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 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

~~Preferred Stock Purchase Rights~~

WLL

~~N/A~~

~~New York Stock Exchange~~

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 July ~~31, 2020: 91,461,283~~28, 2021: 39,117,950 shares.

TABLE OF CONTENTS

Glossary of Certain Definitions		1
PART I – FINANCIAL INFORMATION
Item 1.	Condensed Consolidated Financial Statements (Unaudited)	5
	Condensed Consolidated Balance Sheets ~~as of June 30, 2020 and December 31, 2019~~	5
	Condensed Consolidated Statements of Operations ~~for the Three and Six Months Ended June 30, 2020 and 2019~~	6
	Condensed Consolidated Statements of Cash Flows ~~for the Six Months Ended June 30, 2020 and 2019~~	78
	Condensed Consolidated Statements of Equity ~~(Deficit) for the Six Months Ended June 30, 2020 and 2019~~	910
	Notes to Condensed Consolidated Financial Statements	1011
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	4546
Item 4.	Controls and Procedures	4647
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	4647
Item 1A.	Risk Factors	4647
Item 6.	Exhibits	5347

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GLOSSARY OF CERTAIN DEFINITIONS

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

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

“ASC” Accounting Standards Codification.

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

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

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

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

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

“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. ~~A collar can also contain an additional sold put option. Refer to “three-way collar” for more information.~~

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

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

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

“FASB” Financial Accounting Standards Board.

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

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“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.

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

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

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

~~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.

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

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

“SEC” The United States Securities and Exchange Commission.

“~~three-way collar”~~turn-in-line” or “TIL” ~~A combination of options:~~To turn a ~~sold call, a purchased put~~drilled and ~~a sold put. The sold call establishes a maximum price (ceiling)~~completed well online to ~~be received for the volumes under contract. The purchased put establishes a minimum price (floor), unless the market price~~

~~Table of Contents~~

~~falls below the sold put (sub-floor), at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price.~~ begin sales.

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

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

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PART I – FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements

WHITING PETROLEUM CORPORATION ~~(DEBTOR-IN-POSSESSION)~~

CONDENSED CONSOLIDATED BALANCE SHEETS (unaudited)

(in thousands, except share and per share data)


					Successor
	June 30,		December 31,		June 30,		December 31,
	2020		2019		2021		2020
ASSETS
Current assets:
Cash and cash equivalents	$	492,088	$	8,652
Restricted cash		26,787		-
Cash, cash equivalents and restricted cash					$	19,053	$	28,367
Accounts receivable trade, net		165,492		308,249		214,223		142,830
Prepaid expenses and other		28,692		14,082		14,740		19,224
Total current assets		713,059		330,983		248,016		190,421
Property and equipment:
Oil and gas properties, successful efforts method		4,820,221		12,812,007		1,929,550		1,812,601
Other property and equipment		173,877		178,689		68,443		74,064
Total property and equipment		4,994,098		12,990,696		1,997,993		1,886,665
Less accumulated depreciation, depletion and amortization		(2,016,619)		(5,735,239)		(177,084)		(73,869)
Total property and equipment, net		2,977,479		7,255,457		1,820,909		1,812,796
Other long-term assets		41,665		50,281		39,189		40,723
TOTAL ASSETS	$	3,732,203	$	7,636,721	$	2,108,114	$	2,043,940
LIABILITIES AND EQUITY (DEFICIT)
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	912,259	$	-
Accounts payable trade		31,485		80,100	$	51,786	$	23,697
Revenues and royalties payable		136,401		202,010		191,248		151,196
Accrued capital expenditures		18,533		64,263		22,877		20,155
Accrued liabilities and other		48,830		85,007		35,143		42,007
Accrued lease operating expenses		28,446		38,262		28,642		23,457
Accrued interest		3,590		53,928
Taxes payable		12,265		26,844		16,712		11,997
Derivative liabilities						265,130		49,485
Total current liabilities		1,191,809		550,414		611,538		321,994
Long-term debt		-		2,799,885		115,000		360,000
Asset retirement obligations		91,543		131,208		93,276		91,864
Operating lease obligations		-		31,722		16,265		17,415
Deferred income taxes		69,847		73,593
Long-term derivative liabilities						89,354		9,750
Other long-term liabilities		7,745		24,928		12,909		14,113
Total liabilities not subject to compromise		1,360,944		3,611,750
Liabilities subject to compromise		2,549,538		-
Total liabilities		3,910,482		3,611,750		938,342		815,136
Commitments and contingencies
Equity (Deficit):
Common stock, $0.001 par value, 225,000,000 shares authorized; 91,636,883 issued and 91,461,283 outstanding as of June 30, 2020 and 91,743,571 issued and 91,326,469 outstanding as of December 31, 2019		92		92
Equity:
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		6,409,627		6,409,991		1,193,095		1,189,693
Accumulated deficit		(6,587,998)		(2,385,112)
Total equity (deficit)		(178,279)		4,024,971
TOTAL LIABILITIES AND EQUITY (DEFICIT)	$	3,732,203	$	7,636,721
Accumulated earnings (deficit)						(23,362)		39,073
Total equity						1,169,772		1,228,804
TOTAL LIABILITIES AND EQUITY					$	2,108,114	$	2,043,940

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

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WHITING PETROLEUM CORPORATION ~~(DEBTOR-IN-POSSESSION)~~

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)

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WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)

(in thousands, except per share data)


	Three Months Ended June 30,				Six Months Ended June 30,					Successor		Predecessor
	2020		2019		2020		2019			Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
OPERATING REVENUES
Oil, NGL and natural gas sales	$	91,600	$	426,264	$	336,446	$	815,753		$	654,662	$	336,446
Purchased gas sales											4,375		-
Total operating revenues											659,037		336,446
OPERATING EXPENSES
Lease operating expenses		53,242		86,987		125,582		171,064			123,521		125,582
Transportation, gathering, compression and other		9,044		11,128		18,007		20,969			14,471		18,007
Purchased gas expense											3,080		-
Production and ad valorem taxes		8,419		39,420		30,842		67,576			49,819		30,842
Depreciation, depletion and amortization		83,549		203,009		267,517		401,141			105,347		267,517
Exploration and impairment		421,156		13,406		4,174,613		33,155			4,669		4,174,613
General and administrative		28,136		32,573		75,303		67,547			22,286		75,303
Derivative (gain) loss, net		6,632		(24,877)		(224,739)		38,028			402,102		(224,739)
(Gain) loss on sale of properties		511		1,063		(353)		1,086
Gain on sale of properties											(10,110)		(353)
Amortization of deferred gain on sale		(1,908)		(2,326)		(3,945)		(4,697)			-		(3,945)
Total operating expenses		608,781		360,383		4,462,827		795,869			715,185		4,462,827
INCOME (LOSS) FROM OPERATIONS		(517,181)		65,881		(4,126,381)		19,884
LOSS FROM OPERATIONS											(56,148)		(4,126,381)
OTHER INCOME (EXPENSE)
Interest expense		(16,425)		(48,728)		(61,675)		(96,827)			(9,084)		(61,675)
Gain on extinguishment of debt		-		-		25,883		-			-		25,883
Interest income and other		76		642		72		958
Other income											2,797		72
Reorganization items, net		(41,813)		-		(41,813)		-			-		(41,813)
Total other expense		(58,162)		(48,086)		(77,533)		(95,869)			(6,287)		(77,533)
INCOME (LOSS) BEFORE INCOME TAXES		(575,343)		17,795		(4,203,914)		(75,985)
LOSS BEFORE INCOME TAXES											(62,435)		(4,203,914)
INCOME TAX EXPENSE (BENEFIT)
Current		(1,028)		-		2,718		-			-		2,718
Deferred		-		23,482		(3,746)		(1,373)			-		(3,746)
Total income tax expense (benefit)		(1,028)		23,482		(1,028)		(1,373)
Total income tax benefit											-		(1,028)
NET LOSS	$	(574,315)	$	(5,687)	$	(4,202,886)	$	(74,612)		$	(62,435)	$	(4,202,886)
INCOME (LOSS) PER COMMON SHARE
LOSS PER COMMON SHARE
Basic	$	(6.28)	$	(0.06)	$	(45.98)	$	(0.82)		$	(1.61)	$	(45.98)
Diluted	$	(6.28)	$	(0.06)	$	(45.98)	$	(0.82)		$	(1.61)	$	(45.98)
WEIGHTED AVERAGE SHARES OUTSTANDING
Basic		91,429		91,286		91,409		91,261			38,883		91,409
Diluted		91,429		91,286		91,409		91,261			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)

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

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WHITING PETROLEUM CORPORATION ~~(DEBTOR-IN-POSSESSION)~~

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(in thousands)

Six Months Ended June 30,

2020

2019
CASH FLOWS FROM OPERATING ACTIVITIES

Net loss

$
(4,202,886)

$
(74,612)
Adjustments to reconcile net loss to net cash provided by operating activities:

Depreciation, depletion and amortization

267,517

401,141
Deferred income tax benefit

(3,746)

(1,373)
Amortization of debt issuance costs, debt discount and debt premium

9,786

15,734
Stock-based compensation

3,401

8,617
Amortization of deferred gain on sale

(3,945)

(4,697)
(Gain) loss on sale of properties

(353)

1,086
Oil and gas property impairments

4,154,369

13,179
Gain on extinguishment of debt

(25,883)

-
Non-cash derivative (gain) loss

(178,525)

42,371
Non-cash reorganization items, net

38,145

-
Other, net

829

3,492
Changes in current assets and liabilities:

Accounts receivable trade, net

152,560

(1,813)
Prepaid expenses and other

(12,036)

3,453
Accounts payable trade and accrued liabilities

(51,783)

20,261
Revenues and royalties payable

(65,609)

(41,637)
Taxes payable

(14,579)

(3,269)
Net cash provided by operating activities

67,262

381,933
CASH FLOWS FROM INVESTING ACTIVITIES

Drilling and development capital expenditures

(223,905)

(425,349)
Acquisition of oil and gas properties

(351)

(4,507)
Other property and equipment

(423)

(8,233)
Proceeds from sale of properties

28,243

15,444
Net cash used in investing activities

(196,436)

(422,645)
CASH FLOWS FROM FINANCING ACTIVITIES

Borrowings under credit agreement

1,185,000

1,160,000
Repayments of borrowings under credit agreement

(490,000)

(1,120,000)
Repurchase of 1.25% Convertible Senior Notes due 2020

(52,890)

-
Restricted stock used for tax withholdings

(304)

(3,693)
Principal payments on finance lease obligations

(2,409)

(2,522)
Net cash provided by financing activities

$
639,397

$
33,785

(Continued)


	Successor		Predecessor
	Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
CASH FLOWS FROM 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		105,347		267,517
Deferred income tax benefit		-		(3,746)
Amortization of debt issuance costs, debt discount and debt premium		1,773		9,786
Stock-based compensation		4,764		3,401
Amortization of deferred gain on sale		-		(3,945)
Gain on sale of properties		(10,110)		(353)
Oil and gas property impairments		2,691		4,154,369
Gain on extinguishment of debt		-		(25,883)
Non-cash derivative (gain) loss		295,249		(178,525)
Non-cash reorganization items, net		-		38,145
Other, net		(3,670)		829
Changes in current assets and liabilities:
Accounts receivable trade, net		(69,957)		152,560
Prepaid expenses and other		4,484		(12,036)
Accounts payable trade and accrued liabilities		23,536		(51,783)
Revenues and royalties payable		40,052		(65,609)
Taxes payable		4,715		(14,579)
Net cash provided by operating activities		336,439		67,262
CASH FLOWS FROM INVESTING ACTIVITIES
Drilling and development capital expenditures		(103,379)		(223,905)
Acquisition of oil and gas properties		(509)		(351)
Other property and equipment		490		(423)
Proceeds from sale of properties		6,442		28,243
Net cash used in investing activities		(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
Repayments of borrowings under Predecessor Credit Agreement		-		(490,000)
Repurchase of 1.25% Convertible Senior Notes due 2020		-		(52,890)
Principal payments on finance lease obligations		(2,436)		(2,409)
Restricted stock used for tax withholdings		(1,361)		(304)
Net cash provided by (used in) financing activities	$	(248,797)	$	639,397

				(Continued)

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WHITING PETROLEUM CORPORATION ~~(DEBTOR-IN-POSSESSION)~~

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(in thousands)


		Six Months Ended June 30,					Successor		Predecessor
		2020		2019			Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH		$	510,223	$	(6,927)		$	(9,314)	$	510,223
CASH, CASH EQUIVALENTS AND RESTRICTED CASH
Beginning of period			8,652		13,607			28,367		8,652
End of period		$	518,875	$	6,680		$	19,053	$	518,875
SUPPLEMENTAL CASH FLOW DISCLOSURES
Interest paid, net of amounts capitalized		$	72,199	$	79,341		$	6,189	$	72,199
Cash paid for reorganization items		$	3,668	$	-		$	396	$	3,668
NONCASH INVESTING ACTIVITIES
Accrued capital expenditures and accounts payable related to property additions		$	38,504	$	122,098		$	26,935	$	38,504
NONCASH FINANCING ACTIVITIES
Derivative termination settlement payments used to repay borrowings under credit agreement		$	157,741	$	-
Derivative termination settlement payments used to repay borrowings under Predecessor Credit Agreement							$	-	$	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)

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WHITING PETROLEUM CORPORATION ~~(DEBTOR-IN-POSSESSION)~~

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

(in thousands)

Additional

Common Stock

Paid-in

Accumulated

Total

Shares

Amount

Capital

Deficit

Equity (Deficit)
BALANCES - January 1, 2019

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

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

91,891

$
92

$
6,419,093

$
(2,218,558)

$
4,200,627

BALANCES - January 1, 2020

91,744

$
92

$
6,409,991

$
(2,385,112)

$
4,024,971
Net loss

-

-

-

(3,628,571)

(3,628,571)
Adjustment to equity component of 2020 Convertible Senior Notes upon extinguishment

-

-

(3,461)

-

(3,461)
Restricted stock issued

185

-

-

-

-
Restricted stock forfeited

(238)

-

-

-

-
Restricted stock used for tax withholdings

(54)

-

(304)

-

(304)
Stock-based compensation

-

-

2,068

-

2,068
BALANCES - March 31, 2020

91,637

92

6,408,294

(6,013,683)

394,703
Net loss

-

-

-

(574,315)

(574,315)
Stock-based compensation

-

-

1,333

-

1,333
BALANCES - June 30, 2020

91,637

$
92

$
6,409,627

$
(6,587,998)

$
(178,279)


				Additional		Accumulated
	Common Stock			Paid-in		Earnings		Total
	Shares	Amount		Capital		(Deficit)		Equity
BALANCES - January 1, 2020 (Predecessor)	91,744	$	92	$	6,409,991	$	(2,385,112)	$	4,024,971
Net loss	-		-		-		(3,628,571)		(3,628,571)
Adjustment to equity component of Convertible Senior Notes upon extinguishment	-		-		(3,461)		-		(3,461)
Restricted stock issued	185		-		-		-		-
Restricted stock forfeited	(238)		-		-		-		-
Restricted stock used for tax withholdings	(54)		-		(304)		-		(304)
Stock-based compensation	-		-		2,068		-		2,068
BALANCES - March 31, 2020 (Predecessor)	91,637		92		6,408,294		(6,013,683)		394,703
Net loss	-		-		-		(574,315)		(574,315)
Stock-based compensation	-		-		1,333		-		1,333
BALANCES - June 30, 2020 (Predecessor)	91,637	$	92	$	6,409,627	$	(6,587,998)	$	(178,279)


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	95		-		-		-		-
Restricted stock used for tax withholdings	(41)		-		(1,357)		-		(1,357)
Stock-based compensation	-		-		2,309		-		2,309
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.

910

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WHITING PETROLEUM CORPORATION ~~(DEBTOR-IN-POSSESSION)~~

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 ~~acquisition~~ and ~~exploration~~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 ~~Corporation,~~LLC (“WRC,” formerly Whiting Resources Corporation) and Whiting Programs, ~~Inc,~~Inc. In September 2020, Whiting ~~Raven Colorado Corp.~~US Holding Company merged with and into WOG with WOG surviving, and WRC transferred all of its operating assets to WOG. In November 2020, WRC, over a series of steps, was amalgamated with Whiting ~~ND Sakakawea LLC.~~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. ~~The~~On June 30, 2020, the Debtors filed the Joint Chapter 11 ~~Cases are being administered jointly under the caption~~ ~~In re~~Plan of Reorganization of Whiting Petroleum Corporation ~~et al.~~ ~~Case No. 20-32021. The Debtors continue to operate their businesses as “debtors-in-possession” under~~and its Debtor affiliates (as amended, modified and supplemented, the ~~jurisdiction of the Bankruptcy Court, in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court.~~

“Plan”). On ~~July 1,~~August 14, 2020, the Bankruptcy Court entered an order approving the Debtors’ disclosure statement, allowing for solicitation of the Debtors’ chapter 11 plan of reorganization (the “Plan”) to commence. A Bankruptcy Court hearing to consider confirmation ofconfirmed the Plan ~~is scheduled to be held~~and on ~~August 10, 2020.~~September 1, 2020 (the “Emergence Date”), the Debtors satisfied all conditions required for Plan effectiveness and emerged from the Chapter 11 Cases.

~~The commencement of a voluntary proceeding~~Upon emergence, the Company adopted fresh start accounting in bankruptcy constituted an immediate event of default under Whiting Oil and Gas’ credit agreement (the “Credit Agreement”) and the indentures governing the Company’s senior notes, resulting in the automatic and immediate acceleration of all of the Company’s debt outstanding.

~~The Company has applied~~accordance with FASB ASC Topic 852 – Reorganizations (“ASC 852”) ~~in preparing the condensed consolidated financial statements,~~ , which specifies the accounting and financial reporting requirements for entities reorganizing through chapter 11 bankruptcy proceedings. ~~These requirements include~~The application of fresh start accounting resulted in a new basis of accounting and the Company becoming a new entity for financial reporting purposes. As a result of the implementation of the Plan and the application of fresh start accounting, the consolidated financial statements after the Emergence Date are not comparable to the consolidated financial statements before that date and the historical financial statements on or before the Emergence Date are not a reliable indicator of the Company’s financial condition and results of operations for any period after its adoption of fresh start accounting. Refer to the “Fresh Start Accounting” footnote for more information. References to “Successor” refer to the Company and its financial position and results of operations after the Emergence Date. References to “Predecessor” refer to the Company and its financial position and results of operations on or before the Emergence Date. References to “Successor Period” and “Successor YTD Period” refer to the three and six months ended June 30, 2021, respectively. References to “Predecessor Period” and “Predecessor YTD Period” refer to the three and six months ended June 30, 2020, respectively.

During the 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 may be impacted by the chapter 11 proceedings have been classified as liabilities subject to compromise on the condensed consolidated balance sheet as of June 30, 2020. Additionally, certain expenses, realized gains and losses and provisions for losses that ~~are~~were realized or incurred during the Chapter 11 Cases, including adjustments to the carrying value of certain indebtedness, ~~are~~were recorded as reorganization items, net in the condensed consolidated statements of operations for the ~~three and six months ended June 30, 2020.~~Predecessor periods. Refer to the “Chapter 11 ~~Cases”~~Emergence” footnote for more information on the events of the bankruptcy proceedings as well as the accounting and reporting impacts of the ~~reorganization.~~

~~Ability to Continue as a Going Concern—The accompanying condensed consolidated financial statements are prepared in accordance with generally accepted accounting principles applicable to a going concern, which contemplates~~reorganization during the ~~realization of assets and the satisfaction of liabilities in the normal course of business.~~

As discussed above, the filing of the Chapter 11 Cases constituted an event of default under the Company’s outstanding debt agreements, resulting in the automatic and immediate acceleration of all of the Company’s debt outstanding. The Company projects that it will not have sufficient cash on hand or available liquidity to repay such debt. These conditions and events raise substantial doubt about the Company’s ability to continue as a going concern.

As part of the Chapter 11 Cases, the Company submitted the Plan to the Bankruptcy Court. The Company’s operations and its ability to develop and execute its business plan are subject to a high degree of risk and uncertainty associated with the Chapter 11 Cases. The outcome of the Chapter 11 Cases is subject to a high degree of uncertainty and is dependent upon factors that are outside of the Company’s control, including actions of the Bankruptcy Court and the Company’s creditors. There can be no assurance that the Company will confirm and consummate the plan of reorganization as contemplated by the restructuring support agreement (“RSA”) with certain holders of the Company’s senior notes or complete another plan of reorganization with respect to the Chapter 11 Cases. As

~~Table of Contents~~

~~a result, the Company has concluded that management’s plans do not alleviate substantial doubt about the Company’s ability to continue as a going concern.~~

While operating as a debtor-in-possession, the Company may sell or otherwise dispose of or liquidate assets or settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business, for amounts other than those reflected in the accompanying condensed consolidated financial statements. Further, the Plan or other bankruptcy proceedings could materially change the amounts and classifications of assets and liabilities reported in the condensed consolidated financial statements, including liabilities subject to compromise which will be resolved in connection with the Chapter 11 Cases. The accompanying condensed consolidated financial statements do not include any adjustments related to the recoverability and classification of assets or the amounts and classification of liabilities or any other adjustments that might be necessary should the Company be unable to continue as a going concern or as a consequence of the Chapter 11 Cases.Predecessor YTD Period.

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

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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 June 30, ~~2020~~2021 and December 31, ~~2019.~~2020. The Company maintains its cash and cash equivalents in the form of money market and checking accounts with financial institutions that are also lenders under the ~~Credit Agreement.~~Successor’s credit agreement. The Company has not experienced any losses on its deposits of cash and cash equivalents.

Restricted cash as of June 30, 2021 and December 31, 2020 ~~includes $23 million~~consist of funds ~~related to derivative termination settlements~~remaining in a professional fee escrow account that were ~~directed by~~reserved to pay certain professional fees upon emergence from the ~~counterparty to be held in a segregated account until the Company emerges from chapter~~Chapter 11 bankruptcy, at which point the Company intends to apply the funds toward its outstanding borrowings under the Credit Agreement. Refer to the “Derivative Financial Instruments” footnote for additional information on terminated derivative settlements. Additionally, $4 million of the restricted cash balance as of June 30, 2020 consists of amounts set aside as adequate assurance for certain utility and credit card providers, which funds will also be restricted until the Company emerges from chapter 11 bankruptcy.Cases.

~~Table of Contents~~

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):

June 30,

December 31,

2020

2019
Cash and cash equivalents

$
492,088

$
8,652
Restricted cash

26,787

-
Total cash, cash equivalents and restricted cash

$
518,875

$
8,652


	Successor
	June 30,		December 31,
	2021		2020
Cash and cash equivalents	$	16,652	$	25,607
Restricted cash		2,401		2,760
Total cash, cash equivalents and restricted cash	$	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, ~~2020~~2021 and December 31, ~~2019,~~2020 (Successor), the Company had ~~an allowance~~immaterial allowances for credit ~~losses~~losses.

Table of ~~$11 million and $9 million, respectively.~~Contents

2. CHAPTER 11 ~~CASES~~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. To ensure ordinary course operations, the Debtors have obtained approval from the Bankruptcy Court for certain “first day” motions, including motions to obtain customary relief intended to continue ordinary course operations after the Petition Date. In addition, the Debtors have received authority to use cash collateral of the lenders under the Credit Agreement on an interim basis.

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. ~~The Plan and the related disclosure statement were each filed with~~On August 14, 2020, the Bankruptcy Court ~~on April 23, 2020. Below is a summary of~~confirmed the ~~treatment that~~Plan. On September 1, 2020, the ~~stakeholders of~~Debtors satisfied all conditions required for Plan effectiveness and emerged from the ~~Company would receive under~~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:

●

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

●

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

●

4,837,387 Series A Warrants to 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.

The Company also reserved 3,070,201 shares of the Successor’s common stock for potential future distribution to certain general unsecured claimants whose claim values were pending resolution in the Bankruptcy Court. In February 2021, the Company issued 948,897 shares out of this reserve to a general unsecured claimant in full settlement of such claimant’s claims pending before the Bankruptcy Court and for rejection damages relating to an executory contract. Any remaining reserved shares that are not distributed to resolve pending claims will be cancelled. In addition, 4,035,885 shares 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 “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 Credit Agreement. The Company utilized borrowings from the Credit Agreement ~~Claims.~~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, and the Predecessor Credit Agreement terminated on that date.

(6)

The holders of ~~obligations under the Credit Agreement would have such obligations refinanced or repaid~~trade claims, administrative expense claims, other secured claims and other priority claims received payment in full in cash upon emergence or through the ~~Debtors’ emergence from chapter 11.~~

●

~~Holders~~ordinary course of ~~Senior Notes, Rejection Damages Claims and Litigation Claims.~~ ~~The holders of Whiting’s senior notes and other general unsecured claims (including rejection damages claims and litigation claims) would receive 97% of~~business after the ~~reorganized company’s equity interests.~~

●	~~Trade and Other Claims.~~ ~~The holders of the Debtors’ other secured, priority and trade vendor claims would receive payment in full in cash following emergence.~~

●	~~Existing Equity Holders.~~ ~~The holders of the Company’s existing stock would receive (a) 3% of the reorganized company’s equity interests and (b) warrants on the terms set forth in the Plan.~~Emergence Date.

~~Unsecured Creditors’ Committee—On April 10, 2020,~~ the United States Trustee appointed the official committee for unsecured creditors (the “Creditors’ Committee”). The Creditors’ Committee and its legal representatives have a right to be heard on all matters affecting unsecured creditors that come before the Bankruptcy Court with respect to the Debtors.

~~Table of Contents~~

~~Solicitation of the Plan~~—On July 1, 2020, the Bankruptcy Court entered into an order approving the Debtors’ disclosure statement, allowing for solicitation of the Plan to commence. A Bankruptcy Court hearing to consider confirmation of the Plan is scheduled to be held on August 10, 2020.

Executory Contracts—Subject to certain exceptions, under the Bankruptcy Code the Debtors ~~may~~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 iswas treated as a pre-petition breach of such contract and, subject to certain exceptions, ~~relieves~~relieved the Debtors from performing future obligations under such contract but ~~entitles~~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 ~~requires~~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. On July 18, 2020,~~Code unless an order settling the ~~Debtors filed their preliminary schedules~~claims

Table of ~~assumed and rejected executory contracts and unexpired leases with~~Contents

has been issued by the Bankruptcy Court. ~~The~~Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the Debtors expressly reserve all of their rights ~~to further modify such schedules at any time prior~~in that regard. Refer to the ~~effective date of the Plan.~~

~~Liabilities Subject~~“Commitments and Contingencies” footnote for more information on potential future rejection damages related to ~~Compromise~~—The accompanying condensed consolidated balance sheets include amounts classified as “liabilities subject to compromise,” which represent pre-petition liabilities that have been allowed, or that the Company anticipates will be allowed, as claims in the Chapter 11 Cases, although they may be settled for less. The Company will continue to evaluate these liabilities throughout the Chapter 11 Cases and adjust amounts as necessary. Such adjustments may be material.

~~The following table summarizes the components of liabilities subject to compromise included in the condensed consolidated balance sheets (in thousands):~~

June 30, 2020
Debt subject to compromise

$
2,368,497
Accounts payable trade

48,434
Accrued liabilities and other

63,557
Accrued interest on debt subject to compromise

30,028
Asset retirement obligations ⁽¹⁾

39,022
Total liabilities subject to compromise

$
2,549,538

~~(1)~~

~~Amount relates to an executory contract for certain offshore facilities in California.~~

~~Magnitude of Potential Claims~~—The Debtors have filed with the Bankruptcy Court schedules and statements setting forth, among other things, the assets and liabilities of each of the Debtors. These schedules and statements may be subject to further amendment or modification after filing. Certain holders of pre-petition claims that are not governmental units were required to file proofs of claim by the deadline for general ~~claims, which was June 15, 2020.~~

The Debtors have received approximately 1,600 proofs of claim from third parties as of July 31, 2020 for an amount totaling approximately $2.8 billion. Such amount includes duplicate claims across multiple debtor legal entities. These claims will be reconciled to amounts recorded in the Company’s accounting records. Differences in amounts recorded and claims filed by creditors will be investigated and resolved, including through the filing of objections with the Bankruptcy Court, where appropriate. The Bankruptcy Court does not allow for claims that have been acknowledged as duplicates. In addition, the Company may ask the Bankruptcy Court to disallow claims that the Company believes have been later amended or superseded, are without merit, are overstated or should be disallowed for other reasons. As a result of this process, the Company may identify additional liabilities that will need to be recorded or reclassified to liabilities subject to compromise. In light of the substantial number of claims filed, and expected to be filed, the claims resolution process may take considerable time to complete and likely will continue after the Debtors emerge from bankruptcy.unsecured claims.

Interest Expense—The Company ~~has~~ discontinued recording interest on ~~debt instruments classified as liabilities subject to compromise as of~~its senior notes between the Petition ~~Date.~~Date and the Emergence Date in accordance with ASC 852. The contractual interest expense ~~on liabilities subject to compromise~~ not accrued in the condensed consolidated statements of operations was approximately $34 million for the ~~three months~~period from the Petition Date through June 30, ~~2020.~~2020 (Predecessor).

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

For further information on the Company’s reorganization value and the resulting fresh start adjustments made on the Emergence Date, refer to the “Fresh Start Accounting” footnote in the notes to the consolidated financial statements in Item 8 of the Company’s Annual Report on Form 10-K for the period ending December 31, 2020.

Reorganization Items, Net—~~The Company has~~Any expenses, gains and losses that were realized or incurred between the Petition Date and ~~will continue to incur significant costs~~the Emergence Date and as a direct result of the Chapter 11 Cases ~~subsequent to the Petition Date. These costs, which are expensed as incurred, are~~were 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 three and six months ended June 30, 2020 (in thousands):


	Three and Six Months Ended		Predecessor
	June 30, 2020		Three and Six Months Ended
Legal and professional advisory fees ⁽¹⁾	$	26,668
Write-off of unamortized debt issuance costs and premium⁽²⁾		15,145
			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	$	41,813

(1)

As a result of ~~June 30, 2020, $23 million~~the Chapter 11 Cases and the adoption of ~~these fees are accrued~~ASC 852, the Company wrote off all unamortized premium and ~~unpaid and are presented in accrued liabilities and other in~~issuance cost balances related to its senior notes on the ~~condensed consolidated balance sheet. The remaining $4 million represents cash charges for the three and six months ended June 30, 2020.~~Petition Date.

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~~(2)~~

~~Non-cash reorganization item. Refer to the “Long-Term Debt” footnote for further information.~~

3.4. OIL AND GAS PROPERTIES

Net capitalized costs related to the Company’s oil and gas producing activities at June 30, ~~2020~~2021 and December 31, ~~2019~~2020 are as follows (in thousands):

June 30,

December 31,

2020

2019
Costs of completed wells and facilities

$
4,267,233

$
9,847,159
Proved leasehold costs

376,329

2,702,236
Unproved leasehold costs

90,561

103,278
Wells and facilities in progress

86,098

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

4,820,221

12,812,007
Accumulated depletion

(1,936,121)

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

$
2,884,100

$
7,155,078


	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

~~The following table presents impairment~~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 ~~2019, which~~$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 (in thousands):~~

Three Months Ended

Six Months Ended

June 30,

June 30,

2020

2019

2020

2019
Impairment expense for unproved properties

$
132

$
2,308

$
12,483

$
5,830

operations.

Refer to the “Fair Value Measurements” footnote for more information on proved property ~~measurements~~impairments recorded during the three and six months ended June 30, ~~2020 and 2019.~~2020.

4.5. 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 ~~Company~~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.

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~~2019 Acquisitions and Divestitures~~

On July 29, 2019, the Company 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 Company 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 six months ended June 30, 2019.~~

5.6. LONG-TERM DEBT

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

June 30,

December 31,

2020

2019
Credit Agreement

$
912,259

$
375,000
1.25% Convertible Senior Notes due 2020

186,592

262,075
5.75% Senior Notes due 2021

773,609

773,609
6.25% Senior Notes due 2023

408,296

408,296
6.625% Senior Notes due 2026

1,000,000

1,000,000
Total principal

3,280,756

2,818,980
Unamortized debt discounts and premiums ⁽¹⁾

-

(2,575)
Unamortized debt issuance costs on notes ⁽¹⁾

-

(16,520)
Total debt, prior to reclassification to liabilities subject to compromise

3,280,756

2,799,885
Less amounts reclassified to liabilities subject to compromise ⁽²⁾

(2,368,497)

-
Total debt not subject to compromise ⁽³⁾

912,259

2,799,885
Less current portion of long-term debt ⁽⁴⁾

(912,259)

-
Total long-term debt

$
-

$
2,799,885

~~(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 to reorganization items, net in the condensed consolidated statements of operations for the three and six months ended June 30, 2020. Refer to the “Chapter 11 Cases” footnote for more information.

~~(2)~~

Debt subject to compromise includes the principal balances of all of the Company’s senior notes, which are unsecured claims in the Chapter 11 Cases. Refer to the “Basis of Presentation” and “Chapter 11 Cases” footnotes for more information.

~~(3)~~

Debt not subject to compromise includes all borrowings outstanding under the Credit Agreement, which are secured claims in the Chapter 11 Cases. Refer to the “Basis of Presentation” and “Chapter 11 Cases” footnotes for more information.

~~(4)~~

Due to uncertainties regarding the outcome of the Chapter 11 Cases, the Company has classified the borrowings outstanding under the Credit Agreement as current as of June 30, 2020. Refer to the “Basis of Presentation” and “Chapter 11 Cases” footnotes for more information.

~~Chapter 11 Cases and Effect of Automatic Stay~~

On April 1, 2020, the Debtors filed for relief under chapter 11 of the Bankruptcy Code. The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under the Credit Agreement and the indentures governing the Company’s senior notes, resulting in the automatic and immediate acceleration of all of the Company’s outstanding debt. In conjunction with the filing of the Chapter 11 Cases, the Company did not make the $187 million principal payment due on its 1.25% 2020 Convertible Senior Notes due April 1, 2020 (the “2020 Convertible Senior Notes”). Any efforts to enforce payment obligations related to the acceleration of the Company’s debt have been automatically stayed as a result of the filing of the Chapter 11 Cases, and the creditors’ rights of enforcement

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~~are subject to the applicable provisions of the Bankruptcy Code. Refer to the “Basis of Presentation” and “Chapter 11 Cases” footnotes for more information on the Chapter 11 Cases.~~

~~Credit Agreement~~

Whiting Oil and Gas, the Company’s wholly owned subsidiary, has a credit agreement with a syndicate of banks that had a borrowing base of $2.05 billion and aggregate commitments of $1.75 billion prior to default. As of June 30, 2020, the Company had $912 millionconsisting entirely of borrowings outstanding under the Company’s Credit ~~Agreement.~~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 ~~result~~borrowing base and aggregate commitments of ~~the commencement~~$750 million. As of ~~the Chapter 11 Cases,~~June 30, 2021, the Company ~~is no longer in compliance with the covenants~~had $633 million of available borrowing capacity under the Credit Agreement, which was net of $115 million of borrowings outstanding and the lenders’ commitments under the Credit Agreement have been terminated. The Company is therefore unable to make additional borrowings or issue additional letters of credit under the Credit Agreement.

Prior to default, a portion of the Credit Agreement in an aggregate amount not to exceed $50 million was available to issue letters of credit for the account of Whiting Oil and Gas or other designated subsidiaries of the Company. As of June 30, 2020, $2 million in letters of credit ~~were outstanding under the agreement.~~outstanding.

~~Prior to default, the~~The borrowing base under the Credit Agreement ~~was~~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 ~~May~~April 1 and ~~November~~October 1 of each year, as well as special redeterminations described in the Credit ~~Agreement. Such redeterminations have~~Agreement, in each case which may increase or

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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 ~~occurred and are not expected~~ to ~~occur~~exceed $50 million may be used to issue letters of credit for the ~~duration~~account of Whiting Oil and Gas or other designated subsidiaries of the ~~Chapter 11 Cases.~~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 ~~Credit Agreement expires~~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 ~~0.50%~~1.75% and ~~1.50%~~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~~eurodollar loan plus a margin between ~~1.50%~~2.75% and ~~2.50%~~3.75% based on the ratio of outstanding borrowings and letters of credit to the lower of the current borrowing ~~base. Prior to the chapter 11 proceedings,~~base or total commitments. Additionally, the Company ~~incurred~~incurs commitment fees of ~~0.375% or 0.50% based on the ratio of outstanding borrowings to the borrowing base~~0.5% on the unused portion of the aggregate commitments of the lenders under the Credit Agreement, which ~~were~~are included as a component of interest expense. During the chapter 11 proceedings, the commitment fee has been terminated and instead all amounts outstanding under the Credit Agreement will bear interest per annum at the applicable rate stated in the agreement plus a 2.0% default rate. At June 30, ~~2020,~~2021, the weighted average interest rate on the outstanding principal balance under the Credit Agreement was ~~4.7%~~4.1%.

Prior to default, the Credit Agreement had a maturity date of April 12, 2023, provided that if at any time and for so long as any senior notes (other than the 2020 Convertible Senior Notes) had a maturity date prior to 91 days after April 12, 2023, the maturity date shall be the date that is 91 days prior to the maturity of such senior notes.

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.~~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 ~~(as defined~~and are calculated in accordance with definitions contained in the Credit ~~Agreement). As of June 30, 2020, there were 0 retained earnings free from restrictions.~~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 (as defined in the Credit Agreement):~~ratios: (i) a consolidated current assets to consolidated current liabilities ratio ~~(which includes an add back of the available borrowing capacity under the credit agreement)~~ of not less than 1.0 to 1.0 and (ii) a total debt to last four quarters’ EBITDAX ratio of not greater than ~~4.0~~3.5 to 1.0.

~~Under~~ As of June 30, 2021, the Company was in compliance with the covenants under the Credit Agreement, a cross-default provision provides that a default under certain other debt of the Company or certain of its subsidiaries in an aggregate principal amount exceeding $100 million may constitute an event of default under such Credit Agreement. Additionally, under the indentures governing the Company’s senior notes and senior convertible notes, a cross-default provision provides that a default under certain other debt of the Company or certain of its subsidiaries in an aggregate principal amount exceeding $100 million (or $50 million in the case of the senior notes due in 2021) may constitute an event of default under such indenture.

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The obligations of Whiting Oil and Gas under the Credit Agreement are ~~collateralized~~secured by a first lien on substantially all of ~~Whiting Oil and Gas’ and Whiting Resource Corporation’s~~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)

~~Senior Notes—In September 2013,~~Prior to the Emergence Date, the Company ~~issued at par $800~~had outstanding notes consisting of $774 million of 5.75% Senior Notes due ~~March 15,~~ 2021, ~~and issued at 101% of par an additional $400~~$408 million ~~of 5.75%~~6.25% Senior Notes due ~~March 15, 2021~~2023 and $1.0 billion 6.625% Senior Notes due 2026 (collectively, the ~~“2021~~“Senior Notes”) and $187 million of 1.25% Convertible Senior Notes due 2020 (the “Convertible Senior Notes”). ~~Prior~~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 ~~Petition Date, the debt premium recorded in connection with the issuance~~holders of the 2021 Senior Notes was amortized to interest expense over the term of the notes using the effective interest method, with an effective interest rate of 5.5% per annum. As a result of the Chapter 11 Cases and the adoption of ASC 852,those outstanding notes. In addition, the remaining unamortized debt issuance costs and debt premium ~~balance was~~were written off to reorganization items, net in the condensed consolidated statements of operations. Refer to the “Chapter 11 ~~Cases” footnote~~Emergence” and “Fresh Start Accounting” footnotes for more information.

~~In March 2015, the Company issued at par $750 million of 6.25% Senior Notes due April 1, 2023 (the “2023 Senior Notes”).~~

In December 2017, the Company issued at par $1.0 billion of 6.625% Senior Notes due January 15, 2026 (the “2026 Senior Notes” and together with the 2021 Senior Notes and the 2023 Senior Notes, the “Senior Notes”).

During 2016, the Company exchanged $326 million aggregate principal amount of 2021 Senior Notes and $342 million aggregate principal amount of 2023 Senior Notes for the same aggregate principal amount of convertible notes. Subsequently during 2016, all $668 million aggregate principal amount of these convertible notes was converted into approximately 16.3 million shares of the Company’s common stock pursuant to the terms of the notes.

~~Repurchases of 2021 Senior Notes.~~ In September 2019, the Company paid $24 million to repurchase $25 million aggregate principal amount of the 2021 Senior Notes, which payment consisted of the average 94.708% purchase price plus all accrued and unpaid interest on the notes. The Company financed the repurchases with borrowings under the Credit Agreement. As a result of the repurchases, the Company recognized a $1 million gain on extinguishment of debt, which included a non-cash charge for the acceleration of unamortized debt issuance costs and debt premium on the notes.

In October 2019, the Company paid an additional $72 million to repurchase $75 million aggregate principal amount of the 2021 Senior Notes, which payment consisted of the average 95.467% purchase price plus all accrued and unpaid interest on the notes. The Company financed the repurchases with borrowings under the Credit Agreement. As a result of the repurchases, the Company recognized a $3 million gain on extinguishment of debt, which included a noncash charge for the acceleration of unamortized debt issuance costs and debt premium on the notes. As of June 30, 2020, $774 million of 2021 Senior Notes remained outstanding.

~~2020 Convertible Senior Notes~~—In March 2015, the Company issued at par $1.25 billion of the 2020 Convertible Senior Notes for net proceeds of $1.2 billion, net of initial purchasers’ fees of $25 million. During 2016, the Company exchanged $688 million aggregate principal amount of its 2020 Convertible Senior Notes for the same aggregate principal amount of new mandatory convertible senior notes. Subsequently during 2016, all $688 million aggregate principal amount of these mandatory convertible notes was converted into approximately 17.8 million shares of the Company’s common stock pursuant to the terms of the notes.

In September 2019, the Company paid $299 million to complete a cash tender offer for $300 million aggregate principal amount of the 2020 Convertible Senior Notes, which payment consisted of the 99.0% purchase price plus all accrued and unpaid interest on the notes, which were allocated to the liability and equity components based on their relative fair values. The Company financed the tender offer with borrowings under the Credit Agreement. As a result of the tender offer, the Company recognized a $4 million gain on extinguishment of debt, which was net of a $7 million charge for the non-cash write-off of unamortized debt issuance costs and debt discount and a $1 million charge for transaction costs. In addition, the Company recorded an $8 million reduction to the equity component of the 2020 Convertible Senior Notes. There was 0 deferred tax impact associated with this reduction due to the full valuation allowance in effect as of September 30, 2019.

In March 2020, the Company paid $53 million to repurchase $73 million aggregate principal amount of the ~~2020~~ 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

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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

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and debt discount. In addition, the Company recorded a $3 million reduction to the equity component of the ~~2020~~ 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.

Prior to January 1, 2020, the 2020 Convertible Senior Notes were convertible only upon the achievement of certain contingent market conditions, which were not met. After January 1, 2020, the 2020 Convertible Senior Notes were convertible at any time until the second scheduled trading day immediately preceding the April 1, 2020 maturity date of the notes and holders of $3 million aggregate principal amount of 2020 Convertible Senior Notes timely elected to convert. Upon conversion, such holders of the converted 2020 Convertible Senior Notes were entitled to receive an insignificant cash payment on April 1, 2020, which the Company did not pay. As a result of such conversion the Company recognized a $3 million gain on extinguishment of debt for the six months ended June 30, 2020. Additionally, at maturity, the Company was obligated to pay in cash the $187 million outstanding principal amount of the 2020 Convertible Senior Notes that did not convert, which the Company did not pay. Under the Bankruptcy Code, the holders of the 2020 Convertible Senior Notes and the prior holders that converted their notes are stayed from taking any action against the Company as a result of the Company’s non-payment. Refer to “Chapter 11 Cases and Effect of Automatic Stay” above for more information.

Upon issuance, the Company separately accounted for the liability and equity components of the 2020 Convertible Senior Notes. The liability component was recorded at the estimated fair value of a similar debt instrument without the conversion feature. The difference between the principal amount of the 2020 Convertible Senior Notes and the estimated fair value of the liability component was recorded as a debt discount and was amortized to interest expense over the term of the notes using the effective interest method, with an effective interest rate of 5.6% per annum. The fair value of the liability component of the 2020 Convertible Senior Notes as of the issuance date was estimated at $1.0 billion, resulting in a debt discount at inception of $238 million. The equity component, representing the value of the conversion option, was computed by deducting the fair value of the liability component from the initial proceeds of the 2020 Convertible Senior Notes issuance. This equity component was recorded, net of deferred taxes and issuance costs, in additional paid-in capital within shareholders’ equity, and will not be remeasured as long as it continues to meet the conditions for equity classification.

Transaction costs related to the 2020 Convertible Senior Notes issuance were allocated to the liability and equity components based on their relative fair values. Issuance costs attributable to the liability component were recorded as a reduction to the carrying value of long-term debt on the consolidated balance sheets and were amortized to interest expense over the term of the notes using the effective interest method. Issuance costs attributable to the equity component were recorded as a charge to additional paid-in capital within shareholders’ equity.

~~The 2020 Convertible Senior Notes consisted of the following at June 30, 2020 and December 31, 2019 (in thousands):~~

June 30,

December 31,

2020

2019
Liability component

Principal

$
186,592

$
262,075
Less: unamortized note discount

-

(2,829)
Less: unamortized debt issuance costs

-

(220)
Net carrying value

$
186,592

$
259,026
Equity component ⁽¹⁾

$
125,009

$
128,452

~~(1)~~

~~Recorded in additional paid-in capital, net of $5 million of issuance costs and $50 million of deferred taxes.~~

The following table presents the interest expense recognized on the 2020 Convertible Senior Notes related to the stated interest rate and amortization of the debt discount for the three and six months ended June 30, 2020 and June 30, 2019 (in thousands):

Three Months Ended

Six Months Ended

June 30,

June 30,

2020

2019

2020

2019
Interest expense on 2020 Convertible Senior Notes

$
-

$
7,574

$
3,463

$
15,068

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~~Security and Guarantees~~

The Senior Notes and the 2020 Convertible Senior Notes are unsecured obligations of Whiting Petroleum Corporation and these unsecured obligations are subordinated to all of the Company’s secured indebtedness, which consists of the Credit Agreement.

The Company’s obligations under the Senior Notes and the 2020 Convertible Senior Notes are guaranteed by the Company’s 100%-owned subsidiaries, Whiting Oil and Gas, Whiting US Holding Company, Whiting Canadian Holding Company ULC and Whiting Resources Corporation (the “Guarantors”). These guarantees are full and unconditional and joint and several among the Guarantors. Any subsidiaries other than these Guarantors are minor subsidiaries as defined by Rule 3-10(h)(6) of Regulation S-X of the SEC. Whiting Petroleum Corporation has no assets or operations independent of this debt and its investments in its consolidated subsidiaries.

6.7. 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 ~~(including removal of certain onshore and offshore facilities in California)~~ in accordance with applicable local, state and federal ~~laws.~~laws and the terms of the Company’s lease agreements. The current portions as of June 30, ~~2020~~2021 and December 31, ~~2019~~2020 (Successor) were $5$6 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 six months ended June 30, ~~2020~~2021 (in thousands):

Asset retirement obligation at January 1, 2020

$
134,893
Additional liability incurred

58
Revisions to estimated cash flows

(1,243)
Accretion expense

6,107
Obligations on sold properties

(693)
Liabilities settled

(2,788)
Asset retirement obligations reclassified to liabilities subject to compromise ⁽¹⁾

(39,022)
Asset retirement obligation at June 30, 2020

$
97,312

~~(1)~~

~~Refer to the “Chapter 11 Cases” footnote for more information on liabilities subject to compromise.~~


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

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. ~~In addition, the Company periodically enters into contracts that contain embedded features which are required to be bifurcated and accounted for separately as derivatives.~~

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 ~~collars~~differential swaps to achieve a more predictable cash flow by reducing its exposure to commodity price volatility, thereby ensuring adequate funding for the Company’s capital programs and facilitating the management of returns on drilling programs and acquisitions. The Company also enters into derivative contracts to maintain its compliance with certain minimum hedging requirements contained in the Credit Agreement. Refer to the “Long-Term Debt” footnote for a detailed discussion of the minimum and maximum hedging requirements of the Credit Agreement. The Company does not enter into derivative contracts for speculative or trading purposes.

Crude Oil, Natural Gas and Natural Gas Liquids Swaps and ~~Collars.~~Collars, Natural Gas Basis Swaps and Crude Oil Differential Swaps. Swaps establish a fixed price for anticipated future oil, gas or ~~gas~~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 establishing a fixed differential between NYMEX prices and the referenced index price. While the use of these derivative instruments limits the downside risk of adverse price movements, ~~they~~it may also limit future ~~revenues~~income from favorable price movements.

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

Commodity

Settlement Period

Index

Derivative Instrument

Total Volumes ⁽¹⁾

Units

Weighted Average Swap Price
Crude Oil

Crude Oil

2020

NYMEX WTI

Fixed Price Swaps

1,564,000

Bbl

$40.96
Crude Oil

2021

NYMEX WTI

Fixed Price Swaps

2,737,500

Bbl

$40.05

Total

4,301,500

Bbl

Natural Gas

Natural Gas

2021

NYMEX Henry Hub

Fixed Price Swaps

3,650,000

MMBtu

$2.60

~~(1)~~

Subsequent to June 30, 2020, the Company entered into additional swap contracts for 459,000 Bbl of crude oil volumes for the remainder of 2020 and additional collar contracts for 854,000 Bbl, 3,739,000 Bbl and 1,365,000 Bbl of crude oil volumes for the remainder of 2020, 2021 and the first nine months of 2022, respectively. The Company also entered into additional swap contracts for 3,650,000 MMBtu of natural gas volumes for 2021 and additional collar contracts for 3,660,000 MMBtu, 10,950,000 MMBtu and 8,190,000 MMBtu of natural gas volumes for the remainder of 2020, 2021 and the first nine months of 2022, respectively.

~~Effect of Chapter 11 Cases~~—The commencement of the Chapter 11 Cases constituted a termination event with respect to the Company’s derivative instruments, which permits the counterparties of such derivative instruments to terminate their outstanding hedges. Such termination events are not stayed under the Bankruptcy Code. During April 2020, certain of the lenders under the 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 Credit Agreement. An additional $23 million of settlement proceeds from terminated derivative positions will be held in escrow until the completion of the Chapter 11 Cases and are recorded in restricted cash in the condensed consolidated balance sheet as of June 30, 2020. As a result of these terminations, all of the Company’s outstanding derivative contracts are concentrated with two counterparties as of June 30, 2020. Both of these counterparties are participants in the Credit Agreement and have investment-grade ratings from Moody’s and Standard & Poor’s.

~~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 the effects of derivative instruments on the condensed consolidated statements of operations for the three and six months ended June 30, 2020 and 2019 (in thousands):

(Gain) Loss Recognized in Income
Not Designated as

Statements of Operations

Three Months Ended June 30,
ASC 815 Hedges

Classification

2020

2019
Commodity contracts

Derivative (gain) loss, net

$
6,632

$
(24,877)
Total

$
6,632

$
(24,877)

(Gain) Loss Recognized in Income
Not Designated as

Statements of Operations

Six Months Ended June 30,
ASC 815 Hedges

Classification

2020

2019
Commodity contracts

Derivative (gain) loss, net

$
(224,739)

$
38,028
Total

$
(224,739)

$
38,028

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

2017

Table of Contents

June 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

$
3,714

$
(289)

$
3,425
Commodity contracts - non-current

Other long-term assets

77

(77)

-
Total derivative assets

$
3,791

$
(366)

$
3,425
Derivative liabilities

Commodity contracts - current

Accrued liabilities and other

$
1,730

$
(289)

$
1,441
Commodity contracts - non-current

Other long-term liabilities

943

(77)

866
Total derivative liabilities

$
2,673

$
(366)

$
2,307

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

December 31, 2019 ⁽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

$
75,654

$
(74,768)

$
886
Commodity contracts - non-current

Other long-term assets

5,648

(5,648)

-
Total derivative assets

$
81,302

$
(80,416)

$
886
Derivative liabilities

Commodity contracts - current

Accrued liabilities and other

$
85,053

$
(74,768)

$
10,285
Commodity contracts - non-current

Other long-term liabilities

6,534

(5,648)

886
Total derivative liabilities

$
91,587

$
(80,416)

$
11,171


					Weighted Average
Settlement Period	Index	Derivative Instrument	Total Volumes	Units	Swap Price	Floor	Ceiling
Crude Oil
2021	NYMEX WTI	Fixed Price Swaps	3,588,000	Bbl	$45.40	-	-
2021	NYMEX WTI	Two-way Collars	3,162,000	Bbl	-	$41.64	$50.50
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	76,500
Natural Gas
2021	NYMEX Henry Hub	Fixed Price Swaps	8,970,000	MMBtu	$2.81	-	-
2021	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	Two-way Collars	10,720,000	MMBtu	-	$2.35	$2.85
Q1-Q2 2023	NYMEX Henry Hub	Two-way Collars	4,975,000	MMBtu	-	$2.37	$2.91
		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)

~~Because substantially~~The weighted average price associated with the crude oil differential swaps shown in the table above represents the average fixed differential to 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 receives the difference. Conversely, if the UHC Clearbrook index price is higher than NYMEX combined with the fixed differential, the Company pays the difference.

(2)

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

Effect of Chapter 11 Cases—The commencement of the Chapter 11 Cases constituted a termination event with respect to the Company’s derivative instruments, which permitted the counterparties of such derivative instruments to terminate their outstanding hedges. Such termination events 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.

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

Offsetting of Derivative Assets and Liabilities. The Company nets its financial derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The following tables summarize the location and fair value amounts of all the 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


		December 31, 2020⁽¹⁾
						Net
		Gross				Recognized
		Recognized		Gross		Fair Value
Not Designated as		Assets/		Amounts		Assets/
ASC 815 Hedges	Balance Sheet Classification	Liabilities		Offset		Liabilities
Derivative assets
Commodity contracts - current	Prepaid expenses and other	$	14,287	$	(14,287)	$	-
Commodity contracts - non-current	Other long-term assets		19,991		(19,991)		-
Total derivative assets		$	34,278	$	(34,278)	$	-
Derivative liabilities
Commodity contracts - current	Derivative liabilities	$	63,772	$	(14,287)	$	49,485
Commodity contracts - non-current	Long-term derivative liabilities		29,741		(19,991)		9,750
Total derivative liabilities		$	93,513	$	(34,278)	$	59,235

(1)

All of the counterparties to the Company’s financial derivative contracts subject to master netting arrangements are lenders under the Credit Agreement, which eliminates ~~its~~the need to post or receive collateral associated with its derivative ~~positions,~~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 Credit Agreement. The Company uses ~~primarily~~ 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.

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9. FAIR VALUE MEASUREMENTS

The Company follows ~~FASB~~ ASC ~~Topic~~ 820~~Fair Value Measurement and Disclosure~~, 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.

~~Table of Contents~~

●

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 Credit Agreement has a recorded value that approximates its fair value since its variable interest rate is tied to current market rates and the applicable margins represent market rates.

The Company’s senior notes are recorded at cost and the convertible senior notes are recorded at fair value at the date of issuance. The following table summarizes the fair values and carrying values of these instruments as of June 30, 2020 and December 31, 2019 (in thousands):

June 30, 2020

December 31, 2019

Fair

Carrying

Fair

Carrying


Value ⁽¹⁾

Value ⁽²⁾

Value ⁽¹⁾

Value ⁽²⁾
1.25% Convertible Senior Notes due 2020

$
35,452

$
186,592

$
260,214

$
259,026
5.75% Senior Notes due 2021

148,920

773,609

732,995

772,080
6.25% Senior Notes due 2023

78,597

408,296

343,989

405,392
6.625% Senior Notes due 2026

192,500

1,000,000

681,250

988,387
Total

$
455,469

$
2,368,497

$
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. All unamortized debt issuance costs and debt discounts and premiums were written off in April 2020 as a result of the Chapter 11 Cases and the adoption of ASC 852. Refer to the “Chapter 11 Cases” footnote for more information.

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


							Total Fair Value								Total Fair Value
	Level 1		Level 2		Level 3		June 30, 2020		Level 1		Level 2		Level 3		June 30, 2021
Financial Assets
Commodity derivatives – current	$	-	$	3,425	$	-	$	3,425
Total financial assets	$	-	$	3,425	$	-	$	3,425
Financial Liabilities
Commodity derivatives – current	$	-	$	1,441	$	-	$	1,441	$	-	$	265,130	$	-	$	265,130
Commodity derivatives – non-current		-		866		-		866		-		89,354		-		89,354
Total financial liabilities	$	-	$	2,307	$	-	$	2,307	$	-	$	354,484	$	-	$	354,484

~~Table of Contents~~


							Total Fair Value								Total Fair Value
	Level 1		Level 2		Level 3		December 31, 2019		Level 1		Level 2		Level 3		December 31, 2020
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 ~~collars~~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 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.

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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 ~~three and six months ended June 30, 2019.~~Successor 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 ~~three~~Predecessor YTD Period and ~~six months ended June 30, 2020, and indicate~~indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values (in thousands):


									Loss (Before		Predecessor
	Net Carrying								Tax) Six		Net Carrying
	Value as of								Months Ended		Value as of								Loss (Before Tax)
	March 31,		Fair Value Measurements Using						June 30,		March 31,		Fair Value Measurements Using						Three Months Ended
	2020		Level 1		Level 2		Level 3		2020		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.


									Loss (Before		Predecessor
	Net Carrying								Tax) Three and Six		Net Carrying
	Value as of								Months Ended		Value as of								Loss (Before Tax)
	June 30,		Fair Value Measurements Using						June 30,		June 30,		Fair Value Measurements Using						Six Months Ended
	2020		Level 1		Level 2		Level 3		2020		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

~~Table of Contents~~

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 ~~analyses~~ based on the net discounted future cash flows from the producing properties and related assets. The discounted cash flows were based on management’s expectations for the future. Unobservable inputs included estimates of future oil and gas production from the Company’s reserve reports, commodity prices based on forward strip price curves (adjusted for basis differentials) as of March 31, 2020 and June 30, 2020, operating and development costs, expected future development plans for the properties and a discount rate of 16% and 17% as of March 31, 2020 and June 30, 2020, respectively, based on a weighted-average cost of capital (all of which were designated as Level 3 inputs within the fair value hierarchy). The impairment tests indicated that 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

9.10. 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 ~~table~~tables below ~~presents~~present the disaggregation of revenue by product and transaction type for the ~~three and six months ended June 30, 2020 and 2019~~periods presented (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019		Successor		Predecessor
OPERATING REVENUES									Three Months Ended June 30, 2021		Three Months Ended June 30, 2020
Oil sales	$	91,904	$	403,870	$	323,849	$	763,324	$	308,417	$	91,904
NGL and natural gas sales ⁽¹⁾		(304)		22,394		12,597		52,429		41,566		(304)
Oil, NGL and natural gas sales	$	91,600	$	426,264	$	336,446	$	815,753		349,983		91,600
Purchased gas sales										1,663		-
Total operating revenues									$	351,646	$	91,600

(1)

Negative NGL and natural gas sales revenue isduring 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 ~~three months ended June 30, 2020.~~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 June 30, ~~2020~~2021 and December 31, ~~2019,~~2020 (Successor), such receivable balances were ~~$54~~$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.

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Table of Contents

~~10.~~11. SHAREHOLDERS’ EQUITY

~~NOL Rights Plan~~Common Stock—AsOn the Emergence Date, the Successor filed an amended and restated certificate of ~~December 31, 2019,~~incorporation with the ~~Company had federal net operating loss (“NOL”) carryforwards~~Delaware Secretary of ~~$3.4 billion. The Company’s ability~~State to ~~use its NOLs would be substantially limited if it experiences an “ownership change” as defined in Section 382~~provide for, among other things, the authority to issue a total of ~~the Internal Revenue Code (“IRC”). A company generally experiences an ownership change if the percentage of its~~550,000,000 shares of all classes of capital stock, ~~owned by its “5-percent shareholders,” as such term is defined in Section 382~~ of ~~the IRC, increases by more than 50% over a rolling three-year period.~~

On March 26, 2020 the Company adopted a Section 382 Rights Agreement (the “Rights Agreement”) designed to preserve the Company’s ability to use its NOLs to offset possible future U.S. taxable income. The Rights Agreement is intended to reduce the likelihood that changes in the Company’s investor base would limit the future use of its tax benefits.

On March 26, 2020, in connection with the adoption of the Rights Agreement, the Company’s Board of Directors declared a dividend of 1 preferred share purchase right (a “Right”) payable on April 6, 2020 to the stockholders of record on that date. Each Right is attached to and trades only with commonwhich 500,000,000 shares until a triggering event, which is defined in the Rights Agreement as close of business on the tenth day following the public announcement or public disclosure of facts indicating that a person or group that already owns 4.9% or more of the Company’sare common stock, ~~(“acquiring person or group”) acquires additional shares. A triggering event entitles the registered holder to purchase from the Company~~ ~~one~~ ~~one-thousandth of a share of Series A Preferred Stock,~~ par value of $0.001 per share, ~~at a price of~~ ~~$7.00~~(the “New Common Stock”) and 50,000,000 shares are preferred stock, par value $0.001 per ~~one one-thousandth of a preferred share represented by a Right, subject to adjustment. Rights held by the acquiring person or group will become void and will not be exercisable.~~share.

~~The Board of Directors has the discretion to exempt certain transactions, persons or entities~~Upon emergence from the ~~operation~~Chapter 11 Cases on the Emergence Date, all existing shares of the ~~Rights Agreement~~Predecessor’s common stock were cancelled and ~~also has~~ the ~~ability~~Successor issued 38,051,125 shares of New Common Stock. Refer to ~~amend or terminate~~ the Rights Agreement prior to a triggering event. Additionally, the Board of Directors may cause the Company to redeem the Rights in whole, but not in part, at a price of $0.001 per Right. The Rights will expire on the day following the certification of the voting results“Chapter 11 Emergence” footnote for Whiting’s 2021 annual meeting of shareholders unless Whiting’s shareholders ratify the Rights Agreement at or prior to such meeting, in which case the Rights Agreement will continue in effect until March 26, 2023 unless terminated earlier in accordance with its terms.more information.

~~Final Order of the Bankruptcy Court~~Warrants—On ~~April 1, 2020,~~ the ~~Bankruptcy Court~~Emergence Date and pursuant to the Plan, the Successor entered ~~a final order~~into warrant agreements with Computershare Inc. and Computershare Trust Company, N.A., as warrant agent, which provide for (i) ~~approving notification and hearing procedures for~~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 ~~transfers~~former holders of ~~and declarations of worthlessness with respect to~~the Predecessor’s common stock and (ii) ~~granting related relief (as amended~~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 ~~April 24, 2020,~~ the ~~“Order”~~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 ~~Order sets forth~~Series B Warrants are exercisable from the ~~procedures (including~~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 ~~requirements) that certain shareholders and potential shareholders must comply with regarding transfers of, or declarations of worthlessness~~as stockholders with respect to any meeting of stockholders for the ~~Company’s common~~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 ~~(as defined~~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 ~~Order),~~“Chapter 11 Emergence” footnote, an additional 2,121,304 shares of New Common Stock remain reserved as ~~well as~~of June 30, 2021 for potential future distribution to certain ~~obligations with respect to notifying the Company of current share ownership (the “Procedures”). The Procedures areintended to reduce the likelihood that changes~~general unsecured claimants whose claim values were pending resolution in ~~the Company’s investor base would limit its future use of its tax benefits~~. ~~The terms and conditions of the Procedures were immediately effective and enforceable upon entry of the Order by~~ the Bankruptcy Court.

~~Any actions in violation~~23

Table of ~~the Procedures (including the notice requirements) are null and void~~ ~~ab initio~~, and (i) the person or entity making such a transfer will be required to take remedial actions specified by the Company to appropriately reflect that such transfer of the Company’s common stock is null and void ~~ab initio~~ and (ii) the person or entity making such a declaration of worthlessness with respect to the Company’s common stock will be required to file an amended tax return revoking such declaration and any related deduction to reflect that such declaration is void ~~ab initio~~.Contents

~~11.~~12. STOCK-BASED COMPENSATION

Equity Incentive Plan—~~The Company maintains~~As discussed in the “Chapter 11 Emergence” 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 1,233,495 shares of Successor common stock on a pro rata basis. On September 1, 2020, the Successor’s board of directors adopted the Whiting Petroleum Corporation ~~2013~~2020 Equity Incentive Plan ~~as amended and restated~~ (the ~~“2013~~“2020 Equity Plan”), which replaced the ~~Whiting Petroleum Corporation 2003 Equity Incentive Plan~~Predecessor’s equity plan (the ~~“2003~~“Predecessor Equity Plan”) ~~and originally granted~~. The 2020 Equity Plan provides the authority to issue ~~1,325,000~~4,035,885 shares of the ~~Company’s~~Successor’s common stock. During 2016, shareholders approved an amendment to the 2013 Equity Plan granting the authority to issue an additional 1,375,000 shares of the Company’s common stock. In May 2019, shareholders approved an additional amendment to the 2013 Equity Plan granting the authority to issue an additional 3,000,000 shares of the Company’s common stock. Upon shareholder approval of the 2013 Equity Plan, the 2003 Equity Plan was terminated. The 2003 Equity Plan continues to govern awards that were outstanding as of the date of its termination, which awards remain in effect pursuant to their terms. Any ~~shares netted or forfeited under the 2003 Equity Plan and any~~ shares forfeited under the ~~2013~~2020 Equity Plan will be available for future issuance under the ~~2013~~2020 Equity Plan. However, shares netted for tax withholding

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under the ~~2013~~2020 Equity Plan will be cancelled and will not be available for future issuance. Under the ~~amended and restated 2013~~2020 Equity Plan, during any calendar year no officer or other key employee participant may be granted options or stock appreciation rights for more than 500,000 shares of common stock or more than 500,000 shares of restricted stock (“RSAs”), restricted stock units (“RSUs”), performance shares (“PSAs”), or performance share units (“PSUs”), the value of which is based on the fair market value of a share of common stock. In addition, no non-employee director participant may be granted ~~during any calendar year options or stock appreciation rights for more than 25,000 shares~~awards having a grant date fair value in excess of ~~common stock, or more than 25,000 shares of RSAs or RSUs.~~$500,000. As of June 30, ~~2020, 3,886,734~~2021, 3,029,358 shares of common stock remained available for grant under the ~~2013~~2020 Equity Plan.

~~The~~Historically, the Company has granted service-based ~~RSAs~~restricted stock awards (“RSAs”) and ~~RSUs~~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 ~~PSAs~~performance share awards (“PSAs”) and ~~PSUs~~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

During ~~the six months ended June 30,~~September and October 2020, ~~and 2019, 53,198 and 389,303~~89,021 shares ~~respectively,~~ of service-based ~~RSAs and~~ RSUs were granted to executive officers and directors under the ~~2013~~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.

In September 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 Company recognizes compensation expense based on the fair value as determined by a Monte Carlo valuation model (the “Monte Carlo Model”) over the expected vesting period, which 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 ~~service-based RSAs and~~serviced-based RSUs was ~~$4.94 per share and $27.97~~$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 ~~2019,~~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

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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 six months ended June 30, 2020, 53,198 shares 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 for the six months ended June 30, 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 six months ended June 30, 2020, ~~and 2019,~~ 1,616,504 ~~and 308,432~~ shares ~~respectively,~~ of cash-settled, service-based RSUs were granted to executive officers and employees under the ~~2013~~Predecessor Equity Plan. The ~~Company determines~~company determined compensation expense for ~~cash-settled RSUs~~these awards using the fair value at the end of each reporting period, which iswas based on the closing bid price of the Company’s common stock on such date. On March 31, 2020, all of the RSUs issued to executive officers in 2020 were forfeited and concurrently replaced with cash incentives. Refer to “2020 Compensation Adjustments” below for more information.

During the six months ended June 30, 2020, ~~and 2019,~~ 1,665,153 ~~and 317,512, respectively,~~shares of PSAs and PSUs subject to certain market-based vesting criteria were granted to executive officers under the ~~2013~~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 will vest at the end of that three-year performance period is 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 of the grant date over the three-year performance period. The number of awards earned could range from 0 up to 2 times the number of shares initially granted. However, awards earned up to the target shares granted (or 100%) will be settled in shares, while awards earned in excess of the target shares granted will be settled in cash. The cash-settled component of such awards is recorded as a liability in the consolidated balance sheets and will be 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 awards subject to market conditions, the grant date fair value is estimated using a Monte Carlo valuation 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 is calculated based on the historical volatility and implied volatility of Whiting’s common stock, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with the three-year vesting period. The key assumptions used in valuing these market-based awards were as follows:

2020

2019
Number of simulations

2,500,000

2,500,000
Expected volatility

76.52%

72.95%
Risk-free interest rate

1.51%

2.60%
Dividend yield

—

—

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

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model, was $4.31 per share in 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.

The Company recognized $1 million and $2 million in total stock-based compensation expense during the three and six months ended June 30, 2020, 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 ~~are~~were subject to a service period and ~~may be clawed~~were subject to claw back provisions if an executive officer ~~terminates~~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 ~~replacement~~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 is being~~ amortized over the ~~relevant service period.~~period from the Petition Date to the Emergence 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. 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’s condensed consolidated statements of operations during the first quarter of 2020.

~~The following table shows a summary of the Company’s service-based and market-based awards activity for the six months ended June 30, 2020:~~

Number of Awards

Weighted Average

Service‑Based

Market-Based

Grant Date


RSAs & RSUs

PSAs & PSUs

Fair Value
Nonvested awards, January 1

467,502

448,387

$
28.28
Granted

53,198

1,665,153

4.33
Vested

(181,728)

-

27.52
Forfeited

(128,870)

(1,773,101)

7.53
Nonvested awards, June 30

210,102

340,439

$
25.45

~~There was no significant stock option activity during the six months ended June 30, 2020 and 2019.~~

Total stock compensation expense recognized for restricted stock was $1 million and $4 million for the three months ended June 30, 2020 and 2019, respectively, and $2 million and $10 million for the six months ended June 30, 2020 and 2019, respectively.

~~12.~~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 ~~provision~~provisions for income taxes for the three and six months ended June 30, 2021 (Successor) and June 30, 2020 ~~and 2019 differs~~(Predecessor) differ 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 ~~(i) an alternative minimum tax refund received for the three months ended June 30, 2020, (ii)~~ a full valuation allowance in effect on the Company’s U.S. deferred tax assets (“DTAs”), resulting in 0 U.S. income tax expense recognized for the ~~three months ended June 30,~~periods presented, outside of a $1 million alternative minimum tax refund received during the first quarter of 2020, and ~~June 30, 2019 and (iii) state income taxes and~~an effective U.S. tax rate of 0%. Additionally, during the ~~effects~~second quarter of ~~permanent taxable differences for the six months ended June 30, 2019.~~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 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 ~~deferred tax assets~~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 11 reorganization and related transactions, the Successor experienced an ownership change within the meaning of IRC Section 382 on the Emergence Date. This ownership change subjected certain of the Company’s tax attributes to an IRC Section 382 limitation. The ownership changes and resulting annual limitation will result in the expiration of net operating loss carryforwards (“NOLs”) or other tax attributes otherwise available, with a corresponding decrease in the Company’s valuation allowance.

The Company estimates that it has federal NOLs of $3.1 billion as of December 31, 2020, which are subject to limitation under IRC Section 382. The Company currently estimates that approximately $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.

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On March 26, 2020 the Company adopted a Rights Agreement and on April 1, 2020 the Bankruptcy Court entered an Order containing certain Procedures, each of which are intended to preserve the Company’s ability to use its net operating losses to offset possible future U.S. taxable income by reducing the likelihood of an ownership change under Section 382 of the IRC. Refer to the “Shareholders’ Equity” footnote for more information on the Rights Agreement and the Order.

~~13.~~14. EARNINGS PER SHARE

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


	Three Months Ended June 30,				Six Months Ended June 30,				Successor		Predecessor
	2020		2019		2020		2019		Three Months Ended June 30, 2021		Three Months Ended June 30, 2020
Basic Loss Per Share
Basic and diluted loss per share
Net loss	$	(574,315)	$	(5,687)	$	(4,202,886)	$	(74,612)	$	(61,489)	$	(574,315)
Weighted average shares outstanding		91,429		91,286		91,409		91,261
Loss per common share	$	(6.28)	$	(0.06)	$	(45.98)	$	(0.82)

Diluted Loss Per Share	��
Net loss	$	(574,315)	$	(5,687)	$	(4,202,886)	$	(74,612)
Weighted average shares outstanding		91,429		91,286		91,409		91,261
Loss per common share	$	(6.28)	$	(0.06)	$	(45.98)	$	(0.82)
Weighted average shares outstanding, basic and diluted										39,067		91,429
Loss per common share, basic and diluted									$	(1.57)	$	(6.28)


	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 ~~periods presented,~~Successor Period, the diluted earnings per share calculations exclude the effect of 4,837,376 common shares for Series A Warrants and 2,418,832 common shares for Series B Warrants that were out-of-the-money as of June 30, 2021, as well as 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 June 30, 2021. Further, during the three and six months ended June 30, 2021, the Company had a net ~~loss~~losses and therefore the diluted earnings per share calculations for those periods exclude the anti-dilutive effect of (i) ~~270,058 shares of service-based awards for the three months ended June 30, 2020, (ii) 182,583~~345,272 shares of service-based awards and ~~96,241~~195,854 shares of market-based awards for the three months ended June 30, ~~2019, (iii) 342,299 shares of service-based awards for the six months ended June 30, 2020,~~2021 and ~~(iv) 293,305~~(ii) 314,524 shares of service-based awards and ~~206,475~~202,643 shares of market-based awards for the six months ended June 30, ~~2019. In addition,~~2021. Finally, the diluted earnings per share calculations ~~exclude the effect of (i) 28,505 and 31,805 common shares~~ for the three and six months ended June 30, ~~2020, respectively, for stock options~~2021 also exclude 94,950 shares of market-based awards that ~~were out-of-the-money~~did not meet the market-based vesting criteria as of June 30, ~~2020 and (ii) 46,396 and 46,502 common shares for the three and six months ended June 30, 2019, respectively, for stock options that were out-of-the-money as of June 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 ~~2020~~ Convertible Senior Notes with cash, shares of common stock or any combination thereof. As the conversion value of the ~~2020~~ 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 ~~ending June 30, 2020 and 2019.~~presented.

~~14.~~15. COMMITMENTS AND CONTINGENCIES

Chapter 11 ~~Proceedings~~Cases—On April 1, 2020, the Debtors filed the Chapter 11 Cases seeking relief under the Bankruptcy Code. The Company expects to continue operations in the normal course for the duration of the Chapter 11 Cases. In addition, commencement of the Chapter 11 Cases automatically stayed all of the proceedings and actions against the Company (other than regulatory enforcement matters), including those noted below. In addition, the filing of the Chapter 11 Cases ~~may allow~~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 ~~Cases”~~Emergence” footnote for more information. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such contract and, subject to certain exceptions, relieves the Company from performing future obligations under such contract but entitles the counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. The claims resolution process is ongoing and certain of

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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.

~~Delivery Commitments~~—~~The~~However, it is reasonably possible that as a result of the legal proceedings associated with the 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 (ii) a claim 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.

Arguello Inc. and Freeport-McMoRan Oil & Gas LLC. WOG had ~~a delivery contract tied to its~~interests in federal oil ~~production~~and gas leases in the ~~Williston Basin. The effective date of this contract was contingent upon~~Point Arguello Unit located offshore in California. While those interests have expired, pursuant to certain related agreements (the “Point Arguello Agreements”), WOG may be subject to abandonment and decommissioning obligations. WOG and Whiting Petroleum Corporation rejected the ~~completion~~related contracts pursuant to the Plan. On October 1, 2020, Arguello Inc. and Freeport-McMoRan Oil & Gas LLC, individually and in its capacity as the designated Point Arguello Unit operator (collectively, the “FMOG Entities”) filed with the Bankruptcy Court an application for allowance of certain ~~related pipelines,~~administrative claims arguing the ~~construction~~FMOG Entities were entitled to recover Whiting’s proportionate share of decommissioning obligations owed to the U.S. government through subrogation to the U.S. government’s economic rights. The FMOG Entities’ application alleged administrative claims of approximately $25 million for estimated decommissioning costs owed to the U.S. government, at least $60 million of estimated decommissioning costs owed to the FMOG Entities and other insignificant amounts. On September 14, 2020, the FMOG Entities also filed with the Bankruptcy Court proofs of claim for rejection damages to serve as an alternative course of action in the event that a court should determine that the FMOG Entities do not hold any applicable administrative claims. The U.S. government may also be able to bring claims against WOG directly for decommissioning costs. On February 18, 2021, WOG entered into a stipulation and agreed order with the United States Department of the Interior, Bureau of Safety & Environmental Enforcement (“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 ~~yet commenced. Under~~issued a ruling on the ~~terms~~damages for rejection of the ~~agreement,~~Point Arguello 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 ~~was committed~~could be liable for claims that must be paid or otherwise satisfied, including through an equity issuance, under and pursuant 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.~~Plan.

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,

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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.~~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 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 ~~the~~these matters ~~involved in the case~~ up to $25 million. This indemnity will terminate on ~~the later of: (i) June 30, 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 June 30, ~~2020.~~2021 (Successor).

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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.

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

Unless the context otherwise requires, the terms “Whiting,” “we,” “us,” “our” or “ours” when used in this Item refer to Whiting Petroleum Corporation, together with its consolidated subsidiaries, Whiting Oil and Gas Corporation (“Whiting Oil and Gas” or “WOG”), Whiting US Holding Company, Whiting Canadian Holding Company ULC, Whiting Resources ~~Corporation~~LLC (“WRC,” formerly Whiting Resources Corporation) and Whiting Programs, ~~Inc,~~Inc. In September 2020, Whiting ~~Raven Colorado Corp.~~US Holding Company merged with and into WOG with WOG surviving, and WRC transferred all of its operating assets to WOG. In November 2020, WRC, over a series of steps, was amalgamated with Whiting ~~ND Sakakawea LLC.~~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 ~~acquisition~~ and ~~exploration~~acquisition activities primarily in the Rocky Mountains region of the United ~~States. Our current operations and capital programs~~States where we are ~~focused on the cost-efficient operation of our existing properties to generate the greatest value to our stakeholders based on the current and expected commodity price environment. During 2019, we~~ focused on developing our large resource play in the Williston Basin of North Dakota and ~~Montana, while closely aligning~~Montana. We are currently focusing our capital ~~spending with~~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 ~~flows generated~~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 will generate significant cash flow from operations. As a result of the sharp decline in commodity prices during the first half of 2020, we have significantly decreased our level of capital spending to more closely align with our reduced cash flows from operating activities and have focused our capital program on projects that are expected to maximize value to our stakeholders. 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
Crude oil

$
62.89

$
67.90

$
69.50

$
58.83

$
54.90

$
59.83

$
56.45

$
56.96

$
46.08

$
27.85
Natural gas

$
3.13

$
2.77

$
2.88

$
3.62

$
3.00

$
2.58

$
2.29

$
2.44

$
1.88

$
1.66


	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, ~~dropping below $21.00 per Bbl in March 2020 and further dropping below negative $37.00 per Bbl in April 2020. This dramatic decline in pricing was~~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 have recovered significantly, uncertainties related to the demand for oil and natural gas products remain as the pandemic continues to impact the world economy and the OPEC continues to negotiate appropriate restraint levels to balance the market. Lower oil, NGL and natural gas prices ~~may not only~~ decrease our revenues ~~on a per unit basis, but may also~~and reduce the amount of oil and natural gas that we can produce economically ~~and therefore potentially lower~~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 ~~ability to finance planned capital expenditures~~ or ability to ~~emerge from bankruptcy (as discussed below~~fund planned capital expenditures. In addition, lower commodity prices may reduce the amount of our borrowing base under ~~“Recent Developments”).~~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”).

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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 ~~Cases.~~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 ~~April 23,~~June 30, 2020, the Debtors ~~entered into a restructuring support agreement (“RSA”) with certain holders~~filed the Joint Chapter 11 Plan of ~~our senior notes to support a restructuring in accordance with~~Reorganization of Whiting Petroleum Corporation and its Debtor affiliates (as amended, modified and supplemented, the ~~terms set forth in our chapter 11 plan of reorganization (the~~ “Plan”). ~~The Plan and the related disclosure statement were each filed with the Bankruptcy Court on April 23, 2020.~~ On ~~July 1,~~August 14, 2020, the Bankruptcy Court ~~entered an~~

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~~order approving~~confirmed the ~~Debtors’ disclosure statement, allowing~~Plan. On September 1, 2020, (the “Emergence Date”) the Debtors satisfied all conditions required for ~~solicitation of the~~ Plan ~~to commence. A Bankruptcy Court hearing to consider confirmation of the Plan is scheduled to be held on August 10, 2020. We expect to continue operations in the normal course for the duration of~~effectiveness and emerged from the Chapter 11 Cases. ~~To ensure ordinary course~~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 and the historical financial statements on or before the Emergence Date are not a reliable indicator of our financial condition and results of operations ~~we have obtained approval from~~for any period after the ~~Bankruptcy Court for certain “first day” motions, including motions~~adoption of fresh start accounting. References to ~~obtain customary relief intended~~“Successor” refer to ~~assure our ability to continue our ordinary course~~Whiting and its financial position and results of operations after the ~~filing date. In addition, we have received authority~~Emergence Date. References to ~~use cash collateral~~“Predecessor” refer to Whiting and its financial position and results of operations on or before the ~~lenders under Whiting Oil and Gas’ credit agreement (the “Credit Agreement”). For more information on~~Emergence Date. References to “Successor YTD Period” relate to the six months ended June 30, 2021. References to “Predecessor YTD Period” relate to the six months ended June 30, 2020.

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 ~~matters, refer~~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, we made a $2 million cash payment and issued 948,897 shares of the Successor’s common stock pursuant to the ~~“Basis of Presentation,” “Chapter 11 Cases” and “Long-Term Debt” footnotes~~confirmed Plan to a Tallgrass entity in ~~the notes to the condensed consolidated financial statements.~~February 2021.

~~Proved Undeveloped Reserves.~~ As a result of lower crude oil, NGL and natural gas prices and a substantial reduction in our capital plan incorporated into our reserve estimates at June 30, 2020, our proved undeveloped reserves decreased from 126.6 MMBOE as of December 31, 2019 to 37.3 MMBOE as of June 30, 2020, which represents a 71% reduction between periods. Approximately 83% of this decrease in 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.

~~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 stakeholders 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 half of 2020, we temporarily suspended all drilling and completion activity and released all of our drilling rigs during 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 used on our wells, deferred the completions of certain wells and delayed placing certain completed wells online during portions of the second quarter. We expect this reduced activity will negatively impact our production across all of our properties for the remainder of 2020. Substantial and extended declines in crude oil prices may result in our decision to voluntarily curtail production or reduce workover activity on our existing wells 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 ~~89.3~~85.2 MBOE/d for the second quarter of ~~2020, representing an 11% decrease~~2021, which represents a 4% increase from ~~100.2 MBOE/d in~~ the first quarter of ~~2020. Second~~2021 and is in line with our production exit rate for the fourth quarter ~~2020 production was negatively impacted by production curtailments and higher downtime as a result~~ of ~~a reduction in workover rigs in April and May 2020, as well as the decisions to defer completions of certain wells and delay placing certain completed wells online.~~2020. Across our acreage in the Williston Basin, we have implemented ~~customized,~~custom, right-sized completion designs ~~which utilize the optimum volume of proppant, fluids, and frac stages~~ to increase well performance while reducing ~~cost and utilize state-of-the-art drilling rigs, high torque mud motors and 3-D bit cutter technology~~cost. We continue to ~~reduce~~focus on reducing time-on-location and total well ~~costs. We have increased stages pumped per day by focusing on new technologies such as quick-install wellhead connections~~cost while maximizing our lateral footage through drilling best practices including utilizing top tier drilling rigs, advanced downhole motor and ~~frac plug innovations. We~~drill bit technology and our custom drilling fluid system.

During portions of the second quarter of 2021, we had one active completion crew in this area, and we plan to continue ~~to use right-sized completion design on future wells we complete during~~with this crew intermittently for the remainder of 2021. In addition, we resumed drilling in the ~~year. We~~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 39 gross (5.6 net) wells and ~~put 12~~TIL 9 gross (5.4 net) wells ~~on production~~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 ~~second quarter of 2020. As noted above in “Operational Response to Market Conditions,” we released all of our drilling rigs during April 2020.~~

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

Our Redtail field in the Denver-Julesburg Basin (“DJ Basin”) in Weld County, Colorado targets the Niobrara and Codell/Fort Hays formations. Net production from the Redtail field averaged 9.0 MBOE/d in the second quarter of 2020, representing a 3% decrease from 9.3 MBOE/d for the first quarter of 2020. We have established production in the Niobrara “A,” “B” and “C” zones and theyear.

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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.

Colorado – Denver-Julesburg Basin

Our properties in the Denver-Julesburg Basin in Weld County, Colorado produce from the Niobrara “A,” “B” and “C” zones and the Codell/Fort Hays formations. ~~We have maintained base~~Net production ~~with improved artificial lift techniques~~from Colorado averaged 7.1 MBOE/d for the second quarter of 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 ~~reductions in lease operating expenses. Future development activity in~~sale agreement to divest all properties associated with our Redtail field, ~~is subject to market conditions.~~

~~Our Redtail gas plant processes~~including the associated ~~gas produced from our wells~~midstream assets, and we expect this transaction to close in ~~this area, and has a current inlet capacity of 50 MMcf/d. As of June 30, 2020, the plant was processing 24 MMcf/d.~~September 2021.

Financing Highlights

~~In March 2020, we paid $53 million to repurchase $73 million aggregate principal amount of~~On the Emergence Date, in connection with our 1.25% Convertible Senior Notes due April 1, 2020 (the “2020 Convertible Senior Notes”), which payment consisted of the average 72.5% purchase price plus all accrued and unpaid interest on the notes. We financed the repurchases with borrowings under the Credit Agreement. Additionally, in March 2020, holders of $3 million aggregate principal amount of 2020 Convertible Senior Notes timely elected to convert. Upon such conversion, such holders of converted 2020 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. Refer to the “Chapter 11 Cases” and “Long-Term Debt” footnotes in the notes to the condensed consolidated financial statements for more information on these repurchases and conversions.

~~On April 1, 2020, in conjunction with the filing of~~emergence from the Chapter 11 Cases, we ~~did not make~~repaid all outstanding borrowings and accrued interest on the ~~$187~~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 borrowing base and aggregate commitments under the Credit Agreement of $750 million ~~principal payment due on~~were reaffirmed in connection with our 2020 Convertible Senior Notes. Any efforts to enforce payment obligations related to the acceleration of our debt have been automatically stayed as a result of the filing of the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code.semi-annual borrowing base redetermination. Refer to the ~~“Long-Term~~“Long-Term Debt” footnote in the notes to the condensed consolidated financial statements for more ~~information on the Chapter 11 Cases and the automatic stay.~~information.

~~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 (“DAPL”) because it had failed to ~~conduct~~prepare an environmental impact ~~statement; as~~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 of~~(“D.C. Appellate Court”), on January 26, 2021, affirmed the ~~portion of~~D.C. District Court’s decision to vacate the ~~order directing~~easement and concluded that the D.C. District Court must further consider whether shut down of the ~~DAPL. The stay allows~~DAPL is an appropriate remedy while the 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 toand that the DAPL could 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 August, we expect to transport approximately 30%~~production, which could have an adverse effect on our business, financial condition, results of ~~our crude oil volumes through~~operations or cash flows. To help mitigate the ~~DAPL. To mitigate any~~ potential impact of an unfavorable ~~ruling,~~outcome, we ~~are coordinating~~have coordinated with our midstream partners and downstream markets to source transportation alternatives.

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Results of Operations

~~Six Months Ended June 30, 2020~~Successor YTD Period Compared to ~~Six Months Ended June 30, 2019~~Predecessor YTD Period


	Six Months Ended June 30,				Successor		Predecessor
	2020		2019		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
Net production
Oil (MMBbl)		11.8		15.0		9.7		11.8
NGLs (MMBbl)		3.4		3.9		3.4		3.4
Natural gas (Bcf)		22.6		25.6		20.9		22.6
Total production (MMBOE)		19.0		23.1		16.5		19.0
Net sales (in millions)
Net sales (in millions) ⁽¹⁾
Oil ⁽¹⁾	$	323.8	$	763.3	$	565.1	$	323.8
NGLs		11.3		29.2		55.3		11.3
Natural gas		1.3		23.3		34.3		1.3
Total oil, NGL and natural gas sales	$	336.4	$	815.8	$	654.7	$	336.4
Average sales prices
Oil (per Bbl) ⁽¹⁾	$	27.42	$	50.91	$	58.37	$	27.42
Effect of oil hedges on average price (per Bbl)		3.91		0.29		(10.91)		3.91
Oil after the effect of hedging (per Bbl)	$	31.33	$	51.20	$	47.46	$	31.33
Weighted average NYMEX price (per Bbl) ⁽²⁾	$	37.25	$	57.26	$	61.95	$	37.25
NGLs (per Bbl)(1)	$	3.27	$	7.52	$	16.47	$	3.27
Natural gas (per Mcf)	$	0.06	$	0.91
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⁾					$	1.64	$	0.06
Effect of natural gas hedges on average price (per Mcf)						(0.02)		-
Natural gas after the effect of hedging (per Mcf)					$	1.62	$	0.06
Weighted average NYMEX price (per MMBtu) ⁽²⁾	$	1.77	$	2.79	$	2.65	$	1.77
Costs and expenses (per BOE)
Lease operating expenses	$	6.61	$	7.39	$	7.48	$	6.61
Transportation, gathering, compression and other	$	0.95	$	0.91	$	0.88	$	0.95
Production and ad valorem taxes	$	1.62	$	2.92	$	3.02	$	1.62
Depreciation, depletion and amortization	$	14.07	$	17.33	$	6.38	$	14.07
General and administrative	$	3.96	$	2.92	$	1.35	$	3.96

(1)	Before consideration of hedging transactions.

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

Oil, NGL and Natural Gas Sales. Our oil, NGL and natural gas sales revenue ~~decreased $479~~increased $318 million to ~~$336~~$655 million when comparing the ~~first half of 2020~~Successor YTD Period to the ~~same period in 2019.~~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 ~~first half of 2020, decreases in total production accounted for approximately $168 million of~~Successor YTD Period to the ~~change in revenue and decreases~~Predecessor YTD Period, increases in commodity prices realized between periods accounted for ~~approximately $311~~a $377 million ~~of the change~~increase in revenue, ~~when comparing to the first half of 2019.~~

Our oil, NGL and gas volumes decreased 21%, 11% and 12%, respectively, between periods. The volume decreases between periods were primarily attributable to (i) production curtailment, additional downtime on certain wells due to a reduced workover rig count and the decisions to defer completions of certain wells and delay placing certain completed wells online for a portion of the second quarter as described in “Operational Response to Market Conditions” above, (ii) the impact of severe weather conditions and associated electric submersible pump failures on multiple high value wells in the Williston Basin in the first quarter of 2020 and (iii) normal field production decline. These decreases werewhich was partially offset by ~~increased~~a decrease in total production ~~from new wells drilled and completed over the last twelve months~~between periods that accounted for a $59 million decrease in ~~the Williston Basin.~~ revenue.

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Our oil, NGL and gas volumes decreased 18%, 3% and 7%, respectively, between periods. The volume decreases between periods were primarily 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 majority of 2020 as a result of sustained lower prices and our bankruptcy filing. This decline was partially offset by production from new wells drilled and completed during the first half of 2021 in the Williston Basin.

Our average price for oil, NGLs and natural gas (before the effects of hedging) increased 113%, 404% and 2,633%, respectively, between periods. Our average realized price for oil, NGLs and natural gas ~~decreased 46%, 57%~~primarily increased as a result of favorable movements in the NYMEX and ~~93%, respectively. Our~~Mont Belvieu market indices between periods. During the first half of 2020, our average ~~sales~~realized price ~~realized~~ for oil was impacted by deficiency payments we made under a physical delivery contract ~~at our Redtail field~~in Colorado due to our inability to meet the minimum volume commitments under this contract. During the six months ended June 30, 2020 and 2019, our total average sales price realized for oil was $2.05 per Bbl lower and $1.89 per Bbl lower, respectively, as a result of these deficiency payments. This contract was terminated in April 2020 and ~~will~~did not continue to negatively impact the price we receive for oil from our Redtail field inafter that time. During the ~~future. Our~~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 ~~for NGLs~~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 average realized price differentials to NYMEX also improved significantly as a result of stronger regional pricing in the Williston Basin during the ~~first half of 2020 was negatively impacted by rising market differentials as compared to market indices as well as high fixed third-party costs for transportation, gathering and compression services.~~Successor YTD Period.

Lease Operating Expenses. Our lease operating expenses (“LOE”) during the ~~first half of 2020~~Successor YTD Period were ~~$126~~$124 million, a ~~$45~~$2 million decrease over the ~~same period in 2019.~~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~~contributed to an additional $3 million decrease in ~~the third quarter of 2019, (ii) increased saltwater disposal income and (iii) a decrease~~LOE between periods, partially offset by an $8 million increase 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 ~~first half of 2020~~Successor YTD Period to the ~~same 2019 period.~~Predecessor YTD Period. LOE per BOE amounted to ~~$6.61~~$7.48 during the ~~first half of 2020,~~Successor YTD Period, which represents ~~a decrease~~an increase of ~~$0.78~~$0.87 per BOE (or ~~11%~~13%) from the ~~first half of 2019.~~Predecessor YTD Period. This ~~decrease~~increase was mainly due to lower overall production volumes between periods, partially offset by the overall decrease in LOE ~~expense~~ 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 ~~first half of 2020~~Successor YTD Period were ~~$18~~$14 million, a $3$4 million decrease over the ~~same period in 2019. TGC per BOE, however, increased slightly when comparing the first half of 2020 to the same 2019 period. These changes were primarily due~~Predecessor YTD Period. This decrease mainly relates to lower production volumes ~~during~~between periods and decreased rates negotiated with midstream partners as a result of the ~~period.~~Chapter 11 Cases.

TGC per BOE also decreased when comparing the Successor YTD Period to the Predecessor YTD Period. TGC per BOE amounted to $0.88 per BOE, which represents a decrease of $0.07 per BOE (or 7%) from the Predecessor YTD Period. This decrease was primarily due to the decreased rates negotiated with midstream partners discussed above.

Production and Ad Valorem ~~Taxes~~Taxes.. Our production and ad valorem taxes during the ~~first half of 2020~~Successor YTD Period were ~~$31~~$50 million, a ~~$37~~$19 million ~~decrease~~increase over the ~~same period in 2019,~~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 ~~8.7%~~7.2% and ~~8.3%~~8.7% for the ~~first half of 2020~~Successor YTD Period and ~~2019,~~the Predecessor YTD Period, respectively. Our production tax rate for ~~2020~~the Successor YTD Period was ~~higher~~lower than the rate for ~~2019 due to our concentration of development activity over~~ the ~~past twelve months in~~Predecessor YTD Period as certain production taxes levied on natural gas are volume-based and did not increase with the ~~Williston Basin states of North Dakota and Montana, which have higher tax rates than Colorado where we have had limited development activity over the past twelve months. This~~ increase in ~~rate was partially offset by certain North Dakota wells receiving stripper well status, which reduces~~realized prices. Additionally, we recognized Colorado severance tax refunds during the ~~applicable tax rate from 10% to 5%.~~Successor YTD period.

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Depreciation, Depletion and Amortization. ~~Our~~The components of our depletion, depreciation and amortization (“DD&A”) expense ~~decreased $134 million in 2020 as compared to the first half of 2019. The components of our DD&A expense~~ were as follows (in thousands):


	Six Months Ended June 30,				Successor		Predecessor
	2020		2019		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
Depletion	$	258,894	$	392,527	$	98,232	$	258,894
Accretion of asset retirement obligations		6,107		5,819		4,412		6,107
Depreciation		2,516		2,795		2,703		2,516
Total	$	267,517	$	401,141	$	105,347	$	267,517

DD&A decreased between ~~periods~~the Successor YTD Period and the Predecessor YTD Period primarily due to ~~$134~~$161 million in lower depletion expense, consisting of a ~~$56 million decrease due to lower overall production volumes during the first half of 2020, as well as a $78~~$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 ~~$14.07~~$6.38 per BOE for the ~~first half of 2020~~Successor YTD Period was ~~19%~~55% lower than the rate of ~~$17.33~~$14.07 per BOE for the ~~same period in 2019.~~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 ~~quarter~~and second quarters of 2020 and ~~downward~~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 fair values on the Emergence Date. Refer to the “Fresh Start Accounting” footnote in the 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, ~~over the last twelve months,~~ which were largely driven by ~~lower~~higher commodity ~~prices.~~

~~Table~~prices during the first half of ~~Contents~~2021.

Exploration and Impairment Costs. ~~Our exploration and impairment costs increased $4 billion for the first half of 2020 as compared to the same period in 2019.~~ The components of our exploration and impairment expense were as follows (in thousands):


	Six Months Ended June 30,				Successor		Predecessor
	2020		2019		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
Impairment	$	4,154,369	$	13,179	$	2,691	$	4,154,369
Exploration		20,244		19,976		1,978		20,244
Total	$	4,174,613	$	33,155	$	4,669	$	4,174,613

Impairment expense for the ~~first half~~Successor YTD Period primarily relates to the amortization of ~~2020~~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 ~~first half of 2019 primarily relates~~Successor YTD Period compared to the ~~amortization~~Predecessor YTD Period primarily due to (i) $12 million of ~~leasehold costs associated with individually insignificant unproved properties.~~lower deficiency fees paid under our produced water disposal agreement at our Redtail field, which contract was rejected through the Chapter 11 Cases and (ii) $5 million of lower geology-related general and administrative expenses due to a company restructuring in September 2020.

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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):


	Six Months Ended June 30,				Successor		Predecessor
	2020		2019		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
General and administrative expenses	$	111,772	$	117,451
General and administrative expenses, other⁽¹⁾					$	54,098	$	108,371
Stock-based compensation, non-cash						4,764		3,401
Reimbursements and allocations		(36,469)		(49,904)		(36,576)		(36,469)
General and administrative expenses, net	$	75,303	$	67,547
General and administrative expenses, net (GAAP)						22,286		75,303
Less: Significant cost drivers ⁽²⁾						-		(26,884)
Non-GAAP general and administrative expenses less significant cost drivers⁽³⁾					$	22,286	$	48,419

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

(2)	Includes 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 reimbursement and allocations decreased $6 million~~expenses, other during the ~~first half of 2020~~Successor YTD Period decreased $54 million compared to the Predecessor YTD Period primarily due to $27 million of significant cost ~~reduction initiatives instituted as part of a company restructuring beginning in~~drivers incurred during the ~~third quarter of 2019,~~Predecessor YTD Period, including ~~$24~~(i) $16 million in ~~lower compensation costs between periods. These decreases were partially offset by (i) additional expense related to executive and employee~~ cash retention incentives ~~during the first half~~paid to executives and directors, (ii) $8 million of ~~2020 of $11 million, (ii) third-party~~third party advisory and legal fees incurred ~~prior to the Petition Date~~ to prepare for the Chapter 11 Cases ~~of $8 million~~ and (iii) $3 million of additional ~~expenses~~costs related to a ~~litigation~~legal settlement. ~~The decrease in reimbursements and allocations for the first half of 2020 was the~~In addition, compensation costs decreased by $18 million as a result of a ~~lower number~~company restructuring completed in the third quarter of ~~field workers on Whiting-operated properties associated with reduced drilling activity.~~2020.

~~Our G&A expenses on a BOE basis increased when comparing the first half of 2020 to the same 2019 period.~~ G&A expense per BOE amounted to ~~$3.96~~$1.35 during the ~~first half of 2020,~~Successor YTD Period, which represents ~~an increase~~a decrease of ~~$1.04~~$2.61 per BOE (or ~~36%~~66%) from the ~~first half of 2019.~~Predecessor YTD Period. This ~~increase~~decrease was mainly due to the overall ~~decreases~~decrease in ~~reimbursements and allocations~~G&A discussed above ~~as well as~~partially offset by lower overall production volumes between periods. G&A expense per BOE excluding significant cost drivers was $2.55 per BOE during the Predecessor YTD 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 loss of $402 million and a gain of $225 million ~~and a loss of $38 million~~ for the ~~six months ended June 30, 2020~~Successor YTD Period and ~~2019,~~the Predecessor YTD Period, respectively. These gains and losses ~~are primarily related~~relate to our collar, swap, basis swap and ~~option~~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.

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


	Six Months Ended June 30,				Successor		Predecessor
	2020		2019		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
Notes	$	34,840	$	74,512
Credit agreement		16,496		6,242
Credit agreements					$	6,911	$	16,496
Amortization of debt issue costs, discounts and premiums		9,786		15,734		1,773		9,786
Other		553		339		400		553
Notes						-		34,840
Total	$	61,675	$	96,827	$	9,084	$	61,675

The decrease in interest expense of ~~$35~~$53 million ~~between periods~~during the Successor YTD Period compared to the Predecessor 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 first half of 2020 compared to the first half of 2019.~~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 ~~$40~~$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 $6~~an $8 million decrease in amortization expense ~~during~~between periods. Upon emergence from the ~~first half~~Chapter 11 Cases, all outstanding obligations under our notes were cancelled in exchange for shares of ~~2020 compared to the first half of 2019.~~Successor common stock. Refer to the “Chapter 11 ~~Cases”~~Emergence” and “Long-Term Debt” footnotes in the notes to the condensed consolidated financial statements for more information.

The decrease in ~~note~~ interest ~~and amortization~~expense incurred on our credit agreements of ~~debt issue costs, discounts and premiums was partially offset by a~~ $10 million ~~increase in interest incurred on the Credit Agreement between periods due to a higher average outstanding balance as well as an additional 2% default interest rate charged on~~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 ~~first half of 2020~~Successor YTD Period were ~~$710~~$268 million compared to ~~$104~~$710 million ~~for~~weighted average borrowings outstanding under the ~~first half of 2019.~~ Predecessor Credit Agreement during the Predecessor YTD Period.

Our weighted average debt outstanding during the ~~first half~~Successor YTD Period, consisting solely of ~~2020~~borrowings under the Credit Agreement, was $268 million, with a weighted average cash interest rate of 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, ~~versus $2.9 billion for the first half of 2019. Our~~with a weighted average ~~effective~~ cash interest rate ~~was~~of 3.3% ~~during the first half of 2020 compared to 5.5% during the first half of 2019, primarily due to the discontinuation of interest expense on our Senior Notes beginning in April 2020.~~.

Gain on Extinguishment of Debt. ~~In March 2020,~~During the Predecessor YTD Period, we paid $53 million to repurchase $73 million aggregate principal amount of our ~~2020~~ 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 ~~2020~~ Convertible Senior Notes elected to convert. Upon conversion, such holders of the converted ~~2020~~ 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 ~~for~~during the six months ended June 30, 2020. Refer to the “Long-Term Debt” footnote in the notes to condensed consolidated financial statements for more information on this repurchase and conversion and the effect of the automatic stay issued in conjunction with the filing of the Chapter 11 Cases.Predecessor YTD Period.

Reorganization Items, Net. During the ~~six months ended June 30, 2020,~~Predecessor YTD Period, we recognized $42 million of reorganization costs related to the Chapter 11 Cases, consisting of professional fees and the write-off of debt issuance costs and premiums. Refer to the “Chapter 11 ~~Cases”~~Emergence” footnote in the notes to the condensed consolidated financial statements for more information on amounts recorded to reorganization items, net.

Income Tax ~~Benefit~~Expense (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. Additionally, 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 six months ended June 30, 2020, $4 million of this Canadian deferred tax expense became current. Refer to the “Income Taxes” footnote in the notes to the consolidated financial statements of 2019 Annual Report on Form 10-K for more information on this deferred tax liability. As a result of the full valuation allowance on our U.S. ~~DTAs~~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 ~~first half of 2020,~~periods presented, outside of a $1 million alternative minimum tax refund received during the Predecessor YTD period. ~~Income~~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 ~~(benefit) for the first half of 2019 totaled~~ to ~~a benefit of $1 million and related primarily to the recognition of a full valuation allowance during the second quarter of 2019 as a result of pre-tax losses.~~

~~Our overall effective tax rate of 0.0% for the first half of 2020 was lower than the U.S. statutory income tax rate as a result of the full valuation allowance on our U.S. DTAs.~~current.

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Three Months Ended June 30, ~~2020~~2021 Compared to Three Months Ended ~~June 30, 2019~~March 31, 2021


					Successor
					Three Months Ended
	Three Months Ended June 30,				June 30,		March 31,
	2020		2019		2021		2021
Net production
Oil (MMBbl)		5.5		7.5		4.9		4.8
NGLs (MMBbl)		1.6		1.9		1.8		1.6
Natural gas (Bcf)		10.9		13.0		10.7		10.2
Total production (MMBOE)		9.0		11.6		8.4		8.1
Net sales (in millions)
Oil ⁽¹⁾	$	91.9	$	403.9
Net sales (in millions) ⁽¹⁾
Oil					$	308.4	$	256.7
NGLs		0.4		16.3		28.3		27.0
Natural gas		(0.7)		6.1		13.3		21.0
Total oil, NGL and natural gas sales	$	91.6	$	426.3	$	350.0	$	304.7
Average sales prices
Oil (per Bbl) ⁽¹⁾	$	16.57	$	54.14	$	63.46	$	53.24
Effect of oil hedges on average price (per Bbl)		2.59		0.38		(13.64)		(8.16)
Oil net of hedging (per Bbl)	$	19.16	$	54.52
Oil after the effect of hedging (per Bbl)					$	49.82	$	45.08
Weighted average NYMEX price (per Bbl) ⁽²⁾	$	27.31	$	59.73	$	66.03	$	57.83
NGLs (per Bbl)	$	0.23	$	8.43
Natural gas (per Mcf)	$	(0.06)	$	0.47
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⁾					$	1.25	$	2.05
Effect of natural gas hedges on average price (per Mcf)						(0.04)		0.01
Natural gas after the effects of hedging (per Mcf)					$	1.21	$	2.06
Weighted average NYMEX price (per MMBtu) ⁽²⁾	$	1.66	$	2.58	$	2.74	$	2.56
Cost and expenses (per BOE)
Costs and expenses (per BOE)
Lease operating expenses	$	5.92	$	7.52	$	7.61	$	7.34
Transportation, gathering, compression and other	$	1.01	$	0.96	$	0.88	$	0.87
Production and ad valorem taxes	$	0.94	$	3.41	$	3.04	$	2.99
Depreciation, depletion and amortization	$	9.29	$	17.55	$	6.12	$	6.64
General and administrative	$	3.13	$	2.82	$	1.42	$	1.27

(1)	Before consideration of hedging transactions.

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

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Oil, NGL and Natural Gas Sales. Our oil, NGL and natural gas sales revenue ~~decreased $335~~increased $45 million to ~~$92~~$350 million when comparing the second quarter of ~~2020~~2021 to the ~~same period in 2019.~~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 second quarter of ~~2020, decreases in total production accounted for approximately $107 million~~2021 to the first quarter of ~~the change in revenue and decreases~~2021, increases in commodity prices realized between periods accounted for ~~approximately $228~~a $38 million ~~of the change~~increase in revenue ~~when comparing to the second quarter of 2019.~~and increases in total production between periods accounted for a $7 million increase in revenue.

Our oil, NGL and gas volumes ~~decreased 26%~~increased 1%, ~~16%~~15% and ~~16%~~4%, respectively, between periods. The overall volume ~~decreases~~increase between periods ~~were~~was primarily attributable to production curtailment, additional downtime on certain wells due to reduced workover rig count and the decisions to defer completions of certain wells and delay placing certain completed wells online for a portion of the second quarter as described in “Operational Response to Market Conditions” above, as well as normal field production decline. These decreases were 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.

Our average price for oil (before the effects of hedging)~~, NGLs~~ increased 19% between periods, and our average price for natural gas and NGLs decreased ~~69%, 97%~~39% and ~~113%~~9%, respectively. Our average sales price realized for oil was impacted by deficiency payments we made under a physical delivery contract at our Redtail field due to our inability to meet the minimum volume commitments under this contract. During the three months ended June 30, 2020 and 2019, our total average sales price realized for oil was $1.07 per Bbl lower and $2.07 per Bbl lower, respectively,primarily increased as a result of ~~these deficiency payments. This contract terminated in April 2020 and will not continue to negatively impact the price we receive for oil from our Redtail field~~favorable movements in the ~~future.~~NYMEX market index between periods. Our average sales price realized for ~~NGLs and~~ natural gas ~~for~~decreased as a result of unusually strong regional pricing in the ~~second~~Williston Basin during the first quarter of ~~2020~~2021 that was ~~negatively~~

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impacted by rising market differentials as compared to market indices as well as 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 can result in negative gas revenues, which occurrednot repeated in the second quarter of 2020. While these negative gas prices adversely affect our gas revenues, we have continued to produce our wells in order to sell oil, to meet lease and regulatory requirements and to sell NGLs derived from the processing of associated gas.2021.

Lease Operating ~~Expenses~~Expenses.. Our LOE during the second quarter of ~~2020~~2021 were ~~$53~~$64 million, a ~~$34~~$5 million ~~decrease~~increase over the ~~same period in 2019.~~first quarter of 2021. This ~~decrease~~increase between periods was primarily due to ~~ongoing cost reduction initiatives which were implemented beginning in the third quarter of 2019, increased saltwater disposal income received between periods and a decrease~~an increase in well workover costs and certain variable expenses associated with increased activity ~~between periods.~~and production during the second quarter of 2021.

Our lease operating expenses on a BOE basis also ~~decreased~~increased when comparing the second quarter of ~~2020~~2021 to the ~~same 2019 period.~~first quarter of 2021. LOE per BOE amounted to ~~$5.92~~$7.61 during the second quarter of ~~2020,~~2021, which represents ~~a decrease~~an increase of ~~$1.60~~$0.27 per BOE (or ~~21%~~4%) ~~decrease~~ from the ~~second~~first quarter of ~~2019.~~2021. This ~~decrease~~increase was mainly due to the overall ~~decrease~~increase in LOE ~~expense~~ discussed ~~above partially offset by lower overall production volumes between periods.~~above.

Transportation, Gathering, Compression and ~~Other.~~Other. Our TGC expenses during the second quarter of ~~2020~~2021 were $9$7 million, ~~a $2 million decrease over~~which is consistent with TGC expenses incurred during the ~~same period in 2019.~~ first quarter of 2021.

TGC per BOE ~~however,~~ increased slightly when comparing the second quarter of ~~2020~~2021 to the ~~same 2019 period. These changes were primarily due~~first quarter of 2021. TGC per BOE amounted to ~~lower production volumes~~$0.88 per BOE during the ~~period.~~second quarter of 2021, which represents an increase of $0.01 per BOE (or 1%) from the first quarter of 2021.

Production and Ad Valorem ~~Taxes~~Taxes.. Our production and ad valorem taxes during the second quarter of ~~2020 were $8~~2021 totaled $26 million, a ~~$31~~$2 million ~~decrease~~increase over the ~~same period in 2019,~~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 ~~8.5%~~6.9% and ~~9.0%~~7.6% for the second quarter of ~~2020~~2021 and ~~2019,~~the 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%.~~refunds recognized during the period.

Depreciation, Depletion and Amortization. ~~Our DD&A expense decreased $119 million in 2020 as compared to the second quarter of 2019.~~ The components of our DD&A expense were as follows (in thousands):

Three Months Ended June 30,

2020

2019
Depletion

$
79,198

$
198,656
Accretion of asset retirement obligations

3,079

2,937
Depreciation

1,272

1,416
Total

$
83,549

$
203,009


	Successor
	Three Months Ended
	June 30,		March 31,
	2021		2021
Depletion	$	48,081	$	50,150
Accretion of asset retirement obligations		2,190		2,222
Depreciation		1,347		1,357
Total	$	51,618	$	53,729

DD&A decreased between ~~periods~~the second quarter of 2021 and the first quarter of 2021 primarily due to ~~$119~~$2 million in lower depletion expense ~~consisting of a $23 million decrease~~ due ~~to lower overall production volumes during the second quarter of 2020, as well as a $96 million decrease related~~ to a lower depletion rate between periods. On a BOE basis, ~~however,~~ our overall DD&A rate of ~~$9.29~~$6.12 per BOE for the second quarter of ~~2020~~2021 was ~~47%~~8% lower than the rate of ~~$17.55~~$6.64 per BOE for the ~~same period in 2019.~~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 quarter of 2020 and downward~~was upward revisions to proved reserves ~~over~~during the ~~last twelve months,~~second quarter of 2021, which were largely driven by ~~lower~~higher commodity prices.

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Exploration and Impairment Costs. ~~Our exploration and impairment costs increased $408 million for the second quarter of 2020 as compared to the same period in 2019.~~ The components of our exploration and impairment expense were as follows (in thousands):

Three Months Ended June 30,

2020

2019
Impairment

$
409,277

$
3,336
Exploration

11,879

10,070
Total

$
421,156

$
13,406


	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 first and second ~~quarter~~quarters of ~~2020~~2021 primarily related to a $409 million non-cash impairment charge for the partial write-down of proved oil and gas properties in one of our Williston Basin resource plays due to a reduction in reserves, driven by depressed

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~~oil prices and a resultant decline in future development plans for the properties. Impairment expense for the second quarter of 2019 primarily relates~~ 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):


	Three Months Ended June 30,				Successor
	2020		2019		Three Months Ended
General and administrative expenses	$	47,859	$	57,966
					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		(19,723)		(25,393)		(17,657)		(18,919)
General and administrative expenses, net	$	28,136	$	32,573
General and administrative expenses, net (GAAP)					$	11,995	$	10,291

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

G&A expense before reimbursement and allocations decreased $10 million during the second quarter of 2020 primarily due to cost reduction initiatives instituted as part of a company restructuring beginning in the third quarter of 2019, including $12 million in lower compensation between periods. These decreases were partially offset by additional expense related to executive and employee cash retention incentives during the second quarter of 2020 of $5 million and $3 million of additional expenses related to a litigation settlement. The decrease in reimbursements and allocations for the second quarter of 2020 was the result of a lower number of field workers on Whiting-operated properties associated with reduced drilling activity.

~~Our~~ G&A expenses, ~~on a BOE basis, however, increased when comparing the second quarter of 2020 to the same 2019 period.~~other were consistent between periods. G&A expense per BOE amounted to ~~$3.13~~$1.42 per BOE during the second quarter of ~~2020,~~2021, which represents an increase of ~~$0.31~~$0.15 per BOE (or ~~11%~~12%) from the ~~second~~first quarter of ~~2019.~~2021. This increase was mainly due to the decrease in reimbursements and allocations between periods resulting from lower ~~overall production volumes between periods.~~employee benefit costs 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 $7$255 million and ~~a gain of $25~~$147 million for the three months ended June 30, ~~2020~~2021 and ~~2019,~~March 31, 2021, respectively. These ~~gains and~~ losses ~~are primarily related~~relate to our collar, swap, differential swap and ~~option~~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.

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


					Successor
					Three Months Ended
	Three Months Ended June 30,				June 30,		March 31,
	2020		2019		2021		2021
Credit agreement	$	10,977	$	3,256	$	2,974	$	3,936
Amortization of debt issue costs, discounts and premiums		5,250		7,915
Amortization of debt issue costs						887		887
Other		198		300		120		280
Notes		-		37,257
Total	$	16,425	$	48,728	$	3,981	$	5,103

The decrease in interest expense ~~of $32 million~~ between periods ~~was~~is primarily ~~attributable~~due to lower interest costs incurred on our notes during the second quarter of 2020 compared to the same period of 2019. 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 between periods. Refer to the “Chapter 11 Cases” and “Long-Term Debt” footnotes in the condensed consolidated financial statements for more information.~~

~~The decrease in note interest was partially offset by an $8 million increase~~ in interest incurred on the Credit Agreement ~~between 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 ~~second~~first quarter of ~~2020~~2021 were ~~$930~~$324 million, ~~compared to $118 million for~~with a weighted average cash interest rate of 4.9%.

Income Tax Benefit. As a result of the full valuation allowance on our DTAs as of June 30, 2021 and March 31, 2021, no income tax expense or benefit was recognized during the second quarter of ~~2019.~~ 2021 or the first quarter of 2021. This resulted in overall effective tax rates of 0% for both periods.

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Our weighted average debt outstanding during the second quarter of 2020 was $3.3 billion versus $3.0 billion for the second quarter of 2019. Our weighted average effective cash interest rate was 1.3% during the second quarter of 2020 compared to 5.5% during the second quarter of 2019 due to the discontinuation of interest expense on our Senior Notes beginning in April 2020.

~~Reorganization Items, Net.~~ During the three months ended June 30, 2020, we recognized $42 million of reorganization costs related to the Chapter 11 Cases, consisting of professional fees and the write-off of debt issuance costs and premiums. Refer to the “Chapter 11 Cases” footnote in the notes to the condensed consolidated financial statements for more information on amounts recorded to reorganization items, net.

~~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 June 30, 2020, we did not recognize any U.S. income tax expense or benefit during the second quarter of 2020 outside of a $1 million alternative minimum tax refund received during the period. Income tax expense for the second quarter of 2019 totaled $23 million, primarily due to the recognition of a full valuation allowance during the second quarter of 2019 as a result of pre-tax losses during the period.

~~Our overall effective tax rate of 0.2% for the second quarter of 2020 was lower than the U.S. statutory income tax rate as a result of the full valuation allowance on our U.S. DTAs.~~

Liquidity and Capital Resources

Overview. At June 30, ~~2020,~~2021, we had ~~$492~~$17 million of unrestricted cash on hand, ~~and $178~~$115 million of long-term debt and $1.2 billion of shareholders’ ~~deficit,~~equity, while at December 31, ~~2019,~~2020, we had $9$26 million of unrestricted cash on hand, $360 million of long-term debt and ~~$4.0~~$1.2 billion of equity. ~~In March 2020, we took proactive steps to ensure we had sufficient~~We expect that our liquidity ~~to fund ongoing operations during the Chapter 11 Cases by drawing $650 million on the Credit Agreement.~~

~~One of the primary sources of variability in our~~going forward will be primarily derived from cash flows from operating activities, ~~is commodity price volatility, which we partially mitigate through~~cash on hand and availability under the ~~use~~Credit Agreement and that these sources of ~~commodity hedge contracts. Oil accounted for 62% and 65% of~~liquidity will be sufficient to provide us the ability to fund our ~~total production in the first half of 2020 and 2019, respectively. As a result,~~material cash requirements, as described below, as well as our operating ~~cash flows are more sensitive~~and development activities and planned capital programs. We may need to ~~fluctuations in oil prices than they are to fluctuations in NGL~~fund acquisitions or ~~natural gas prices. As~~pursuits of ~~July 31, 2020, we had crude oil derivative contracts covering~~business opportunities that support our strategy through additional borrowings or the ~~sale~~issuance of ~~17,000 Bbl, 18,000 Bbl and 5,000 Bbl~~common stock or other forms of oil per day for the remainder of 2020, 2021 and the first nine months of 2022, respectively. Additionally, we had natural gas derivative contracts covering the sale of 24,000 MMBtu, 50,000 MMBtu and 30,000 MMBtu of natural gas per day through the remainder of 2020, 2021 and the first nine months 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.equity.

Cash Flows. During the ~~first half of 2020,~~Successor YTD Period, we generated ~~$67~~$336 million of cash ~~provided by~~from operating activities, ~~a decrease~~an increase of ~~$315~~$269 million from the ~~same period in 2019.~~Predecessor YTD Period. Cash provided by operating activities ~~decreased~~increased between periods primarily due to ~~lower~~higher realized sales prices, ~~and production volumes for oil, NGLs and natural gas,~~ as well as ~~higher~~lower cash G&A, cash interest expense and ~~reorganization~~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 during the first half of 2020 as compared to the same period in 2019.~~between periods. Refer to “Results of Operations” for more information on the impact of volumes and prices on revenues and for more information on increases and decreases in certain expenses between periods.

During the ~~first half of 2020,~~Successor YTD Period, cash flows from operating activities ~~$695 million of net borrowings under the Credit Agreement~~ and proceeds from the sale of properties were used ~~to finance $224~~for the net repayment of $245 million of outstanding borrowings under the Credit Agreement and $103 million of drilling and development 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 derivative contracts. As of July 28, 2021, we had crude oil derivative contracts (consisting of collars, swaps and differential swaps) covering the sale of 37,000 Bbl, 28,000 Bbl and 18,000 Bbl of oil per day for the remainder of 2021, the full year 2022 and the first six months of 2023, respectively. As of July 28, 2021, we had natural gas derivative contracts (consisting of collars, swaps and basis swaps) covering the sale of 99,000 MMBtu, 53,000 MMBtu and 54,000 MMBtu of natural gas per day through the remainder of 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.

Material Cash Requirements. Our material short-term cash requirements include payments under our short-term lease agreements, recurring payroll and benefits obligations for our employees, capital and operating expenditures and other working capital needs. Working capital, defined as total current assets less total current liabilities, fluctuates depending on commodity pricing and effective management of payables to our vendors and receivables from our purchasers and working interest partners. As commodity prices improve, our working capital requirements may increase as we spend additional capital, 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 Credit Agreement, settlements on our outstanding commodity derivative contracts, future obligations to plug, abandon and remediate our oil and gas properties at the ~~repurchase~~end of ~~$73 million aggregate principal amount~~their productive lives, operating and finance lease obligations and contracts to transport a minimum volume of ~~2020 Senior Convertible Notes, which resulted in $492 million of remaining unrestricted~~crude oil and natural gas within specified time frames. The following table summarizes our estimated material cash ~~on hand~~requirements for known obligations as of June 30, ~~2020.~~

~~Chapter 11 Cases and Effect~~2021. This table does not include repayments of ~~Automatic Stay.~~ ~~On April 1, 2020, the Debtors filed for relief under chapter 11 of the Bankruptcy Code. The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under the~~outstanding borrowings on our Credit Agreement, or the associated interest payments, as the timing and ~~the indentures governing our senior notes, resulting in the automatic~~amount of borrowings and ~~immediate acceleration~~repayments cannot be forecasted with certainty and are based on working capital requirements, commodity prices and acquisition and divestiture activity, among other factors. As of ~~all of~~June 30, 2021, our outstanding ~~debt. In conjunction~~borrowings under our Credit Agreement were $115 million, with a weighted average interest rate on the ~~filing~~outstanding principal balance of the Chapter 11 Cases, we did not make the $187 million principal payment due on our 2020 Convertible Senior Notes. Any efforts to enforce payment obligations related to the acceleration of our debt have been automatically stayed as a result of the filing of the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the

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~~Bankruptcy Code.~~4.1%. Refer to “Credit Agreement” below as well as the ~~“Basis of Presentation” and “Chapter 11 Cases” footnotes~~“Long-Term Debt” footnote in the notes to the condensed consolidated financial statements for more ~~information~~information. This table also does not include amounts payable under obligations where we cannot forecast with certainty the amount and timing of such payments, including any amounts we may be obligated to pay under our derivative contracts, as such payments are dependent on commodity prices in effect at the ~~Chapter 11 Cases.~~

~~On April 23, 2020,~~time of settlement. Refer to the Debtors entered into the RSA with certain holders of our senior notes to support a restructuring in accordance with the terms set forth in our chapter 11 plan of reorganization (the “Plan”). As more fully disclosed in the “Basis of Presentation” and “Chapter 11 Cases” footnotes“Derivative Financial Instruments” footnote in the notes to the condensed consolidated financial statements ~~the Plan~~for further information on these contracts and ~~the RSA contemplate a restructuring which would provide for the treatment~~their fair values as of ~~holders of certain claims and existing equity interests.~~

We expect to continue operations in the normal course for the duration of the Chapter 11 Cases. To ensure ordinary course operations, we have obtained approval from the Bankruptcy Court for certain “first day” motions, including motions to obtain customary relief intended to continue our ordinary course operations after the filing date. In addition, we have received authority to use cash collateral of the lenders under the Credit Agreement on an interim basis.

However, for the duration of the Chapter 11 Cases, our operations and our ability to develop and execute our business plan are subject to a high degree of risk and uncertainty associated with the Chapter 11 Cases. The outcome of the Chapter 11 Cases is dependent upon factors that are outside of our control, including actions of the Bankruptcy Court and our creditors. The significant risks and uncertainties related to our liquidity and Chapter 11 Cases described above raise substantial doubt about our ability to continue as a going concern. There can be no assurance that we will confirm and consummate the Plan as contemplated by the RSA or complete another plan of reorganization with respect to the Chapter 11 Cases. As a result, we have concluded that management’s plans do not alleviate substantial doubt about our ability to continue as a going concern.

~~As a result of the Chapter 11 Cases, our total available liquidity at~~ June 30, ~~2020 consisted~~2021, which fair values represent the cash settlement amount required to terminate such instruments based on forward price curves for commodities as of ~~our unrestricted $492 million~~that date.

Table of cash on hand. We expect to continue using additional cash that will further reduce this liquidity. With the Bankruptcy Court’s authorization to use cash collateral under the Credit Agreement, we believe that we will have sufficient liquidity, including cash on hand and funds generated from ongoing operations, to fund anticipated cash requirements through the Chapter 11 Cases. As such, we expect to pay vendor and royalty obligations on a go-forward basis according to the terms of our current contracts and consistent with applicable court orders, if any, approving such payments.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)	Asset retirement obligations represent the present value of estimated amounts expected to be incurred in the future to plug and abandon oil and gas wells, remediate oil and gas properties and dismantle their related plants and facilities.

(2)

We have operating and finance leases for corporate and field offices, 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, 2020 for more information on these leases.

(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.

Exploration and Development Expenditures. During the six months ended June 30, ~~2020~~2021 and ~~2019,~~2020, we incurred ~~$179 million and $451 million, respectively, of~~accrual basis exploration and development (“E&D”) ~~expenditures.~~expenditures of $114 million and $179 million, respectively. Of these expenditures, ~~95%~~98% and ~~99%~~95%, respectively, were incurred in our large resource play in the Williston Basin of North Dakota and Montana, where we have focused our ~~development~~current development. Capital expenditures reported in ~~2019 and~~ the ~~first half~~condensed consolidated statements of ~~2020.~~cash flows are calculated on a cash basis, which differs from the accrual basis used to calculate the incurred capital expenditures as detailed in the table below:


	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 ~~2020~~2021 E&D budget is ~~$215~~a range of $240 million to $252 million, which we expect to fund with net cash provided by operating activities and cash on hand, and represents a ~~substantial decrease~~slight increase from the ~~$778 million incurred on~~ E&D expenditures incurred during 2019. This reduced capital budget is in response to the significantly lower crude oil prices experienced during the first half of 2020 and our plan to preserve our liquidity while improving capital efficiency and continue aligning our capital spending with cash flows generated from operations.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 ~~significantly~~ depending on commodity prices, cash flows, available opportunities and development results, among other factors. ~~With the Bankruptcy Court’s authorization to use cash collateral under the Credit Agreement, we~~We believe that we have sufficient liquidity and capital resources to execute our ~~business~~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.

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Credit ~~Agreement~~Agreement. .Whiting Petroleum Corporation, as parent guarantor, and Whiting Oil and Gas, ~~our wholly owned subsidiary, has~~as borrower, have a reserves-based credit ~~agreement~~facility, with a syndicate of banks that had a borrowing base ~~of $2.05 billion~~ and aggregate commitments of ~~$1.75 billion prior to default.~~$750 million as of June 30, 2021. As of June 30, ~~2020,~~2021, we had ~~$912~~$633 million of available borrowing capacity under the Credit Agreement, which was net of $115 million of borrowings outstanding ~~under the Credit Agreement. As a result of the commencement of the Chapter 11 Cases, we are no longer in compliance with the covenants under the Credit Agreement~~ and ~~the lenders' commitments under the Credit Agreement have been terminated. We are therefore unable to make additional borrowings or issue additional letters of credit under the Credit Agreement.~~

The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default that automatically accelerated our obligations under the Credit Agreement. Any efforts to enforce payment obligations related to the acceleration of our obligations under the Credit Agreement have been automatically stayed as a result of the filing of the Chapter 11 Cases, and the lenders’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code.

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Prior to default, a portion of the Credit Agreement in an aggregate amount not to exceed $50 million was available to issue letters of credit for the account of Whiting Oil and Gas or other designated subsidiaries of ours. As of June 30, 2020, $2 million in letters of credit ~~were outstanding under the agreement.~~outstanding.

~~Prior to default, the~~The borrowing base under the Credit Agreement ~~was~~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 ~~May~~April 1 and ~~November~~October 1 of each year, as well as special redeterminations described in the Credit ~~Agreement. Such redeterminations have~~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 ~~occurred and are not expected~~ to ~~occur~~exceed $50 million may be used to issue letters of credit for the ~~duration~~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 ~~Chapter 11 Cases.~~Credit Agreement.

The Credit Agreement provides for interest only payments until maturity on April 1, 2024, when the ~~Credit Agreement expires~~agreement terminates and all outstanding borrowings are due. In addition, the Credit Agreement provides for certain mandatory prepayments, including a provision pursuant to which, if our cash balances are in excess of approximately $75 million during any given week, such excess must be utilized to repay borrowings under the Credit Agreement. Interest under the Credit Agreement accrues at our option at either (i) a base rate for a base rate loan plus a margin between ~~0.50%~~1.75% and ~~1.50%~~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~~eurodollar loan plus a margin between ~~1.50%~~2.75% and ~~2.50%~~3.75% based on the ratio of outstanding borrowings and letters of credit to the lower of the current borrowing ~~base. Prior to the chapter 11 proceedings,~~base or total commitments. Additionally, we ~~incurred~~incur commitment fees of ~~0.375% or 0.50% based on the ratio of outstanding borrowings to the borrowing base~~0.5% on the unused portion of the aggregate commitments of the lenders under the Credit ~~Agreement. During the chapter 11 proceedings, the commitment fee has been terminated and instead all amounts outstanding under the Credit~~ Agreement, ~~will bear~~which are included as a component of interest per annum at the applicable rate stated in the agreement plus a 2.0% default rate. At June 30, 2020, the weighted average interest rate on the outstanding principal balance under the Credit Agreement was 4.7%.

Prior to default, the Credit Agreement had a maturity date of April 12, 2023, provided that if at any time and for so long as any senior notes (other than the 2020 Convertible Senior Notes) had a maturity date prior to 91 days after April 12, 2023, the maturity date shall have been the date that is 91 days prior to the maturity of such senior notes.expense.

The Credit Agreement contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, enter into hedging contracts, incur liens and engage in certain other transactions without the prior consent of our lenders. Except for limited exceptions, the ~~credit agreement~~Credit Agreement also restricts our ability to make any dividend payments or distributions on our common ~~stock.~~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 ~~(as defined~~and are calculated in accordance with definitions contained in the Credit ~~Agreement).~~

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 (as defined in the Credit Agreement):~~ratios: (i) a consolidated current assets to consolidated current liabilities ratio ~~(which includes an add back of the available borrowing capacity under the credit agreement)~~ of not less than 1.0 to 1.0 and (ii) a total debt to ~~the~~ last four quarters’ EBITDAX ratio of not greater than ~~4.0~~3.5 to 1.0.

For ~~more~~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.

Under the Credit Agreement, a cross-default provision provides that a default under certain other debt of ours or certain of our subsidiaries in an aggregate principal amount exceeding $100 million may constitute an event of default under such credit agreement. Additionally, under the indentures governing our senior notes and senior convertible notes, a cross-default provision provides that a default under certain other debt of ours or certain of our subsidiaries in an aggregate principal amount exceeding $100 million (or $50 million in the case of the 2021 Senior Notes) may constitute an event of default under such indenture.

~~Senior Notes~~. In December 2017, we issued at par $1.0 billion of 6.625% Senior Notes due January 15, 2026 (the “2026 Senior Notes”). In March 2015, we issued at par $750 million of 6.25% Senior Notes due April 1, 2023 (the “2023 Senior Notes”). In September 2013, we issued at par $800 million of 5.75% Senior Notes due March 15, 2021 and issued at 101% of par an additional $400 million of 5.75% Senior Notes due March 15, 2021 (collectively the “2021 Senior Notes” and together with the 2023 Senior Notes and the 2026 Senior Notes, the “Senior Notes”).

During 2016, we exchanged $326 million aggregate principal amount of our 2021 Senior Notes and $342 million aggregate principal amount of our 2023 Senior Notes for the same aggregate principal amount of convertible notes. Subsequently during 2016, all $668 million aggregate principal amount of these convertible notes was converted into approximately 16.3 million shares of our common stock pursuant to the terms of the notes.

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The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default that automatically accelerated our obligations under the indentures governing our Senior Notes. Any efforts to enforce payment obligations related to the acceleration of our Senior Notes have been automatically stayed as a result of the filing of the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code.

~~Repurchases of 2021 Senior Notes.~~ In September 2019, we paid $24 million to repurchase $25 million aggregate principal amount of the 2021 Senior Notes, which payment consisted of the average 94.708% purchase price plus all accrued and unpaid interest on the notes. We financed the repurchases with cash and borrowings under the Credit Agreement. As of September 30, 2019, $849 million of 2021 Senior Notes remained outstanding.

In October 2019, we paid an additional $72 million to repurchase $75 million aggregate principal amount of the 2021 Senior Notes, which payment consisted of the average 95.467% purchase price plus all accrued and unpaid interest on the notes. We financed the repurchases with borrowings under the Credit Agreement. As of October 4, 2019, $774 million of 2021 Senior Notes remained outstanding.

Prior to default, the indentures governing the Senior Notes restricted us from incurring additional indebtedness, subject to certain exceptions, unless our fixed charge coverage ratio (as defined in the indentures) is at least 2.0 to 1.

~~2020 Convertible Senior Notes.~~ In March 2015, we issued at par $1,250 million of 2020 Convertible Senior Notes. During 2016, we exchanged $688 million aggregate principal amount of our 2020 Convertible Senior Notes for the same aggregate principal amount of new mandatory convertible senior notes. Subsequently during 2016, all $688 million aggregate principal amount of these mandatory convertible senior notes was converted into approximately 17.8 million shares of our common stock pursuant to the terms of the notes.

In September 2019, we paid $299 million to complete a cash tender offer for $300 million aggregate principal amount of the 2020 Convertible Senior Notes, which payment consisted of the 99.0% purchase price plus all accrued and unpaid interest on the notes and associated transaction costs. We financed the tender offer with cash and borrowings under the Credit Agreement.

In March 2020, we paid $53 million to repurchase $73 million aggregate principal amount of the 2020 Convertible Senior Notes, which payment consisted of the average 72.5% purchase price plus all accrued and unpaid interest on the notes. We financed the repurchases with borrowings under the Credit Agreement.

Prior to January 1, 2020, the 2020 Convertible Senior Notes were convertible only upon the achievement of certain contingent market conditions, which were not met. After January 1, 2020, the 2020 Convertible Senior Notes were convertible at any time until the second scheduled trading day immediately preceding the April 1, 2020 maturity date of the notes and holders of $3 million aggregate principal amount of 2020 Convertible Senior Notes timely elected to convert. Upon conversion, such holders of the converted 2020 Convertible Senior Notes were entitled to receive an insignificant cash payment on April 1, 2020, which we did not pay. Additionally, at maturity, we were obligated to pay in cash the $187 million outstanding principal amount of the 2020 Convertible Senior Notes that did not convert, which we did not pay. Under the Bankruptcy Code, the holders of the 2020 Convertible Senior Notes and the prior holders that converted their notes are stayed from taking any action against us as a result of our non-payment. Refer to “Chapter 11 Cases and Effect of Automatic Stay” above for more information.

~~Contractual Obligations and Commitments~~

We have various contractual obligations in the normal course of our operating and financing activities. For more information, refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contractual Obligations and Commitments” in our Annual Report on Form 10-K for the year ended December 31, 2019. There have been no material changes to our obligations since year-end 2019 except as discussed below.

On April 1, 2020, we did not make the $187 million cash principal payment due on the 2020 Convertible Senior Notes. On the same date, the Debtors filed the Chapter 11 Cases in the Bankruptcy Court seeking relief under the Bankruptcy Code. The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under the Credit Agreement and the indentures governing our Senior Notes, resulting in the automatic and immediate acceleration of all of our outstanding debt. Any efforts to enforce such payment obligations were automatically stayed as a result of the filing of the Chapter 11 Cases and the creditors’ rights of enforcement in respect of the Senior Notes and the Credit Agreement are subject to the applicable provisions of the Bankruptcy Code.

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In addition, commencement of the Chapter 11 Cases automatically stayed all of the proceedings and actions against us (other than regulatory enforcement matters). For a further discussion of the Chapter 11 Cases and related matters, refer to the “Basis of Presentation,” “Chapter 11 Cases” and “Long-Term Debt” footnotes in the notes to the condensed consolidated financial statements.

Additionally, in connection with the Chapter 11 Cases, we have incurred and will continue to incur professional fees as discussed in “Results of Operations.” While we cannot currently estimate the total amount of the fees to be incurred over the restructuring period, we expect that it will be material.

~~Delivery Commitments.~~ We had a delivery contract tied to our 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, we were committed 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 net cash generated from operations, together with cash on hand, will be adequate to meet future liquidity needs, including funding our operating, development and exploration activities.

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 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~~, 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 separate from activities related to ongoing operations of the business.

~~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. 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. Although commodity prices have declined sharplyestimates during the first part of 2020, these costs have not yet declined in response. 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, ~~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: our ability to obtain Bankruptcy Court approval with respect to motions or other requests made to the Bankruptcy Court; our ability to confirm and consummate the Plan; the effects of the Chapter 11 Cases on our liquidity or results of operations or business prospects; the effects of the Chapter 11 Cases on our business and the interests of

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~~various constituents; the length of time that we will operate under chapter 11 protection;~~ risks associated with ~~third-party motions in the Chapter 11 Cases;~~our emergence from 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 our ~~credit agreement~~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; 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; 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 and natural gas reserves;~~ negative impacts from litigation and legal proceedings; 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; 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.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

The price we receive for our oil, NGL and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Crude oil, NGL and natural gas are commodities, and 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 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 June 30, ~~2020.~~2021.

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 June 30, ~~2020~~2021 was a net ~~asset~~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 June 30, ~~2020~~2021 would cause an increase of $123 million or a decrease ~~or increase~~ of ~~$17~~$115 million, respectively, in this fair value ~~asset.~~liability. The fair value of our natural gas ~~contracts~~derivative positions was a net liability of ~~$40,000.~~$23 million. A hypothetical upward or downward shift of 10% per MMBtu in the NYMEX forward curve for natural gas as of 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 $1$2 million in this fair value liability.

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While these collars, fixed-price swaps, basis swaps and 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 ~~hedges and options and~~collars, (ii) upward price movements generally with respect to the fixed-price ~~swaps.~~

~~On April 1, 2020 we filed for relief under chapter 11 of the Bankruptcy Code, which permitted the counterparties of our derivative instruments~~swaps and (iii) decreasing floating market differentials relative to ~~terminate their outstanding hedges, and certain of our counterparties elected to exercise their right to terminate. Refer~~NYMEX with respect to the “Derivative Financial Instruments” footnote in the notes to the condensed consolidated financial statements for more information on these terminations, the effect such terminations will have on our cash flows, financial positionbasis swaps and ~~results of operations and other subsequent hedging activity.~~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 ~~our credit agreement. Our credit agreement~~the Credit Agreement. The Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance for a period up to one month. To the extent that the interest rate is fixed, interest rate changes affect the instrument’s fair market value but do not impact results of operations or cash flows. Conversely, for the portion of the ~~credit agreement~~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 June 30, ~~2020,~~2021, our outstanding principal balance under ~~our credit agreement~~the Credit Agreement was ~~$912~~$115 million, and the weighted average interest rate on the outstanding principal balance was ~~4.7%~~4.1%. At June 30, ~~2020,~~2021, the carrying amount approximated fair market value. Assuming a constant debt level of ~~$912~~$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 $7$1 million over a 12-month time period. ~~Changes in interest rates do not affect the amount~~

Table of ~~interest we pay on our fixed-rate senior notes, but changes in interest rates do affect the fair values of these notes.~~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 ~~Chairman, President and~~ Chief Executive Officer and our Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of June 30, ~~2020.~~2021. Based upon their evaluation of these disclosure controls and procedures, the ~~Chairman, President and~~ Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures were effective as of 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 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:~~

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~~We are subject to~~factors has occurred during the ~~risks and uncertainties associated with proceedings under chapter 11 of the Bankruptcy Code.~~

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 April 23, 2020, the Debtors entered into a restructuring support agreement (the “RSA”) with certain holders of our senior notes to support a restructuring in accordance with the terms set forth in our chapter 11 plan of reorganization (the “Plan”). For the duration of our Chapter 11 Cases, our operations and our ability to develop and execute the business plan, as well as our continuation as a going concern, are subject to risks and uncertainties associated with bankruptcy. These risks include the following:

●	~~our ability to execute, confirm and consummate the Plan as contemplated by the RSA with respect to the Chapter 11 Cases;~~

●	~~the high costs of bankruptcy proceedings and related fees;~~

●	~~our ability to obtain sufficient financing to allow us to emerge from bankruptcy and execute our business plan post-emergence;~~

●	~~our ability to maintain our relationships with our suppliers, service providers, customers, employees and other third parties;~~

●	~~our ability to maintain contracts that are critical to our operations;~~

●	~~our ability to execute our business plan in the current depressed commodity price environment;~~

●	~~our ability to attract, motivate and retain key employees;~~

●	~~the ability of third parties to seek and obtain court approval to terminate contracts and other agreements with us;~~

●	~~the ability of third parties to seek and obtain court approval to convert the Chapter 11 Cases to a chapter 7 proceeding; and~~

●	~~the actions and decisions of our creditors and other third parties who have interests in our Chapter 11 Cases that may be inconsistent with our plans.~~

~~Delays in our Chapter 11 Cases increase the risks of us being unable to reorganize our business and emerge from bankruptcy and increase our costs associated with the bankruptcy process.~~

These risks and uncertainties could affect our business and operations in various ways. For example, negative events or publicity associated with our Chapter 11 Cases could adversely affect our relationships with suppliers, service providers, customers, employees and other third parties, which in turn could adversely affect our operations and financial condition. Also, pursuant to the Bankruptcy Code, we need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond timely to certain events or take advantage of certain opportunities. We also need Bankruptcy Court confirmation of the Plan as contemplated by the RSA. Because of the risks and uncertainties associated with our Chapter 11 Cases, we cannot accurately predict or quantify the ultimate impact that events that occur during our Chapter 11 Cases will have on our business, financial condition, results of operations and cash flows.

Even if the Plan is consummated, we will continue to face a number of risks, including our ability to reduce expenses, implement any strategic initiatives and generally maintain favorable relationships with and secure the confidence of our counterparties. Accordingly, we cannot guarantee that the proposed financial restructuring will achieve our stated goals nor can we give any assurance of our ability to continue as a going concern.

~~Operating under the Bankruptcy Court protection for a long period of time may harm our business.~~

A long period of operations under the Bankruptcy Court protection could have a material adverse effect on our business, financial condition, results of operations and liquidity. A prolonged period of operating under Bankruptcy Court protection may also make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, the longer

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the Chapter 11 Cases continue, the more likely it is that our customers and suppliers will lose confidence in our ability to reorganize our business successfully and will seek to establish alternative commercial relationships.

Furthermore, so long as the Chapter 11 Cases continue, we will be required to incur substantial costs for professional fees and other expenses associated with the administration of the Chapter 11 Cases. Although no such financing has been sought to date, and we do not currently anticipate seeking such financing, the Chapter 11 Cases may also require us to seek debtor-in-possession financing to fund operations. If we are unable to obtain such financing on favorable terms or at all, our chances of successfully reorganizing our business may be seriously jeopardized, and as a result, our securities could become further devalued or become worthless.

Furthermore, we cannot predict the ultimate amount of all settlement terms for the liabilities that will be subject to the Plan. Even once the plan is approved and implemented, our operating results may be adversely affected by the possible reluctance of prospective lenders and other counterparties to do business with a company that recently emerged from chapter 11 bankruptcy.

~~We may not be able to obtain confirmation of the Plan.~~

To emerge successfully from Bankruptcy Court protection as a viable entity, we must meet certain statutory requirements with respect to adequacy of disclosure with respect to a chapter 11 plan of reorganization, solicit and obtain the requisite acceptances of such a reorganization plan and fulfill other statutory conditions for confirmation of such a plan. However, even if the Plan contemplated by the RSA meets other requirements under the Bankruptcy Code, certain parties in interest may file objections to the plan in an effort to persuade the Bankruptcy Court that we have not satisfied the confirmation requirements under section 1129 of the Bankruptcy Code. Even if no objections are filed and the requisite acceptances of our plan are received from creditors entitled to vote on the plan, the Bankruptcy Court, which can exercise substantial discretion, may not confirm the Plan. The precise requirements and evidentiary showing for confirming a plan, notwithstanding its rejection by one or more impaired classes of claims or equity interests, depends upon a number of factors including, without limitation, the status and seniority of the claims or equity interests in the rejecting class (i.e., secured claims or unsecured claims, subordinated or senior claims).

If the Plan is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if anything, holders of claims against us would ultimately receive with respect to their claims.

~~We have substantial liquidity needs and may not be able to obtain sufficient liquidity for the duration of the Chapter 11 Cases or to confirm a plan of reorganization or liquidation.~~

Although we have lowered our capital budget and reduced the scale of our operations significantly, our business remains capital intensive. In addition to the cash requirements necessary to fund ongoing operations, we have incurred, and expect to continue to incur, significant professional fees and other costs in connection with the Chapter 11 Cases. As ofsix months ended June 30, 2020, our total available liquidity, consisting of unrestricted cash on hand, was $492 million. We expect to continue using additional cash that will further reduce this liquidity. With the Bankruptcy Court’s authorization to use cash collateral under the Credit Agreement, we believe that we will have sufficient liquidity, including cash on hand and funds generated from ongoing operations, to fund anticipated cash requirements through the Chapter 11 Cases. As such, we expect to pay vendor and royalty obligations on a go-forward basis according to the terms of our current contracts and consistent with applicable court orders, if any, approving such payments. However, there can be no assurance that our current liquidity will be sufficient to allow us to satisfy our obligations related to the Chapter 11 Cases or to pursue confirmation of the Plan. We can provide no assurance that we will be able to secure additional interim financing or exit financing sufficient to meet our liquidity needs or, if sufficient funds are available, offered to us on acceptable terms.

~~As a result of the Chapter 11 Cases, our financial results may be volatile and may not reflect historical trends.~~

During the Chapter 11 Cases, we expect our financial results to continue to be volatile as restructuring activities and expenses, contract terminations and rejections and claims assessments significantly impact our financial results. As a result, our historical financial performance is likely not indicative of financial performance after the date of the bankruptcy filing. In addition, if we emerge from Chapter 11, the amounts reported in subsequent periods may materially change relative to historical results, including due to revisions to our operating plans pursuant to the Plan. We also may be required to adopt fresh start accounting, in which case our assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities prior to seeking bankruptcy protection. Our financial results after the application of fresh start accounting also may be different from historical trends.

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~~We may be subject to claims that will not be discharged in the Chapter 11 Cases, which could have a material adverse effect on our financial condition and results of operations.~~

The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to the Petition Date. With few exceptions, all claims that arose before the Petition Date (i) would be subject to compromise and/or treatment under the Plan and/or (ii) would be discharged in accordance with the terms of the Plan. Any claims not ultimately discharged through the Plan could be asserted against the reorganized entities and may have an adverse effect on their financial condition and results of operations on a post-reorganization basis.

The pursuit of the Chapter 11 Cases has consumed and will continue to consume a substantial portion of the time and attention of our management, which may have an adverse effect on our business and results of operations, and we may face increased levels of employee attrition.

While the Chapter 11 Cases continue, our management will be required to spend a significant amount of time and effort focusing on the Chapter 11 Cases instead of focusing exclusively on our business operations. This diversion of attention may materially adversely affect the conduct of our business, and, as a result, our financial condition and results of operations, particularly if the Chapter 11 Cases are protracted.

During the duration of the Chapter 11 Cases, our employees will face considerable distraction and uncertainty and we may experience increased levels of employee attrition. A loss of key personnel or material erosion of employee morale could have a material adverse effect on our ability to meet customer expectations, thereby adversely affecting our business and results of operations. The failure to retain or attract members of our management team and other key personnel could impair our ability to execute our strategy and implement operational initiatives, thereby having a material adverse effect on our financial condition and results of operations.

~~In certain instances, a chapter 11 case may be converted to a case under chapter 7 of the Bankruptcy Code.~~

Upon a showing of cause, the Bankruptcy Court may convert our Chapter 11 Cases to cases under chapter 7 of the Bankruptcy Code. In such event, a chapter 7 trustee would be appointed or elected to liquidate our assets and the assets of our subsidiaries for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under chapter 7 would result in significantly smaller distributions being made to our creditors than those provided for in a plan of reorganization because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, (ii) additional administrative expenses involved in the appointment of a chapter 7 trustee, and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations.

Any plan of reorganization that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, our plan may be unsuccessful in its execution.

Any plan of reorganization that we may implement could affect both our capital structure and the ownership, structure and operation of our businesses and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. In addition, any plan of reorganization will rely upon financial projections, including with respect to revenues, capital expenditures, debt service and cash flow. Financial forecasts are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial forecasts will not be accurate. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to (i) our ability to substantially change our capital structure, (ii) our ability to obtain adequate liquidity and financing sources, (iii) our ability to maintain customers’ confidence in our viability as a continuing entity and to attract and retain sufficient business from them, (iv) our ability to retain key employees and (v) the overall strength and stability of general economic conditions of the financial and oil and gas industries, both in the U.S. and in global markets. The failure of any of these factors could materially adversely affect the successful reorganization of our businesses. Consequently, there can be no assurance that the results or developments contemplated by any plan of reorganization we may implement will occur or, even if they do occur, that they will have the anticipated effects on us and our subsidiaries or our businesses or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of any plan of reorganization.

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~~Even if the Plan is consummated, we may not be able to achieve our stated goals and continue as a going concern.~~

Even if the Plan is consummated, we will continue to face a number of risks, including further deterioration in commodity prices or other changes in economic conditions, changes in our industry, changes in market demand and increasing expenses. Accordingly, we cannot guarantee that the Plan or any other chapter 11 plan of reorganization will achieve our stated goals.

Furthermore, even if our debts are reduced or discharged through such plan, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of our Chapter 11 Cases. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited, if it is available at all. Therefore, adequate funds may not be available when needed or may not be available on favorable terms, if they are available at all.

Our ability to continue as a going concern is dependent upon our ability to raise additional capital. As a result, we cannot give any assurance of our ability to continue as a going concern, even if a chapter 11 plan of reorganization is confirmed.

~~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;~~

●	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;~~

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●	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 upcoming 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 during the first quarter of 2020, dropping below $21.00 per Bbl in March 2020 and further dropping to below negative $37.00 per Bbl in April 2020. This dramatic decline in pricing was 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 or sell assets. 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” in our Annual Report on Form 10-K for the period ended December 31, 2019.

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.

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~~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 shut down 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 30% 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.

Our ability to use our net operating loss carryforwards (“NOLs”) may be limited. We have adopted a Section 382 Rights Agreement and the Bankruptcy Court has entered an order that are each designed to protect our NOLs.

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. 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. 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.

On March 26, 2020, our Board of Directors approved the Section 382 Rights Agreement (the “Rights Agreement”) designed to make it more difficult for a third party to acquire, and to discourage a third party from acquiring, a large block of our common stock. On April 1, 2020, and as amended on April 24, 2020, the Bankruptcy Court entered an order that sets forth procedures (including notice requirements) that certain shareholders and potential shareholders must comply with regarding transfers of, or declarations of worthlessness with respect to, our common stock, as well as certain obligations with respect to notifying us of current share ownership (the “Procedures”). The Rights Agreement and the Procedures are each designed to reduce the likelihood of an “ownership change” in order to protect our NOLs from the effect of Section 382 of the IRC discussed above. However, there is no assurance that the Rights Agreement or the Procedures will prevent all transfers that could result in such an “ownership change.”

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If we are out of compliance with the New York Stock Exchange’s (the “NYSE”) minimum share price requirement, we may be at risk of the NYSE delisting our common stock, which would have an adverse impact on the trading volume, liquidity and market price of our common stock.

On April 14, 2020, we received written notification from the NYSE that we did not satisfy the NYSE’s continued listing compliance standards because the average closing price of our common stock was below $1.00 over a 30 consecutive trading-day period. On July 1, 2020 we received written notification from the NYSE that we regained compliance with the minimum share price requirement. Although we are currently in compliance with the minimum share price requirement, there is no assurance we will be in compliance in the future. If we are not in compliance with such requirement in the future, the NYSE might delist our common stock. Delisting would have an adverse effect on the liquidity of our common stock and, as a result, the market price for our common stock might become more volatile. Delisting could also reduce the number of investors willing to hold or acquire our common stock and negatively impact our ability to access equity markets and obtain financing.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.

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EXHIBIT INDEX

Exhibit Number		Exhibit Description
(2)		Joint Chapter 11 Plan of Reorganization of Whiting Petroleum Corporation and its Debtor Affiliates [Incorporated by reference to Exhibit A of the Order Confirming the Joint Chapter 11 Plan of Reorganization, filed as Exhibit 2 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on August 17, 2020 (File No. 001-31899)].
(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 ~~November 9, 2017 (File No. 001-31899)].~~

~~(3.2)~~		Amended and Restated By-laws of Whiting Petroleum Corporation, effective October 24, 2017 [Incorporated by reference to Exhibit 3.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on October 26, 2017 (File No. 001-31899)].

~~(3.3)~~		Certificate of Designations of Series A Preferred Stock of Whiting Petroleum Corporation [Incorporated by reference to Exhibit 3 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on March 27,September 1, 2020 (File No. 001-31899)].

~~(4.1)~~		~~Tripartite Agreement, dated June 25, 2020, by and among Whiting Petroleum Corporation, Delaware Trust Company and The Bank of New York Mellon Trust Company, N.A.~~

(10.1)		~~Restructuring Support~~First Amendment to Credit Agreement, dated ~~April 23, 2020 [Incorporated by reference to Exhibit 10 to~~as of June 7, 2021, among Whiting Oil and Gas Corporation as Borrower, its Parent Guarantor Whiting Petroleum ~~Corporation’s Current Report on Form 8-K filed on April 24, 2020 (File No. 001-31899)].~~Corporation, JPMorgan Chase Bank, N.A. as Administrative Agent and the lenders signatory thereto.

(31.1)		Certification by the ~~Chairman,~~ 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 ~~Chairman,~~ 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 June 30, ~~2020~~2021 are filed herewith, formatted in iXBRL (Inline Extensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets, ~~as of June 30, 2020 and December 31, 2019,~~ (ii) the Condensed Consolidated Statements of Operations, ~~for the Three and Six Months Ended June 30, 2020 and 2019,~~ (iii) the Condensed Consolidated Statements of Cash Flows, ~~for the Six Months Ended June 30, 2020 and 2019,~~ (iv) the Condensed Consolidated Statements of Equity ~~(Deficit) for the Six Months Ended June 30, 2020 and 2019~~ 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.

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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 64^th day of August, ~~2020.~~2021.


		WHITING PETROLEUM CORPORATION


	By	/s/ ~~Bradley J. Holly~~Lynn A. Peterson
		~~Bradley J. Holly~~Lynn A. Peterson
		~~Chairman,~~ President and Chief Executive Officer


	By	/s/ ~~Correne S. Loeffler~~James P. Henderson
		~~Correne S. Loeffler~~James P. Henderson
		Executive Vice President Finance and Chief Financial Officer


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

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	June 30, 2020
Debt subject to compromise	$	2,368,497
Accounts payable trade		48,434
Accrued liabilities and other		63,557
Accrued interest on debt subject to compromise		30,028
Asset retirement obligations ⁽¹⁾		39,022
Total liabilities subject to compromise	$	2,549,538


Asset retirement obligation at January 1, 2020	$	134,893
Additional liability incurred		58
Revisions to estimated cash flows		(1,243)
Accretion expense		6,107
Obligations on sold properties		(693)
Liabilities settled		(2,788)
Asset retirement obligations reclassified to liabilities subject to compromise ⁽¹⁾		(39,022)
Asset retirement obligation at June 30, 2020	$	97,312


		(Gain) Loss Recognized in Income
Not Designated as	Statements of Operations	Three Months Ended June 30,
ASC 815 Hedges	Classification	2020		2019
Commodity contracts	Derivative (gain) loss, net	$	6,632	$	(24,877)
Total		$	6,632	$	(24,877)


		June 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	$	3,714	$	(289)	$	3,425
Commodity contracts - non-current	Other long-term assets		77		(77)		-
Total derivative assets		$	3,791	$	(366)	$	3,425
Derivative liabilities
Commodity contracts - current	Accrued liabilities and other	$	1,730	$	(289)	$	1,441
Commodity contracts - non-current	Other long-term liabilities		943		(77)		866
Total derivative liabilities		$	2,673	$	(366)	$	2,307


		December 31, 2019 ⁽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	$	75,654	$	(74,768)	$	886
Commodity contracts - non-current	Other long-term assets		5,648		(5,648)		-
Total derivative assets		$	81,302	$	(80,416)	$	886
Derivative liabilities
Commodity contracts - current	Accrued liabilities and other	$	85,053	$	(74,768)	$	10,285
Commodity contracts - non-current	Other long-term liabilities		6,534		(5,648)		886
Total derivative liabilities		$	91,587	$	(80,416)	$	11,171


	June 30, 2020				December 31, 2019
	Fair		Carrying		Fair		Carrying
	Value ⁽¹⁾		Value ⁽²⁾		Value ⁽¹⁾		Value ⁽²⁾
1.25% Convertible Senior Notes due 2020	$	35,452	$	186,592	$	260,214	$	259,026
5.75% Senior Notes due 2021		148,920		773,609		732,995		772,080
6.25% Senior Notes due 2023		78,597		408,296		343,989		405,392
6.625% Senior Notes due 2026		192,500		1,000,000		681,250		988,387
Total	$	455,469	$	2,368,497	$	2,018,448	$	2,424,885


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