, Colorado produce from the Niobrara “A,” “B” and “C” zones and the Codell/Fort Hays formations. Net production from ~~the Redtail field~~Colorado averaged ~~8.8~~7.1 MBOE/d ~~in the third quarter of 2020, representing a 2% decrease from 9.0 MBOE/d in~~for the second quarter of ~~2020.~~ 2021, representing a 5% decrease from the first quarter of 2021. As detailed in “Recent Developments” above, on July 21, 2021, we entered into a purchase and sale agreement to divest all properties associated with our Redtail field, including the associated midstream assets, and we expect this transaction to close in September 2021.

Financing Highlights

On the Emergence Date, in connection with our emergence from the Chapter 11 Cases, we repaid all outstanding borrowings and accrued interest on the Predecessor’s credit agreement (the “Predecessor Credit Agreement”) and entered into a reserves-based credit agreement with a syndicate of banks (the “Credit Agreement”). In April 2021, the ~~Exit~~borrowing base and aggregate commitments under the Credit Agreement. of $750 million were reaffirmed in connection with our semi-annual borrowing base redetermination. Refer to ~~“Recent Developments” above and~~ the “Long-Term Debt” footnote in the notes to the condensed consolidated financial statements for more information.

Additionally, on the Emergence Date, we issued 36,817,630 shares of the Successor’s common stock to the holders of our outstanding senior notes in settlement of the outstanding principal and related accrued interest. Upon such settlement, we recognized a $1 billion gain in reorganization items, net. Refer to the “Fresh Start Accounting” footnote in the condensed consolidated financial statements for more information.

In March 2020, we paid $53 million to repurchase $73 million aggregate principal amount of our 1.25% Convertible Senior Notes due April 1, 2020 (the “Convertible Senior Notes”), which payment consisted of the average 72.5% purchase price plus all accrued and

~~Table of Contents~~

unpaid interest on the notes. We financed the repurchases with borrowings under the Predecessor Credit Agreement. Additionally, in March 2020, holders of $3 million aggregate principal amount of Convertible Senior Notes timely elected to convert. Upon such conversion, the holders of these notes were entitled to receive an insignificant cash payment on April 1, 2020, which we did not pay in conjunction with the filing of the Chapter 11 Cases. Refer to the “Chapter 11 Emergence” and “Long-Term Debt” footnotes in the notes to the condensed consolidated financial statements for more information on these repurchases and conversions.

~~Acquisition and Divestiture Highlights~~

On January 9, 2020, we completed the divestiture of our 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). The divested properties consisted of less than 1% of our estimated proved reserves as of December 31, 2019 and 1% of our average daily production for the year ended December 31, 2019.

Dakota Access Pipeline

On March 25, 2020, the U.S. District Court for D.C. (“D.C. District Court”) found that the U.S. Army Corps of Engineers (“Army Corps”) had violated the National Environmental Policy Act when it granted an easement relating to a portion of the Dakota Access Pipeline ~~(the “DAPL”~~(“DAPL”) because it had failed to ~~conduct~~prepare an environmental impact ~~statement.~~statement (“EIS”). As a result, in an order issued July 6, 2020, the ~~court~~D.C. District Court vacated the easement and directed that the DAPL be shut down and emptied of oil by August 5, 2020. OnAfter issuing a stay of the order to shut down the pipeline on August 5, 2020, the U.S. Court of Appeals for the D.C. Circuit ~~granted a stay~~(“D.C. Appellate Court”), on January 26, 2021, affirmed the D.C. District Court’s decision to vacate the easement and concluded that the D.C. District Court must further consider whether shut down of the ~~portion of~~DAPL is an appropriate remedy while the ~~order directing~~Army Corps develops an EIS. On May 21, 2021, the D.C. District Court ruled that it would not issue an injunction requiring a shutdown of the ~~DAPL. The stay allows~~DAPL and that the DAPL tocould continue to operate while the Army Corps prepares an EIS. The D.C. District Court further ruled on June 22, 2021 that the litigation be dismissed and that the plaintiffs could renew their challenge to DAPL upon the Army Corps’ issuance of an EIS. Barring an appeal by plaintiffs or different discretionary action by the Army Corps, these rulings allow the DAPL’s continued operation unless and until ~~a further ruling is made. It is possible~~new challenges are made and succeed following issuance of the ~~DAPL may be required to be shut down as a result~~EIS, which the Army Corps anticipates issuing in the spring of ~~such litigation.~~2022. The potential disruption of transportation as a result of the DAPL being shut down or the anticipation of the DAPL being shut down could negatively impact our ability to achieve the most favorable prices for our crude oil ~~production. In November, we expect to transport approximately 40%~~production, which could have an adverse effect on our business, financial condition, results of ~~our crude oil volumes through the DAPL.~~operations or cash flows. To help mitigate the potential impact of an unfavorable ~~ruling,~~outcome, we ~~are coordinating~~have coordinated with our midstream partners and downstream markets to source transportation alternatives.

~~Restructuring~~

During September 2020, we executed a workforce reduction as part of an organizational redesign and cost reduction strategy to better align our business with the current operating environment and drive long-term value. We incurred a one-time net charge related to this restructuring of $7 million, which was recorded to general and administrative expenses during the Successor Period.

4132

Table of Contents

Results of Operations

We cannot adequately benchmark certain operating results of the Successor Period against any of the previous periods reported in our condensed consolidated financial statements without combining that period with the Current Predecessor YTD Period or the Current Predecessor Quarter, as applicable, and we do not believe that reviewing the results of this period in isolation would be useful in identifying trends in or reaching conclusions regarding our overall operating performance. Management believes that our key performance metrics such as sales, production, lease operating expenses and general and administrative expenses for the Successor Period when combined with the Current Predecessor YTD Period or the Current Predecessor Quarter, as applicable, provide more meaningful comparisons to prior periods and is more useful in identifying current business trends. Accordingly, in addition to presenting our results of operations as reported in our condensed consolidated financial statements in accordance with GAAP, in certain circumstances the discussion in “Results of Operations” below utilizes the combined results for the three and nine months ended September 30, 2020.

Successor ~~Period and Current Predecessor~~ YTD Period Compared to ~~Prior~~ Predecessor YTD Period


	Successor		Predecessor		Non-GAAP		Predecessor		Successor		Predecessor
	One Month Ended September 30, 2020		Eight Months Ended August 31, 2020		Combined Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
Net production
Oil (MMBbl)		1.7		15.3		17.0		22.4		9.7		11.8
NGLs (MMBbl)		0.6		4.5		5.1		5.7		3.4		3.4
Natural gas (Bcf)		3.6		29.7		33.3		38.2		20.9		22.6
Total production (MMBOE)		2.9		24.7		27.7		34.5		16.5		19.0
Net sales (in millions)
Net sales (in millions) ⁽¹⁾
Oil ⁽¹⁾	$	60.4	$	440.8	$	501.2	$	1,133.3	$	565.1	$	323.8
NGLs		1.8		20.1		21.9		34.8		55.3		11.3
Natural gas ⁽¹⁾		(1.1)		(1.9)		(3.0)		23.5		34.3		1.3
Total oil, NGL and natural gas sales	$	61.1	$	459.0	$	520.1	$	1,191.6	$	654.7	$	336.4
Average sales prices
Oil (per Bbl) ⁽¹⁾	$	34.58	$	28.86	$	29.45	$	50.51	$	58.37	$	27.42
Effect of oil hedges on average price (per Bbl)		0.28		3.00		2.72		0.66		(10.91)		3.91
Oil after the effect of hedging (per Bbl)	$	34.86	$	31.86	$	32.17	$	51.17	$	47.46	$	31.33
Weighted average NYMEX price (per Bbl) ⁽²⁾	$	39.63	$	38.23	$	38.37	$	56.99	$	61.95	$	37.25
NGLs (per Bbl)(1)	$	3.19	$	4.45	$	4.31	$	6.09	$	16.47	$	3.27
Effect of NGL hedges on average price (per Bbl)										(0.26)		-
NGLs after the effect of hedging (per Bbl)									$	16.21	$	3.27
Natural gas (per Mcf) ⁽¹⁾	$	(0.30)	$	(0.06)	$	(0.09)	$	0.62	$	1.64	$	0.06
Effect of natural gas hedges on average price (per Mcf)		0.15		(0.01)		0.01		-		(0.02)		-
Natural gas (per Mcf)(1)	$	(0.15)	$	(0.07)	$	(0.08)	$	0.62
Natural gas after the effect of hedging (per Mcf)									$	1.62	$	0.06
Weighted average NYMEX price (per MMBtu) ⁽²⁾	$	2.24	$	1.76	$	1.81	$	2.62	$	2.65	$	1.77
Costs and expenses (per BOE)
Lease operating expenses	$	6.37	$	6.40	$	6.39	$	7.43	$	7.48	$	6.61
Transportation, gathering, compression and other	$	0.68	$	0.90	$	0.88	$	0.93	$	0.88	$	0.95
Production and ad valorem taxes	$	2.03	$	1.67	$	1.70	$	2.98	$	3.02	$	1.62
Depreciation, depletion and amortization	$	6.91	$	13.69	$	12.98	$	17.74	$	6.38	$	14.07
General and administrative	$	3.55	$	3.71	$	3.69	$	2.82	$	1.35	$	3.96

(1)	Before consideration of hedging transactions.

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

~~Table of Contents~~

Oil, NGL and Natural Gas Sales. Our oil, NGL and natural gas sales revenue ~~decreased $672~~increased $318 million to ~~$520~~$655 million when comparing the ~~Combined Current~~Successor YTD Period to the ~~Prior~~ Predecessor YTD Period. Changes in sales revenue between periods are due to changes in production sold and changes in average commodity prices realized (excluding the impacts of hedging). ~~For~~When comparing the ~~Combined Current~~Successor YTD Period ~~decreases in total production accounted for approximately $281 million of~~to the ~~change in revenue and decreases~~Predecessor YTD Period, increases in commodity prices realized between periods accounted for ~~approximately $391~~a $377 million ~~of the change~~increase in revenue, ~~when comparing to the Prior Predecessor YTD Period.~~which was partially offset by a decrease in total production between periods that accounted for a $59 million decrease in revenue.

Table of Contents

Our oil, NGL and gas volumes decreased ~~24%~~18%, ~~11%~~3% and ~~13%~~7%, respectively, between periods. The volume decreases between periods were primarily ~~attributable to~~driven by normal field production decline as a result of operational decisions to curtail production, reduce drilling and workover activity, defer completions of certain wells and delay placing some of our completed wells online during the ~~second~~majority of 2020 as a result of sustained lower prices and ~~third quarters as described in “Operational Response to Market Conditions” above and normal field production decline. These decreases were~~our bankruptcy filing. This decline was partially offset by ~~increased~~ production from new wells drilled and completed ~~over~~during the ~~last twelve months~~first half of 2021 in the Williston Basin.

Our average price for oil, NGLs and natural gas (before the effects of hedging) ~~decreased 42%~~increased 113%, ~~29%~~404% and ~~115%~~2,633%, respectively, between periods. Our average ~~sales~~realized price ~~realized~~ for oil, NGLs and natural gas ~~during~~primarily increased as a result of favorable movements in the ~~Combined Current YTD Period~~NYMEX and Mont Belvieu market indices between periods. During the first half of 2020, our average realized price for oil was ~~negatively~~ impacted by ~~rising market differentials as compared~~deficiency payments we made under a physical delivery contract in Colorado due to ~~market indices as well as high fixed third-party costs for transportation, gathering~~our inability to meet the minimum volume commitments under this contract. This contract was terminated in April 2020 and ~~compression services. These third-party costs sometimes exceed~~did not continue to negatively impact the ~~ultimate~~ price we receive for oil from our Redtail field after that time. During the Predecessor YTD Period, our total average sales price was $2.05 per Bbl lower as a result of these deficiency payments. Additionally, our oil average realized price differentials to NYMEX improved between periods as a result of decreased basin-wide utilization of pipeline capacity and lower firm transportation costs, and our natural gas ~~and accordingly can~~average realized price differentials to NYMEX also improved significantly as a result of stronger regional pricing in ~~negative gas revenues, which occurred~~the Williston Basin during the ~~Combined Current~~Successor YTD Period. While these negative gas prices adversely affect our total revenues, we have continued to produce our wells in order to sell the associated oil and NGLs from these wells and to meet lease and regulatory requirements.

Lease Operating Expenses. Our lease operating expenses (“LOE”) during the ~~Combined Current~~Successor YTD Period were ~~$177~~$124 million, ~~an $80~~a $2 million decrease over the ~~Prior~~ Predecessor YTD Period. This decrease was primarily due to ~~(i)~~an $11 million decrease in saltwater disposal costs as well as other ongoing cost reduction initiatives which ~~were implemented beginning in the third quarter of 2019 which led~~contributed to ~~a $62~~an additional $3 million decrease in LOE ~~(ii) a $12~~between periods, partially offset by an $8 million increase in ~~saltwater disposal income and (iii) a $6 million decrease in~~ well workover costs associated with increased activity ~~between periods.~~during the Successor YTD Period.

Our lease operating expenses on a BOE basis ~~also decreased~~increased when comparing the ~~Combined Current~~Successor YTD Period to the ~~Prior~~ Predecessor YTD Period. LOE per BOE amounted to ~~$6.39~~$7.48 during the ~~Combined Current~~Successor YTD Period, which represents ~~a decrease~~an increase of ~~$1.04~~$0.87 per BOE (or ~~14%~~13%) from the ~~Prior~~ Predecessor YTD Period. This ~~decrease~~increase was mainly due to lower overall production volumes between periods, partially offset by the overall decrease in LOE discussed ~~above partially offset by lower overall production volumes between periods.~~above.

Transportation, Gathering, Compression and Other. Our transportation, gathering, compression and other (“TGC”) expenses during the ~~Combined Current~~Successor YTD Period were ~~$24~~$14 million, ~~an $8~~a $4 million decrease over the ~~Prior~~ Predecessor YTD Period. This decrease mainly relates to lower production ~~volumes. Additionally, during the Combined Current YTD Period, certain oil~~ volumes ~~that are typically transported by pipeline were instead transported by truck. Trucking fees are recorded~~between periods and decreased rates negotiated with midstream partners as a ~~reduction to~~result of the ~~oil price received and not as TGC expense as control transfers prior to transport.~~Chapter 11 Cases.

TGC per BOE ~~slightly~~also decreased when comparing the ~~Combined Current~~Successor YTD Period to the ~~Prior~~ Predecessor YTD Period. TGC per BOE amounted to $0.88 per BOE, ~~during the Combined Current YTD Period,~~ which represents a decrease of ~~$0.05~~$0.07 per BOE (or 5%7%) from the ~~Prior~~ Predecessor YTD Period. This decrease was primarily due to ~~additional volumes being trucked during~~ the ~~Combined Current YTD Period as described above, partially offset by lower production volumes between periods.~~decreased rates negotiated with midstream partners discussed above.

Production and Ad Valorem ~~Taxes~~Taxes.. Our production and ad valorem taxes during the ~~Combined Current~~Successor YTD Period were ~~$47~~$50 million, a ~~$56~~$19 million ~~decrease~~increase over the ~~Prior~~ Predecessor YTD Period, which was primarily due to ~~lower~~higher sales revenue between periods. Our production taxes, however, are generally calculated as a percentage of net oil, NGL and natural gas sales revenue before the effects of hedging, and this percentage on a company-wide basis was ~~8.6%~~7.2% and ~~8.5%~~8.7% for the ~~Combined Current~~Successor YTD Period and ~~Prior~~the Predecessor YTD Period, respectively. Our production tax rate for the Successor YTD Period was lower than the rate for the Predecessor YTD Period as certain production taxes levied on natural gas are volume-based and did not increase with the increase in realized prices. Additionally, we recognized Colorado severance tax refunds during the Successor YTD period.

4334

Table of Contents

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


	Successor		Predecessor		Non-GAAP		Predecessor		Successor		Predecessor
	One Month Ended September 30, 2020		Eight Months Ended August 31, 2020		Combined Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
Depletion	$	18,735	$	327,227	$	345,962	$	599,320	$	98,232	$	258,894
Accretion of asset retirement obligations		928		8,200		9,128		8,680		4,412		6,107
Depreciation		447		3,330		3,777		4,166		2,703		2,516
Total	$	20,110	$	338,757	$	358,867	$	612,166	$	105,347	$	267,517

DD&A decreased between the ~~Current Predecessor~~Successor YTD Period and the ~~Prior~~ Predecessor YTD Period primarily due to ~~$272~~$161 million in lower depletion expense, consisting of ~~an $80 million decrease due to lower overall production volumes during the Current Predecessor YTD Period, as well as~~ a ~~$192~~$146 million decrease related to a lower depletion rate between ~~periods.~~periods and a $15 million decrease related to lower overall production volumes during the Successor YTD Period. On a BOE basis, our overall DD&A rate of ~~$13.69~~$6.38 per BOE for the ~~Current Predecessor~~Successor YTD Period was ~~23%~~55% lower than the rate of ~~$17.74~~$14.07 per BOE for the ~~Prior~~ Predecessor YTD Period. The primary factors contributing to this lower DD&A rate were impairment write-downs on proved oil and gas properties in the Williston Basin recognized in the first and second quarters of 2020 ~~offset by downward revisions to proved reserves over the last twelve months, which were largely driven by lower commodity prices~~ and ~~development plan changes. The Successor Period DD&A rate of $6.91 is lower than both Predecessor periods due to~~ the application of fresh start accounting upon emergence from the Chapter 11 Cases, under which we adjusted the value of our oil and gas properties down to their ~~current~~ fair ~~values.~~values on the Emergence Date. Refer to the “Fresh Start Accounting” footnote in the ~~condensed~~notes to the consolidated financial statements in Item 8 of our Annual Report on Form 10-K for the period ending December 31, 2020 for more information. Also contributing to the lower DD&A rate in the Successor YTD Period were upward reserve revisions to proved reserves, which were largely driven by higher commodity prices during the first half of 2021.

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


	Successor		Predecessor		Non-GAAP		Predecessor		Successor		Predecessor
	One Month Ended September 30, 2020		Eight Months Ended August 31, 2020		Combined Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
Impairment									$	2,691	$	4,154,369
Exploration	$	4,207	$	22,945	$	27,152	$	28,316		1,978		20,244
Impairment		-		4,161,885		4,161,885		15,729
Total	$	4,207	$	4,184,830	$	4,189,037	$	44,045	$	4,669	$	4,174,613

Impairment expense for ~~Current~~the Successor YTD Period primarily relates to the amortization of leasehold costs associated with individually insignificant unproved properties. Impairment expense for the Predecessor YTD Period primarily related to (i) $4 billion in non-cash impairment charges for the partial write-down of proved oil and gas properties across our Williston Basin resource play due to a reduction in reserves driven by depressed oil prices and a resultant decline in future development plans for those properties at the ~~properties~~time and (ii) $12 million in impairment write-downs of undeveloped acreage costs for leases where we no longer ~~have~~had plans to drill. ~~Impairment expense for~~

Exploration costs decreased $18 million during the ~~Prior~~Successor YTD Period compared to the Predecessor YTD Period primarily ~~relates~~due to (i) $12 million of lower deficiency fees paid under our produced water disposal agreement at our Redtail field, which contract was rejected through the ~~amortization~~Chapter 11 Cases and (ii) $5 million of ~~leasehold costs associated with individually insignificant unproved properties.~~lower geology-related general and administrative expenses due to a company restructuring in September 2020.

4435

Table of Contents

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


	Successor		Predecessor		Non-GAAP		Predecessor		Successor		Predecessor
	One Month Ended September 30, 2020		Eight Months Ended August 31, 2020		Combined Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
General and administrative expenses	$	16,618	$	139,934	$	156,552	$	170,924
General and administrative expenses, other⁽¹⁾									$	54,098	$	108,371
Stock-based compensation, non-cash										4,764		3,401
Reimbursements and allocations		(6,273)		(48,118)		(54,391)		(73,487)		(36,576)		(36,469)
General and administrative expenses, net (GAAP)		10,345		91,816		102,161		97,437		22,286		75,303
Less: Significant one-time costs ⁽¹⁾		(9,333)		(32,888)		(42,221)		(7,781)
Non-GAAP general and administrative expenses less one-time costs	$	1,012	$	58,928	$	59,940	$	89,656
Less: Significant cost drivers ⁽²⁾										-		(26,884)
Non-GAAP general and administrative expenses less significant cost drivers⁽³⁾									$	22,286	$	48,419

(1)

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

(2)	Includes cash retention incentives for Predecessor executives and directors, third-party advisory and legal fees related to the Chapter 11 Cases and charges related to a litigation settlement discussed below.

(3)

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

G&A ~~expense before reimbursements and allocations~~expenses, other during the ~~Combined Current~~Successor YTD Period decreased ~~$14~~$54 million compared to the ~~Prior~~ Predecessor YTD Period primarily due to $27 million of significant cost ~~reduction initiatives instituted beginning~~drivers incurred during the Predecessor YTD Period, including (i) $16 million in cash retention incentives paid to executives and directors, (ii) $8 million of third party advisory and legal fees incurred to prepare for the Chapter 11 Cases and (iii) $3 million of additional costs related to a legal settlement. In addition, compensation costs decreased by $18 million as a result of a company restructuring completed in the third quarter of 2019 and two separate company restructurings in August 2019 and September 2020, resulting in $33 million of lower compensation costs and $9 million of lower corporate overhead between periods. In addition, we incurred $7 million of severance and restructuring costs in the Combined Current YTD Period, as compared to $8 million of severance and restructuring costs in the Prior Predecessor YTD Period. These decreases were partially offset by (i) $22 million paid to Predecessor executives and directors as cash retention incentives during the Combined Current YTD Period, (ii) $10 million of third-party advisory and legal fees related to the Chapter 11 Cases that were incurred prior to the Petition Date or after the Emergence Date and (iii) $3 million of charges related to a litigation settlement. The decrease in reimbursements and allocations for the Combined Current YTD Period was the result of a lower number of field workers on Whiting-operated properties associated with reduced drilling activity and staffing reductions. 2020.

G&A expense per BOE amounted to ~~$3.69~~$1.35 during the ~~Combined Current~~Successor YTD Period, which represents ~~an increase~~a decrease of ~~$0.87~~$2.61 per BOE (or ~~31%~~66%) from the ~~Prior~~ Predecessor YTD Period. This ~~increase~~decrease was mainly due to the ~~one-time costs~~overall decrease in G&A discussed above ~~as well as~~partially offset by lower overall production volumes between periods. G&A expense per BOE excluding ~~one-time costs were $2.17~~significant cost drivers was $2.55 per BOE ~~and $2.60 per BOE, for~~during the ~~Combined Current YTD Period and the Prior~~ Predecessor YTD ~~period, respectively.~~Period.

Derivative (Gain) Loss, Net. Our commodity derivative contracts are marked to market each quarter with fair value gains and losses recognized immediately in earnings as derivative (gain) loss, net. Cash flow, however, is only impacted to the extent that settlements under these contracts result in us making or receiving a payment to or from the counterparty. Derivative (gain) loss, net, amounted to a ~~gain~~loss of ~~$212~~$402 million and a ~~loss~~gain of $7$225 million for the ~~Combined Current~~Successor YTD Period and ~~Prior~~the Predecessor YTD Period, respectively. These gains and losses relate to our collar, swap, basis swap and differential swap commodity derivative contracts and resulted from the ~~downward~~upward and ~~upward~~downward shifts, respectively, in the futures curve of forecasted commodity prices for crude oil, ~~and~~ natural gas and NGLs during ~~the respective~~those periods.

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

Gain on Sale of Properties. During the Successor YTD period, a series of non-core producing oil and gas properties were divested for aggregate sales proceeds of $6.4 million (before closing adjustments). As a result of one of these divestitures, our asset retirement obligation liability decreased by $10 million and we recognized a corresponding gain on sale of $10 million.

4536

Table of Contents

Interest Expense. The components of our interest expense were as follows (in thousands):


	Successor		Predecessor		Non-GAAP		Predecessor		Successor		Predecessor
	One Month Ended September 30, 2020		Eight Months Ended August 31, 2020		Combined Nine Months Ended September 30, 2020		Nine Months Ended September 30, 2019		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
Credit agreements	$	1,665	$	23,948	$	25,613	$	9,281	$	6,911	$	16,496
Amortization of debt issue costs, discounts and premiums		371		13,536		13,907		23,707		1,773		9,786
Other		92		730		822		607		400		553
Notes		-		34,840		34,840		111,679		-		34,840
Total	$	2,128	$	73,054	$	75,182	$	145,274	$	9,084	$	61,675

The decrease in interest expense of ~~$72~~$53 million ~~between~~during the Successor YTD Period compared to the Predecessor ~~periods~~YTD Period was primarily attributable to lower interest costs incurred on our notes and our credit agreements and lower amortization of debt issue costs, discounts and ~~premiums during the Current Predecessor YTD Period compared to the Prior Predecessor YTD Period.~~premiums. Upon the filing of the Chapter 11 Cases on April 1, 2020, we discontinued accruing interest on our ~~Senior Notes,~~notes, which resulted in a ~~$77~~$35 million decrease in note interest expense between periods. ~~Additionally,~~In addition, the remaining unamortized debt issuance costs and premiums associated with ~~our Senior Notes~~these notes were written off ~~to reorganization items, net in conjunction with~~on the ~~filing of the Chapter 11 Cases,~~Petition Date, resulting in ~~a $10~~an $8 million decrease in amortization expense ~~during~~between periods. Upon emergence from the ~~Current Predecessor YTD Period compared to the Prior Predecessor YTD Period.~~Chapter 11 Cases, all outstanding obligations under our notes were cancelled in exchange for shares of Successor common stock. Refer to the “Chapter 11 Emergence” and “Long-Term Debt” footnotes in the notes to the condensed consolidated financial statements for more information.

The ~~decreases~~decrease in interest expense ~~discussed above were partially offset by a $15 million increase in interest~~ incurred on ~~the Predecessor Credit Agreement between Predecessor periods due to a higher average outstanding balance as well as an additional 2% default interest rate charged on~~our credit agreements of $10 million resulted from lower borrowings outstanding ~~for the duration of the Chapter 11 Cases.~~between periods. Our weighted average borrowings outstanding under the Credit Agreement during the ~~Current Predecessor~~Successor YTD Period were ~~$761~~$268 million compared to ~~$105~~$710 million ~~for~~weighted average borrowings outstanding under the ~~Prior~~Predecessor Credit Agreement during the Predecessor YTD Period.

Our weighted average debt outstanding during the ~~Current Predecessor~~Successor YTD Period, ~~was $3.2 billion versus $2.9 billion for~~consisting solely of borrowings under the Prior Predecessor YTD Period. Our weighted average effective cash interest rate was 2.8% during the Current Predecessor YTD Period compared to 5.5% during the Prior Predecessor YTD Period, primarily due to the discontinuation of interest expense on our Senior Notes beginning in April 2020.

Upon emergence from the Chapter 11 Cases, we were relieved of all liabilities related to our Senior Notes in exchange for Successor common stock, we repaid all outstanding borrowings and accrued interest on the Predecessor Credit Agreement, ~~and we entered into the Exit Credit Agreement. Our weighted average borrowings outstanding during the Successor Period were $419~~was $268 million, with a weighted average cash interest rate of ~~4.8%~~5.2%. Our weighted average debt outstanding during the Predecessor YTD Period, consisting of the notes and borrowings outstanding on the Predecessor Credit Agreement, was $3.1 billion, with a weighted average cash interest rate of 3.3%.

Gain on Extinguishment of Debt. During the ~~Current~~ Predecessor YTD Period, we paid $53 million to repurchase $73 million aggregate principal amount of our Convertible Senior Notes and recognized a $23 million gain on extinguishment of debt. Refer to the “Long-Term Debt” footnote in the notes to condensed consolidated financial statements for more information on this repurchase. Additionally, in March 2020, the holders of $3 million aggregate principal amount of our Convertible Senior Notes elected to convert. Upon conversion, such holders of the converted Convertible Senior Notes were entitled to receive an insignificant cash payment on April 1, 2020, which we did not pay in conjunction with the filing of the Chapter 11 Cases. As a result of such conversion we recognized a $3 million gain on extinguishment of debt during the ~~Current~~ Predecessor YTD Period. ~~Refer to the “Long-Term Debt” footnote in the notes to condensed consolidated financial statements for more information on this repurchase and conversion.~~

Reorganization Items, Net. During the ~~Current~~ Predecessor YTD Period, we recognized ~~a net gain~~$42 million of ~~$217 million~~reorganization costs related to the Chapter 11 Cases, consisting of ~~(i) gains on settlement of certain liabilities, including our Senior Notes, upon consummation of the Plan, (ii) fresh start accounting fair value adjustments, (iii)~~ professional fees ~~recognized between the Petition Date~~ and ~~the Emergence Date and (iv)~~ the write-off of debt issuance costs and ~~premiums associated with our Senior Notes.~~premiums. Refer to the “Chapter 11 Emergence” ~~and “Fresh Start Accounting” footnotes~~footnote in the notes to the condensed consolidated financial statements for more information on amounts recorded to reorganization items, net.

Income Tax Expense (Benefit). As a result of the full valuation allowance on our U.S. deferred tax assets (“DTAs”) as of June 30, 2021 (Successor) and June 30, 2020 (Predecessor), we did not recognize any U.S. income tax expense or benefit during the periods presented, outside of a $1 million alternative minimum tax refund received during the Predecessor YTD period. This resulted in overall U.S. effective tax rates of 0% for both periods. During the Predecessor YTD Period, we reclassified $4 million of Canadian deferred tax expense to current.

4637

Table of Contents

~~Income Tax Benefit~~. As a result of pre-tax losses for the first six months of 2019, we transitioned from a net deferred tax liability position to a net deferred tax asset position which resulted in the recognition of a full valuation allowance on our deferred tax assets (“DTAs”) during the second quarter of 2019. During the fourth quarter of 2019, we recognized $74 million of Canadian deferred tax expense associated with the outside basis difference in Whiting Canadian Holding Company ULC pursuant to ASC 740-30-25-17. During the Combined Current YTD Period, we recorded a tax benefit of $68 million reflecting a reduction in the overall expected Canadian tax liability as a result of a legal entity restructuring we executed during the period. The remaining $6 million Canadian tax liability is expected to be payable in the fourth quarter of 2020. Refer to the “Income Taxes” footnote in the notes to the condensed consolidated financial statements for more information on the legal restructuring and related Canadian deferred tax liability.

We also recognized a $1 million U.S. income tax benefit during the Combined Current YTD Period related to an alternative minimum tax refund received. As a result of the full valuation allowance on our U.S. DTAs as of SeptemberThree Months Ended June 30, 2020 (Successor) and August 31, 2020 (Predecessor), no additional U.S. tax benefit or expense was recognized. Similarly, for the Prior Predecessor YTD Period we recognized a $1 million alternative tax refund received and no other U.S. tax expense or benefit was recognized as a result of the full valuation allowance recognized on our U.S. DTAs.

Our overall effective tax rate of 1.72% for the Combined Current YTD Period was lower than the U.S. statutory income tax rate as a result of the full valuation allowance on our U.S. DTAs and the reduction of our overall expected Canadian tax liability discussed above.

~~Table of Contents~~

~~Successor Period and Current Predecessor YTD Period~~2021 Compared to ~~Prior Predecessor YTD Period~~Three Months Ended March 31, 2021


									Successor
									Three Months Ended
	Successor		Predecessor		Non-GAAP		Predecessor		June 30,		March 31,
	One Month Ended September 30, 2020		Two Months Ended August 31, 2020		Combined Three Months Ended September 30, 2020		Three Months Ended September 30, 2019		2021		2021
Net production
Oil (MMBbl)		1.7		3.5		5.2		7.4		4.9		4.8
NGLs (MMBbl)		0.6		1.1		1.6		1.8		1.8		1.6
Natural gas (Bcf)		3.6		7.1		10.7		12.5		10.7		10.2
Total production (MMBOE)		2.9		5.7		8.6		11.4		8.4		8.1
Net sales (in millions)
Oil ⁽¹⁾	$	60.4	$	117.0	$	177.4	$	370.0
Net sales (in millions) ⁽¹⁾
Oil									$	308.4	$	256.7
NGLs		1.8		8.9		10.7		5.6		28.3		27.0
Natural gas ⁽¹⁾		(1.1)		(3.3)		(4.4)		0.3
Natural gas										13.3		21.0
Total oil, NGL and natural gas sales	$	61.1	$	122.6	$	183.7	$	375.9	$	350.0	$	304.7
Average sales prices						0.1
Oil (per Bbl) ⁽¹⁾	$	34.58	$	33.78	$	34.05	$	49.71	$	63.46	$	53.24
Effect of oil hedges on average price (per Bbl)		0.28		(0.12)		0.01		1.41		(13.64)		(8.16)
Oil net of hedging (per Bbl)	$	34.86	$	33.66	$	34.06	$	51.12
Oil after the effect of hedging (per Bbl)									$	49.82	$	45.08
Weighted average NYMEX price (per Bbl) ⁽²⁾	$	39.63	$	41.57	$	40.92	$	56.43	$	66.03	$	57.83
NGLs (per Bbl)	$	3.19	$	8.18	$	6.48	$	3.07
NGLs (per Bbl) ⁽¹⁾									$	15.76	$	17.28
Effect of NGL hedges on average price (per Bbl)										(0.47)		-
NGLs after the effect of hedging (per Bbl)									$	15.29	$	17.28
Natural gas (per Mcf) ⁽¹⁾	$	(0.30)	$	(0.46)	$	(0.41)	$	0.03	$	1.25	$	2.05
Effect of natural gas hedges on average price (per Mcf)		0.15		(0.04)		0.03		-		(0.04)		0.01
Natural gas (per Mcf)	$	(0.15)	$	(0.50)	$	(0.38)	$	0.03
Natural gas after the effects of hedging (per Mcf)									$	1.21	$	2.06
Weighted average NYMEX price (per MMBtu) ⁽²⁾	$	2.24	$	1.72	$	1.90	$	2.29	$	2.74	$	2.56
Cost and expenses (per BOE)
Costs and expenses (per BOE)
Lease operating expenses	$	6.37	$	5.70	$	5.92	$	7.51	$	7.61	$	7.34
Transportation, gathering, compression and other	$	0.68	$	0.74	$	0.72	$	0.98	$	0.88	$	0.87
Production and ad valorem taxes	$	2.03	$	1.81	$	1.88	$	3.10	$	3.04	$	2.99
Depreciation, depletion and amortization	$	6.91	$	12.43	$	10.57	$	18.58	$	6.12	$	6.64
General and administrative	$	3.55	$	2.88	$	3.11	$	2.63	$	1.42	$	1.27

(1)	Before consideration of hedging transactions.

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

Table of Contents

Oil, NGL and Natural Gas Sales. Our oil, NGL and natural gas sales revenue ~~decreased $192~~increased $45 million to ~~$184~~$350 million when comparing the ~~Combined Current Quarter~~second quarter of 2021 to the ~~Prior Predecessor Quarter.~~first quarter of 2021. Changes in sales revenue between periods are due to changes in production sold and changes in average commodity prices realized (excluding the impacts of hedging). ~~For~~When comparing the ~~Combined Current Quarter, decreases in total production accounted for approximately $111 million~~second quarter of 2021 to the ~~change in revenue and decreases~~first quarter of 2021, increases in commodity prices realized between periods accounted for ~~approximately $81~~a $38 million ~~of the change~~increase in revenue ~~when comparing to the Prior Predecessor Quarter.~~and increases in total production between periods accounted for a $7 million increase in revenue.

Our oil, NGL and gas volumes ~~decreased 30%~~increased 1%, ~~10%~~15% and ~~14%~~4%, respectively, between periods. The overall volume ~~decreases~~increase between periods ~~were~~was primarily attributable to normal field production decline as fewer wells have been drilled and completed in 2020 as described in “Operational Response to Market Conditions” above. This decline was partially offsetdriven by ~~increased~~ production from new wells drilled and completed ~~over~~during the ~~last twelve months~~first half of 2021 in the Williston ~~Basin.~~ Basin and increased workover activity, partially offset by normal field production decline.

~~Table of Contents~~

Our average price for oil ~~and natural gas~~ (before the effects of hedging) ~~decreased 32% and 1,467%, respectively~~increased 19% between periods, and our average price for natural gas and NGLs decreased 39% and 9%, respectively. Our average sales price realized for oil primarily increased ~~111%.~~as a result of favorable movements in the NYMEX market index between periods. Our average sales price realized for natural gas for the Combined Current Quarter was negatively impacted by high fixed third-party costs for transportation, gathering and compression services. These third-party costs sometimes exceed the ultimate price we receive for our natural gas and accordingly candecreased as a result ~~in negative gas revenues, which occurred~~of unusually strong regional pricing in the ~~Combined Current Quarter. While these negative gas prices adversely affect our total revenues, we have continued to produce our wells~~Williston Basin during the first quarter of 2021 that was not repeated in ~~order to sell~~ the ~~associated oil and NGLs from these wells and to meet lease and regulatory requirements.~~second quarter of 2021.

Lease Operating ~~Expenses~~Expenses.. Our LOE during the ~~Combined Current Quarter~~second quarter of 2021 were ~~$51~~$64 million, a ~~$34~~$5 million ~~decrease~~increase over the ~~Prior Predecessor Quarter.~~first quarter of 2021. This ~~decrease~~increase between periods was primarily due to ~~ongoing cost reduction initiatives which were implemented beginning~~an increase in well workover costs and certain variable expenses associated with increased activity and production during the ~~third~~second quarter of ~~2019.~~2021.

Our lease operating expenses on a BOE basis also ~~decreased~~increased when comparing the ~~Combined Current Quarter~~second quarter of 2021 to the ~~Prior Predecessor Quarter.~~first quarter of 2021. LOE per BOE amounted to ~~$5.92~~$7.61 during the ~~Combined Current Quarter,~~second quarter of 2021, which represents ~~a decrease~~an increase of ~~$1.59~~$0.27 per BOE (or ~~21%~~4%) from the ~~Prior Predecessor Quarter.~~first quarter of 2021. This ~~decrease~~increase was mainly due to the overall ~~decrease~~increase in LOE discussed ~~above partially offset by lower overall production volumes between periods.~~above.

Transportation, Gathering, Compression and ~~Other.~~Other. Our TGC expenses during the ~~Combined Current Quarter~~second quarter of 2021 were $6$7 million, ~~a $5 million decrease over the Prior Predecessor Quarter. This decrease mainly relates to lower production volumes between periods. Additionally,~~which is consistent with TGC expenses incurred during the Combined Current Quarter, certain oil volumes that are typically transported by pipeline were instead transported by truck. Trucking fees are recorded as a reduction to the oil price received and not as TGC expense as control transfers prior to transport.first quarter of 2021.

TGC per BOE ~~also decreased~~increased slightly when comparing the ~~Combined Current Quarter~~second quarter of 2021 to the ~~Prior Predecessor Quarter.~~first quarter of 2021. TGC per BOE amounted to ~~$0.72~~$0.88 per BOE during the second quarter of 2021, which represents ~~a decrease~~an increase of ~~$0.26~~$0.01 per BOE (or ~~27%~~1%) from the Prior Predecessor Quarter. This decrease was primarily due to additional volumes being trucked during the Combined Current Quarter as described above, partially offset by lower production volumes between periods.first quarter of 2021.

Production and Ad Valorem ~~Taxes~~Taxes.. Our production and ad valorem taxes during the ~~Combined Current Quarter were $16~~second quarter of 2021 totaled $26 million, a ~~$19~~$2 million ~~decrease~~increase over the ~~Prior Predecessor Quarter,~~first quarter of 2021, which was primarily due to ~~lower~~higher sales revenue between ~~periods.~~periods, partially offset by Colorado severance tax refunds recognized during the second quarter of 2021. Our production taxes, however, are generally calculated as a percentage of net oil, NGL and natural gas sales revenue before the effects of hedging, and this percentage on a company-wide basis was ~~8.4%~~6.9% and ~~9.1%~~7.6% for the ~~Combined Current Quarter~~second quarter of 2021 and the ~~Prior Predecessor Quarter,~~first quarter of 2021, respectively. Our production tax rate for ~~2020~~the second quarter of 2021 was lower than the rate for ~~2019~~the first quarter of 2021 primarily due to ~~certain North Dakota wells receiving stripper well status, which reduces~~ the ~~applicable~~Colorado severance tax ~~rate from 10% to 5% as well as the impact of lower natural gas volumes sold~~refunds recognized during the ~~Combined Current Quarter on volume-based gas taxes.~~period.

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


									Successor
									Three Months Ended
	Successor		Predecessor		Non-GAAP		Predecessor		June 30,		March 31,
	One Month Ended September 30, 2020		Two Months Ended August 31, 2020		Combined Three Months Ended September 30, 2020		Three Months Ended September 30, 2019		2021		2021
Depletion	$	18,735	$	68,331	$	87,066	$	206,793	$	48,081	$	50,150
Accretion of asset retirement obligations		928		2,094		3,022		2,861		2,190		2,222
Depreciation		447		815		1,262		1,371		1,347		1,357
Total	$	20,110	$	71,240	$	91,350	$	211,025	$	51,618	$	53,729

DD&A decreased between the ~~Current Predecessor Quarter~~second quarter of 2021 and the ~~Prior Predecessor Quarter~~first quarter of 2021 primarily due to ~~$138~~$2 million in lower depletion expense ~~consisting of a $23 million decrease related to lower overall production volumes during the Current Predecessor Quarter, as well as a $115 million decrease related~~due to a lower depletion rate between periods. On a BOE basis, our overall DD&A rate of ~~$12.43~~$6.12 per BOE for the ~~Current Predecessor Quarter~~second quarter of 2021 was ~~33%~~8% lower than the rate of ~~$18.58~~$6.64 per BOE for the ~~Prior Predecessor Quarter.~~first quarter of 2021. The primary ~~factors~~factor contributing to this lower DD&A rate ~~were impairment write-downs on proved oil and gas properties in the Williston Basin recognized in the first and second quarters of 2020 offset by downward~~was upward revisions to proved reserves ~~over~~during the ~~last twelve months,~~second quarter of 2021, which were largely driven by higher commodity prices.

4939

Table of Contents

were largely driven by lower commodity prices and development plan changes. The Successor Period DD&A rate of $6.91 is lower than both Predecessor periods due to the application of fresh start accounting, under which we adjusted the value of our oil and gas properties down to their current fair values. Refer to the “Fresh Start Accounting” footnote in the condensed consolidated financial statements for more information.

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

Successor

Predecessor

Non-GAAP

Predecessor

One Month Ended September 30, 2020

Two Months Ended August 31, 2020

Combined Three Months Ended September 30, 2020

Three Months Ended September 30, 2019
Exploration

$
4,207

$
2,701

$
6,908

$
8,340
Impairment

-

7,516

7,516

2,550
Total

$
4,207

$
10,217

$
14,424

$
10,890


	Successor
	Three Months Ended
	June 30,		March 31,
	2021		2021
Impairment	$	1,250	$	1,441
Exploration		797		1,181
Total	$	2,047	$	2,622

Impairment expense for the ~~Current Predecessor Quarter~~first and second quarters of 2021 primarily ~~relates to the write-off of obsolete equipment inventory. Impairment expense for the Prior Predecessor Quarter primarily relates~~related to the amortization of leasehold costs associated with individually insignificant unproved properties.

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


	Successor		Predecessor		Non-GAAP		Predecessor		Successor
	One Month Ended September 30, 2020		Two Months Ended August 31, 2020		Combined Three Months Ended September 30, 2020		Three Months Ended September 30, 2019		Three Months Ended
General and administrative expenses	$	16,618	$	28,163	$	44,781	$	53,473
									June 30,		March 31,
									2021		2021
General and administrative expenses, other⁽¹⁾									$	27,197	$	26,901
Stock-based compensation, non-cash										2,455		2,309
Reimbursements and allocations		(6,273)		(11,650)		(17,923)		(23,583)		(17,657)		(18,919)
General and administrative expenses, net		10,345		16,513		26,858		29,890
Less: Significant one-time costs ⁽¹⁾		(9,333)		(6,004)		(15,337)		(7,781)
Non-GAAP general and administrative expenses less one-time costs	$	1,012	$	10,509	$	11,521	$	22,109
General and administrative expenses, net (GAAP)									$	11,995	$	10,291

(1)

~~Includes severance~~General and ~~restructuring charges, cash retention incentives for Predecessor executives~~administrative expenses, other excludes non-cash stock-based compensation expense and ~~directors~~reimbursements and ~~third-party advisory~~allocations. We believe general and ~~legal fees related~~administrative expenses, other provides useful information to compare our expenses between periods without the ~~Chapter 11 Cases discussed below.~~impact of the aforementioned items.

G&A expense before reimbursements and allocations during the Combined Current Quarter decreased $9 million compared to the Prior Predecessor Quarter primarily due to cost reduction initiatives instituted beginning in the third quarter of 2019 and two separate company restructurings in August 2019 and September 2020, resulting in $9 million in lower compensation and $5 million of lower corporate overheadexpenses, other were consistent between periods. In addition, we incurred $7 million of severance and restructuring costs in the Combined Current Quarter, as compared to $8 million of severance and restructuring costs in the Prior Predecessor Quarter. These decreases were partially offset by $6 million paid to Predecessor executives and directors as cash retention incentives during the Combined Current Quarter and $2 million of third-party advisory and legal fees related to the Chapter 11 Cases that were incurred after the Emergence Date. The decrease in reimbursements and allocations for the Combined Current Quarter was the result of a lower number of field workers on Whiting-operated properties associated with reduced drilling activity and staffing reductions.

G&A expense per BOE amounted to ~~$3.11~~$1.42 per BOE during the ~~Combined Current Quarter,~~second quarter of 2021, which represents an increase of ~~$0.48~~$0.15 per BOE (or ~~18%~~12%) from the ~~Prior Predecessor Quarter.~~first quarter of 2021. This increase was mainly due to the ~~one-time~~decrease in reimbursements and allocations between periods resulting from lower employee benefit costs ~~discussed above as well as lower overall~~

~~Table of Contents~~

production volumes between periods. G&A expense per BOE excluding one-time costs was $1.33 per BOE and $1.95 per BOE, for the Combined Current Quarter and the Prior Predecessor Quarter, respectively.associated with field workers on Whiting-operated properties.

Derivative ~~(Gain)~~ Loss, Net. Our commodity derivative contracts are marked to market each quarter with fair value gains and losses recognized immediately in earnings as derivative (gain) loss, net. Cash flow, however, is only impacted to the extent that settlements under these contracts result in us making or receiving a payment to or from the counterparty. Derivative (gain) loss, net, amounted to ~~a loss~~losses of ~~$13~~$255 million and ~~a gain of $31~~$147 million for the ~~Combined Current Quarter~~three months ended June 30, 2021 and ~~the Prior Predecessor Quarter,~~March 31, 2021, respectively. These ~~gains and~~ losses relate to our collar, swap, differential swap and basis swap commodity derivative contracts and resulted from the upward ~~and downward shifts, respectively,~~shift in the futures curve of forecasted commodity prices for crude oil, ~~and~~ natural gas and NGLs during the respective periods.

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

(Gain) Loss on Sale of Properties. During the second quarter of 2021, a series of non-core producing oil and gas properties were divested for aggregate sales proceeds of $6.4 million (before closing adjustments). As a result of one of these divestitures, our asset retirement obligation liability decreased by $10 million and we recognized a corresponding gain on sale of $10 million.

Table of Contents

Interest Expense. The components of our interest expense were as follows (in thousands):


	Successor		Predecessor		Non-GAAP		Predecessor		Successor
	One Month Ended September 30, 2020		Two Months Ended August 31, 2020		Combined Three Months Ended September 30, 2020		Three Months Ended September 30, 2019		Three Months Ended
Credit agreements	$	1,665	$	7,452	$	9,118	$	3,039
Amortization of debt issue costs, discounts and premiums		371		3,750		4,120		7,973
									June 30,		March 31,
									2021		2021
Credit agreement									$	2,974	$	3,936
Amortization of debt issue costs										887		887
Other		92		177		269		270		120		280
Notes		-		-		-		37,165
Total	$	2,128	$	11,379	$	13,507	$	48,447	$	3,981	$	5,103

The decrease in interest expense ~~of $37 million~~ between ~~the Current Predecessor Quarter and the Prior Predecessor Quarter was~~periods is primarily ~~attributable~~due to ~~lower interest costs incurred on our Senior Notes. Upon filing of the Chapter 11 Cases on April 1, 2020, we discontinued accruing interest on our Senior Notes, which resulted in~~ a ~~$37 million~~ decrease ~~in note interest expense between periods. Refer to the “Chapter 11 Emergence” and “Long-Term Debt” footnotes in the condensed consolidated financial statements for more information.~~

~~The decrease in note interest expense discussed above was partially offset by a $4 million increase~~ in interest incurred on the ~~Predecessor~~ Credit Agreement ~~between Predecessor periods due to~~as a ~~higher~~result of lower average outstanding ~~balance as well as an additional 2% default~~borrowings during the second quarter of 2021. Our weighted average borrowings outstanding under the Credit Agreement during the second quarter of 2021 were $214 million, with a weighted average cash interest rate ~~charged on borrowings outstanding for the duration~~ of ~~the Chapter 11 Cases.~~5.6%. Our weighted average borrowings outstanding during the ~~Current Predecessor Quarter~~first quarter of 2021 were ~~$912 million compared to $108 million for the Prior Predecessor Quarter.~~

Our weighted average debt outstanding during the Current Predecessor Quarter was $3.3 billion versus $2.9 billion for the Prior Predecessor Quarter. Our weighted average effective cash interest rate was 1.4% during the Current Predecessor Quarter compared to 5.5% during the Prior Predecessor Quarter due to the discontinuation of interest expense on our Senior Notes beginning in April 2020.

Upon our emergence from the Chapter 11 Cases, we were relieved of all liabilities related to our Senior Notes in exchange for Successor common stock, we repaid all outstanding borrowings and accrued interest on the Predecessor Credit Agreement and we entered into the Exit Credit Agreement. Our weighted average borrowings outstanding during the Successor Period were $419$324 million, with a weighted average ~~effective~~ cash interest rate of ~~4.8%~~4.9%.

~~Reorganization Items, Net.~~ Income Tax Benefit~~During the Current Predecessor Quarter, we recognized~~. As a ~~net gain of $259 million related to the Chapter 11 Cases consisting of (i) gains from the settlement of certain liabilities, including our Senior Notes, upon consummation~~result of the ~~Plan, (ii) fair value adjustments to adopt fresh start accounting~~full valuation allowance on our DTAs as of June 30, 2021 and ~~(iii) professional fees~~March 31, 2021, no income tax expense or benefit was recognized ~~up to~~during the ~~Emergence Date. Refer to~~second quarter of 2021 or the ~~“Chapter 11 Emergence” and “Fresh Start Accounting” footnotes~~first quarter of 2021. This resulted in ~~the notes to the condensed consolidated financial statements~~overall effective tax rates of 0% for ~~more information on amounts recorded to reorganization items, net.~~both periods.

5141

Table of Contents

~~Income Tax Benefit~~. As a result of pre-tax losses for the first six months of 2019, we transitioned from a net deferred tax liability position to a net deferred tax asset position which resulted in the recognition of a full valuation allowance on our deferred tax assets (“DTAs”) during the second quarter of 2019. As a result of the full valuation allowance on our U.S. DTAs as of September 30, 2020 and September 30, 2019, we did not recognize any U.S. income tax expense or benefit during the periods presented. During the Combined Current Quarter, we recorded a tax benefit of $68 million reflecting a reduction in the overall expected Canadian tax liability as a result of a legal entity restructuring we executed during the period. The remaining $6 million Canadian tax liability is expected to be payable in the fourth quarter of 2020. Refer to the “Income Taxes” footnote in the notes to the condensed consolidated financial statements for more information on the legal restructuring and related Canadian deferred tax liability.

Our overall effective tax rate of (32.1)% for the Combined Current Quarter was lower than the U.S. statutory income tax rate as a result of the full valuation allowance on our U.S. DTAs as well as the reduction of our overall expected Canadian tax liability discussed above.

Liquidity and Capital Resources

Overview. At ~~September~~June 30, ~~2020, the Successor entity~~2021, we had ~~$14~~$17 million of unrestricted cash on hand, ~~$400~~$115 million of long-term debt and $1.2 billion of shareholders’ equity, while at December 31, ~~2019, the Predecessor entity~~2020, we had $9$26 million of unrestricted cash on hand, ~~$2.8 billion~~$360 million of long-term debt and ~~$4.0~~$1.2 billion of equity. The decrease in long-term debt and shareholders’ equity between periods primarily relates to adjustments made as a result of the implementation of the Plan and application of fresh start accounting upon emergence from bankruptcy on September 1, 2020, as well as net operating losses incurred during the Current Predecessor YTD Period. We expect that our liquidity going forward will be primarily derived from cash flows from operating activities, cash on hand and availability under the ~~Exit~~ Credit Agreement and that these sources of liquidity will be sufficient to provide us the ability to fund our material cash requirements, as described below, as well as our operating and development activities and planned capital programs. We may need to fund acquisitions or pursuits of business opportunities that support our strategy through additional borrowings or the issuance of ~~additional new~~ common stock or other forms of equity.

Cash Flows. During the ~~Combined Current~~Successor YTD Period, we generated ~~$124~~$336 million of cash ~~provided by~~from operating activities, ~~a decrease~~an increase of ~~$397~~$269 million from the ~~Prior~~ Predecessor YTD Period. Cash provided by operating activities increased between ~~Predecessor~~ periods ~~decreased~~ primarily due to ~~lower~~higher realized sales prices, ~~and production volumes for oil, NGLs and natural gas,~~ as well as ~~higher reorganization and~~lower cash G&A, cash interest expense and exploration expenses. These ~~negative~~positive factors were partially offset by an increase in cash settlements ~~received~~paid on our commodity derivative contracts ~~lower lease operating expenses,~~and higher production ~~and ad valorem~~ taxes ~~cash interest expense and TGC costs~~ between periods. Refer to “Results of Operations” for more information on the impact of volumes and prices on revenues and for more information on increases and decreases in certain expenses between periods. During the ~~Combined Current~~Successor YTD Period, cash flows from operating activities ~~$400 million of net borrowings under the Exit Credit Agreement~~ and proceeds from the sale of properties were used ~~to finance~~for the net repayment of ~~$912~~$245 million of outstanding borrowings under the ~~Predecessor~~ Credit Agreement ~~$247~~and $103 million of drilling and development ~~expenditures and the repurchase of $73 million aggregate principal amount of 2020 Senior Convertible Notes in March 2020.~~expenditures.

One of the primary sources of variability in our cash flows from operating activities is commodity price volatility, which we partially mitigate through the use of commodity ~~hedge~~derivative contracts. Oil accounted for 62% and 65% of our total production in the Combined Current YTD Period and the Prior Predecessor YTD Period, respectively. As a result, our operating cash flows are more sensitive to fluctuations in oil prices than they are to fluctuations in NGL or natural gas prices. As of ~~October 30, 2020,~~July 28, 2021, we had crude oil derivative contracts (consisting of collars, swaps and differential swaps) covering the sale of ~~31,000~~37,000 Bbl, ~~24,000~~28,000 Bbl and ~~13,000~~18,000 Bbl of oil per day for the remainder of ~~2020,~~ 2021, the full year 2022 and the first ~~nine~~six months of ~~2022,~~2023, respectively. ~~Additionally,~~As of July 28, 2021, we had natural gas derivative contracts (consisting of collars, swaps and basis swaps) covering the sale of ~~70,000~~99,000 MMBtu, ~~64,000~~53,000 MMBtu and ~~33,000~~54,000 MMBtu of natural gas per day through the remainder of ~~2020,~~2021, the full year 2022 and the first six months of 2023, respectively. As of July 28, 2021, we had NGL derivative contracts (consisting of swaps) covering the sale of 105,000 gallons and 42,000 gallons of NGLs per day for the remainder of 2021 and first quarter of 2022, respectively. For more information on our outstanding derivatives refer to the “Derivative Financial Instruments” footnote in the notes to the condensed consolidated financial statements.

~~Exploration~~Material Cash Requirements. Our material short-term cash requirements include payments under our short-term lease agreements, recurring payroll and ~~Development Expenditures. During the Combined Current YTD Period~~benefits obligations for our employees, capital and ~~the Prior Predecessor YTD Period, we incurred accrual basis exploration~~operating expenditures and ~~development (“E&D”) expenditures~~other working capital needs. Working capital, defined as total current assets less total current liabilities, fluctuates depending on commodity pricing and effective management of $189 million and $676 million, respectively. Of these expenditures, 96% and 99%, respectively, were incurred in our large resource play in the Williston Basin of North Dakota and Montana, where we have focused our development. Capital expenditures reported in the condensed consolidated statements of cash flows are

~~Table of Contents~~

~~calculated on a cash basis, which differs from the accrual basis used to calculate the incurred capital expenditures detailed in the table below:~~

Successor

Predecessor

One Month Ended September 30, 2020

Eight Months Ended August 31, 2020

Nine Months Ended September 30, 2019
Capital expenditures, accrual basis

$
3,489

$
185,363

$
675,552
Decrease (increase) in accrued capital expenditures

5,551

53,093

(50,845)
Capital expenditures, cash basis

$
9,040

$
238,456

624,707

~~We continually evaluate our capital needs and compare them~~payables to our vendors and receivables from our purchasers and working interest partners. As commodity prices improve, our working capital ~~resources. The midpoint~~requirements may increase as we spend additional capital, increase production and pay larger settlements on our outstanding commodity derivative contracts. Additionally, as discussed in “Recent Developments” above, on July 19, 2021 we entered into a purchase and sale agreement that results in a material short-term cash commitment of $271 million, subject to normal closing adjustments.

Our long-term material cash requirements from currently known obligations include repayment of outstanding borrowings and interest payment obligations under our ~~2020 E&D budget range is $215 million, which we expect~~Credit Agreement, settlements on our outstanding commodity derivative contracts, future obligations to ~~fund with net cash provided by~~plug, abandon and remediate our oil and gas properties at the end of their productive lives, operating ~~activities~~ and ~~cash on hand. This represents~~finance lease obligations and contracts to transport a ~~substantial decrease from the $778 million incurred on E&D expenditures during 2019 in response to the significantly lower~~minimum volume of crude oil ~~prices experienced during~~and natural gas within specified time frames. The following table summarizes our estimated material cash requirements for known obligations as of June 30, 2021. This table does not include repayments of outstanding borrowings on our Credit Agreement, or the ~~first half of 2020 and our plan to more closely align our capital spending with cash flows generated from operations. Currently, we anticipate a similar level of capital spending in 2021~~associated interest payments, as we incurred in 2020, which we expect to fund with net cash provided by operating activities. Our level of E&D expenditures is largely discretionary, although a portion of our E&D expenditures are for non-operated properties where we have limited control over the timing and amount of ~~such expenditures,~~borrowings and ~~the amount of funds we devote to any particular activity may increase or decrease significantly depending~~repayments cannot be forecasted with certainty and are based on working capital requirements, commodity prices ~~cash flows, available opportunities~~ and ~~development results,~~acquisition and divestiture activity, among other factors. ~~We believe that we have sufficient liquidity and capital resources to execute~~As of June 30, 2021, our ~~development plan over the next 12 months. With~~outstanding borrowings under our expected cash flow streams, commodity price hedging strategies, current liquidity levels (primarily consisting of availability under the Exit Credit Agreement) and flexibility to modify future capital expenditure programs, we expect to fund all planned capital programs, comply with our debt covenants and meet other obligations that may arise from our oil and gas operations.

~~Exit Credit Agreement~~~~. On September 1, 2020, Whiting Petroleum Corporation, as parent guarantor, and Whiting Oil and Gas, as borrower, entered into the Exit~~ Credit Agreement were $115 million, with a ~~syndicate of banks~~. As of September 30, 2020, the Exit Credit Agreement had a borrowing base and aggregate commitments of $750 million. As of September 30, 2020, we had $348 million of available borrowing capacity under the Exit Credit Agreement, which was net of $400 million of borrowings outstanding and $2 ~~million in letters of credit outstanding.~~

~~The borrowing base under the Exit Credit Agreement is determined at the discretion of the lenders, based~~weighted average interest rate on the ~~collateral value~~outstanding principal balance of ~~our proved reserves that have been mortgaged~~4.1%. Refer to ~~such lenders, and is subject to initial redetermination on April 1, 2021, regular redeterminations on April 1 and October 1 of each year thereafter,~~“Credit Agreement” below as well as ~~special redeterminations described in the Exit Credit Agreement, in each case which may increase or decrease the amount of the borrowing base. Additionally, we can increase the aggregate commitments~~ ~~by up to an additional $750 million, subject to certain conditions.~~

A portion of the revolving credit facility in an aggregate amount not to exceed $50 million may be used to issue letters of credit for the account of Whiting Oil and Gas or our other designated subsidiaries. As of September 30, 2020, $48 million was available for additional letters of credit under the Exit Credit Agreement.

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

~~Table of Contents~~

The Exit Credit Agreement contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, enter into hedging contracts, incur liens and engage in certain other transactions without the prior consent of our lenders. Except for limited exceptions, the Exit Credit Agreement also restricts the Company’s ability to make any dividend payments or distributions on its common stock prior to September 1, 2021, and thereafter only to the extent that the Company has distributable free cash flow and (i) at least 20% of available borrowing capacity, (ii) 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 Exit Credit Agreement.. These restrictions apply to all of our restricted subsidiaries (as defined in the Exit Credit Agreement). The Exit Credit Agreement requires us, as of the last day of any quarter to maintain commodity hedges covering a minimum of 65% of our projected production for the succeeding twelve months, and 35% of our projected production for the next succeeding twelve months. The Exit Credit Agreement also requires us, as of the last day of any quarter beginning with the quarter ending December 31, 2020, to maintain the following ratios (as defined in the Exit 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. For further information on the loan security related to the Exit Credit Agreement, refer to the “Long-Term Debt” footnote in the notes to the condensed consolidated financial ~~statements.~~

~~Senior Notes~~. Upon emergence from the Chapter 11 Cases on September 1, 2020, we issued 36,817,630 shares of the Successor’s common stock to the holders of all our senior notes in settlement of the outstanding principal and related accrued interest. Upon such settlement, we no longer have any senior notes outstanding. Refer to the “Fresh Start Accounting” footnote in the condensed consolidated financial statements for more information.

~~Contractual Obligations and Commitments~~

~~Schedule of Contractual Obligations.~~ ~~The following~~ This table summarizes our obligations and commitments as of September 30, 2020 to make future payments under certain contracts, aggregated by category of contractual obligation, for the time periods specified below. This tablealso does not include amounts payable under ~~contracts~~obligations where we cannot ~~predict~~forecast with ~~accuracy~~certainty the amount and timing of such payments, including any amounts we may be obligated to pay under our derivative contracts, as such payments are dependent on ~~the price of crude oil~~commodity prices in effect at the time of ~~settlement, and any penalties that may be incurred for underdelivery under our physical delivery contracts. For further information on these contracts refer~~settlement. Refer to the “Derivative Financial Instruments” footnote in the notes to the condensed consolidated financial statements for further information on these contracts and ~~“Delivery Commitments” in Item 2~~their fair values as of ~~our Annual Report~~June 30, 2021, which fair values represent the cash settlement amount required to terminate such instruments based on ~~Form 10-K~~forward price curves for ~~the year ended December 31, 2019.~~commodities as of that date.

Payments due by period

(in thousands)

Less than 1

More than 5
Contractual Obligations

Total

year

1-3 years

3-5 years

years
Long-term debt ⁽¹⁾

$
400,328

$
-

$
-

$
400,328

$
-
Cash interest expense on debt ⁽²⁾

67,584

19,287

38,574

9,723

-
Asset retirement obligations ⁽³⁾

127,690

8,429

35,410

11,390

72,461
Operating leases ⁽⁴⁾

25,978

1,471

7,141

6,114

11,252
Finance leases ⁽⁴⁾

21,168

1,487

10,248

7,048

2,385
Pipeline transportation agreements ⁽⁵⁾

13,306

6,402

5,810

1,094

-
Total

$
656,054

$
37,076

$
97,183

$
435,697

$
86,098

Table of Contents


	Payments due by period
		(in thousands)
			Less than 1						More than 5
Material Cash Requirements	Total		year		1-3 years		3-5 years		years
Asset retirement obligations ⁽¹⁾	$	99,523	$	6,247		35,876	$	12,621	$	44,779
Operating leases ⁽²⁾		22,526		3,215		6,601		4,325		8,385
Finance leases ⁽²⁾		16,765		5,058		7,714		3,993		-
Pipeline transportation agreements ⁽³⁾		8,523		4,693		3,830		-		-
Total	$	147,337	$	19,213	$	54,021	$	20,939	$	53,164

(1)	~~Long-term debt consists of the outstanding borrowings under the Exit Credit Agreement. The Exit Credit Agreement matures on April 1, 2024.~~

~~(2)~~

Cash interest expense on the Exit Credit Agreement is estimated assuming no further principal borrowings or repayments through the April 1, 2024 maturity date and a fixed interest rate of 4.4%. Commitment fees on the Exit Credit Agreement are estimated assuming no further principal borrowings or repayments or changes to commitments through the April 1, 2024 maturity date.

~~(3)~~

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

~~Table of Contents~~

~~(4)~~(2)

We have operating and finance leases for corporate and field offices, pipeline and midstream facilities and automobiles. The obligations reported above represent our minimum financial commitments pursuant to the terms of these contracts, however our actual expenditures under these contracts may exceed the minimum commitments presented above. Refer to the “Leases” footnote in the notes to the consolidated financial statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, ~~2019~~2020 for more information on these leases.

~~(5)~~(3)

Our pipeline transportation agreements consist of contracts through 2024 with various third parties to facilitate the delivery of our produced oil, gas and NGLs to market. These contracts require either fixed monthly reservation fees or commitments to deliver minimum volumes at fixed rates in exchange for dedicated pipeline capacity. If minimum volume commitments are not met, we are required to pay any deficiencies at the prices stipulated in the contracts. The obligations reported above represent our minimum financial commitments pursuant to the terms of these contracts, however, our actual expenditures under these contracts may exceed the minimum commitments presented above.

~~Delivery Commitments.~~ Exploration and Development Expenditures~~We had a delivery contract tied to~~. During the six months ended June 30, 2021 and 2020, we incurred accrual basis exploration and development (“E&D”) expenditures of $114 million and $179 million, respectively. Of these expenditures, 98% and 95%, respectively, were incurred in our ~~oil production~~large resource play in the Williston ~~Basin. The effective date~~Basin of ~~this contract was contingent upon~~North Dakota and Montana, where we have focused our current development. Capital expenditures reported in the ~~completion~~condensed consolidated statements of ~~certain related pipelines,~~cash flows are calculated on a cash basis, which differs from the ~~construction~~accrual basis used to calculate the incurred capital expenditures as detailed in the table below:


	Successor		Predecessor
	Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
Capital expenditures, accrual basis	$	114,070	$	178,596
Decrease (increase) in accrued capital expenditures		(10,691)		45,309
Capital expenditures, cash basis	$	103,379	$	223,905

We continually evaluate our capital needs and compare them to our capital resources. Our 2021 E&D budget is a range of $240 million to $252 million, which ~~has not yet commenced. Under the terms of the agreement,~~ we ~~were committed~~expect to ~~deliver 10 MBbl/d for a term of seven years. In July 2020, we elected to terminate the agreement and are no longer required to deliver the committed volumes.~~

~~Based on current oil and natural gas prices and anticipated levels of production, we believe that the estimated~~fund with net cash ~~generated from operations, together with~~provided by operating activities and cash on hand, and represents a slight increase from the E&D expenditures incurred during 2020. Our level of E&D expenditures is largely discretionary, although a portion of our E&D expenditures are for non-operated properties where we have limited control over the timing and amount of such expenditures, and the amount of funds we devote to any particular activity may increase or decrease depending on commodity prices, cash flows, available opportunities and development results, among other factors. We believe that we have sufficient liquidity and capital resources to execute our development plan over the next 12 months. With our expected cash flow streams, commodity price hedging strategies, current liquidity levels (primarily consisting of availability under the Credit Agreement) and flexibility to modify future capital expenditure programs, we expect to fund all planned capital programs, comply with our debt covenants and meet other obligations that may arise from our oil and gas operations.

Table of Contents

Credit Agreement. Whiting Petroleum Corporation, as parent guarantor, and Whiting Oil and Gas, as borrower, have a reserves-based credit facility, with a syndicate of banks that had a borrowing base and aggregate commitments of $750 million as of June 30, 2021. As of June 30, 2021, we had $633 million of available borrowing capacity under the Credit Agreement, which was net of $115 million of borrowings outstanding and $2 million in letters of credit outstanding.

The borrowing base under the Credit Agreement is determined at the discretion of the lenders, based on the collateral value of our proved reserves that have been mortgaged to 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. In April 2021, our borrowing base and aggregate commitments of $750 million were reaffirmed in connection with our regular borrowing base redetermination. Asset sales that materially impact the value of our proved reserves may result in a reduction of our borrowing base.

A portion of the borrowing base in an aggregate amount not to exceed $50 million may be used to issue letters of credit for the account of Whiting Oil and Gas or our other designated subsidiaries. As of June 30, 2021, $48 million was available for additional letters of credit under the Credit Agreement.

The Credit Agreement provides for interest only payments until maturity on April 1, 2024, when the agreement terminates and all outstanding borrowings are due. In addition, the Credit Agreement provides for certain mandatory prepayments, including a provision pursuant to which, if our cash balances are in excess of approximately $75 million during any given week, such excess must be utilized to repay borrowings under the ~~Exit~~Credit Agreement. Interest under the Credit Agreement ~~will be adequate~~accrues at our option at either (i) a base rate for a base rate loan plus a margin between 1.75% and 2.75% based on the ratio of outstanding borrowings and letters of credit to ~~meet future liquidity needs, including funding~~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. Additionally, we incur commitment fees of 0.5% on the unused portion of the aggregate commitments of the lenders under the Credit Agreement, which are included as a component of interest expense.

The Credit Agreement contains restrictive covenants that may limit our ~~operating~~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 ~~development activities.~~engage in certain other transactions without the prior consent of our lenders. Except for limited exceptions, the Credit Agreement also restricts our ability to make any dividend payments or distributions on our common stock prior to September 1, 2021, and thereafter only to the extent that we have distributable free cash flow and (i) have at least 20% of available borrowing capacity, (ii) have a consolidated net leverage ratio of less than or equal to 2.0 to 1.0, (iii) do not have a borrowing base deficiency and (iv) are not in default under the Credit Agreement. These restrictions apply to all of our restricted subsidiaries and are calculated in accordance with definitions contained in the Credit Agreement. The Credit Agreement requires us, as of the last day of any quarter, to maintain commodity hedges covering a minimum of 65% of our projected production for the succeeding twelve months, and 35% of our projected production for the next succeeding twelve months, both as reflected in our reserves report most recently provided to the lenders under the Credit Agreement. We are also limited to hedging a maximum of 85% of our production from proved reserves. The Credit Agreement requires us to maintain the following ratios: (i) a consolidated current assets to consolidated current liabilities ratio of not less than 1.0 to 1.0 and (ii) a total debt to last four quarters’ EBITDAX ratio of not greater than 3.5 to 1.0.

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

Table of Contents

Critical Accounting Policies and Estimates

Information regarding critical accounting policies and estimates is contained in Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, ~~2019. The following is a~~2020. No material ~~update~~updates were made to such critical accounting policies and ~~estimates:~~

~~Reorganization and Fresh Start Accounting.~~ ~~Effective April 1, 2020, as a result of the filing of the Chapter 11 Cases we began accounting and reporting according to FASB ASC Topic 852 –~~ ~~Reorganizations~~ (“ASC 852”), which specifies the accounting and financial reporting requirements for entities reorganizing through chapter 11 bankruptcy proceedings. These requirements include distinguishing transactions associated with the reorganization and implementation of the plan of reorganization separate from activities related to ongoing operations of the business. Additionally upon emergence from the Chapter 11 Cases, ASC 852 requires us to allocate our reorganization value to our individual assets based on their estimated fair values, resulting in a new entity for financial reporting purposes. After the Emergence Date, the accounting and reporting requirements of ASC 852 are no longer applicable and have no impact on the Successor periods.

~~Effects of Inflation and Pricing~~

~~As commodity prices began to recover during 2018 and 2019 from previous lows, the cost of oil field goods and services also rose. Although commodity prices have declined sharply~~estimates during the first part of 2020, the costs of oil field goods and services were slower to decline in response. The oil and gas industry is very cyclical, and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and not adjust downward in proportion to prices. Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, depletion expense, impairment assessments of oil and gas properties and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrow money and retain personnel. While we do not currently expect business costs to materially increase in the near term, higher demand in the industry could result in increases in the costs of materials, services and personnel.six months ended June 30, 2021.

Forward-Looking Statements

This report contains statements that we believe to be “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than historical facts, including, without limitation, statements regarding our future financial position, business strategy, ~~projected revenues, earnings,~~cash flows, acquisitions and divestitures, returns, costs and capital expenditures,

~~Table of Contents~~

~~and debt levels,~~ and plans and objectives of management for future operations, are forward-looking statements. When used in this report, words such as we “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe” or “should” or the negative thereof or variations thereon or similar terminology are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements.

These risks and uncertainties include, but are not limited to: risks associated with our emergence from ~~the chapter 11~~ bankruptcy; declines in, or extended periods of low oil, NGL or natural gas prices; the occurrence of epidemic or pandemic diseases, including the coronavirus pandemic; actions of the Organization of Petroleum Exporting Countries and other oil exporting nations to set and maintain production levels; the potential shutdown of the Dakota Access Pipeline; our level of success in ~~exploration,~~ development and production activities; impacts resulting from the allocation of resources among our strategic opportunities; our ability to replace our oil and natural gas reserves; the geographic concentration of our operations; our inability to access oil and gas markets due to market conditions or operational impediments; market availability of, and risks associated with, transport of oil and gas; weakened differentials impacting the price we receive for oil and natural gas; our ability to successfully complete asset acquisitions and dispositions and the risks related thereto; the impacts of hedging on our results of operations; shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs and completion services; the timing of our development expenditures; properties that we acquire may not produce as projected and may have unidentified liabilities; adverse weather conditions that may negatively impact development or production activities; we may incur substantial losses and be subject to liability claims as a result of our ~~level~~oil and gas operations, including uninsured or underinsured losses resulting from our oil and gas operations; lack of ~~indebtedness,~~control over non-operated properties; unforeseen underperformance of or liabilities associated with acquired properties or other strategic partnerships or investments; competition in the oil and gas industry; cybersecurity attacks or failures of our telecommunication and other information technology infrastructure; our ability to comply with debt covenants, periodic redeterminations of the borrowing base under ~~the Exit~~our Credit Agreement and our ability to generate sufficient cash flows from operations to service our indebtedness; our ability to generate sufficient cash flows from operations to meet the internally funded portion of our capital expenditures budget; our ability to obtain external capital to finance exploration and development operations; negative impacts from outbreaks of communicable diseases, including the COVID-19 pandemic; our inability to access oil and gas markets due to market conditions or operational impediments, including any court rulings which may result in the inability to transport oil on the Dakota Access Pipeline; negative impacts from litigation and legal proceedings, including ongoing claims in connection with the chapter 11 bankruptcy; the impact of negative shifts in investor sentiment towards the oil and gas industry; impacts resulting from the allocation of resources among our strategic opportunities; the geographic concentration of our operations; impacts to financial statements as a result of impairment write-downs and other cash and noncash charges; federal and state initiatives relating to the regulation of hydraulic fracturing and air emissions; revisions to reserve estimates as a result of changes in commodity prices, regulation and other factors; inaccuracies of our reserve estimates or our assumptions underlying them; ~~the timing of our exploration and development expenditures; risks relating to decreases in our credit rating; market availability of, and risks associated with, transport of oil and gas;~~ our ability to ~~successfully complete asset dispositions~~use net operating loss carryforwards in future periods; impacts to financial statements as a result of impairment write-downs and other cash and noncash charges; the ~~risks related thereto; our ability to drill producing wells on undeveloped acreage prior to its lease expiration; shortages~~impact of ~~or delays~~negative shifts in ~~obtaining qualified personnel or equipment, including drilling rigs and completion services; weakened differentials impacting~~investor sentiment towards the price we receive for oil and natural gas; risks relating to any unforeseen liabilities of ours; the impacts of hedging on our results of operations; adverse weather conditions that may negatively impact development or production activities; uninsured or underinsured losses resulting from our oil and gas ~~operations; lack~~industry; federal and state initiatives relating to the regulation of ~~control over non-operated properties; failure of our properties to yield oil or gas in commercially viable quantities;~~hydraulic fracturing and air emissions; the Biden administration could enact regulations that impose more onerous permitting and other costly environmental, health and safety requirements; the impact and costs of compliance with laws and regulations governing our oil and gas operations; the potential impact of changes in laws that could have a negative effect on the oil and gas industry; impacts of local regulations, climate change issues, negative ~~public~~ perception of our industry and corporate governance standards; ~~our ability to replace our oil~~negative impacts from litigation and natural gas reserves; unforeseen underperformance of or liabilities associated with acquired properties or other strategic partnerships or investments; competition in the oil and gas industry; any loss of our senior management or technical personnel; cybersecurity attacks or failures of our telecommunication and other information technology infrastructure;legal proceedings; and other risks described under the caption “Risk Factors” in Item 1A of ~~this Quarterly Report on Form 10-Q and~~ our Annual Report on Form 10-K for the period ended December 31, ~~2019.~~2020. We assume no obligation, and disclaim any duty, to update the forward-looking statements in this Quarterly Report on Form 10-Q.

Table of Contents

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

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

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

Crude Oil, ~~and~~ Natural Gas and NGL Collars, Swaps and Basis and Differential Swaps.Our hedging portfolio currently consists of crude oil, natural gas and NGL collars and swaps, as well as crude oil differential swaps and natural gas ~~collars and~~basis swaps. Refer to the “Derivative Financial Instruments” footnote in the notes to the condensed consolidated financial statements for a description and list of our outstanding derivative contracts at ~~September~~June 30, ~~2020.~~2021.

~~Table of Contents~~

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

The fair value of our oil derivative positions at ~~September~~June 30, ~~2020~~2021 was a net liability of $1$325 million. A hypothetical upward or downward shift of 10% per Bbl in the NYMEX forward curve for crude oil as of ~~September~~June 30, ~~2020~~2021 would cause an increase of ~~$51~~$123 million or a decrease of ~~$46~~$115 million, respectively, in this fair value liability. The fair value of our natural gas ~~contracts~~derivative positions was a net liability of $8$23 million. A hypothetical upward or downward shift of 10% per MMBtu in the NYMEX forward curve for natural gas as of ~~September~~June 30, ~~2020~~2021 would cause an increase of $8 million or a decrease of $12 million, respectively, in this fair value liability. The fair value of our NGL contracts was a net liability of $7 million. A hypothetical upward or downward shift of 10% per Bbl in the Mont Belvieu forward curve for propane as of June 30, 2021 would cause an increase or decrease, respectively, of ~~$10~~$2 million in this fair value liability.

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

Interest Rate Risk

Market risk is estimated as the change in fair value resulting from a hypothetical 100 basis point change in the interest rate on the outstanding balance under the ~~Exit~~ Credit Agreement. The ~~Exit~~ Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance for a period up to one month. To the extent that the interest rate is fixed, interest rate changes affect the instrument’s fair market value but do not impact results of operations or cash flows. Conversely, for the portion of the ~~Exit~~ Credit Agreement that has a floating interest rate, interest rate changes will not affect the fair market value but will impact future results of operations and cash flows. At ~~September~~June 30, ~~2020,~~2021, our outstanding principal balance under the ~~Exit~~ Credit Agreement was ~~$400~~$115 million, and the weighted average interest rate on the outstanding principal balance was ~~4.3%~~4.1%. At ~~September~~June 30, ~~2020,~~2021, the carrying amount approximated fair market value. Assuming a constant debt level of ~~$400~~$115 million, the cash flow impact resulting from a 100 basis point change in interest rates during periods when the interest rate is not fixed would be $4$1 million over a 12-month time period.

Table of Contents

Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures. In accordance with Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), our management evaluated, with the participation of our Chief Executive Officer and our Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of ~~September~~June 30, ~~2020.~~2021. Based upon their evaluation of these disclosure controls and procedures, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures were effective as of ~~September~~June 30, ~~2020~~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.

Changes in internal control over financial reporting. There was no change in our internal control over financial reporting that occurred during the quarter ended ~~September~~June 30, ~~2020~~2021 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

Risk factors relating to us are contained in Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, ~~2019. The following is a~~2020. No material ~~update~~change to such risk ~~factors:~~

~~Table of Contents~~

~~We recently emerged from bankruptcy, which may adversely affect our business and relationships.~~

It is possible that our having filed for bankruptcy and our recent emergence from the voluntary cases under chapter 11 of the Bankruptcy Code (the “Chapter 11 Cases”) may adversely affect our business and relationships with customers, vendors, contractors, employees or suppliers. Due to uncertainties, many risks exist, including the following:

●	key suppliers, vendors or other contract counterparties may terminate their relationships with us, require additional financial assurances or enhanced performance from us or pursue unreasonable fee increases for their goods or services;

●	~~our ability to renew existing contracts and compete for new business may be adversely affected;~~

●	~~our ability to attract, motivate and/or retain key employees and executives may be adversely affected;~~

●	~~landowners may not be willing to lease acreage to us; and~~

●	~~competitors may take business away from us and our ability to attract and retain customers may be negatively impacted.~~

The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.

Our actual financial results after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of our chapter 11 plan of reorganization (the “Plan”) and the transactions contemplated thereby.

In connection with the disclosure statement we filed with the Bankruptcy Court, and the hearing to consider confirmation of the Plan, we prepared projected financial information to demonstrate to the Bankruptcy Court the feasibility of the Plan and our ability to continue operations upon our emergence from the Chapter 11 Cases. Those projections were prepared solely for the purpose of bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results may vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.

~~Our historical financial information may not be indicative of future financial performance.~~

Our capital structure was significantly impacted by the Plan. Under fresh start accounting rules that applied to us upon the Emergence Date, assets and liabilities were adjusted to fair values. Accordingly, because fresh start accounting rules applied, our financial condition and results of operations following emergence from the Chapter 11 Cases will not be comparable to the financial condition and results of operations reflected in our historical financial statements.

~~Upon our emergence from the Chapter 11 Cases, the composition of our board of directors changed significantly.~~

Pursuant to the Plan, the composition of our board of directors (the “Board”) changed significantly. Upon emergence, our Board consists of seven directors, none of whom served on the Board prior to our emergence from the Chapter 11 Cases. The new directors have different backgrounds, experiences and perspectives from those individuals who previously served on our Board and, thus, may have different views on the issues that will determine our future. There is no guarantee that our new Board will pursue, or will pursue in the same manner, our current strategic plans. As a result, the future strategy and our plans may differ materially from those of the past.

~~The market price of our securities is subject to volatility.~~

Upon our emergence from the Chapter 11 Cases, our old common stock was cancelled and we issued new common stock. The market price of our new common stock could be subject to wide fluctuations in response to, and the level of trading that develops with our new

~~Table of Contents~~

~~common stock may be affected by, numerous~~ factors many of which are beyond our control. These factors include, among other things, our new capital structure as a result of the transactions contemplated by the Plan, our limited trading history subsequent to our emergence from bankruptcy, our limited trading volume, the lack of comparable historical financial information due to our adoption of fresh start accounting, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this Part II, Item 1A of this Quarterly Report on Form 10-Q.

The exercise of all or any number of outstanding Warrants, the issuance of stock-based awards or the issuance of our common stock to settle the claims of general unsecured claimants may dilute your holding of shares of our common stock.

As of the date of filing this report, we have outstanding Warrants (as defined in the “Shareholders’ Equity” footnote in the notes to the condensed consolidated financial statements under the heading “Warrants,” which is incorporated herein by reference) to purchase approximately 7.3 million shares of our common stock at average exercise prices of either $73.44 or $83.45 per share. In addition, as of September 30, 2020, approximately 3.8 million shares of our common stock remained available for grant under the Whiting Petroleum Corporation 2020 Equity Incentive Plan. We also reserved approximately 3.0 million shares of our common stock for potential future distribution to certain general unsecured claimants whose claim values are currently pending resolution in the Bankruptcy Court. The exercise of equity awards, including any stock options that we may grant in the future and the Warrants, the sale of shares of our common stock underlying any such options or Warrants, and the issuance of our common stock to general unsecured claimants could have an adverse effect on the market for our common stock, including the price that an investor could obtain for their shares.

~~The ability to attract and retain key personnel is critical to the success of our business and may be affected by our emergence from the Chapter 11 Cases~~.

The success of our business depends on key personnel. The ability to attract and retain these key personnel may be difficult in light of our emergence from the Chapter 11 Cases, the uncertainties currently facing the business and changes we may make to the organizational structure to adjust to changing circumstances. We may need to enter into retention or other arrangements that could be costly to maintain. If executives, managers or other key personnel resign, retire or are terminated, or their service is otherwise interrupted, we may not be able to replace them in a timely manner and we could experience significant declines in productivity.

~~Oil and natural gas prices are very volatile. An extended period of low oil and natural gas prices may adversely affect our business, financial condition, results of operations or cash flows.~~

The oil and gas markets are very volatile, and we cannot predict future oil and natural gas prices. The price we receive for our oil, NGL and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. The prices we receive for our production depend on numerous factors beyond our control, including, but not limited to, the following:

●	~~changes in regional, domestic and global supply and demand for oil and natural gas;~~

●	~~the level of global oil and natural gas inventories and storage capacity;~~

●	~~the occurrence or threat of epidemic or pandemic diseases, such as the coronavirus (“COVID-19”) pandemic, or any government response to such occurrence or threat;~~

●	~~the actions of the Organization of Petroleum Exporting Countries (“OPEC”);~~

●	proximity, capacity and availability of oil and natural gas pipelines and other transportation facilities, including any court rulings which may result in the inability to transport oil on the Dakota Access Pipeline;

●	~~the price and quantity of imports of oil and natural gas;~~

●	~~market demand and capacity limitations on exports of oil and natural gas;~~

~~Table of Contents~~

●	political and economic conditions, including embargoes and sanctions, in oil-producing countries or affecting other oil-producing activity, such as the U.S. imposed sanctions on Venezuela and Iran and conflicts in the Middle East;

●	developments relating to North American energy infrastructure, including legislative, regulatory and court actions that may impact such infrastructure and other developments that may cause short- or long-term capacity constraints;

●	~~the level of global oil and natural gas exploration and production activity;~~

●	~~the effects of global conservation and sustainability measures;~~

●	~~the effects of the global and domestic economies, including the impact of expected growth, access to credit and financial and other economic issues;~~

●	~~weather conditions;~~

●	~~technological advances affecting energy consumption;~~

●	current and anticipated changes to domestic and foreign governmental regulations, such as regulation of oil and natural gas gathering and transportation, including those that may arise as a result of the U.S. Presidential election;

●	~~the price and availability of competitors’ supplies of oil and natural gas;~~

●	~~basis differentials associated with market conditions, the quality and location of production and other factors;~~

●	~~acts of terrorism;~~

●	~~the price and availability of alternative fuels; and~~

●	~~acts of force majeure.~~

These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements. Also, prices for crude oil and prices for natural gas do not necessarily move in tandem. Declines in oil or natural gas prices would not only reduce revenue, but could also reduce the amount of oil and natural gas that we can economically produce and therefore potentially lower our oil and gas reserve quantities. If the oil and natural gas industry experiences extended periods of low prices, we may, among other things, be unable to meet all of our financial obligations or make planned expenditures.

~~Oil prices declined sharply~~has occurred during the first half of 2020 primarily in response to Saudi Arabia’s announcement of plans to abandon previously agreed upon output restraints and the economic effects of the COVID-19 pandemic on the demand for oil and natural gas. Substantial and extended declines in oil, NGL and natural gas prices have resulted and may continue to result in impairments of our proved oil and gas properties or undeveloped acreage and may materially and adversely affect our future business, financial condition, cash flows, results of operations, liquidity or ability to finance planned capital expenditures. To the extent commodity prices received from production are insufficient to fund planned capital expenditures, we will be required to reduce spending, borrow under Whiting Oil and Gas’ credit agreement (the “Exit Credit Agreement”) or sell assets. Lower commodity prices may reduce the amount of our borrowing base under the Exit Credit Agreement, which is determined at the discretion of our lenders based on the collateral value of our proved reserves that have been mortgaged to the lenders, and is subject to regular redeterminations on April 1 and October 1 of each year, as well as special redeterminations described in the Exit Credit Agreement. Upon a redetermination, if total outstanding credit exposure exceeds the redetermined borrowing base, we could be forced to repay borrowings under the Exit Credit Agreement.

Lower commodity prices may also make it more difficult for us to comply with the covenants and other restrictions in the agreements governing our debt as described under the risk factor entitled “The instruments governing our indebtedness contain various covenants limiting the discretion of our management in operating our business.”

~~Table of Contents~~

Alternatively, higher oil, NGL and natural gas prices may result in significant mark-to-market losses being incurred on our commodity-based derivatives, which may in turn cause us to experience net losses.

~~Outbreaks of communicable diseases, including the COVID-19 pandemic, could adversely affect our business, financial condition, results of operations and cash flows.~~

Global or national health concerns, including the outbreak of pandemic or contagious disease, can negatively impact the global economy and, therefore, demand and pricing for oil and natural gas products. For example, there have been recent outbreaks in many countries, including the United States, of a highly transmissible and pathogenic coronavirus, which the World Health Organization declared a pandemic in March 2020. The outbreak of communicable diseases, or the perception that such an outbreak could occur, could result in a widespread public health crisis that could adversely affect the economies and financial markets of many countries, resulting in an economic downturn that would negatively impact the demand for oil and natural gas products. Furthermore, uncertainty regarding the impact and length of any outbreak of pandemic or contagious disease, including COVID-19, could lead to increased volatility in oil and natural gas prices. The occurrence or continuation of any of these events could lead to decreased revenues and limit our ability to execute on our business plan, which could adversely affect our business, financial condition, results of operations and cash flows.

Additionally, in response to the COVID-19 pandemic, our corporate staff has been working remotely and many of our key vendors, service suppliers and partners have similarly been working remotely. As a result of such remote work arrangements, certain operational, reporting, accounting and other processes may slow, which could result in longer time to execute critical business functions, higher operating costs and uncertainties regarding the quality of services and supplies. Also, in the event that there is an outbreak of COVID-19 at any of our operating locations, we could be forced to cease operations at such location. Any of the foregoing could adversely affect our business, financial condition, results of operations and cash flows.

~~The ability or willingness of OPEC and other oil exporting nations to set and maintain production levels has a significant impact on oil and natural gas commodity prices.~~

OPEC is an intergovernmental organization that seeks to manage the price and supply of oil on the global energy market. Actions taken by OPEC members, including those taken alongside other oil exporting nations, have a significant impact on global oil supply and pricing. For example, OPEC and certain other oil exporting nations have previously agreed to take measures, including production cuts, to support crude oil prices. In March 2020, members of OPEC and Russia considered extending and potentially increasing these oil production cuts. However, those negotiations were unsuccessful. As a result, Saudi Arabia announced an immediate reduction in export prices and Russia announced that all previously agreed upon oil production cuts would expire on April 1, 2020. These actions led to an immediate and steep decrease in oil prices, which reached a closing NYMEX price low of under negative $37.00 per Bbl of crude oil in April 2020. Although OPEC members subsequently agreed on certain production cuts beginning in May 2020 and continuing through April 2022, there can be no assurance that OPEC members and other oil exporting nations will continue to agree to future production cuts or other actions to support and stabilize oil prices, nor can there be any assurance that they will not further reduce oil prices or increase production. Uncertainty regarding future actions to be taken by OPEC members or other oil exporting countries could lead to increased volatility in the price of oil, which could adversely affect our business, financial condition, results of operations and cash flows.

We transport a portion of our crude oil through the Dakota Access Pipeline (“DAPL”), which is subject to ongoing litigation that may result in a shutdown of the DAPL, which could adversely affect our business, financial condition, results of operations or cash flows.

On March 25, 2020, the U.S. District Court for D.C. found that the U.S. Army Corps of Engineers had violated the National Environmental Policy Act when it granted an easement relating to a portion of the DAPL because it had failed to conduct an environmental impact statement; as a result, in an order issued July 6, 2020, the court directed that the DAPL be shut down and emptied of oil by August 5, 2020. On August 5, 2020, the U.S. Court of Appeals for the D.C. Circuit granted a stay of the portion of the order directing the shutdown of the DAPL. The stay allows the DAPL to continue to operate until a further ruling is made. We cannot provide any assurance as to the ultimate outcome of the litigation and it is possible the DAPL may be required to be shut down as a result of such litigation. In August, we expect to transport approximately 40% of our crude oil volumes through the DAPL. The disruption of transportation as a result of the DAPL being shut down could negatively impact our ability to achieve the most favorable prices for our crude oil production, which could have a material adverse effect on our business, financial condition, results of operations or cash flows.

~~Table of Contents~~

~~The Exit Credit Agreement contains various covenants limiting the discretion of our management in operating our business.~~

The Exit Credit Agreement contains various restrictive covenants that may limit our management’s discretion in certain respects. In particular, these agreements limit our and our subsidiaries’ ability to, among other things:

●	~~prepay, redeem or repurchase certain debt;~~

●	~~pay dividends or make other distributions or repurchase or redeem our capital stock;~~

●	~~make loans and investments;~~

●	~~incur or guarantee additional indebtedness or issue preferred stock;~~

●	~~create certain liens;~~

●	~~enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;~~

●	~~sell assets;~~

●	~~consolidate, merge or transfer all or substantially all of our assets and those of our restricted subsidiaries taken as a whole;~~

●	~~engage in transactions with affiliates;~~

●	~~enter into hedging contracts; and~~

●	~~create unrestricted subsidiaries.~~

~~The Exit Credit Agreement requires us, as of the last day of any quarter to maintain commodity hedges covering a minimum of 65% of our projected production for the succeeding twelve~~six months and 35% of our projected production for the next succeeding twelve months. In addition, the Exit Credit Agreement requires us, as of the last day of any quarter beginning with the quarter ending December 31, 2020, to maintain the following ratios (as defined in the Exit 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. Factors that may adversely affect our ability to comply with these covenants include oil or natural gas price declines, lack of liquidity in property and capital markets and our inability to execute on our development plan.

Moreover, the borrowing base limitation on the Exit Credit Agreement is redetermined on April 1 and October 1 of each year, and may be the subject of special redeterminations described in the Exit Credit Agreement based on an evaluation of our oil and gas reserves. Because oil and gas prices are principal inputs into the valuation of our reserves, if oil and gas prices decline, our borrowing base could be reduced at the next redetermination date or during future redeterminations. Upon a redetermination, if total outstanding credit exposure exceeds the redetermined borrowing base, we will be required to prepay outstanding borrowings under the Exit Credit Agreement.

~~We may be negatively impacted by litigation and legal proceedings, including ongoing claims in connection with the Chapter 11 Cases.~~

We are subject from time to time, and in the future may become subject, to litigation claims. These claims and legal proceedings are typically claims that arise in the normal course of business and include, without limitation, claims relating to environmental, safety and health matters, commercial or contractual disputes with suppliers and customers, claims regarding ownership of mineral interests, including from royalty owners, claims regarding acquisitions and divestitures, regulatory matters and employment and labor matters. We may also become subject to governmental or regulatory proceedings. The outcome of such claims and legal proceedings cannot be predicted with certainty and some may be disposed of unfavorably to us. In addition, the claims resolutions process in connection with the Chapter 11 Cases is ongoing and certain of these claims remain subject to the jurisdiction of the Bankruptcy Court. To the extent that these legal proceedings result in claims being allowed against us, such claims will be satisfied through the issuance of shares of our

~~Table of Contents~~

common stock, except as noted herein. As a result, we have not established reserves within our liabilities in connection with these claims. However, as discussed in more detail in the “Commitments and Contingencies” footnote in the notes to the condensed consolidated financial statements under the heading “Chapter 11 Cases,” it is possible with respect to certain claims that the ultimate outcome of the legal proceedings may result in the contracts not being treated as rejected or the amounts at issue being treated as administrative claims by the Bankruptcy Court, either of which could require us to make cash payments to resolve claims instead of issuing shares of our common stock or require us to establish reserves and accrue liabilities with respect to such claims at a future date. We also may not have insurance that covers such claims and legal proceedings. Successful claims or litigation against us for significant amounts could have a material adverse effect on our reputation, business, financial condition, results of operations and cash flows. Further, even if successful in resolving a claim or legal proceeding, such process could require the attention of members of our senior management, reducing the time they have available to devote to managing our business, and require us to incur substantial legal expenses.

~~Our ability to use our net operating loss carryforwards (“NOLs”) in future periods may be limited.~~

As of December 31, 2019, we had U.S. federal NOLs of $3.4 billion, the majority of which will expire between 2023 and 2037, if not limited by triggering events prior to such time. Under the provisions of the Internal Revenue Code (“IRC”), changes in our ownership, in certain circumstances, will limit the amount of U.S. federal NOLs that can be utilized annually in the future to offset taxable income. In particular, Section 382 of the IRC imposes limitations on a company’s ability to use NOLs upon certain changes in such ownership. As a result of the chapter 11 reorganization and related transactions, we experienced an ownership change within the meaning of IRC Section 382 that subjected certain of our tax attributes, including NOLs, to an IRC Section 382 limitation. Calculations pursuant to Section 382 of the IRC can be very complicated and no assurance can be given that upon further analysis, our ability to take advantage of our NOLs may be limited to a greater extent than we currently anticipate. If we are limited in our ability to use our NOLs in future years in which we have taxable income, we will pay more taxes than if we were able to utilize our NOLs fully, which could have a negative impact on our financial position and results of operations. Additionally, we may experience ownership changes in the future as a result of subsequent shifts in our stock ownership that we cannot predict or control that could result in further limitations being placed on our ability to utilize our federal NOLs.ended June 30, 2021.

Item 6. Exhibits

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

6347

Table of Contents

EXHIBIT INDEX

Exhibit Number		Exhibit Description
(2)		Joint Chapter 11 Plan of Reorganization of Whiting Petroleum Corporation and its Debtor Affiliates ~~(incorporated~~[Incorporated by reference to Exhibit A of the Order Confirming the Joint Chapter 11 Plan of Reorganization, filed as Exhibit 2 to ~~Whiting’s~~Whiting Petroleum Corporation’s Current Report on Form 8-K filed on August 17, ~~2020)~~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)].

(10.1)		~~Whiting Petroleum Corporation 2020 Equity Incentive Plan [Incorporated by reference~~First Amendment to ~~Exhibit 10.4 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on September 1, 2020 (File No. 001-31899)].~~

~~(10.2)~~		Credit Agreement, dated as of ~~September 1, 2020, by and~~June 7, 2021, among ~~Whiting Petroleum Corporation, as parent guarantor,~~ Whiting Oil and Gas Corporation as ~~borrower,~~Borrower, its Parent Guarantor Whiting Petroleum Corporation, JPMorgan Chase Bank, N.A., as ~~administrative agent,~~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)].~~signatory thereto.

~~(10.3)~~		~~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)].~~

~~(10.4)~~		Amendment to Employment Agreement and General Release, by and between Whiting Petroleum Corporation and Bruce R. DeBoer, dated September 10, 2020 [Incorporated by reference to Exhibit 10 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on September 11, 2020 (File No. 001-31899)].

~~(10.5)~~		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)].

~~(10.6)~~		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)].

~~(10.7)~~		Employment Agreement, by and between Whiting Petroleum Corporation and Lynn A. Peterson, dated September 1, 2020 [Incorporated by reference to Exhibit 10.5 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on September 1, 2020 (File No. 001-31899)].

~~(10.8)~~		Employment Agreement, by and between Whiting Petroleum Corporation and James P. Henderson, dated September 1, 2020 [Incorporated by reference to Exhibit 10.6 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on September 1, 2020 (File No. 001-31899)].

~~(10.9)~~		Amendment to Employment Agreement, by and between Whiting Petroleum Corporation and Correne S. Loeffler, dated September 1, 2020 [Incorporated by reference to Exhibit 10.7 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on September 1, 2020 (File No. 001-31899)].

~~(10.10)~~		~~Employment Agreement, by and between Whiting Petroleum Corporation and Charles J. Rimer, dated September 1, 2020.~~

~~Table of Contents~~

~~(10.11)~~		Amendment to Employment Agreement, by and between Whiting Petroleum Corporation and Bradley J. Holly, dated August 13, 2020 [Incorporated by reference to Exhibit 10.8 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on August 17, 2020 (File No. 001-31899)].

~~(10.12)~~		~~Summary of Non-Employee Director Compensation for Whiting Petroleum Corporation.~~

~~(10.13)~~		~~Form of Restricted Stock Unit Award Agreement (Officer Time Vesting) pursuant to the Whiting Petroleum Corporation 2020 Equity Incentive Plan.~~

~~(10.14)~~		~~Form of Restricted Stock Unit Award Agreement (Officer Stock Price Performance Vesting) pursuant to the Whiting Petroleum Corporation 2020 Equity Incentive Plan.~~

~~(10.15)~~		~~Form of Restricted Stock Unit Award Agreement (Non-Employee Director) pursuant to the Whiting Petroleum Corporation 2020 Equity Incentive Plan.~~

(31.1)		Certification by the President and Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.

(31.2)		Certification by the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.

(32.1)		Written Statement of the President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.

(32.2)		Written Statement of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350.

(99)		Order Confirming Joint Chapter 11 Plan of Reorganization of Whiting Petroleum Corporation [Incorporated by reference to Exhibit 99.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on August 17, 2020 (File No. 001-31899)].

(101)		The following materials from Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q for the quarter ended ~~September~~June 30, ~~2020~~2021 are filed herewith, formatted in iXBRL (Inline Extensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Operations, (iii) the Condensed Consolidated Statements of Cash Flows, (iv) the Condensed Consolidated Statements of Equity ~~(Deficit)~~ and (v) Notes to Condensed Consolidated Financial Statements. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the iXBRL document.

(104)		Cover Page Interactive Data File (formatted as Inline XBRL) – The cover page interactive data file does not appear in the interactive data file because its XBRL tags are embedded within the iXBRL document.

6548

Table of Contents

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on this 54^th day of ~~November, 2020.~~August, 2021.


		WHITING PETROLEUM CORPORATION


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


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


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

6649

Glossary of Certain Definitions		1
PART I – FINANCIAL INFORMATION
Item 1.	Condensed Consolidated Financial Statements (Unaudited)	5
	Condensed Consolidated Balance Sheets	5
	Condensed Consolidated Statements of Operations	6
	Condensed Consolidated Statements of Cash Flows	8
	Condensed Consolidated Statements of Equity ~~(Deficit)~~	10
	Notes to Condensed Consolidated Financial Statements	11
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3830
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	5646
Item 4.	Controls and Procedures	5747
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	5747
Item 1A.	Risk Factors	5747
Item 6.	Exhibits	6347


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


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


	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


Sources:
Release of restricted cash upon bankruptcy emergence	$	28,205
Borrowings under the Exit 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 Exit 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)


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)


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


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


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


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


Lease Asset/Liability	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


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)
Ending balance as of 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
Accretion expense		929
Asset retirement obligation at September 30, 2020 (Successor)	$	127,690


		(Gain) Loss Recognized in Income
		Successor		Predecessor
Not Designated as ASC 815 Hedges	Statements of Operations Classification	One Month Ended September 30, 2020		Two Months Ended August 31, 2020		Three Months Ended September 30, 2019
Commodity contracts	Derivative (gain) loss, net	$	(30,594)	$	43,125	$	(30,597)
Total		$	(30,594)	$	43,125	$	(30,597)


		Successor
		September 30, 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	$	23,607	$	(21,631)	$	1,976
Commodity contracts - non-current	Other long-term assets		22,817		(22,368)		449
Total derivative assets		$	46,424	$	(43,999)	$	2,425
Derivative liabilities
Commodity contracts - current	Accrued liabilities and other	$	29,298	$	(21,631)	$	7,667
Commodity contracts - non-current	Other long-term liabilities		26,027		(22,368)		3,659
Total derivative liabilities		$	55,325	$	(43,999)	$	11,326


	Predecessor
	December 31, 2019
	Fair		Carrying
	Value ⁽¹⁾		Value ⁽²⁾
1.25% Convertible Senior Notes due 2020	$	260,214	$	259,026
5.75% Senior Notes due 2021		732,995		772,080
6.25% Senior Notes due 2023		343,989		405,392
6.625% Senior Notes due 2026		681,250		988,387
Total	$	2,018,448	$	2,424,885


	2018								2019								2020
	Q1		Q2		Q3		Q4		Q1		Q2		Q3		Q4		Q1		Q2		Q3
Crude oil	$	62.89	$	67.90	$	69.50	$	58.83	$	54.90	$	59.83	$	56.45	$	56.96	$	46.08	$	27.85	$	40.94
Natural gas	$	3.13	$	2.77	$	2.88	$	3.62	$	3.00	$	2.58	$	2.29	$	2.44	$	1.88	$	1.66	$	1.89