Chord Energy 10Q 2021 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2021

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

For the transition period from _______________ to _______________

Commission file number: 001-31899


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


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

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

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

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


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

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

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

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


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

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

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

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

Number of shares of the registrant’s common stock outstanding at November 1, 2021: 39,133,637 shares.

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GLOSSARY OF CERTAIN DEFINITIONS

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

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

“ASC” Accounting Standards Codification.

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

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

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

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

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

“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.

“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.

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

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“ISDA” International Swaps and Derivatives Association, Inc.

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

“LIBOR” London interbank offered rate.

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

“MBbl/d” One MBbl per day.

“MBOE” One thousand BOE.

“MBOE/d” One MBOE per day.

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

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

“MMBOE” One million BOE.

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

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

“MMcf/d” One MMcf per day.

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

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

“NGL” Natural gas liquid.

“NYMEX” The New York Mercantile Exchange.

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

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

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

“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.

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

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

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

Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid 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.

“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.

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“SEC” The United States Securities and Exchange Commission.

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

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

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

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

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PART I – FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements

WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (unaudited)

(in thousands, except share and per share data)


	Successor
	September 30,		December 31,
	2021		2020
ASSETS
Current assets:
Cash, cash equivalents and restricted cash	$	12,909	$	28,367
Accounts receivable trade, net		217,698		142,830
Prepaid expenses and other		14,325		19,224
Total current assets		244,932		190,421
Property and equipment:
Oil and gas properties, successful efforts method		2,166,379		1,812,601
Other property and equipment		45,671		74,064
Total property and equipment		2,212,050		1,886,665
Less accumulated depreciation, depletion and amortization		(203,628)		(73,869)
Total property and equipment, net		2,008,422		1,812,796
Other long-term assets		37,883		40,723
TOTAL ASSETS	$	2,291,237	$	2,043,940
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable trade	$	57,518	$	23,697
Revenues and royalties payable		193,474		151,196
Accrued capital expenditures		38,255		20,155
Accrued liabilities and other		35,572		42,007
Accrued lease operating expenses		22,730		23,457
Taxes payable		16,744		11,997
Derivative liabilities		299,602		49,485
Total current liabilities		663,895		321,994
Long-term debt		72,000		360,000
Asset retirement obligations		85,120		91,864
Operating lease obligations		15,550		17,415
Long-term derivative liabilities		83,355		9,750
Other long-term liabilities		2,159		14,113
Total liabilities		922,079		815,136
Commitments and contingencies
Equity:
Successor common stock, $0.001 par value, 500,000,000 shares authorized; 39,127,389 issued and outstanding as of September 30, 2021 and 38,051,125 issued and outstanding as of December 31, 2020		39		38
Additional paid-in capital		1,194,319		1,189,693
Accumulated earnings		174,800		39,073
Total equity		1,369,158		1,228,804
TOTAL LIABILITIES AND EQUITY	$	2,291,237	$	2,043,940

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

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WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)

(in thousands, except per share data)


	Successor				Predecessor
	Three Months Ended September 30, 2021		One Month Ended September 30, 2020		Two Months Ended August 31, 2020
OPERATING REVENUES
Oil, NGL and natural gas sales	$	394,333	$	61,084	$	122,558
Purchased gas sales		6,704		-		-
Total operating revenues		401,037		61,084		122,558
OPERATING EXPENSES
Lease operating expenses		56,562		18,526		32,646
Transportation, gathering, compression and other		8,835		1,980		4,259
Purchased gas expense		5,496		-		-
Production and ad valorem taxes		28,712		5,908		10,362
Depreciation, depletion and amortization		51,927		20,110		71,240
Exploration and impairment		3,446		4,207		10,217
General and administrative		11,961		10,345		16,513
Derivative (gain) loss, net		122,559		(30,594)		43,125
(Gain) loss on sale of properties		(90,194)		395		1,280
Amortization of deferred gain on sale		-		-		(1,171)
Total operating expenses		199,304		30,877		188,471
INCOME (LOSS) FROM OPERATIONS		201,733		30,207		(65,913)
OTHER INCOME (EXPENSE)
Interest expense		(3,871)		(2,128)		(11,379)
Other income		300		6		139
Reorganization items, net		-		-		259,232
Total other income (expense)		(3,571)		(2,122)		247,992
INCOME BEFORE INCOME TAXES		198,162		28,085		182,079
INCOME TAX EXPENSE (BENEFIT)
Current		-		2,316		-
Deferred		-		(14,501)		(55,346)
Total income tax benefit		-		(12,185)		(55,346)
NET INCOME	$	198,162	$	40,270	$	237,425
INCOME PER COMMON SHARE
Basic	$	5.07	$	1.06	$	2.60
Diluted	$	5.00	$	1.06	$	2.60
WEIGHTED AVERAGE SHARES OUTSTANDING
Basic		39,121		38,051		91,464
Diluted		39,622		38,051		91,464

						(Continued)

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WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)

(in thousands, except per share data)


	Successor				Predecessor
	Nine Months Ended September 30, 2021		One Month Ended September 30, 2020		Eight Months Ended August 31, 2020
OPERATING REVENUES
Oil, NGL and natural gas sales	$	1,048,995	$	61,084	$	459,004
Purchased gas sales		11,079		-		-
Total operating revenues		1,060,074		61,084		459,004
OPERATING EXPENSES
Lease operating expenses		180,083		18,526		158,228
Transportation, gathering, compression and other		23,306		1,980		22,266
Purchased gas expense		8,576		-		-
Production and ad valorem taxes		78,531		5,908		41,204
Depreciation, depletion and amortization		157,274		20,110		338,757
Exploration and impairment		8,115		4,207		4,184,830
General and administrative		34,247		10,345		91,816
Derivative (gain) loss, net		524,661		(30,594)		(181,614)
(Gain) loss on sale of properties		(100,304)		395		927
Amortization of deferred gain on sale		-		-		(5,116)
Total operating expenses		914,489		30,877		4,651,298
INCOME (LOSS) FROM OPERATIONS		145,585		30,207		(4,192,294)
OTHER INCOME (EXPENSE)
Interest expense		(12,955)		(2,128)		(73,054)
Gain on extinguishment of debt		-		-		25,883
Interest income and other		3,097		6		211
Reorganization items, net		-		-		217,419
Total other income (expense)		(9,858)		(2,122)		170,459
INCOME (LOSS) BEFORE INCOME TAXES		135,727		28,085		(4,021,835)
INCOME TAX EXPENSE (BENEFIT)
Current		-		2,316		2,718
Deferred		-		(14,501)		(59,092)
Total income tax benefit		-		(12,185)		(56,374)
NET INCOME (LOSS)	$	135,727	$	40,270	$	(3,965,461)
INCOME (LOSS) PER COMMON SHARE
Basic	$	3.48	$	1.06	$	(43.37)
Diluted	$	3.44	$	1.06	$	(43.37)
WEIGHTED AVERAGE SHARES OUTSTANDING
Basic		38,963		38,051		91,423
Diluted		39,479		38,051		91,423

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

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WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(in thousands)


	Successor				Predecessor
	Nine Months Ended September 30, 2021		One Month Ended September 30, 2020		Eight Months Ended August 31, 2020
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	135,727	$	40,270	$	(3,965,461)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		157,274		20,110		338,757
Deferred income tax benefit		-		(14,501)		(59,092)
Amortization of debt issuance costs, debt discount and debt premium		2,660		371		13,535
Stock-based compensation		7,508		-		4,188
Amortization of deferred gain on sale		-		-		(5,116)
(Gain) loss on sale of properties		(100,304)		395		927
Oil and gas property impairments		5,130		-		4,161,885
Gain on extinguishment of debt		-		-		(25,883)
Non-cash derivative (gain) loss		326,395		(29,563)		(136,131)
Non-cash reorganization items, net		-		-		(274,588)
Other, net		(6,103)		(438)		(223)
Changes in current assets and liabilities:
Accounts receivable trade, net		(73,198)		7,752		181,416
Prepaid expenses and other		4,351		1,133		(5,491)
Accounts payable trade and accrued liabilities		26,455		(18,163)		(46,734)
Revenues and royalties payable		35,452		1,261		(56,504)
Taxes payable		4,982		3,013		(12,872)
Net cash provided by operating activities		526,329		11,640		112,613
CASH FLOWS FROM INVESTING ACTIVITIES
Drilling and development capital expenditures		(151,394)		(9,040)		(238,456)
Acquisition of oil and gas properties		(272,043)		(162)		(493)
Other property and equipment		(3,539)		56		(1,072)
Proceeds from sale of properties		179,680		532		29,273
Net cash used in investing activities		(247,296)		(8,614)		(210,748)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under Credit Agreement		1,262,000		75,000		425,328
Repayments of borrowings under Credit Agreement		(1,550,000)		(100,000)		-
Borrowings under Predecessor Credit Agreement		-		-		1,185,000
Repayments of borrowings under Predecessor Credit Agreement		-		-		(1,402,259)
Repurchase of 1.25% Convertible Senior Notes due 2020		-		-		(52,890)
Debt issuance costs		-		-		(12,784)
Principal payments on finance lease obligations		(3,610)		(498)		(3,198)
Restricted stock used for tax withholdings		(2,881)		-		(307)
Net cash provided by (used in) financing activities	$	(294,491)	$	(25,498)	$	138,890

						(Continued)

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WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(in thousands)


	Successor				Predecessor
	Nine Months Ended September 30, 2021		One Month Ended September 30, 2020		Eight Months Ended August 31, 2020
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH	$	(15,458)	$	(22,472)	$	40,755
CASH, CASH EQUIVALENTS AND RESTRICTED CASH
Beginning of period		28,367		49,407		8,652
End of period	$	12,909	$	26,935	$	49,407
SUPPLEMENTAL CASH FLOW DISCLOSURES
Interest paid, net of amounts capitalized	$	8,739	$	301	$	80,220
Cash paid for reorganization items	$	396	$	14,353	$	33,238
NONCASH INVESTING ACTIVITIES
Accrued capital expenditures and accounts payable related to property additions	$	42,606	$	23,245	$	26,796
NONCASH FINANCING ACTIVITIES
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.						(Concluded)

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WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (unaudited)

(in thousands)


				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)
Net income	-		-		-		237,425		237,425
Restricted stock issued	9		-		-		-		-
Restricted stock used for tax withholdings	(4)		-		(4)		-		(4)
Stock-based compensation	-		-		787		-		787
Cancellation of Predecessor equity	(91,642)		(92)		(6,410,410)		6,350,573		(59,929)
BALANCES - August 31, 2020 (Predecessor)	-	$	-	$	-	$	-	$	-


Issuance of Successor equity	38,051	$	38	$	1,159,818	$	-	$	1,159,856
Issuance of Successor warrants	-		-		29,360		-		29,360
BALANCES - September 1, 2020 (Successor)	38,051		38		1,189,178		-		1,189,216
Net income	-		-		-		40,270		40,270
BALANCES - September 30, 2020 (Successor)	38,051	$	38	$	1,189,178	$	40,270	$	1,229,486


BALANCES - 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
Net income	-		-		-		198,162		198,162
Restricted stock issued	64		-		-		-		-
Restricted stock used for tax withholdings	(28)		-		(1,520)		-		(1,520)
Stock-based compensation	-		-		2,744		-		2,744
BALANCES - September 30, 2021 (Successor)	39,127	$	39	$	1,194,319	$	174,800	$	1,369,158

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

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WHITING PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. BASIS OF PRESENTATION

Description of Operations—Whiting Petroleum Corporation, a Delaware corporation, is an independent oil and gas company engaged in the development, production and acquisition of crude oil, NGLs and natural gas primarily in the Rocky Mountains region of the United States. Unless otherwise specified or the context otherwise requires, all references in these notes to “Whiting” or the “Company” are to Whiting Petroleum Corporation, together with its consolidated subsidiaries, Whiting Oil and Gas Corporation (“Whiting Oil and Gas” or “WOG”), Whiting US Holding Company, Whiting Canadian Holding Company ULC, Whiting Resources LLC (“WRC,” formerly Whiting Resources Corporation) and Whiting Programs, Inc. In September 2020, Whiting US Holding Company merged with and into WOG with WOG surviving, and WRC transferred all of its operating assets to WOG. In November 2020, WRC, over a series of steps, was amalgamated with Whiting Canadian Holding Company ULC and subsequently dissolved. When the context requires, the Company refers to these entities separately.

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

Upon emergence, the Company adopted fresh start accounting in accordance with FASB ASC Topic 852 – Reorganizations (“ASC 852”), which specifies the accounting and financial reporting requirements for entities reorganizing through chapter 11 bankruptcy proceedings. The application of fresh start accounting resulted in a new basis of accounting and the Company becoming a new entity for financial reporting purposes. As a result of the implementation of the Plan and the application of fresh start accounting, the consolidated financial statements after the Emergence Date are not comparable to the consolidated financial statements before that date and the historical financial statements on or before the Emergence Date are not a reliable indicator of the Company’s financial condition and results of operations for any period after its adoption of fresh start accounting. Refer to the “Fresh Start Accounting” footnote for more information. References to “Successor” refer to the Company and its financial position and results of operations after the Emergence Date. References to “Predecessor” refer to the Company and its financial position and results of operations on or before the Emergence Date. References to “Current Successor Quarter” and “Current Successor YTD Period” relate to the three and nine months ended September 30, 2021, respectively. References to “Prior Successor Period” relate to the period of September 1, 2020 through September 30, 2020. References to “Predecessor Period” and “Predecessor YTD Period” relate to the periods of July 1, 2020 through August 31, 2020 and January 1, 2020 through August 31, 2020, respectively. The Company previously evaluated the events between August 31, 2020 and September 1, 2020 and concluded that the use of an accounting convenience date of August 31, 2020 did not have a material impact on the Company’s financial position or results of operations.

During the 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, certain expenses, realized gains and losses and provisions for losses that were realized or incurred during the Chapter 11 Cases, including adjustments to the carrying value of certain indebtedness, were recorded as reorganization items, net in the condensed consolidated statements of operations for the Predecessor periods. Refer to the “Chapter 11 Emergence” footnote for more information on the events of the bankruptcy proceedings as well as the accounting and reporting impacts of the reorganization during the 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,

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operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. The condensed consolidated financial statements and related notes included in this Quarterly Report on Form 10-Q should be read in conjunction with Whiting’s consolidated financial statements and related notes included in the Company’s Annual Report on Form 10-K for the period ended December 31, 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 Annual Report on Form 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 income, 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 insurance limits as of September 30, 2021 and December 31, 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 its credit agreement. The Company has not experienced any losses on its deposits of cash and cash equivalents.

Restricted cash as of December 31, 2020 consisted of funds remaining in a professional fee escrow account that were reserved to pay certain professional fees upon emergence from the Chapter 11 Cases.

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


	Successor
	September 30,		December 31,
	2021		2020
Cash and cash equivalents	$	12,909	$	25,607
Restricted cash		-		2,760
Total cash, cash equivalents and restricted cash	$	12,909	$	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 September 30, 2021 and December 31, 2020 (Successor), the Company had immaterial allowances for credit losses.

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2. CHAPTER 11 EMERGENCE

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

On the Emergence Date and pursuant to the Plan:

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

(2)	The Company constituted a new Successor board of directors.

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

(4)	The Company issued:

●

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

●

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

●

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

●

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

The Company also reserved 3,070,201 shares of the Successor’s common stock for potential future distribution to certain general unsecured claimants whose claim values were pending resolution in the Bankruptcy Court. In February 2021, the Company issued 948,897 shares out of this reserve to a general unsecured claimant in full settlement of such claimant’s claims pending before the Bankruptcy Court and for rejection damages relating to an executory contract. Any remaining reserved shares that are not distributed to resolve pending claims will be cancelled. In addition, 4,035,885 shares 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 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 trade claims, administrative expense claims, other secured claims and other priority claims received payment in full in cash upon emergence or through the ordinary course of business after the Emergence Date.

Executory Contracts—Subject to certain exceptions, under the Bankruptcy Code the Debtors were entitled to assume, assign or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and fulfillment of certain other conditions. Generally, the rejection of an executory contract or unexpired lease was treated as a pre-petition breach of such contract and, subject to certain exceptions, relieved the Debtors from performing future obligations under such contract but entitled the counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Alternatively, the assumption of an executory contract or unexpired lease required the Debtors to cure existing monetary defaults under such executory contract or unexpired lease, if any. Accordingly, any description of an executory contract or unexpired lease with the Debtors in this document, including where applicable quantification of the Company’s obligations under such executory or unexpired lease of the Debtors, is qualified by any overriding rejection rights the Company has under the Bankruptcy Code unless an order settling the claims

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has been issued by the Bankruptcy Court. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the Debtors expressly reserve all of their rights in that regard. Refer to the “Commitments and Contingencies” footnote for more information on potential future rejection damages related to general unsecured claims.

Interest Expense—The Company discontinued recording interest on its senior notes between the Petition Date and the Emergence Date in accordance with ASC 852. The contractual interest expense not accrued in the condensed consolidated statements of operations was approximately $57 million for the period from the Petition Date through the Emergence Date.

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

3. FRESH START ACCOUNTING

Fresh Start—In connection with the Company’s emergence from bankruptcy and in accordance with ASC 852, the Company qualified for and adopted fresh start accounting on the Emergence Date. 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—Any expenses, gains and losses that were realized or incurred between the Petition Date and the Emergence Date and as a direct result of the Chapter 11 Cases were recorded in reorganization items, net in the Company’s condensed consolidated statements of operations. The following table summarizes the components of reorganization items, net for the periods presented (in thousands):


	Successor		Predecessor
	One Month Ended September 30, 2020		Two Months Ended August 31, 2020		Eight Months Ended August 31, 2020
Legal and professional advisory fees	$	-	$	30,502	$	57,170
Net gain on liabilities subject to compromise		-		(1,324,940)		(1,324,940)
Fresh start adjustments, net		-		1,025,742		1,025,742
Write-off of unamortized debt issuance costs and premium⁽¹⁾		-		-		15,145
Other items, net		-		9,464		9,464
Total reorganization items, net	$	-	$	(259,232)	$	(217,419)

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

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4. OIL AND GAS PROPERTIES

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


	Successor
	September 30,		December 31,
	2021		2020
Proved oil and gas properties	$	1,905,535	$	1,701,163
Unproved leasehold costs		197,525		105,073
Wells and facilities in progress		63,319		6,365
Total oil and gas properties, successful efforts method		2,166,379		1,812,601
Accumulated depletion		(198,604)		(71,064)
Oil and gas properties, net	$	1,967,775	$	1,741,537

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


	Successor				Predecessor
	Three Months Ended September 30, 2021		One Month Ended September 30, 2020		Two Months Ended August 31, 2020
Impairment expense for unproved properties	$	836	$	-	$	83


	Successor				Predecessor
	Nine Months Ended September 30, 2021		One Month Ended September 30, 2020		Eight Months Ended August 31, 2020
Impairment expense for unproved properties	$	2,487	$	-	$	12,566

Refer to the “Fair Value Measurements” footnote for more information on proved property impairments recorded during the Predecessor YTD Period.

5. ACQUISITIONS AND DIVESTITURES

2021 Acquisitions and Divestitures

On September 14, 2021, the Company completed the acquisition of interests in approximately 8,750 net acres in the Williston Basin, including interests in 76 gross (50.2 net) producing wells, 5 gross (2.4 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 post-closing adjustments). The transaction was funded primarily with borrowings under the Credit Agreement. The revenue and earnings from these properties since the acquisition date are included in our condensed consolidated financial statements for the three and nine months ended September 30, 2021 and are not material. Pro forma revenue and earnings for the acquired properties are not material to our condensed consolidated financial statements and have therefore not been presented.

The acquisition was accounted for as a business combination and was recorded using the acquisition method of accounting. The following table summarizes the preliminary allocation of the $271 million adjusted purchase price (which is still subject to post-closing adjustments) to the assets acquired and liabilities assumed in this acquisition based on their respective fair values at the acquisition date, which did not result in the recognition of goodwill or a bargain purchase gain. Refer to the “Fair Value Measurements” footnote for a detailed discussion of the fair value inputs used by the Company in determining the valuation of the significant assets acquired and liabilities assumed. As the purchase price is further adjusted for post-close adjustments and as the oil and gas property valuation is completed, the final purchase price allocation may result in a different allocation than what is presented in the table below (in thousands):

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Cash consideration	$	270,800

Fair value of assets acquired:
Prepaid expenses and other	$	730
Oil and gas properties, successful efforts method:
Proved oil and gas properties		167,435
Unproved leasehold costs		105,950
Total fair value of assets acquired		274,115

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

Total fair value of assets acquired and liabilities assumed	$	270,800

On September 23, 2021, the Company completed the sale of all of its interests in producing assets and undeveloped acreage, including the associated midstream assets, of its Redtail field located in the Denver-Julesburg Basin of Weld County, Colorado for aggregate net sales proceeds of $171 million (before post-closing adjustments). The sale was effective June 1, 2021 and resulted in a pre-tax gain on sale of $90 million. The Company used the net proceeds from the sale to repay a portion of the borrowings outstanding under the Credit Agreement. This transaction included the removal of approximately $20 million in asset retirement obligations as well as certain finance leases for a pipeline and vehicles, which resulted in the termination of approximately $16 million of finance lease right-of-use assets, $3 million of accumulated depreciation and $12 million of long-term finance lease obligations.

2020 Acquisitions and Divestitures

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

There were no significant acquisitions during the nine months ended September 30, 2020.

6. LONG-TERM DEBT

Long-term debt, consisting entirely of borrowings outstanding under the Credit Agreement, totaled $72 million and $360 million at September 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 September 30, 2021, the Credit Agreement had a borrowing base and aggregate commitments of $750 million. As of September 30, 2021, the Company had $676 million of available borrowing capacity under the Credit Agreement, which was net of $72 million of borrowings outstanding and $2 million in letters of credit outstanding. On September 15, 2021, the Company entered into an amendment to its existing Credit Agreement in connection with the October 1, 2021 regular borrowing base redetermination that (i) reaffirmed the $750 million borrowing base with such redetermination contemplating the closing of our recent divestiture described in the “Acquisitions and Divestitures” footnote, (ii) reduced the Company’s requirement to maintain commodity hedges covering its projected production for the succeeding twelve months from a minimum of 65% to a minimum of 50% and (iii) eliminated the Company’s requirement to maintain commodity hedges covering its projected production for the second succeeding twelve-month period, provided that the Company maintains a consolidated net leverage ratio of less than 1.0 to 1.0 as of the last day of any fiscal quarter (the “Compliance Date”). If the Company’s consolidated net leverage ratio equals or exceeds 1.0 to 1.0 at any Compliance Date, the Company will be required to hedge 35% of its projected production for the second succeeding twelve-month period.

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

Up to $50 million of the borrowing base may be used to issue letters of credit for the account of Whiting Oil and Gas or other designated subsidiaries of the Company. As of September 30, 2021, $48 million was available for additional letters of credit under the Credit Agreement.

The Credit Agreement provides for interest only payments until maturity on April 1, 2024, when the agreement terminates and all outstanding borrowings are due. In addition, the Credit Agreement provides for certain mandatory prepayments, including a provision pursuant to which, if the Company’s cash balances are in excess of approximately $75 million during any given week, such excess must be utilized to repay borrowings under the Credit Agreement. Interest under the Credit Agreement accrues at the Company’s option at either (i) a base rate for a base rate loan plus a margin between 1.75% and 2.75% based on the ratio of outstanding borrowings and letters of credit to the lower of the current borrowing base or total commitments, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.5% per annum, or an adjusted LIBOR plus 1.0% per annum, or (ii) an adjusted LIBOR for a eurodollar loan plus a margin between 2.75% and 3.75% based on the ratio of outstanding borrowings and letters of credit to the lower of the current borrowing base or total commitments. Additionally, the Company incurs commitment fees of 0.5% on the unused portion of the aggregate commitments of the lenders under the Credit Agreement, which are included as a component of interest expense. At September 30, 2021, the weighted average interest rate on the outstanding principal balance under the Credit Agreement was 3.8%.

The Credit Agreement contains restrictive covenants that may limit the Company’s ability to, among other things, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, enter into hedging contracts, incur liens and engage in certain other transactions without the prior consent of its lenders. The Credit Agreement also restricts the Company’s ability to make any dividend payments or distributions of cash on its common stock except to the extent that the Company has distributable free cash flow and (i) has at least 20% of available borrowing capacity, (ii) has a consolidated net leverage ratio of less than or equal to 2.0 to 1.0, (iii) does not have a borrowing base deficiency and (iv) is not in default under the Credit Agreement. These restrictions apply to all of the Company’s restricted subsidiaries and are calculated in accordance with definitions contained in the Credit Agreement. The amended Credit Agreement requires the Company, as of the last day of any quarter, to maintain commodity hedges covering a minimum of 50% of its projected production for the succeeding twelve months, as reflected in the reserves report most recently provided by the Company to the lenders under the Credit Agreement. If the Company’s consolidated net leverage ratio equals or exceeds 1.0 to 1.0 as of the last day of any fiscal quarter, the Company will also be required to hedge 35% of its projected production for the next succeeding twelve months. The Company is also limited to hedging a maximum of 85% of its production from proved reserves. The Credit Agreement requires the Company to maintain the following ratios: (i) a consolidated current assets to consolidated current liabilities ratio of not less than 1.0 to 1.0 and (ii) a total debt to last four quarters’ EBITDAX ratio of not greater than 3.5 to 1.0. As of September 30, 2021, the Company was in compliance with the covenants under the Credit Agreement.

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

Senior Notes and Convertible Senior Notes (Predecessor)

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

In March 2020, the Company paid $53 million to repurchase $73 million aggregate principal amount of the Convertible Senior Notes, which payment consisted of the average 72.5% purchase price plus all accrued and unpaid interest on the notes, which were allocated to the liability and equity components based on their relative fair values. The Company financed the repurchases with borrowings under

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the Predecessor Credit Agreement. As a result of these repurchases, the Company recognized a $23 million gain on extinguishment of debt during the Predecessor Period, which was net of a $0.2 million charge for the non-cash write-off of unamortized debt issuance costs and debt discount. In addition, the Company recorded a $3 million reduction to the equity component of the Convertible Senior Notes. There was no deferred tax impact associated with this reduction due to the full valuation allowance in effect as of March 31, 2020.

7. ASSET RETIREMENT OBLIGATIONS

The Company’s asset retirement obligations represent the present value of estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws and the terms of the Company’s lease agreements. The current portions as of September 30, 2021 and December 31, 2020 (Successor) were $7 million and $6 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 nine months ended September 30, 2021 (in thousands):


Asset retirement obligation at January 1, 2021 (Successor)	$	98,130
Additional liability incurred or assumed		3,402
Revisions to estimated cash flows		17,363
Accretion expense		6,241
Obligations on sold properties		(29,244)
Liabilities settled		(3,387)
Asset retirement obligation at September 30, 2021 (Successor)	$	92,505

8. DERIVATIVE FINANCIAL INSTRUMENTS

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

Commodity Derivative Contracts—Historically, prices received for crude oil, natural gas and natural gas liquids production have been volatile because of supply and demand factors, worldwide political factors, general economic conditions and seasonal weather patterns. Whiting primarily enters into derivative contracts such as crude oil, natural gas and natural gas liquids swaps, collars, basis swaps and differential swaps to achieve a more predictable cash flow by reducing its exposure to commodity price volatility, thereby ensuring adequate funding for the Company’s capital programs and facilitating the management of returns on drilling programs and acquisitions. The Company 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, Natural Gas Basis Swaps and Crude Oil Differential Swaps. Swaps establish a fixed price for anticipated future oil, gas or NGL production, while collars are designed to establish floor and ceiling prices on anticipated future oil or gas production. Natural gas basis swaps and crude oil differential swaps mitigate risk associated with anticipated future production by 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, it may also limit future income from favorable price movements.

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

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					Weighted Average
Settlement Period	Index	Derivative Instrument	Total Volumes	Units	Swap Price	Floor	Ceiling
Crude Oil
2021	NYMEX WTI	Fixed Price Swaps	2,162,000	Bbl	$44.90	-	-
2021	NYMEX WTI	Two-way Collars	1,150,000	Bbl	-	$42.48	$51.80
Q1 2022	NYMEX WTI	Fixed Price Swaps	630,000	Bbl	$54.30	-	-
2022	NYMEX WTI	Two-way Collars	9,559,000	Bbl	-	$43.23	$53.73
Q1-Q3 2023	NYMEX WTI	Two-way Collars	3,443,500	Bbl	-	$46.75	$58.87
		Total	16,944,500
Crude Oil Differentials ⁽¹⁾
2021	UHC Clearbrook to NYMEX	Fixed Price Swaps	30,500	Bbl	-$1.95	-	-
		Total	30,500
Natural Gas
2021	NYMEX Henry Hub	Fixed Price Swaps	5,290,000	MMBtu	$3.16	-	-
2021	NYMEX Henry Hub	Two-way Collars	2,760,000	MMBtu	-	$2.60	$2.79
Q1-Q3 2022	NYMEX Henry Hub	Fixed Price Swaps	5,259,000	MMBtu	$2.81	-	-
2022	NYMEX Henry Hub	Two-way Collars	17,304,000	MMBtu	-	$2.70	$3.32
Q1-Q3 2023	NYMEX Henry Hub	Two-way Collars	6,999,000	MMBtu	-	$2.42	$2.94
		Total	37,612,000
Natural Gas Basis ⁽²⁾
2021	NNG Ventura to NYMEX	Fixed Price Swaps	2,760,000	MMBtu	-$0.07	-	-
Q1-Q2 2022	NNG Ventura to NYMEX	Fixed Price Swaps	5,330,000	MMBtu	$0.43	-	-
Q1-Q2 2023	NNG Ventura to NYMEX	Fixed Price Swaps	4,740,000	MMBtu	$0.20	-	-
		Total	12,830,000
NGL - Propane
2021	Mont Belvieu	Fixed Price Swaps	9,660,000	Gallons	$0.78	-	-
2021	Conway	Fixed Price Swaps	7,728,000	Gallons	$1.31	-	-
Q1 2022	Mont Belvieu	Fixed Price Swaps	3,780,000	Gallons	$0.81	-	-
Q1 2022	Conway	Fixed Price Swaps	3,780,000	Gallons	$1.20	-	-
		Total	24,948,000

(1)

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.

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Subsequent to September 30, 2021, the Company entered into additional crude oil, natural gas, natural gas basis and propane swaps and collars for 2022. The table below details the Company’s additional swap and collar derivatives entered into during October 2021.


					Weighted Average
Settlement Period	Index	Derivative Instrument	Total Volumes	Units	Swap Price	Floor	Ceiling
Crude Oil
2022	NYMEX WTI	Fixed Price Swaps	1,645,000	Bbl	$75.12	-	-
2022	NYMEX WTI	Two-way Collars	1,645,000	Bbl	-	$69.43	$80.00
		Total	3,290,000
Natural Gas
Q2-Q4 2022	NYMEX Henry Hub	Fixed Price Swaps	2,750,000	MMBtu	$4.07	-	-
		Total	2,750,000
Natural Gas Basis
Q1 2022	NNG Ventura to NYMEX	Fixed Price Swaps	900,000	MMBtu	$1.00	-	-
		Total	900,000
NGL - Propane
2022	Mont Belvieu	Fixed Price Swaps	15,330,000	Gallons	$1.15	-	-
2022	Conway	Fixed Price Swaps	15,330,000	Gallons	$1.16	-	-
		Total	30,660,000

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.

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):

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		September 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	$	9,407	$	(9,407)	$	-
Commodity contracts - non-current	Other long-term assets		19,209		(19,209)		-
Total derivative assets		$	28,616	$	(28,616)	$	-
Derivative liabilities
Commodity contracts - current	Derivative liabilities	$	309,009	$	(9,407)	$	299,602
Commodity contracts - non-current	Long-term derivative liabilities		102,564		(19,209)		83,355
Total derivative liabilities		$	411,573	$	(28,616)	$	382,957


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

(1)

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

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

9. FAIR VALUE MEASUREMENTS

The Company follows ASC 820 which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

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

●

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

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

The Company’s derivative financial instruments are recorded at fair value and include a measure of the Company’s own nonperformance risk or that of its counterparty, as appropriate. The following tables present information about the Company’s financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2021 and December 31, 2020 (Successor), and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values (in thousands):


							Total Fair Value
	Level 1		Level 2		Level 3		September 30, 2021
Financial Liabilities
Commodity derivatives – current	$	-	$	299,602	$	-	$	299,602
Commodity derivatives – non-current		-		83,355		-		83,355
Total financial liabilities	$	-	$	382,957	$	-	$	382,957


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

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

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

Non-recurring Fair Value Measurements—Nonfinancial assets and liabilities, such as the initial measurement of oil and natural gas properties and asset retirement obligations upon acquisition or the impairment of proved properties, are recognized at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. The Company did not recognize any impairment write-downs with respect to its proved property during the Current 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 Predecessor YTD Period and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values (in thousands):

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

(1)

During the first quarter of 2020, certain proved oil and gas properties across the Company’s Williston Basin resource play with a previous carrying amount of $4.5 billion were written down to their fair value as of March 31, 2020 of $816 million, resulting in a non-cash impairment charge of $3.7 billion, which was recorded within exploration and impairment expense. These impaired properties were written down due to a reduction in anticipated future cash flows primarily driven by an expectation of sustained depressed oil prices and a resultant decline in future development plans for the properties as of March 31, 2020.


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

(2)

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

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

Williston Basin Acquisition. On September 14, 2021, the Company acquired interests in producing assets and undeveloped acreage in the Williston Basin, as further described in the “Acquisitions and Divestitures” footnote above. The assets acquired and liabilities assumed were recorded at their fair values as of September 14, 2021. The inputs utilized in the valuation of the oil and gas properties and related assets acquired included mostly unobservable inputs which fall within Level 3 of the fair value hierarchy. Such inputs included estimates of future oil and gas production from the properties’ reserve reports, commodity prices based on forward strip price curves (adjusted for basis differentials) as of September 14, 2021, operating and development costs, expected future development plans for the properties and a discount rate of 11% based on a weighted-average cost of capital. The Company also recorded the asset retirement obligations assumed at fair value. The inputs utilized in valuing the asset retirement obligations were mostly Level 3 unobservable inputs, including estimated economic lives of oil and natural gas wells as of September 14, 2021, anticipated future plugging and abandonment costs and an appropriate credit-adjusted risk-free rate to discount such costs.

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10. REVENUE RECOGNITION

The Company recognizes revenue in accordance with FASB ASC Topic 606 – Revenue from Contracts with Customers (“ASC 606”). Revenue is recognized at the point in time at which the Company’s performance obligations under its commodity sales contracts are satisfied and control of the commodity is transferred to the customer. The Company has determined that its contracts for the sale of crude oil, unprocessed natural gas, residue gas and NGLs contain monthly performance obligations to deliver product at locations specified in the contract. Control is transferred at the delivery location, at which point the performance obligation has been satisfied and revenue is recognized. Fees included in the contract that are incurred prior to control transfer are classified as transportation, gathering, compression and other, and fees incurred after control transfers are included as a reduction to the transaction price. The transaction price at which revenue is recognized consists entirely of variable consideration based on quoted market prices less various fees and the quantity of volumes delivered. Purchased gas sales revenue relates to the sale of natural gas from Whiting facilities that was not produced from the Company’s properties. The tables below present the disaggregation of revenue by product and transaction type for the periods presented (in thousands):


	Successor				Predecessor
OPERATING REVENUES	Three Months Ended September 30, 2021		One Month Ended September 30, 2020		Two Months Ended August 31, 2020
Oil sales	$	316,914	$	60,392	$	116,971
NGL and natural gas sales		77,419		692		5,587
Oil, NGL and natural gas sales		394,333		61,084		122,558
Purchased gas sales		6,704		-		-
Total operating revenues	$	401,037	$	61,084	$	122,558


	Successor				Predecessor
OPERATING REVENUES	Nine Months Ended September 30, 2021		One Month Ended September 30, 2020		Eight Months Ended August 31, 2020
Oil sales	$	882,040	$	60,392	$	440,820
NGL and natural gas sales		166,955		692		18,184
Oil, NGL and natural gas sales		1,048,995		61,084		459,004
Purchased gas sales		11,079		-		-
Total operating revenues	$	1,060,074	$	61,084	$	459,004

Whiting receives payment for product sales from one to three months after delivery. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in accounts receivable trade, net in the condensed consolidated balance sheets. As of September 30, 2021 and December 31, 2020 (Successor), such receivable balances were $139 million and $88 million, respectively. Variances between the Company’s estimated revenue and actual payments are recorded in the month the payment is received, but differences have been and are insignificant. Accordingly, the variable consideration is not constrained.

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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11. SHAREHOLDERS’ EQUITY

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

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

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

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

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

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

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

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

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

As discussed in the “Chapter 11 Emergence” footnote, an additional 2,121,304 shares of New Common Stock remain reserved as of September 30, 2021 for potential future distribution to certain general unsecured claimants whose claim values are pending resolution in the Bankruptcy Court.

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12. STOCK-BASED COMPENSATION

Equity Incentive Plan—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 2020 Equity Incentive Plan (the “2020 Equity Plan”), which replaced the Predecessor’s equity plan (the “Predecessor Equity Plan”). The 2020 Equity Plan provides the authority to issue 4,035,885 shares of the Successor’s common stock. Any shares forfeited under the 2020 Equity Plan will be available for future issuance under the 2020 Equity Plan. However, shares netted for tax withholding under the 2020 Equity Plan will be cancelled and will not be available for future issuance. Under the 2020 Equity Plan, during any calendar year no non-employee director participant may be granted awards having a grant date fair value in excess of $500,000. As of September 30, 2021, 3,031,871 shares of common stock remained available for grant under the 2020 Equity Plan.

Historically, the Company has granted service-based restricted stock awards (“RSAs”) and restricted stock units (“RSUs”) to executive officers and employees, which generally vest ratably over a two, three or five-year service period. The Company has granted service-based RSAs and RSUs to directors, which generally vest over a one-year service period. In addition, the Company has granted performance share awards (“PSAs”) and performance share units (“PSUs”) to executive officers that are subject to market-based vesting criteria, which generally vest over a three-year service period. 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 September and October 2020, 89,021 shares of service-based RSUs were granted to executive officers and directors under the 2020 Equity Plan. The Company determines compensation expense for these share-settled awards using their fair value at the grant date based on the closing bid price of the Company’s common stock on such date. The weighted average grant date fair value of these RSUs was $17.47 per share.

In September 2020, 189,900 shares of market-based RSUs were granted to executive officers under the 2020 Equity Plan. The awards 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% vested when the VWAP exceeded $32.57 per share, an additional 25% vested when the daily VWAP exceeded $48.86 per share and the final 25% will vest 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 was estimated to be between 1.8 and 3.8 years at the grant date. Upon vesting, any unrecognized compensation expense related to the shares is accelerated and recognized. The weighted average grant date fair value of these RSUs was $6.54 per share. More information on the inputs to the Monte Carlo Model are explained below. During the nine months ended September 30, 2021, the first 75% of these awards vested as the Company’s VWAP exceeded both $32.57 and $48.86 per share for 20 consecutive trading days during the period.

During the nine months ended September 30, 2021, 360,017 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 nine months ended September 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 nine months ended September 30, 2021, 23,730 shares of service-based RSUs were granted to directors under the 2020 Equity Plan, which vest over a one-year period. The Company determines compensation expense for these share-settled awards using their fair value at the grant date, which is based on the closing bid price of the Company’s common stock on such date. The weighted average grant date fair value of serviced-based RSUs was $23.82 per share for the nine months ended September 30, 2021.

During the nine months ended September 30, 2021, 232,150 shares of PSUs subject to certain market-based vesting criteria were granted to executive officers under the 2020 Equity Plan. These market-based awards vest at the end of the performance period, which is December 31, 2023, and the number of shares that vest at the end of the performance period is determined based on two performance goals: (i) 116,075 shares vest based on the Company’s annualized absolute total stockholder return (“ATSR”) over the performance period as compared to certain preestablished target returns and (ii) 116,075 shares vest based on the Company’s relative total stockholder return (“RTSR”) compared to the stockholder returns of a preestablished peer group of companies over the performance period. The

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number of awards earned could range from 0 up to 2 times the number of shares initially granted, all of which will be settled in shares. The weighted average grant date fair value of the market-based awards 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 nine months ended September 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	501,354	-	232,150		26.04
Vested	(53,787)	(142,425)	-		9.54
Forfeited	(8,411)	-	-		22.46
Nonvested awards, September 30	528,177	47,475	232,150	$	24.55

The Company recognized $3 million and $8 million in stock-based compensation expense during the three and nine months ended September 30, 2021, respectively.

Predecessor Awards

During the eight months ended August 31, 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 eight months ended August 31, 2020. On March 31, 2020, all of the RSAs issued to executive officers in 2020 were forfeited and concurrently replaced with cash incentives. Refer to “2020 Compensation Adjustments” below for more information.

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

During the eight months ended August 31, 2020, 1,665,153 shares of PSAs and PSUs subject to certain market-based vesting criteria were granted to executive officers under the Predecessor Equity Plan. These market-based awards were to cliff vest on the third anniversary of the grant date, however, on March 31, 2020, all of the PSAs and PSUs issued to executive officers in 2020 were forfeited and concurrently replaced with cash incentives. Refer to “2020 Compensation Adjustments” below for more information. The weighted average grant date fair value of the market-based awards that were to be settled in shares, as determined by the Monte Carlo valuation

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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 Predecessor Period and the Predecessor YTD Period, respectively.

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

13. INCOME TAXES

Income tax expense during interim periods is based on applying an estimated annual effective income tax rate to year-to-date income, plus any significant unusual or infrequently occurring items which are recorded in the interim period. The provisions for income taxes for the three and nine months ended September 30, 2021 (Successor) differ from the amounts that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax income primarily due to 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 periods presented and an effective U.S. tax rate of 0%.

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

During the Prior Successor Period, the Company partially executed a legal entity restructuring plan to reduce administrative expenses and burden with a simplified corporate structure. Several steps of the restructuring plan were executed during the Prior Successor Period, with the remaining steps completed in the fourth quarter of 2020, which ultimately resulted in Whiting Oil and Gas, under its parent Whiting Petroleum Corporation, holding all of the Company’s oil and gas operations. As a result of impacts from fresh start accounting, the Company reduced its deferred tax liability for its outside basis difference related to Whiting Canadian Holding Company ULC and recorded a tax benefit of $55 million during the Predecessor YTD Period. As a result of the restructuring, the Company reduced its deferred tax liability and recorded a tax benefit of $15 million during the Prior Successor Period.

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

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

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Internal Revenue Code (“IRC”) Section 382 addresses tax impacts of an ownership change and specifically limits the utilization of net operating loss carryforwards (“NOLs”) and certain other deductions for tax periods 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 change and resulting annual limitation on the Company’s NOL usage will result in the expiration of certain NOLs and other tax attributes otherwise available, with a corresponding decrease in the Company’s valuation allowance.

As of December 31, 2020, the Company had federal NOLs of $3 billion which are subject to limitation under IRC Section 382. Due to the annual IRC Section 382 limitation, certain other attribute reductions and the carryforward period of NOLs, approximately $2.4 billion of these federal NOLs will expire before they are able to be used. The remaining non-expiring NOLs are subject to a full valuation allowance as of September 30, 2021 and December 31, 2020.

14. EARNINGS PER SHARE

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


	Successor				Predecessor
	Three Months Ended September 30, 2021		One Month Ended September 30, 2020		Two Months Ended August 31, 2020
Basic earnings per share
Net income	$	198,162	$	40,270	$	237,425
Weighted average shares outstanding, basic		39,121		38,051		91,464
Earnings per common share, basic	$	5.07	$	1.06	$	2.60

Diluted earnings per share
Net income	$	198,162	$	40,270	$	237,425
Weighted average shares outstanding, basic		39,121		38,051		91,464
Service-based awards and market-based awards		501		-		-
Weighted average shares outstanding, diluted		39,622		38,051		91,464
Earnings per common share, diluted	$	5.00	$	1.06	$	2.60


	Successor				Predecessor
	Nine Months Ended September 30, 2021		One Month Ended September 30, 2020		Eight Months Ended August 31, 2020
Basic earnings (loss) per share
Net income (loss)	$	135,727	$	40,270	$	(3,965,461)
Weighted average shares outstanding, basic		38,963		38,051		91,423
Earnings (loss) per common share, basic	$	3.48	$	1.06	$	(43.37)

Diluted earnings (loss) per share
Net income (loss)	$	135,727	$	40,270	$	(3,965,461)
Weighted average shares outstanding, basic		38,963		38,051		91,423
Service-based awards and market-based awards		516		-		-
Weighted average shares outstanding, diluted		39,479		38,051		91,423
Earnings (loss) per common share, diluted	$	3.44	$	1.06	$	(43.37)

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Successor

During the Current Successor Quarter, Current Successor YTD Period and Prior Successor Period, the diluted earnings per share calculations exclude the effect of common shares that may be issued pursuant to the Series A Warrants and Series B Warrants, as such Warrants were out-of-the-money as of September 30, 2021 and September 30, 2020. During the Current Successor Quarter and Current Successor YTD Period, the diluted earnings per share calculations also exclude the effect of 47,475 shares of market-based awards that did not meet the market-based vesting criteria as of September 30, 2021 and 2,121,304 contingently issuable shares related to the settlement of general unsecured claims associated with the Chapter 11 Cases, as all necessary conditions had not been met to be considered dilutive shares as of September 30, 2021. During the Prior Successor Period, the diluted earnings per share calculation also excludes the effect of 189,900 shares of market-based awards that did not meet the market-based vesting criteria as of September 30, 2020, 87,171 shares of service-based awards that were anti-dilutive and 3,070,201 contingently issuable shares related to the settlement of general unsecured claims associated with the Chapter 11 Cases, as all necessary conditions had not been met to be considered dilutive shares as of September 30, 2020.

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

Predecessor

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

During the Predecessor YTD Period, the Company had a net loss and therefore the diluted earnings per share calculations excludes the anti-dilutive effect of 314,896 shares of service-based awards.

In addition, the diluted earnings per share calculations exclude the effect of 18,310 and 29,465 common shares for the Predecessor Period and the Predecessor YTD Period, respectively, for stock options that were out of the money as of August 31, 2020.

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

15. COMMITMENTS AND CONTINGENCIES

Chapter 11 Cases—On April 1, 2020, the Debtors filed the Chapter 11 Cases seeking relief under the Bankruptcy Code. The filing of the Chapter 11 Cases allowed the Company to, upon approval of the Bankruptcy Court, assume, assign or reject certain contractual commitments, including certain executory contracts. Refer to the “Chapter 11 Emergence” footnote for more information. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such contract and, subject to certain exceptions, relieves the Company from performing future obligations under such contract but entitles the counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. The claims resolution process is ongoing and certain of these claims remain subject to the jurisdiction of the Bankruptcy Court. To the extent that these Bankruptcy Court proceedings result in unsecured claims being allowed against the Company, such claims will be satisfied through the issuance of shares of the Successor’s common stock. As a result, the Company has not established material liabilities in connection with these claims.

However, it is reasonably possible that as a result of the legal proceedings associated with the 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.

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

Litigation—The Company is subject to litigation, claims and governmental and regulatory proceedings arising in the ordinary course of business. The Company accrues a loss contingency for these lawsuits and claims when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. While the outcome of these lawsuits and claims cannot be predicted with certainty, it is the opinion of the Company’s management that the loss for any litigation matters and claims that are reasonably possible to occur will not have a material adverse effect, individually or in the aggregate, on its consolidated financial position, cash flows or results of operations unless separately disclosed.

The Company was involved in litigation related to a payment arrangement with a third party. In June 2020, the Company and the third party reached a settlement agreement resulting in the Company paying the third party a settlement amount of $14 million. The Company recorded $3 million of additional litigation settlement expense in general and administrative expenses in the condensed consolidated statements of operations for the Predecessor YTD Period upon settling this litigation. Upon settlement, the Company agreed to indemnify a party involved in the litigation for any further claims resulting from these matters up to $25 million. This indemnity will terminate on the date on which the statute of limitations for the relevant claims expires. The Company does not expect to pay additional amounts to this party as a result of this indemnity and thus has not recorded any liability related to the indemnity as of September 30, 2021 (Successor).

16. COMPANY RESTRUCTURING

During September 2020, the Company executed a workforce reduction as part of an organizational redesign and cost reduction strategy to better align its business with the current operating environment and drive long-term value. The Company incurred one-time net charges related to this restructuring of $7 million in net restructuring costs associated with one-time employee termination benefits. These charges were recorded to general and administrative expenses during the Prior Successor Period in the condensed consolidated statement of operations.

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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 LLC (“WRC,” formerly Whiting Resources Corporation) and Whiting Programs, Inc. In September 2020, Whiting US Holding Company merged with and into WOG with WOG surviving, and WRC transferred all of its operating assets to WOG. In November 2020, WRC, over a series of steps, was amalgamated with Whiting Canadian Holding Company ULC and subsequently dissolved. When the context requires, we refer to these entities separately. This document contains forward-looking statements, which give our current expectations or forecasts of future events. Please refer to “Forward-Looking Statements” at the end of this Item for an explanation of these types of statements.

Overview

We are an independent oil and gas company engaged in development, production and acquisition activities primarily in the Rocky Mountains region of the United States where we are focused on developing our large resource play in the Williston Basin of North Dakota and Montana. We are currently focusing our capital programs on drilling and workover opportunities that we believe provide the greatest well-level returns in order to maintain consistent production levels and generate free cash flow, and we are selectively pursuing acquisitions that complement our existing core properties. During 2021, we are focused on high-return projects in our asset portfolio that will generate significant cash flow from operations. We continually evaluate our property portfolio and sell properties when we believe that the sales price realized will provide an above average rate of return for the property or when the property no longer matches the profile of properties we desire to own. Refer to “Recent Developments” below for more information on our recent acquisition and divestiture activity.

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

Our revenue, profitability, future growth rate and cash flows depend on many factors which are beyond our control, such as oil and gas prices; economic, political and regulatory developments; the financial condition of our industry partners; competition from other sources of energy; and the other items discussed under the caption “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the period ended December 31, 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 2019:


	2019								2020								2021
	Q1		Q2		Q3		Q4		Q1		Q2		Q3		Q4		Q1		Q2		Q3
Crude oil	$	54.90	$	59.83	$	56.45	$	56.96	$	46.08	$	27.85	$	40.94	$	42.67	$	57.80	$	66.06	$	70.55
Natural gas	$	3.00	$	2.58	$	2.29	$	2.44	$	1.88	$	1.66	$	1.89	$	2.51	$	2.56	$	2.74	$	3.95

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Oil prices improved during the first three quarters of 2021 compared to the lows experienced during 2020, when prices were depressed primarily due to the economic effects of the coronavirus pandemic on the demand for oil and natural gas and uncertainty around output restraints on oil production agreed upon by the Organization of Petroleum Exporting Countries (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 production levels to balance the market. Lower oil, NGL and natural gas prices decrease our revenues and reduce the amount of oil and natural gas that we can produce economically, which decreases our oil and gas reserve quantities. Substantial and extended declines in oil, NGL and natural gas prices have resulted, and may result, in impairments of our proved oil and gas properties or undeveloped acreage (such as the impairments discussed below under “Results of Operations”) and may materially and adversely affect our future business, financial condition, cash flows, results of operations, liquidity or ability to fund planned capital expenditures. In addition, lower commodity prices may result in a reduction of the borrowing base under our credit agreement, which is determined at the discretion of our lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders. Upon a redetermination, if borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of the debt outstanding under our credit agreement. Alternatively, higher oil prices may result in significant mark-to-market losses being incurred on our commodity-based derivatives (such as the net derivative losses discussed below under “Results of Operations”).

Recent Developments

Williston Basin Acquisition. On September 14, 2021, we completed the acquisition of approximately 8,750 net acres, including interests in 76 gross (50.2 net) producing wells, 5 gross (2.4 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 post-closing adjustments). This transaction was funded primarily with borrowings under our credit agreement.

Denver-Julesburg Basin Divestiture. On September 23, 2021, we completed the divestiture of all of our interests in producing assets 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 $171 million (before closing adjustments). The production from the divested properties (which was approximately 51% oil) represented approximately 8% of our average total production for the nine months ended September 30, 2021. We used the net proceeds from the sale to repay a portion of the borrowings outstanding under our credit agreement.

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

Beginning on the Emergence Date, we applied fresh start accounting, which resulted in a new basis of accounting and we became a new entity for financial reporting purposes. As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the consolidated financial statements after September 1, 2020 are not comparable with the consolidated financial statements on or prior to that date and the historical financial statements on or before the Emergence Date are not a reliable indicator of our financial condition and results of operations for any period after the adoption of fresh start accounting. References to “Successor” refer to Whiting and its financial position and results of operations after the Emergence Date. References to “Predecessor” refer to Whiting and its financial position and results of operations on or before the Emergence Date. References to “Current Successor YTD Period” relate to the nine months ended September 30, 2021. References to “Predecessor YTD Period” relate to the period of January 1, 2020 through August 31, 2020. References to “Prior Successor Period” relate to the period of September 1, 2020 through September 30, 2020. Although GAAP requires that we report on our results for the Prior Successor Period and Predecessor YTD Period separately, in certain circumstances management views our operating results for the nine months ended September 30, 2020 by combining the results of the applicable Predecessor and Successor periods in order to provide the most meaningful comparison of our current results to prior periods. Accordingly, references to “Combined Prior YTD Period” refer to the nine months ended September 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 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 confirmed Plan to a Tallgrass entity in February 2021.

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2021 Highlights and Future Considerations

Operational Highlights

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 North Dakota and Montana averaged 85.2 MBOE/d for the third quarter of 2021, which is consistent with the second quarter of 2021 and is in line with our production exit rate for the fourth quarter of 2020. Across our acreage in the Williston Basin, we have implemented custom, right-sized completion designs to increase well performance while reducing cost. We continue to focus on reducing time-on-location and total well cost while maximizing our lateral footage through drilling best practices including utilizing top tier drilling rigs, advanced downhole motor and drill bit technology and our custom drilling fluid system.

On September 14, 2021, we completed the acquisition of additional oil and gas properties in the Williston Basin for an aggregate purchase price of $271 million (before post-closing adjustments). Refer to “Recent Developments” above for additional details.

During the majority of the third quarter of 2021, we had one active completion crew in the Williston Basin, and we plan to continue with this crew intermittently for the remainder of 2021. In addition, we resumed drilling in the area in February with one rig and we added a second rig at the end of September. During the third quarter of 2021, we drilled 10 gross (5.6 net) wells and TIL 17 gross (9.1 net) wells in this area. As of September 30, 2021, we have 25 gross (14.3 net) drilled uncompleted wells, which includes 5 gross (2.4 net) uncompleted wells we acquired via the transaction discussed above. Under our current 2021 capital program, we expect to TIL approximately 55 gross (35.4 net) wells in this area during the year.

Colorado – Denver-Julesburg Basin

As detailed in “Recent Developments” above, on September 23, 2021, we completed the divestiture of all properties associated with our Redtail field, including the associated midstream assets. Net production from Colorado averaged 6.7 MBOE/d for the third quarter of 2021, representing a 6% decrease from the second quarter of 2021.

Other Non-Core Properties

Whiting USA Trust II. On December 31, 2021, the net profits interest (“NPI”) conveyed to Whiting USA Trust II (“Trust II”) on March 28, 2012 will terminate. Upon termination, the NPI in the underlying properties, which receives 90% of the net proceeds from the sale of oil and natural gas production from the underlying properties prior to its termination, will revert to Whiting. As of December 31, 2020, the NPI included interests in 1,301 gross (364.1 net) producing wells. The incremental production from the underlying properties that will revert to Whiting upon termination is approximately 2.1 MBOE/d based on the production during the third quarter of 2021. The asset retirement obligations of these properties were not conveyed to Trust II and have therefore been included in our consolidated financial statements for all periods presented. Additionally, the reserves disclosed in our Annual Report on Form 10-K for the period ending December 31, 2020 contemplated the reversion of the NPI on January 1, 2022.

Financing Highlights

On the Emergence Date, in connection with our emergence from the Chapter 11 Cases, we repaid all outstanding borrowings and accrued interest on the Predecessor’s credit agreement (the “Predecessor Credit Agreement”) and entered into a reserves-based credit agreement with a syndicate of banks (the “Credit Agreement”). In September 2021, the borrowing base under the Credit Agreement of $750 million was reaffirmed in connection with our semi-annual borrowing base redetermination. On September 15, 2021, we amended the Credit Agreement to reduce the amount of future production we are required to hedge. In accordance with the amendment, we are now only required to hedge 50% of our projected production for any succeeding twelve months, as compared to 65% prior to the amendment. Additionally, as long as we maintain a net leverage ratio of less than 1.0 to 1.0, we are no longer required to hedge any production for the next succeeding twelve months, compared to a 35% requirement prior to the amendment. Refer to the “Long-Term Debt” footnote in the notes to the condensed consolidated financial statements for more information.

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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 prepare an environmental impact statement (“EIS”). As a result, in an order issued July 6, 2020, the D.C. District Court vacated the easement and directed that the DAPL be shut down and emptied of oil by August 5, 2020. After 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 (“D.C. Appellate Court”), on January 26, 2021, affirmed the D.C. District Court’s decision to vacate the easement and concluded that the D.C. District Court must further consider whether shut down of the 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 and 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 new challenges are made and succeed following issuance of the EIS, which the Army Corps anticipates issuing in the fall of 2022. On September 20, 2021, the DAPL’s owner filed a petition with the U.S. Supreme Court seeking review of the lower courts’ decisions requiring a new EIS and permit. The U.S. Supreme Court has not yet decided whether to accept the case for review. The potential disruption of transportation as a result of the DAPL being shut down or the anticipation of the DAPL being shut down could negatively impact our ability to achieve the most favorable prices for our crude oil production, which could have an adverse effect on our business, financial condition, results of operations or cash flows. To help mitigate the potential impact of an unfavorable outcome, we have coordinated with our midstream partners and downstream markets to source transportation alternatives.

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Results of Operations

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

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


	Successor				Predecessor		Non-GAAP
	Nine Months Ended September 30, 2021		One Month Ended September 30, 2020		Eight Months Ended August 31, 2020		Combined Nine Months Ended September 30, 2020
Net production
Oil (MMBbl)		14.4		1.7		15.3		17.0
NGLs (MMBbl)		5.3		0.6		4.5		5.1
Natural gas (Bcf)		31.7		3.6		29.7		33.3
Total production (MMBOE)		25.0		2.9		24.7		27.7
Net sales (in millions)⁽¹⁾
Oil	$	882.0	$	60.4	$	440.8	$	501.2
NGLs		106.7		1.8		20.1		21.9
Natural gas		60.3		(1.1)		(1.9)		(3.0)
Total oil, NGL and natural gas sales	$	1,049.0	$	61.1	$	459.0	$	520.1
Average sales prices
Oil (per Bbl) ⁽¹⁾	$	61.06	$	34.58	$	28.86	$	29.45
Effect of oil hedges on average price (per Bbl)		(12.78)		0.28		3.00		2.72
Oil after the effect of hedging (per Bbl)	$	48.28	$	34.86	$	31.86	$	32.17
Weighted average NYMEX price (per Bbl) ⁽²⁾	$	64.78	$	39.63	$	38.23	$	38.37
NGLs (per Bbl) ⁽¹⁾	$	20.23	$	3.19	$	4.45	$	4.31
Effect of NGL hedges on average price (per Bbl)		(0.86)		-		-		-
NGLs after the effect of hedging (per Bbl)	$	19.37	$	3.19	$	4.45	$	4.31
Natural gas (per Mcf) ⁽¹⁾	$	1.90	$	(0.30)	$	(0.06)	$	(0.09)
Effect of natural gas hedges on average price (per Mcf)		(0.28)		0.15		(0.01)		0.01
Natural gas after the effect of hedging (per Mcf)	$	1.62	$	(0.15)	$	(0.07)	$	(0.08)
Weighted average NYMEX price (per MMBtu) ⁽²⁾	$	3.09	$	2.24	$	1.76	$	1.81
Costs and expenses (per BOE)
Lease operating expenses	$	7.21	$	6.37	$	6.40	$	6.39
Transportation, gathering, compression and other	$	0.93	$	0.68	$	0.90	$	0.88
Production and ad valorem taxes	$	3.14	$	2.03	$	1.67	$	1.70
Depreciation, depletion and amortization	$	6.29	$	6.91	$	13.69	$	12.98
General and administrative	$	1.37	$	3.55	$	3.71	$	3.69

(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 increased $529 million to $1 billion when comparing the Current Successor YTD Period to the Combined Prior 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). When comparing the Current Successor YTD Period to the Combined Prior YTD Period, increases in commodity prices realized between periods accounted for a $604 million increase in revenue, which was partially offset by a decrease in total production between periods that accounted for a $75 million decrease in revenue.

Our oil and gas volumes decreased by 15% and 5%, respectively, while our NGL volumes increased by 4% between periods. The volume decreases between periods were primarily driven by normal field production decline and reduced development activity in 2020 as a result of sustained lower prices and our bankruptcy filing which negatively impacted production during the Current Successor YTD Period. The decline in production resulting from lower activity was partially offset by production from new wells drilled and completed during the Current Successor YTD Period in the Williston Basin as well as higher NGL yields.

Our average price for oil, NGLs and natural gas (before the effects of hedging) increased 107%, 369% and 2,211%, respectively, between periods. Our average realized price for oil, NGLs and natural gas primarily increased as a result of favorable movements in the NYMEX, Mont Belvieu and Conway market indices between periods. Our oil average realized price differentials to NYMEX improved between periods as a result of decreased basin-wide utilization of pipeline capacity and lower firm transportation costs during the Current Successor YTD Period, 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 Current Successor YTD Period. During the Combined Prior YTD Period, our average sales price realized for NGLs and natural gas 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. These third-party costs sometimes exceeded the ultimate price we received for our natural gas and accordingly resulted in negative gas revenues during the Combined Prior YTD Period. While these negative gas prices adversely affected our total revenues, we continued to produce our wells in order to sell the associated oil and NGLs from these wells and to meet lease and regulatory requirements.

Lease Operating Expenses. Our lease operating expenses (“LOE”) during the Current Successor YTD Period were $180 million, a $3 million increase over the Combined Prior YTD Period. This increase was primarily due to a $9 million increase in well workover costs and a $5 million increase in the cost of oil field goods and services, partially offset by an $11 million decrease in saltwater disposal costs due to lower volumes between periods.

Our lease operating expenses on a BOE basis increased when comparing the Current Successor YTD Period to the Combined Prior YTD Period. LOE per BOE amounted to $7.21 during the Current Successor YTD Period, which represents an increase of $0.82 per BOE (or 13%) from the Combined Prior YTD Period. This increase was mainly due to lower overall production volumes between periods and the overall increase in LOE discussed above.

Transportation, Gathering, Compression and Other. Our transportation, gathering, compression and other (“TGC”) expenses during the Current Successor YTD Period were $23 million, a slight decrease over the Combined Prior YTD Period.

TGC per BOE, however, increased when comparing the Current Successor YTD Period to the Combined Prior YTD Period. TGC per BOE amounted to $0.93 per BOE, which represents an increase of $0.05 per BOE (or 6%) from the Combined Prior YTD Period. This increase was mainly due to the transportation of certain oil volumes to additional delivery points during the third quarter of 2021 as well as lower overall production volumes between periods. These impacts were partially offset by decreased rates negotiated with midstream partners as a result of the Chapter 11 Cases.

Production and Ad Valorem Taxes. Our production and ad valorem taxes during the Current Successor YTD Period were $79 million, a $31 million increase over the Combined Prior YTD Period, which was primarily due to higher sales revenue between periods. Our production taxes, however, are generally calculated as a percentage of net oil, NGL and natural gas sales revenue before the effects of hedging, and this percentage on a company-wide basis was 7.1% and 8.6% for the Current Successor YTD Period and the Combined Prior YTD Period, respectively. Our production tax rate for the Current Successor YTD Period was lower than the rate for the Combined Prior YTD Period as certain production taxes levied on unprocessed gas are volume-based and did not increase with the increase in realized prices. Additionally, we recognized Colorado severance tax refunds during the Current Successor YTD Period.

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


	Successor				Predecessor		Non-GAAP
	Nine Months Ended September 30, 2021		One Month Ended September 30, 2020		Eight Months Ended August 31, 2020		Combined Nine Months Ended September 30, 2020
Depletion	$	147,047	$	18,735	$	327,227	$	345,962
Accretion of asset retirement obligations		6,241		928		8,200		9,128
Depreciation		3,986		447		3,330		3,777
Total	$	157,274	$	20,110	$	338,757	$	358,867

DD&A decreased between the Current Successor YTD Period and the Predecessor YTD Period primarily due to $180 million in lower depletion expense related to a lower depletion rate between periods. On a BOE basis, our overall DD&A rate of $6.29 per BOE for the Current Successor YTD Period was 118% lower than the rate of $13.69 per BOE for the Predecessor YTD Period. The primary factors contributing to this lower DD&A rate were impairment write-downs on proved oil and gas properties in the Williston Basin recognized in the first and second quarters of 2020 and 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 Current Successor YTD Period were upward reserve revisions to proved reserves, which were largely driven by higher commodity prices during the period.

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


	Successor				Predecessor		Non-GAAP
	Nine Months Ended September 30, 2021		One Month Ended September 30, 2020		Eight Months Ended August 31, 2020		Combined Nine Months Ended September 30, 2020
Impairment	$	5,130	$	-	$	4,161,885	$	4,161,885
Exploration		2,985		4,207		22,945		27,152
Total	$	8,115	$	4,207	$	4,184,830	$	4,189,037

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

Exploration costs decreased $24 million during the Current Successor YTD Period compared to the Combined Prior YTD Period primarily due to $17 million of lower deficiency fees paid under our produced water disposal agreement at our Redtail field, which contract was rejected through the Chapter 11 Cases, and $3 million of lower geology-related general and administrative expenses due to a company restructuring in September 2020. Additionally, the Combined Prior YTD Period includes $4 million of costs related to write-offs of certain suspended well costs for wells we no longer intend to drill and early rig termination fees incurred during the period.

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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):


	Successor				Predecessor		Non-GAAP
	Nine Months Ended September 30, 2021		One Month Ended September 30, 2020		Eight Months Ended August 31, 2020		Combined Nine Months Ended September 30, 2020
General and administrative expenses, other⁽¹⁾	$	82,059	$	16,618	$	135,746	$	152,364
Stock-based compensation, non-cash		7,508		-		4,188		4,188
Reimbursements and allocations		(55,320)		(6,273)		(48,118)		(54,391)
General and administrative expenses, net (GAAP)		34,247		10,345		91,816		102,161
Less: Significant cost drivers ⁽²⁾		-		(9,333)		(32,888)		(42,221)
Non-GAAP general and administrative expenses less significant cost drivers⁽³⁾	$	34,247	$	1,012	$	58,928	$	59,940

(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 severance and restructuring charges, 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 expenses, other during the Current Successor YTD Period decreased $70 million compared to the Combined Prior YTD Period primarily due to $42 million of significant cost drivers incurred during the Combined Prior YTD Period, including (i) $22 million in cash retention incentives paid to Predecessor executives and directors, (ii) $10 million of third party advisory and legal fees related to the Chapter 11 Cases that were incurred prior to the Petition Date or after the Emergence Date, (iii) $7 million of severance and restructuring costs for a company restructuring completed in the third quarter of 2020 and (iv) $3 million of additional costs related to a legal settlement. In addition, compensation costs decreased by $21 million and corporate overhead costs decreased by $8 million as a result of the aforementioned company restructuring in the third quarter of 2020 and other cost reduction strategies implemented upon emergence from the Chapter 11 Cases, including the renegotiation of certain contracts.

G&A expense per BOE amounted to $1.37 during the Current Successor YTD Period, which represents a decrease of $2.32 per BOE (or 63%) from the Combined Prior YTD Period. This decrease was mainly due to the overall decrease in G&A discussed above partially offset by lower overall production volumes between periods. G&A expense per BOE excluding significant cost drivers was $2.17 per BOE during the Combined Prior 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 $525 million and a gain of $212 million for the Current Successor YTD Period and the Combined Prior YTD Period, respectively. These gains and losses relate to our collar, swap, basis swap and differential swap commodity derivative contracts and resulted from the upward and downward shifts, respectively, in the futures curve of forecasted commodity prices for crude oil, natural gas and NGLs during those periods.

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

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(Gain) Loss on Sale of Properties. During the Current Successor YTD Period, we sold all of our interests in the producing assets 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 $171 million (before post-closing adjustments), which resulted in a pre-tax gain on sale of $90 million. Refer to the “Acquisitions and Divestitures” footnote in the consolidated financial statements for more information on this transaction. Additionally, during the Current 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.

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


	Successor				Predecessor		Non-GAAP
	Nine Months Ended September 30, 2021		One Month Ended September 30, 2020		Eight Months Ended August 31, 2020		Combined Nine Months Ended September 30, 2020
Credit agreements	$	9,453	$	1,665	$	23,948	$	25,613
Amortization of debt issue costs, discounts and premiums		2,660		371		13,536		13,907
Other		842		92		730		822
Notes		-		-		34,840		34,840
Total	$	12,955	$	2,128	$	73,054	$	75,182

The decrease in interest expense of $60 million during the Current 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. Upon filing of the Chapter 11 Cases on April 1, 2020, we discontinued accruing interest on our notes, which resulted in a $35 million decrease in note interest expense between periods. In addition, the remaining unamortized debt issuance costs and premiums associated with these notes were written off on the Petition Date, resulting in an $11 million decrease in amortization expense between periods. Upon emergence from the Chapter 11 Cases, all outstanding obligations under our notes were cancelled in exchange for shares of Successor common stock. Refer to the “Chapter 11 Emergence” and “Long-Term Debt” footnotes in the notes to the condensed consolidated financial statements for more information.

The decrease in interest expense incurred on our credit agreements of $14 million during the Current Successor YTD Period compared to the Predecessor YTD Period resulted from lower borrowings outstanding between periods. Our weighted average borrowings outstanding under the Credit Agreement during the Current Successor YTD Period were $226 million compared to $761 million of weighted average borrowings outstanding under the Predecessor Credit Agreement during the Predecessor YTD Period.

Our weighted average debt outstanding during the Current Successor YTD Period, consisting solely of borrowings under the Credit Agreement, was $226 million, with a weighted average cash interest rate of 5.6%. Our weighted average debt outstanding during the Predecessor YTD Period, consisting of the notes and borrowings outstanding on the Predecessor Credit Agreement, was $3.2 billion, with a weighted average cash interest rate of 2.8%. The lower interest rate during the Predecessor YTD Period primarily relates to the discontinuation of interest on our Senior Notes beginning in April 2020 as a result of filing the Chapter 11 Cases.

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

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Reorganization Items, Net. During the Predecessor YTD Period, we recognized a net gain of $217 million related to the Chapter 11 Cases consisting of (i) gains on settlement of certain liabilities, including our Senior Notes, upon consummation of the Plan, (ii) fresh start accounting fair value adjustments, (iii) legal and professional advisory fees recognized between the Petition Date and the Emergence Date and (iv) the write-off of debt issuance costs and premiums associated with our Senior Notes. Refer to the “Chapter 11 Emergence” and “Fresh Start Accounting” footnotes 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 the full valuation allowance on our U.S. deferred tax assets (“DTAs”) as of September 30, 2021 (Successor), we did not recognize any U.S. income tax expense resulting in an overall U.S. effective tax rate of 0% for the Current Successor YTD Period.

During the Combined Prior YTD Period, we recorded a tax benefit of $68 million reflecting a reduction in the overall expected Canadian tax liability as a result of a legal entity restructuring we initiated during the period. Refer to the “Income Taxes” footnote in the notes to the condensed consolidated financial statements for more information on the legal restructuring and related Canadian deferred tax liability.

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

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

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Three Months Ended September 30, 2021 Compared to Three Months Ended June 30, 2021


	Successor
	Three Months Ended
	September 30,		June 30,
	2021		2021
Net production
Oil (MMBbl)		4.8		4.9
NGLs (MMBbl)		1.9		1.8
Natural gas (Bcf)		10.7		10.7
Total production (MMBOE)		8.5		8.4
Net sales (in millions) ⁽¹⁾
Oil	$	316.9	$	308.4
NGLs		51.4		28.3
Natural gas		26.0		13.3
Total oil, NGL and natural gas sales	$	394.3	$	350.0
Average sales prices
Oil (per Bbl) ⁽¹⁾	$	66.54	$	63.46
Effect of oil hedges on average price (per Bbl)		(16.57)		(13.64)
Oil after the effect of hedging (per Bbl)	$	49.97	$	49.82
Weighted average NYMEX price (per Bbl) ⁽²⁾	$	70.55	$	66.03
NGLs (per Bbl) ⁽¹⁾	$	26.81	$	15.76
Effect of NGL hedges on average price (per Bbl)		(1.93)		(0.47)
NGLs after the effect of hedging (per Bbl)	$	24.88	$	15.29
Natural gas (per Mcf) ⁽¹⁾	$	2.42	$	1.25
Effect of natural gas hedges on average price (per Mcf)		(0.82)		(0.04)
Natural gas after the effects of hedging (per Mcf)	$	1.60	$	1.21
Weighted average NYMEX price (per MMBtu) ⁽²⁾	$	3.95	$	2.74
Costs and expenses (per BOE)
Lease operating expenses	$	6.68	$	7.61
Transportation, gathering, compression and other	$	1.04	$	0.88
Production and ad valorem taxes	$	3.39	$	3.04
Depreciation, depletion and amortization	$	6.13	$	6.12
General and administrative	$	1.41	$	1.42

(1)	Before consideration of hedging transactions.

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

Oil, NGL and Natural Gas Sales. Our oil, NGL and natural gas sales revenue increased $44 million to $394 million when comparing the third quarter of 2021 to the second quarter of 2021. Changes in sales revenue between periods are due to changes in production sold and changes in average commodity prices realized (excluding the impacts of hedging). When comparing the third quarter of 2021 to the second quarter of 2021, increases in commodity prices realized between periods accounted for a $48 million increase in revenue, which was partially offset by a decrease in oil production between periods that accounted for a $4 million decrease in revenue.

Our NGL and natural gas volumes increased by 7% and 1%, respectively, while our oil volumes decreased by 2% between periods. The overall volume increase between periods was primarily driven by production from new wells drilled and completed during the first three quarters of 2021 in the Williston Basin and higher NGL yields, partially offset by normal field production decline.

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Our average price for oil, NGLs and natural gas (before the effects of hedging) increased 5%, 70% and 94%, respectively, between periods. Our average sales price realized for oil, NGLs and natural gas primarily increased as a result of favorable movements in the NYMEX, Mont Belvieu and Conway market indices between periods.

Lease Operating Expenses. Our LOE during the third quarter of 2021 were $57 million, an $8 million decrease over the second quarter of 2021. This decrease between periods was primarily due to $4 million of lower LOE from ongoing cost reduction initiatives, $2 million of lower saltwater disposal costs and a $2 million decrease in well workover activity between periods.

Our lease operating expenses on a BOE basis also decreased when comparing the third quarter of 2021 to the second quarter of 2021. LOE per BOE amounted to $6.68 during the third quarter of 2021, which represents a decrease of $0.93 per BOE (or 12%) from the second quarter of 2021. This decrease was mainly due to the overall decrease in LOE discussed above.

Transportation, Gathering, Compression and Other. Our TGC expenses during the third quarter of 2021 were $9 million, a slight increase over the second quarter of 2021. This increase was primarily due to expense associated with the transportation of certain oil volumes to additional delivery points during the third quarter of 2021.

TGC per BOE increased when comparing the third quarter of 2021 to the second quarter of 2021. TGC per BOE amounted to $1.04 per BOE during the third quarter of 2021, which represents an increase of $0.16 per BOE (or 18%) from the second quarter of 2021. This increase was mainly due to the overall increase in TGC expense discussed above.

Production and Ad Valorem Taxes. Our production and ad valorem taxes during the third quarter of 2021 totaled $29 million, a $3 million increase over the second quarter of 2021, which was primarily due to Colorado severance tax refunds recognized during the second quarter of 2021 and higher sales revenue between periods. Our production taxes, however, are generally calculated as a percentage of net oil, NGL and natural gas sales revenue before the effects of hedging, and this percentage on a company-wide basis was 7.0% and 6.9% for the third quarter of 2021 and the second quarter of 2021, respectively. Our production tax rates for these periods are lower than our historical average rates primarily due to certain production taxes levied on unprocessed gas, which are volume-based and have not increased with the increase in realized prices that occurred over the past six months.

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


	Successor
	Three Months Ended
	September 30,		June 30,
	2021		2021
Depletion	$	48,815	$	48,081
Accretion of asset retirement obligations		1,829		2,190
Depreciation		1,283		1,347
Total	$	51,927	$	51,618

DD&A expense was consistent between periods. On a BOE basis, our overall DD&A rate was $6.13 per BOE for the third quarter of 2021, which represents an increase of $0.01 per BOE from the second quarter of 2021.

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


	Successor
	Three Months Ended
	September 30,		June 30,
	2021		2021
Impairment	$	2,439	$	1,250
Exploration		1,007		797
Total	$	3,446	$	2,047

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


	Successor
	Three Months Ended
	September 30,		June 30,
	2021		2021
General and administrative expenses, other⁽¹⁾	$	27,962	$	27,197
Stock-based compensation, non-cash		2,744		2,455
Reimbursements and allocations		(18,745)		(17,657)
General and administrative expenses, net (GAAP)	$	11,961	$	11,995

(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 expenses were consistent between periods. G&A expense per BOE amounted to $1.41 per BOE during the third quarter of 2021, which represents a decrease of $0.01 per BOE (or 1%) from the second quarter of 2021.

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 losses of $123 million and $255 million for the three months ended September 30, 2021 and June 30, 2021, respectively. These losses relate to our collar, swap, differential swap and basis swap commodity derivative contracts and resulted from the upward shift in the futures curve of forecasted commodity prices for crude oil, 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 third quarter of 2021, we sold all of our interests in producing assets 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 $171 million (before post-closing adjustments), which resulted in a pre-tax gain on sale of $90 million. Refer to the “Acquisitions and Divestitures” footnote in the consolidated financial statements for more information on this transaction.

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


	Successor
	Three Months Ended
	September 30,		June 30,
	2021		2021
Credit agreement	$	2,541	$	2,974
Amortization of debt issue costs		887		887
Other		443		120
Total	$	3,871	$	3,981

Interest expense was slightly lower between periods due to a decrease in weighted average borrowings outstanding under our Credit Agreement.

Income Tax Benefit. As a result of the full valuation allowance on our DTAs as of September 30, 2021 and June 30, 2021 (Successor), no income tax expense or benefit was recognized during the second and third quarters of 2021. This resulted in overall effective tax rates of 0% for both periods.

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Liquidity and Capital Resources

Overview. At September 30, 2021, we had $13 million of unrestricted cash on hand, $72 million of long-term debt and $1.4 billion of shareholders’ equity, while at December 31, 2020, we had $26 million of unrestricted cash on hand, $360 million of long-term debt and $1.2 billion of equity. We expect that our liquidity going forward will be primarily derived from cash flows from operating activities, cash on hand and availability under the Credit Agreement and that these sources of liquidity will be sufficient to provide us the ability to fund our material cash requirements, as described below, as well as our operating and development activities and planned capital programs. We may need to fund acquisitions or other business opportunities that support our strategy through additional borrowings or the issuance of common stock or other forms of equity.

Cash Flows. During the Successor YTD Period, we generated $526 million of cash from operating activities, an increase of $402 million from the Combined Prior YTD Period. Cash provided by operating activities increased between periods primarily due to higher realized sales prices, as well as lower cash G&A, cash interest expense and exploration expenses. These positive factors were partially offset by an increase in cash settlements paid on our commodity derivative contracts and higher production taxes 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 Successor YTD Period, cash flows from operating activities and $180 million of proceeds from the sale of properties were used for the net repayment of $288 million of outstanding borrowings under the Credit Agreement, to fund the $271 million Williston Basin acquisition and for $151 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 October 31, 2021, we had crude oil derivative contracts (consisting of collars, swaps and differential swaps) covering the sale of 36,000 Bbl, 37,000 Bbl and 13,000 Bbl of oil per day for the remainder of 2021, the full year 2022 and the first three quarters of 2023, respectively. As of October 31, 2021, we had natural gas derivative contracts (consisting of collars, swaps and basis swaps) covering the sale of 118,000 MMBtu, 86,000 MMBtu and 43,000 MMBtu of natural gas per day through the remainder of 2021, the full year 2022 and the first three quarters of 2023, respectively. As of October 31, 2021, we had NGL derivative contracts (consisting of swaps) covering the sale of 189,000 gallons and 105,000 gallons of NGLs per day for the remainder of 2021 and the full year 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.

Our long-term material cash requirements from currently known obligations include repayment of outstanding borrowings and interest payment obligations under our Credit Agreement, settlements on our outstanding commodity derivative contracts, future obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, operating and finance lease obligations and contracts to transport a minimum volume of crude oil and natural gas within specified time frames. The following table summarizes our estimated material cash requirements for known obligations as of September 30, 2021. This table does not include repayments of outstanding borrowings on our Credit Agreement, or the associated interest payments, as the timing and amount of borrowings and repayments cannot be forecasted with certainty and are based on working capital requirements, commodity prices and acquisition and divestiture activity, among other factors. As of September 30, 2021, our outstanding borrowings under our Credit Agreement were $72 million, with a weighted average interest rate on the outstanding principal balance of 3.8%. Refer to “Credit Agreement” below as well as the “Long-Term Debt” footnote in the notes to the condensed consolidated financial statements for more information. This table also does not include amounts payable under obligations where we cannot forecast with certainty the amount and timing of such payments, including any amounts we may be obligated to pay under our derivative contracts, as such payments are dependent on commodity prices in effect at the time of settlement. Refer to the “Derivative Financial Instruments” footnote in the notes to the condensed consolidated financial statements for further information on these contracts and their fair values as of September 30, 2021, which fair values represent the cash settlement amount required to terminate such instruments based on forward price curves for commodities as of that date.

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	Payments due by period
		(in thousands)
			Less than 1						More than
Material Cash Requirements	Total		year		1-3 years		3-5 years		5 years
Asset retirement obligations ⁽¹⁾	$	92,505	$	7,384	$	40,344	$	15,342	$	29,435
Operating leases ⁽²⁾		21,574		2,322		6,542		4,325		8,385
Finance leases ⁽²⁾		2,482		1,529		953		-		-
Pipeline transportation agreements ⁽³⁾		1,432		1,432		-		-		-
Total	$	117,993	$	12,667	$	47,839	$	19,667	$	37,820

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

(2)

We have operating and finance leases for corporate and field offices, midstream facilities and automobiles. As a result of the Denver-Julesburg Basin divestiture described in “Recent Developments” above, certain finance leases for a pipeline and vehicles were terminated and reduced our material cash requirements from finance leases by approximately $13 million as compared to our obligations as of June 30, 2021. The obligations reported above represent our minimum financial commitments pursuant to the terms of the remaining contracts. Refer to the “Leases” footnote in the notes to the consolidated financial statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 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 Current Successor YTD Period and the Combined Prior YTD Period, we incurred accrual basis exploration and development (“E&D”) expenditures of $181 million and $189 million, respectively. Of these expenditures, 99% and 96%, respectively, were incurred in our large resource play in the Williston Basin of North Dakota and Montana, where we have focused our current development. Capital expenditures reported in the condensed consolidated statements of cash flows are calculated on a cash basis, which differs from the accrual basis used to calculate the incurred capital expenditures as detailed in the table below:


	Successor				Predecessor		Non-GAAP
	Nine Months Ended September 30, 2021		One Month Ended September 30, 2020		Eight Months Ended August 31, 2020		Combined Nine Months Ended September 30, 2020
Capital expenditures, accrual basis	$	181,006	$	3,489	$	185,363	$	188,852
Decrease (increase) in accrued capital expenditures and other noncash capital activity		(29,612)		5,551		53,093		58,644
Capital expenditures, cash basis	$	151,394	$	9,040	$	238,456	$	247,496

We continually evaluate our capital needs and compare them to our capital resources. Our 2021 E&D budget is a range of $240 million to $252 million, which we expect to fund with net cash provided by operating activities and cash on hand. Our level of E&D expenditures is largely discretionary, although a portion of our E&D expenditures are for non-operated properties where we have limited control over the timing and amount of such expenditures, and the amount of funds we devote to any particular activity may increase or decrease depending on commodity prices, cash flows, available opportunities and development results, among other factors. We believe that we have sufficient liquidity and capital resources to execute our development plan over the next 12 months. With our expected cash flow streams, commodity price hedging strategies, current liquidity levels (primarily consisting of availability under the Credit Agreement) and flexibility to modify future capital expenditure programs, we expect to fund all planned capital programs, comply with our debt covenants and meet other obligations that may arise from our oil and gas operations.

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Credit Agreement. Whiting Petroleum Corporation, as parent guarantor, and Whiting Oil and Gas, as borrower, are parties to the Credit Agreement, a reserves-based credit facility with a syndicate of banks. The Credit Agreement had a borrowing base and aggregate commitments of $750 million as of September 30, 2021. As of September 30, 2021, we had $676 million of available borrowing capacity under the Credit Agreement, which was net of $72 million of borrowings outstanding and $2 million in letters of credit outstanding. On September 15, 2021, we entered into an amendment to the Credit Agreement in connection with the October 1, 2021 regular borrowing base redetermination that (i) reaffirmed the $750 million borrowing base with such redetermination contemplating the closing of our recent divestiture described in the “Acquisitions and Divestitures” footnote, (ii) reduced our requirement to maintain commodity hedges covering our projected production for the succeeding twelve months from a minimum of 65% to a minimum of 50% and (iii) eliminated our requirement to maintain commodity hedges covering our projected production for the second succeeding twelve-month period, provided that we maintain a consolidated net leverage ratio of less than 1.0 to 1.0 as of the last day of any fiscal quarter (the “Compliance Date”). If our consolidated net leverage ratio equals or exceeds 1.0 to 1.0 at any Compliance Date, we will be required to hedge 35% of our projected production for the second succeeding twelve-month period.

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

Up to $50 million of the borrowing base may be used to issue letters of credit for the account of Whiting Oil and Gas or our other designated subsidiaries. As of September 30, 2021, $48 million was available for additional letters of credit under the Credit Agreement.

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

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

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

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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, 2020. No material updates were made to such critical accounting policies and estimates during the nine months ended September 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, cash flows, acquisitions and divestitures, returns, costs and capital expenditures, and plans and objectives of management for future operations, are forward-looking statements. When used in this report, words such as “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe” or “should” or the negative thereof or variations thereon or similar terminology are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements.

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

●

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

●

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

●

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

●

the impacts of hedging on our results of operations;

●

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

●

the geographic concentration of our operations;

●

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

●

adequacy of midstream and downstream transportation capacity and infrastructure;

●

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

●

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

●

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

●

lack of control over non-operated properties;

●

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

●

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

●

inaccuracies of our reserve estimates or our assumptions underlying them;

●

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

●

climate change issues;

●

litigation and other legal proceedings; and

●

other risks described under the caption “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the period ended December 31, 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 their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, NGLs and natural gas have been volatile, and these markets will likely continue to be volatile in the future.

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

Crude Oil, Natural Gas and NGL Collars, Swaps and Basis 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 September 30, 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 require us to pay the counterparty if the settlement price for the applicable calculation period is more than the fixed price. Our basis and differential swap contracts guarantee us a fixed price differential to NYMEX and the referenced index price, with settlement terms based on the difference between the floating market price differential and the fixed price differential.

The fair value of our oil derivative positions at September 30, 2021 was a net liability of $308 million. A hypothetical upward or downward shift of 10% per Bbl in the NYMEX forward curve for crude oil as of September 30, 2021 would cause an increase of $109 million or a decrease of $106 million, respectively, in this fair value liability. The fair value of our natural gas derivative positions was a net liability of $65 million. A hypothetical upward or downward shift of 10% per MMBtu in the NYMEX forward curve for natural gas as of September 30, 2021 would cause an increase of $8 million or a decrease of $23 million, respectively, in this fair value liability. The fair value of our NGL derivative positions was a net liability of $10 million. A hypothetical upward or downward shift of 10% per Bbl in the Mont Belvieu and Conway forward curves for propane as of September 30, 2021 would cause an increase or decrease, respectively, of $4 million in this fair value liability.

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 collars, (ii) upward price movements generally with respect to the fixed-price swaps and (iii) decreasing floating market differentials relative to NYMEX with respect to the basis swaps and differential swaps.

Interest Rate Risk

Market risk is estimated as the change in fair value resulting from a hypothetical 100 basis point change in the interest rate on the outstanding balance under the Credit Agreement. The Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance for a period up to one month. To the extent that the interest rate is fixed, interest rate changes affect the instrument’s fair market value but do not impact results of operations or cash flows. Conversely, for the portion of the Credit Agreement that has a floating interest rate, interest rate changes will not affect the fair market value but will impact future results of operations and cash flows. At September 30, 2021, our outstanding principal balance under the Credit Agreement was $72 million, and the weighted average interest rate on the outstanding principal balance was 3.8%. At September 30, 2021, the carrying amount approximated fair market value. Assuming a constant debt level of $72 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 $1 million over a 12-month time period.

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Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures. In accordance with Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), our management evaluated, with the participation of our Chief Executive Officer and our Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of September 30, 2021. Based upon their evaluation of these disclosure controls and procedures, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures were effective as of September 30, 2021 to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure.

Changes in internal control over financial reporting. There was no change in our internal control over financial reporting that occurred during the quarter ended September 30, 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, 2020. No material change to such risk factors has occurred during the nine months ended September 30, 2021.

Item 6. Exhibits

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

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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 September 1, 2020 (File No. 001-31899)].
(10.1)		First Amendment to Credit Agreement, dated as of June 7, 2021, among Whiting Oil and Gas Corporation as Borrower, its Parent Guarantor Whiting Petroleum Corporation, JPMorgan Chase Bank, N.A. as Administrative Agent and the lenders signatory thereto [Incorporated by reference to Exhibit 10.1 to Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q filed on August 4, 2021 (File No. 001-31899)].
(10.2)		Second Amendment and Waiver to Credit Agreement, dated as of September 15, 2021, among Whiting Oil and Gas Corporation as Borrower, its Parent Guarantor Whiting Petroleum Corporation, JPMorgan Chase Bank, N.A. as Administrative Agent and the lenders signatory thereto.
(31.1)		Certification by the President and Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
(31.2)		Certification by the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
(32.1)		Written Statement of the President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.
(32.2)		Written Statement of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
(99)		Order Confirming Joint Chapter 11 Plan of Reorganization of Whiting Petroleum Corporation [Incorporated by reference to Exhibit 99.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on August 17, 2020 (File No. 001-31899)].
(101)		The following materials from Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2021 are filed herewith, formatted in iXBRL (Inline Extensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Operations, (iii) the Condensed Consolidated Statements of Cash Flows, (iv) the Condensed Consolidated Statements of Equity 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 3^rd day of November, 2021.


		WHITING PETROLEUM CORPORATION


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


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


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

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