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, 2019~~March 31, 2020

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

For the transition period from _______________ to _______________

Commission file number: 001-31899


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


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

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

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

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

Common Stock, $0.001 par value

Preferred Stock Purchase Rights

WLL

N/A

New York Stock Exchange

(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 ☒

Number of shares of the registrant’s common stock outstanding at ~~October 30, 2019: 91,299,706~~May 1, 2020: 91,412,448 shares.

TABLE OF CONTENTS

Glossary of Certain Definitions		1
PART I – FINANCIAL INFORMATION
Item 1.	Condensed Consolidated Financial Statements (Unaudited)	45
	Condensed Consolidated Balance Sheets as of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018~~2019	45
	Condensed Consolidated Statements of Operations for the Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2020 and 2019 ~~and 2018~~	56
	Condensed Consolidated Statements of Cash Flows for the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2020 and 2019 ~~and 2018~~	67
	Condensed Consolidated Statements of Equity for the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2020 and 2019 ~~and 2018~~	89
	Notes to Condensed Consolidated Financial Statements	910
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	4339
Item 4.	Controls and Procedures	4540
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	4540
Item 1A.	Risk Factors	4540
Item 6.	Exhibits	4546

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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.

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

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

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

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

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

“costless collar” An option position where the proceeds from the sale of a call option at its inception fund the purchase of a put option at its inception. A collar can also contain an additional sold put option. Refer to “three-way collar” for more information.

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

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

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

~~“dry hole”~~ ~~A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.~~

~~“exploratory well”~~ ~~A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.~~

“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.~~

“ISDA” International Swaps and Derivatives Association, Inc.

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“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,

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

“LIBOR” London interbank offered rate.

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

“MBbl/d” One MBbl per day.

“MBOE” One thousand BOE.

“MBOE/d” One MBOE per day.

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

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

“MMBOE” One million BOE.

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

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

“MMcf/d” One MMcf per day.

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

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

“NGL” Natural gas liquid.

“NYMEX” The New York Mercantile Exchange.

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

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

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

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

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

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

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

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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.

“SEC” The United States Securities and Exchange Commission.

“three-way collar” A combination of options: a sold call, a purchased put and a sold put. The sold call establishes a maximum price (ceiling) to be received for the volumes under contract. The purchased put establishes a minimum price (floor), unless the market price

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

“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 ~~risks in connection therewith.~~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)


	September 30,		December 31,		March 31,		December 31,
	2019		2018		2020		2019
ASSETS
Current assets:
Cash and cash equivalents	$	-	$	13,607	$	566,273	$	8,652
Accounts receivable trade, net		294,422		294,468		245,909		308,249
Derivative assets		45,038		68,342		179,340		886
Prepaid expenses and other		15,854		22,009		35,801		13,196
Total current assets		355,314		398,426		1,027,323		330,983
Property and equipment:
Oil and gas properties, successful efforts method		12,717,762		12,195,659		6,023,766		12,812,007
Other property and equipment		176,705		134,212		179,019		178,689
Total property and equipment		12,894,467		12,329,871		6,202,785		12,990,696
Less accumulated depreciation, depletion and amortization		(5,528,511)		(5,003,509)		(2,760,812)		(5,735,239)
Total property and equipment, net		7,365,956		7,326,362		3,441,973		7,255,457
Other long-term assets		53,611		34,785		57,007		50,281
TOTAL ASSETS	$	7,774,881	$	7,759,573	$	4,526,303	$	7,636,721
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	256,018	$	-	$	3,423,352	$	-
Accounts payable trade		52,054		42,520		66,724		80,100
Revenues and royalties payable		200,174		228,284		192,381		202,010
Accrued capital expenditures		130,017		73,178		63,746		64,263
Accrued liabilities and other		65,048		69,013		52,211		74,722
Accrued lease operating expenses						33,284		38,262
Accrued interest		33,383		55,080		32,961		53,928
Accrued lease operating expenses		47,077		37,499
Taxes payable		22,742		31,357		13,764		26,844
Derivative liabilities						-		10,285
Total current liabilities		806,513		536,931		3,878,423		550,414
Long-term debt		2,605,023		2,792,321		-		2,799,885
Asset retirement obligations		132,381		131,544		132,633		131,208
Operating lease obligations		33,596		-		30,147		31,722
Deferred income taxes		-		1,373		69,847		73,593
Other long-term liabilities		27,411		27,088		20,550		24,928
Total liabilities		3,604,924		3,489,257		4,131,600		3,611,750
Commitments and contingencies
Equity:
Common stock, $0.001 par value, 225,000,000 shares authorized; 91,761,220 issued and 91,299,706 outstanding as of September 30, 2019 and 92,067,216 issued and 91,018,692 outstanding as of December 31, 2018		92		92
Common stock, $0.001 par value, 225,000,000 shares authorized; 91,636,883 issued and 91,412,448 outstanding as of March 31, 2020 and 91,743,571 issued and 91,326,469 outstanding as of December 31, 2019						92		92
Additional paid-in capital		6,407,490		6,414,170		6,408,294		6,409,991
Accumulated deficit		(2,237,625)		(2,143,946)		(6,013,683)		(2,385,112)
Total equity		4,169,957		4,270,316		394,703		4,024,971
TOTAL LIABILITIES AND EQUITY	$	7,774,881	$	7,759,573	$	4,526,303	$	7,636,721

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

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WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)

(in thousands, except per share data)


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2019		2018		2019		2018		2020		2019
OPERATING REVENUES
Oil, NGL and natural gas sales	$	375,891	$	566,695	$	1,191,644	$	1,608,181	$	244,846	$	389,489
OPERATING EXPENSES
Lease operating expenses		85,320		74,690		256,384		230,434		72,340		84,077
Transportation, gathering, compression and other		11,176		12,842		32,145		35,450		8,963		9,841
Production and ad valorem taxes		35,220		49,989		102,796		133,991		22,423		28,156
Depreciation, depletion and amortization		211,025		197,006		612,166		584,219		183,968		198,132
Exploration and impairment		10,890		12,479		44,045		41,552		3,753,457		19,749
General and administrative		29,890		31,901		97,437		94,982		47,167		34,974
Derivative (gain) loss, net		(30,597)		21,063		7,431		177,210		(231,371)		62,905
Loss on sale of properties		595		230		1,681		1,716
(Gain) loss on sale of properties										(864)		23
Amortization of deferred gain on sale		(2,266)		(2,870)		(6,963)		(8,699)		(2,037)		(2,371)
Total operating expenses		351,253		397,330		1,147,122		1,290,855		3,854,046		435,486
INCOME FROM OPERATIONS		24,638		169,365		44,522		317,326
LOSS FROM OPERATIONS										(3,609,200)		(45,997)
OTHER INCOME (EXPENSE)
Interest expense		(48,447)		(48,328)		(145,274)		(149,558)		(45,250)		(48,099)
Gain (loss) on extinguishment of debt		4,598		-		4,598		(31,968)
Interest income and other		144		363		1,102		2,732
Gain on extinguishment of debt										25,883		-
Interest income and other (expense)										(4)		316
Total other expense		(43,705)		(47,965)		(139,574)		(178,794)		(19,371)		(47,783)
INCOME (LOSS) BEFORE INCOME TAXES		(19,067)		121,400		(95,052)		138,532
LOSS BEFORE INCOME TAXES										(3,628,571)		(93,780)
INCOME TAX BENEFIT
Deferred income tax benefit		-		-		(1,373)		-
NET INCOME (LOSS)	$	(19,067)	$	121,400	$	(93,679)	$	138,532
Current										3,746		-
Deferred										(3,746)		(24,855)
Total income tax benefit										-		(24,855)
NET LOSS									$	(3,628,571)	$	(68,925)
INCOME (LOSS) PER COMMON SHARE
Basic	$	(0.21)	$	1.33	$	(1.03)	$	1.52	$	(39.70)	$	(0.76)
Diluted	$	(0.21)	$	1.32	$	(1.03)	$	1.51	$	(39.70)	$	(0.76)
WEIGHTED AVERAGE SHARES OUTSTANDING
Basic		91,299		90,967		91,274		90,934		91,390		91,235
Diluted		91,299		91,823		91,274		91,862		91,390		91,235

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

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WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(in thousands)


	Nine Months Ended September 30,				Three Months Ended March 31,
	2019		2018		2020		2019
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(93,679)	$	138,532
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net loss					$	(3,628,571)	$	(68,925)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		612,166		584,219		183,968		198,132
Deferred income tax benefit		(1,373)		-		(3,746)		(24,855)
Amortization of debt issuance costs, debt discount and debt premium		23,707		22,976		4,536		7,818
Stock-based compensation		5,086		10,243		2,068		4,651
Amortization of deferred gain on sale		(6,963)		(8,699)		(2,037)		(2,371)
Loss on sale of properties		1,681		1,716
(Gain) loss on sale of properties						(864)		23
Oil and gas property impairments		15,729		25,612		3,745,092		9,843
(Gain) loss on extinguishment of debt		(4,598)		31,968
Non-cash derivative loss		22,228		36,585
Payment for settlement of commodity derivative contract		-		(61,036)
Gain on extinguishment of debt						(25,883)		-
Non-cash derivative (gain) loss						(199,550)		64,435
Other, net		1,141		(102)		805		828
Changes in current assets and liabilities:
Accounts receivable trade, net		(4,076)		(32,919)		62,289		11,775
Prepaid expenses and other		4,998		3,418		(22,624)		2,178
Accounts payable trade and accrued liabilities		(18,397)		31,990		(55,561)		(19,011)
Revenues and royalties payable		(28,110)		12,810		(9,629)		(32,990)
Taxes payable		(8,615)		9,723		(13,080)		(3,022)
Net cash provided by operating activities		520,925		807,036		37,213		148,509
CASH FLOWS FROM INVESTING ACTIVITIES
Drilling and development capital expenditures		(624,707)		(579,746)		(146,299)		(188,848)
Acquisition of oil and gas properties		(5,955)		(140,427)		(350)		(823)
Other property and equipment		(7,525)		(543)		(985)		(6,095)
Proceeds from sale of properties		66,738		3,284		27,453		299
Net cash used in investing activities		(571,449)		(717,432)		(120,181)		(195,467)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under credit agreement		1,980,000		1,672,265		1,185,000		570,000
Repayments of borrowings under credit agreement		(1,615,000)		(1,622,265)		(490,000)		(530,000)
Redemption of 5.0% Senior Notes due 2019		-		(990,023)
Repurchase of 1.25% Convertible Senior Notes due 2020		(297,000)		-		(52,890)		-
Repurchase of 5.75% Senior Notes due 2021		(23,461)		-
Debt issuance costs		(36)		(10,709)
Restricted stock used for tax withholdings		(3,696)		(4,064)		(304)		(3,693)
Principal payments on finance lease obligations		(3,890)		-		(1,217)		(1,264)
Net cash provided by (used in) financing activities	$	36,917	$	(954,796)
Net cash provided by financing activities					$	640,589	$	35,043

				(Continued)				(Continued)

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WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(in thousands)


		Nine Months Ended September 30,					Three Months Ended March 31,
		2019		2018			2020		2019
NET CHANGE IN CASH AND CASH EQUIVALENTS		$	(13,607)	$	(865,192)		$	557,621	$	(11,915)
CASH AND CASH EQUIVALENTS
Beginning of period			13,607		879,379			8,652		13,607
End of period		$	-	$	14,187		$	566,273	$	1,692
NONCASH INVESTING ACTIVITIES
Accrued capital expenditures and accounts payable related to property additions		$	147,295	$	88,880		$	88,424	$	123,827

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

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WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (unaudited)

(in thousands)



				Additional									Additional
	Common Stock			Paid-in		Accumulated		Total		Common Stock			Paid-in		Accumulated		Total
	Shares	Amount		Capital		Deficit		Equity
BALANCES - January 1, 2018	92,095	$	92	$	6,405,490	$	(2,486,440)	$	3,919,142
Net income	-		-		-		15,012		15,012
Restricted stock issued	432		-		-		-		-
Restricted stock forfeited	(96)		-		-		-		-
Restricted stock used for tax withholdings	(105)		-		(3,104)		-		(3,104)
Stock-based compensation	-		-		4,563		-		4,563
BALANCES - March 31, 2018	92,326		92		6,406,949		(2,471,428)		3,935,613
Net income	-		-		-		2,120		2,120
Restricted stock issued	19		-		-		-		-
Restricted stock forfeited	(160)		-		-		-		-
Stock-based compensation	-		-		1,533		-		1,533
BALANCES - June 30, 2018	92,185		92		6,408,482		(2,469,308)		3,939,266
Net income	-		-		-		121,400		121,400
Restricted stock forfeited	(35)		-		-		-		-
Restricted stock used for tax withholdings	(20)		-		(960)		-		(960)
Stock-based compensation	-		-		4,147		-		4,147
BALANCES - September 30, 2018	92,130	$	92	$	6,411,669	$	(2,347,908)	$	4,063,853
										Shares	Amount		Capital		Deficit		Equity
BALANCES - January 1, 2019	92,067	$	92	$	6,414,170	$	(2,143,946)	$	4,270,316	92,067	$	92	$	6,414,170	$	(2,143,946)	$	4,270,316
Net loss	-		-		-		(68,925)		(68,925)	-		-		-		(68,925)		(68,925)
Restricted stock forfeited	(106)		-		-		-		-	(106)		-		-		-		-
Restricted stock used for tax withholdings	(130)		-		(3,693)		-		(3,693)	(130)		-		(3,693)		-		(3,693)
Stock-based compensation	-		-		4,651		-		4,651	-		-		4,651		-		4,651
BALANCES - March 31, 2019	91,831		92		6,415,128		(2,212,871)		4,202,349	91,831	$	92	$	6,415,128	$	(2,212,871)	$	4,202,349

BALANCES - January 1, 2020										91,744	$	92	$	6,409,991	$	(2,385,112)	$	4,024,971
Net loss	-		-		-		(5,687)		(5,687)	-		-		-		(3,628,571)		(3,628,571)
Restricted stock issued	63		-		-		-		-
Restricted stock forfeited	(3)		-		-		-		-
Stock-based compensation	-		-		3,965		-		3,965
BALANCES - June 30, 2019	91,891		92		6,419,093		(2,218,558)		4,200,627
Net loss	-		-		-		(19,067)		(19,067)
Adjustment to equity component of 2020 Convertible Senior Notes upon partial extinguishment	-		-		(8,070)		-		(8,070)
Adjustment to equity component of 2020 Convertible Senior Notes upon extinguishment										-		-		(3,461)		-		(3,461)
Restricted stock issued	45		-		-		-		-	185		-		-		-		-
Restricted stock forfeited	(175)		-		-		-		-	(238)		-		-		-		-
Restricted stock used for tax withholdings	-		-		(3)		-		(2)	(54)		-		(304)		-		(304)
Stock-based compensation	-		-		(3,530)		-		(3,531)	-		-		2,068		-		2,068
BALANCES - September 30, 2019	91,761	$	92	$	6,407,490	$	(2,237,625)	$	4,169,957
BALANCES - March 31, 2020										91,637	$	92	$	6,408,294	$	(6,013,683)	$	394,703

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, acquisition and exploration of crude oil, NGLs and natural gas primarily in the Rocky Mountains region of the United States. Unless otherwise specified or the context otherwise requires, all references in these notes to “Whiting” or the “Company” are to Whiting Petroleum Corporation and its consolidated subsidiaries, Whiting Oil and Gas Corporation (“Whiting Oil and Gas”), Whiting US Holding Company, Whiting Canadian Holding Company ULC, Whiting Resources Corporation and Whiting Programs, Inc.

Voluntary Reorganization under Chapter 11 of the Bankruptcy Code—On April 1, 2020 (the “Petition Date”), Whiting Petroleum Corporation, Whiting Oil and Gas, Whiting US Holding Company, Whiting Canadian Holding Company ULC and Whiting Resources Corporation (collectively, the “Debtors”) commenced voluntary cases (the “Chapter 11 Cases”) under chapter 11 of the Bankruptcy Code. The Debtors continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court, in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court. To ensure ordinary course operations, the Debtors have obtained approval from the Bankruptcy Court for certain “first day” motions, including motions to obtain customary relief intended to continue ordinary course operations after the Petition Date. In addition, the Debtors have received authority to use cash collateral of the lenders under Whiting Oil and Gas’ credit agreement (the “Credit Agreement”) on an interim basis.

The commencement of a voluntary proceeding in bankruptcy constitutes an immediate event of default under the Credit Agreement and the indentures governing the Company’s senior notes, resulting in the automatic and immediate acceleration of all of the Company’s debt outstanding. Accordingly, the Company has classified all of its outstanding debt as a current liability on its condensed consolidated balance sheet as of March 31, 2020.

On April 23, 2020, the Debtors entered into a restructuring support agreement (the “RSA”) with certain holders of the Company’s senior notes to support a restructuring in accordance with the terms set forth in the Company’s chapter 11 plan of reorganization (the “Plan”). The Plan and the related disclosure statement were each filed with the Bankruptcy Court on April 23, 2020. Below is a summary of the treatment that the stakeholders of the Company would receive under the Plan:

●	Holders of Credit Agreement Claims. The holders of obligations under the Credit Agreement would have such obligations refinanced or repaid in full in cash upon the Debtors’ emergence from chapter 11.

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

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

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

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

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

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As part of the Chapter 11 Cases, the Company submitted to the Bankruptcy Court a plan of reorganization. The Company’s operations and its ability to develop and execute its business plan are subject to a high degree of risk and uncertainty associated with the Chapter 11 Cases. The outcome of the Chapter 11 Cases is subject to a high degree of uncertainty and is dependent upon factors that are outside of the Company’s control, including actions of the Bankruptcy Court and the Company’s creditors. There can be no assurance that the Company will confirm and consummate the Plan as contemplated by the RSA or complete another plan of reorganization with respect to the Chapter 11 Cases. As a result, the Company has concluded that management’s plans do not alleviate substantial doubt about the Company’s ability to continue as a going concern.

The condensed consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts or the amounts and classification of liabilities that might result from the outcome of this uncertainty.

Condensed Consolidated Financial Statements—The unaudited condensed consolidated financial statements include the accounts of Whiting Petroleum Corporation and its consolidated subsidiaries. Investments in entities which give Whiting significant influence, but not control, over the investee are accounted for using the equity method. Under the equity method, investments are stated at cost plus the Company’s equity in undistributed earnings and losses. All intercompany balances and transactions have been eliminated upon consolidation. These financial statements have been prepared in accordance with GAAP and the SEC rules and regulations for interim financial reporting. In the opinion of management, the accompanying financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim results. However, operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. The condensed consolidated financial statements and related notes included in this Quarterly Report on Form 10-Q should be read in conjunction with Whiting’s consolidated financial statements and related notes included in the Company’s Annual Report on Form 10-K for the period ended December 31, ~~2018.~~2019. 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 ~~2018~~2019 Annual Report on Form 10-K.

Reclassifications—Certain prior period balances in the condensed consolidated balance sheets have been combined pursuant to Rule 10-01(a)(2) of Regulation S-X of the SEC. Additionally, certain prior period balances in the condensed consolidated statements of operations have been reclassified to conform to the current year presentation. These include the reclassification of transportation, gathering, compression and other expenses and ad valorem taxes from previously reported lease operating expenses in the condensed consolidated statements of operations. For all periods presented, transportation, gathering, compression and other expenses are presented as a separate caption and ad valorem taxes are combined with production taxes. Such reclassifications had no impact on net ~~income,~~loss, cash flows or shareholders’ equity previously reported.

~~Adopted~~Cash and ~~Recently Issued Accounting Pronouncements~~Cash Equivalents—~~In February 2016,~~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 ~~FASB issued Accounting Standards Update No. 2016-02,~~ ~~Leases~~ ~~(“ASU 2016-02”~~Company to a concentration of credit risk as substantially all of its deposits held in financial institutions were in excess of the Federal Deposit Insurance Corporation (“FDIC”). insurance limits as of March 31, 2020 and December 31, 2019. The ~~objective~~Company maintains its cash and cash equivalents in the form of ~~this ASU~~money market and checking accounts with financial institutions that are also lenders under the Credit Agreement. The Company has not experienced any losses on its deposits of cash and cash equivalents.

Accounts Receivable Trade—Whiting’s accounts receivable trade consist mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates. The Company’s collection risk is ~~to increase transparency and comparability among organizations by recognizing lease assets and liabilities~~inherently low based on the ~~balance sheet~~viability of its oil and ~~disclosing key information about leasing arrangements.~~gas purchasers as well as its general ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. The ~~FASB subsequently issued various ASUs~~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 ~~provided additional implementation guidance,~~may include an assessment of the probability of non-payment, financial distress or expected future commodity prices. At March 31, 2020 and ~~these ASUs collectively make up~~December 31, 2019, the Company had an allowance for credit losses of $12 million and $9 million, respectively.

Reorganization Accounting—Effective April 1, 2020, as a result of the filing of the Chapter 11 Cases, the Company began accounting and reporting according to FASB ASC Topic ~~842~~852 – ~~Leases~~ Reorganizations~~(“ASC 842”). ASC 842 is effective~~, which specifies the accounting and financial reporting requirements for ~~fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. The standard permits retrospective application~~entities reorganizing through ~~recognition of a cumulative-effect adjustment at~~chapter 11 bankruptcy proceedings. These requirements include distinguishing transactions associated with the ~~beginning of either~~reorganization separate from activities related to the ~~earliest reporting period presented or the period of adoption. The Company adopted ASC 842 effective January 1, 2019 using the modified retrospective method as~~ongoing operations of the adoption date. Whiting has completed the assessment of its existing accounting policies and documentation, implementation of lease accounting software and enhancement of its internal controls. Adoption of the standard resulted in the recognition of additional lease assets and liabilities on Whiting’s consolidated balance sheet as well as additional disclosures. The adoption did not have a material impact to the Company’s consolidated statement of operations. Refer to the “Leases” footnote for further information on the Company’s implementation of this standard.business.

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2. OIL AND GAS PROPERTIES

Net capitalized costs related to the Company’s oil and gas producing activities at ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018~~2019 are as follows (in thousands):



	September 30,		December 31,		March 31,		December 31,
	2019		2018		2020		2019
Costs of completed wells and facilities	$	9,687,669	$	9,182,384	$	5,372,157	$	9,847,159
Proved leasehold costs		2,704,913		2,729,593		421,666		2,702,236
Wells and facilities in progress		219,340		160,995		139,231		159,334
Unproved leasehold costs		105,840		122,687		90,712		103,278
Total oil and gas properties, successful efforts method		12,717,762		12,195,659		6,023,766		12,812,007
Accumulated depletion		(5,449,887)		(4,937,579)		(2,681,635)		(5,656,929)
Oil and gas properties, net	$	7,267,875	$	7,258,080	$	3,342,131	$	7,155,078

Impairment expense for unproved properties totaled $12 million and $3 million for the three months ended March 31, 2020 and 2019, respectively, and is reported in exploration and impairment expense in the condensed consolidated statement of operations.

3. ACQUISITIONS AND DIVESTITURES

2020 Acquisitions and Divestitures

On January 9, 2020, the Company 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 three months ended March 31, 2020.

2019 Acquisitions and Divestitures

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

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

There were no significant acquisitions during the ~~nine~~three months ended ~~September 30,~~March 31, 2019.

~~2018 Acquisitions and Divestitures~~

On July 31, 2018, the Company completed the acquisition of certain oil and gas properties located in Richland County, Montana and McKenzie County, North Dakota for an aggregate purchase price of $130 million (before closing adjustments). The properties consist of approximately 54,800 net acres in the Williston Basin, including interests in 117 producing oil and gas wells and undeveloped acreage. The revenue and earnings from these properties since the acquisition date are included in the Company’s consolidated financial statements and are not material for the year ended December 31, 2018. Pro forma revenue and earnings for the acquired properties are not material to the Company’s condensed consolidated financial statements and have not been presented accordingly.

The acquisition was recorded using the acquisition method of accounting. The following table summarizes the allocation of the $123 million adjusted purchase price to the tangible assets acquired and liabilities assumed in this acquisition based on their relative fair values at the acquisition date, which did not result in the recognition of goodwill or a bargain purchase gain (in thousands):

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Cash consideration

$
122,861

Fair value of assets acquired:

Accounts receivable trade, net

$
30
Prepaid expenses and other

43
Oil and gas properties, successful efforts method:

Proved oil and gas properties

106,860
Unproved oil and gas properties

21,769
Total fair value of assets acquired

128,702

Fair value of liabilities assumed:

Revenue and royalties payable

3,309
Asset retirement obligations

2,532
Total fair value of liabilities assumed

5,841

Total fair value of assets and liabilities acquired

$
122,861

~~There were no significant divestitures during the nine months ended September 30, 2018.~~

~~4. LEASES~~

~~The Company adopted ASC 842 effective January 1, 2019, which replaces previous lease accounting requirements under FASB ASC Topic 840 –~~ ~~Leases~~ (“ASC 840”). The standard was adopted using the modified retrospective approach which resulted in the recognition of approximately $30 million and $36 million of additional lease assets and liabilities, respectively, on the consolidated balance sheet upon adoption. The Company has elected certain practical expedients available under ASC 842 including those that permit the Company to not (i) reassess prior conclusions reached under ASC 840 for lease identification, lease classification and initial direct costs, (ii) evaluate existing or expired land easements under the new standard and (iii) separate lease and non-lease components contained within a single agreement for all classes of underlying assets. Accordingly, the adoption of the standard did not result in the Company recognizing a cumulative-effect adjustment to retained earnings. Additionally, the Company has elected the short-term lease recognition exemption for all classes of underlying assets, and therefore, leases with a term of one year or less will not be recognized on the consolidated balance sheets.

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

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~~Supplemental balance sheet information for the Company’s leases as of September 30, 2019 consisted of the following (in thousands):~~

Leases

Balance Sheet Classification

September 30, 2019

Operating Leases

Operating lease ROU assets

Other long-term assets

$
37,018
Accumulated depreciation

Other long-term assets

(8,060)
Operating lease ROU assets, net

$
28,958

Short-term operating lease obligations

Accrued liabilities and other

$
8,093
Long-term operating lease obligations

Operating lease obligations

33,596
Total operating lease obligations

$
41,689

Finance Leases

Finance lease ROU assets

Other property and equipment

$
35,227
Accumulated depreciation

Accumulated depreciation, depletion and amortization

(15,388)
Finance lease ROU assets, net

$
19,839

Short-term finance lease obligations

Accrued liabilities and other

$
5,200
Long-term finance lease obligations

Other long-term liabilities

17,060
Total finance lease obligations

$
22,260

The Company’s leases have terms of less than one year to 11 years. Most of the Company’s leases do not state or imply a discount rate. Accordingly, the Company uses its incremental borrowing rate based on information available at lease commencement to determine the present value of the lease payments. Information regarding the Company’s lease terms and discount rates as of September 30, 2019 is as follows:



~~Weighted Average Remaining Lease Term~~
~~Operating leases~~					~~8 years~~
~~Finance leases~~					~~5 years~~

~~Weighted Average Discount Rate~~
~~Operating leases~~					~~4.6%~~
~~Finance leases~~					~~8.8%~~

Operating lease cost is recognized on a straight-line basis over the lease term. Finance lease cost is recognized based on the effective interest method for the lease liability and straight-line amortization of the ROU asset, resulting in more cost being recognized in earlier lease periods. All payments for short-term leases, including leases with a term of one month or less, are recognized in income or capitalized to the cost of oil and gas properties on a straight-line basis over the lease term. Additionally, any variable payments, which are generally related to the corresponding utilization of the asset, are recognized in the period in which the obligation was incurred. Lease cost for the three and nine months ended September 30, 2019 consisted of the following (in thousands):

Three Months Ended

Nine Months Ended

September 30, 2019

September 30, 2019
Operating lease cost

$
3,375

$
9,128

Finance lease cost:

Amortization of ROU assets

$
1,470

$
4,248
Interest on lease liabilities

498

1,522
Total finance lease cost

$
1,968

$
5,770

Short-term lease payments

$
182,455

$
527,518
Variable lease payments

$
11,437

$
22,212

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

~~Supplemental cash flow information related to leases for the three and nine months ended September 30, 2019 consisted of the following (in thousands):~~

Three Months Ended

Nine Months Ended

September 30, 2019

September 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:

Operating cash flows from operating leases

$
3,528

$
8,943
Operating cash flows from finance leases

$
517

$
1,538
Financing cash flows from finance leases

$
1,368

$
3,890

ROU assets obtained in exchange for new operating lease obligations

$
18,647

$
18,658
ROU assets obtained in exchange for new finance lease obligations

$
1,635

$
2,971

~~The Company’s lease obligations as of September 30, 2019 will mature as follows (in thousands):~~

Year ending December 31,

Operating Leases

Finance Leases
2019

$
3,038

$
1,788
2020

8,900

6,750
2021

6,670

5,520
2022

5,268

4,428
2023

4,600

3,563
Remaining

21,286

5,765
Total lease payments

$
49,762

$
27,814
Less imputed interest

(8,073)

(5,554)
Total discounted lease payments

$
41,689

$
22,260

As of September 30, 2019, the Company had a contract for an additional corporate office space that consists of approximately $16 million of undiscounted minimum lease payments. The operating lease has a nine-year lease term and is expected to commence in June 2020.

~~As of December 31, 2018, minimum future contractual payments for long-term leases under the scope of ASC 840 are as follows (in thousands):~~

Pipeline

Automobile and

Real Estate

Transportation

Equipment
Year ending December 31,

Leases

Agreement

Leases
2019

$
7,407

$
3,180

$
4,216
2020

4,770

3,180

3,422
2021

4,066

3,180

1,678
2022

4,188

3,180

488
2023

4,017

3,180

35
Remaining

25,140

5,565

-
Total lease payments

$
49,588

$
21,465

$
9,839

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5.4. LONG-TERM DEBT

Long-term debt, including the current portion, consisted of the following at ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018~~2019 (in thousands):


	September 30,		December 31,		March 31,		December 31,
	2019		2018		2020		2019
Credit agreement	$	365,000	$	-
Credit Agreement					$	1,070,000	$	375,000
1.25% Convertible Senior Notes due 2020		262,075		562,075		186,592		262,075
5.75% Senior Notes due 2021		848,837		873,609		773,609		773,609
6.25% Senior Notes due 2023		408,296		408,296		408,296		408,296
6.625% Senior Notes due 2026		1,000,000		1,000,000		1,000,000		1,000,000
Total principal		2,884,208		2,843,980		3,438,497		2,818,980
Unamortized debt discounts and premiums		(5,284)		(28,994)		202		(2,575)
Unamortized debt issuance costs on notes		(17,883)		(22,665)		(15,347)		(16,520)
Total debt		2,861,041		2,792,321		3,423,352		2,799,885
Less current portion of long-term debt(1)		(256,018)		-		(3,423,352)		-
Total long-term debt	$	2,605,023	$	2,792,321	$	-	$	2,799,885

(1)

Due to uncertainties as of March 31, 2020 regarding default and the commencement of the Chapter 11 Cases on April 1, 2020, the Company has classified all of its outstanding debt as a current liability as of March 31, 2020. Refer to the “Basis of Presentation” footnote for more information on the Chapter 11 Cases.

Chapter 11 Cases and Effect of Automatic Stay

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

Credit Agreement

Whiting Oil and Gas, the Company’s wholly owned subsidiary, has a credit agreement with a syndicate of banks that ~~as of September 30, 2019~~ had a borrowing base of ~~$2.25~~$2.05 billion and aggregate commitments of $1.75 ~~billion.~~billion as of March 31, 2020. As of ~~September 30, 2019,~~March 31, 2020, the Company had ~~$1.4~~$1.07 billion ~~of available borrowing capacity under the credit agreement, which was net of $365 million~~ of borrowings outstanding under the Credit Agreement. As a result of the commencement of the Chapter 11 Cases, the Company is no longer in compliance with the covenants under the Credit Agreement and the lender’s commitments under the Credit Agreement have been terminated. The Company is therefore unable to make additional borrowings or issue additional letters of credit under the Credit Agreement.

Prior to default, a portion of the Credit Agreement in an aggregate amount not to exceed $50 million was available to issue letters of credit for the account of Whiting Oil and Gas or other designated subsidiaries of the Company. As of March 31, 2020, $2 million in letters of credit ~~outstanding.~~were outstanding under the agreement.

The borrowing base under the ~~credit agreement~~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 May 1 and November 1 of each year, as well as special redeterminations described in the ~~credit agreement, in each case which may reduce~~Credit Agreement. Such redeterminations are not expected to occur for the ~~amount~~duration of the borrowing base. Upon a redetermination of the borrowing base, either on a periodic or special redetermination date, if borrowings in excess of the revised borrowing capacity were outstanding, the Company could be forced to immediately repay a portion of its debt outstanding under the credit agreement. In October 2019, the borrowing base under the credit agreement was reduced to $2.05 billion in connection with the semi-annual regular borrowing base redetermination, with no change to the aggregate commitments of $1.75 billion.

A portion of the revolving credit facility in an aggregate amount not to exceed $50 million may be used to issue letters of credit for the account of Whiting Oil and Gas or other designated subsidiaries of the Company. As of September 30, 2019, $48 million was available for additional letters of credit under the agreement.Chapter 11 Cases.

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plus a margin between 0.50% and 1.50% based on the ratio of outstanding borrowings to the borrowing base, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.5% per annum, or an adjusted LIBOR rate plus 1.0% per annum, or (ii) an adjusted LIBOR rate for a Eurodollar loan plus a margin between 1.50% and 2.50% based on the ratio of outstanding borrowings to the borrowing base. Additionally, the Company incurs commitment fees of 0.375% or 0.50% based on the ratio of outstanding borrowings to the borrowing base on the unused portion of the aggregate commitments of the lenders under the ~~credit agreement,~~Credit Agreement, which are included as a component of interest expense. At ~~September 30, 2019,~~March 31, 2020, the weighted average interest rate on the outstanding principal balance under the ~~credit~~Credit Agreement was 3.0%. During the chapter 11 proceedings, all amounts outstanding under the Credit Agreement will bear interest per annum at the applicable rate stated in the agreement ~~was 3.6%.~~plus a 2.0% default rate.

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

The ~~credit agreement~~Credit Agreement contains restrictive covenants that may limit the Company’s ability to, among other things, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, enter into hedging contracts, incur liens and engage in certain other transactions without the prior consent of its lenders. Except for limited exceptions, the ~~credit agreement~~Credit Agreement also restricts the Company’s ability to make any dividend payments or distributions on its common stock. These restrictions apply to all of the

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Company’s restricted subsidiaries (as defined in the ~~credit agreement)~~Credit Agreement). As of ~~September 30, 2019,~~March 31, 2020, there were 0no retained earnings free from restrictions. The ~~credit agreement~~Credit Agreement requires the Company, as of the last day of any quarter, to maintain the following ratios (as defined in the ~~credit agreement)~~Credit Agreement): (i) a consolidated current assets to consolidated current liabilities ratio (which includes an add back of the available borrowing capacity under the credit agreement) of not less than 1.0 to 1.0 and (ii) a total debt to last four quarters’ EBITDAX ratio of not greater than 4.0 to 1.0. ~~The~~

Under the Credit Agreement, a cross-default provision provides that a default under certain other debt of the Company ~~was~~or certain of its subsidiaries in ~~compliance with its covenants~~an aggregate principal amount exceeding $100 million may constitute an event of default under such Credit Agreement. Additionally, under the ~~credit agreement as~~indentures governing the Company’s senior notes and senior convertible notes, a cross-default provision provides that a default under certain other debt of ~~September 30, 2019.~~the Company or certain of its subsidiaries in an aggregate principal amount exceeding $100 million (or $50 million in the case of the senior notes due in 2021) may constitute an event of default under such indenture.

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

Senior Notes and Convertible Senior Notes

Senior Notes—In September 2013, the Company issued at par ~~$1.1 billion of 5.0% Senior Notes due March 15, 2019 (the “2019 Senior Notes”) and~~ $800 million of 5.75% Senior Notes due March 15, 2021 and issued at 101% of par an additional $400 million of 5.75% Senior Notes due March 15, 2021 (collectively, the “2021 Senior Notes”). The debt premium recorded in connection with the issuance of the 2021 Senior Notes is being amortized to interest expense over the term of the notes using the effective interest method, with an effective interest rate of 5.5% per annum.

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

In December 2017, the Company issued at par $1.0 billion of 6.625% Senior Notes due January 15, 2026 (the “2026 Senior Notes” and together with the 2021 Senior Notes and the 2023 Senior Notes, the “Senior Notes”). The Company used the net proceeds from this offering to redeem in January 2018 all of the then outstanding 2019 Senior Notes. Refer to “Redemption of 2019 Senior Notes” below for more information on the redemption of the 2019 Senior Notes.

During 2016, the Company exchanged ~~(i) $139 million aggregate principal amount of its 2019 Senior Notes, (ii)~~ $326 million aggregate principal amount of ~~its~~ 2021 Senior Notes and ~~(iii)~~ $342 million aggregate principal amount of ~~its~~ 2023 Senior Notes for the same aggregate principal amount of convertible notes. Subsequently during 2016, all ~~$807~~$668 million aggregate principal amount of these convertible notes was converted into approximately ~~19.8~~16.3 million shares of the Company’s common stock pursuant to the terms of the notes.

~~Redemption of 2019 Senior Notes.~~ In January 2018, the Company paid $1.0 billion to redeem all of the remaining $961 million aggregate principal amount of the 2019 Senior Notes, which payment consisted of the 102.976% redemption price plus all accrued and unpaid interest on the notes. The Company financed the redemption with proceeds from the issuance of the 2026 Senior Notes and borrowings under its credit agreement. As a result of the redemption, the Company recognized a $31 million loss on extinguishment of debt, which included the redemption premium and a non-cash charge for the acceleration of unamortized debt issuance costs on the notes. As of March 31, 2018, 0 2019 Senior Notes remained outstanding.

Repurchases of 2021 Senior Notes. In September 2019, the Company paid $24 million to repurchase $25 million aggregate principal amount of the 2021 Senior Notes, which payment consisted of the average 94.708% purchase price plus all accrued and unpaid interest on the notes. The Company financed the repurchases with borrowings under ~~its credit agreement.~~the Credit Agreement. As a result of the repurchases, the

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Company recognized a $1 million gain on extinguishment of debt, which included a non-cash charge for the acceleration of unamortized debt issuance costs and debt premium on the notes. ~~As of September 30, 2019, $849 million of 2021 Senior Notes remained outstanding.~~

In October 2019, the Company paid an additional $72 million to repurchase $75 million aggregate principal amount of the 2021 Senior Notes, which payment consisted of the average 95.467% purchase price plus all accrued and unpaid interest on the notes. The Company financed the repurchases with borrowings under ~~its credit agreement.~~the Credit Agreement. As a result of the repurchases, the Company recognized a $3 million gain on extinguishment of debt, which included a noncash charge for the acceleration of unamortized debt issuance costs and debt premium on the notes. As of ~~October 4, 2019,~~March 31, 2020, $774 million of 2021 Senior Notes remained outstanding.

2020 Convertible Senior Notes—In March 2015, the Company issued at par ~~$1,250 million~~$1.25 billion of ~~1.25%~~the 2020 Convertible Senior Notes ~~due April 2020 (the “2020 Convertible Senior Notes”)~~ for net proceeds of $1.2 billion, net of initial purchasers’ fees of $25 million. During 2016, the Company exchanged $688 million aggregate principal amount of its 2020 Convertible Senior Notes for the same aggregate principal amount of new mandatory convertible senior notes. Subsequently during 2016, all $688 million aggregate principal amount

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of these mandatory convertible notes was converted into approximately 17.8 million shares of the Company’s common stock pursuant to the terms of the notes.

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

~~The remaining $262~~In March 2020, the Company paid $53 million to repurchase $73 million aggregate principal amount of the 2020 Convertible Senior Notes, ~~outstanding~~which payment consisted of the average 72.5% purchase price plus all accrued and unpaid interest on the notes, which were allocated to the liability and equity components based on their relative fair values. The Company financed the repurchases with borrowings under the Credit Agreement. As a result of these repurchases, the Company recognized a $23 million gain on extinguishment of debt, 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 2020 Convertible Senior Notes. There was no deferred tax impact associated with this reduction due to the full valuation allowance in effect as of ~~September 30, 2019 are convertible exclusively at the holder’s option.~~ March 31, 2020.

Prior to January 1, 2020, the 2020 Convertible Senior Notes ~~will be~~were convertible ~~at the holder’s option~~ only under the following circumstances: (i) during any calendar quarter commencing after the calendar quarter ending on June 30, 2015 (and only during such calendar quarter), if the last reported sale price of the Company’s common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day; (ii) during the five business day period after any five consecutive trading day period (the “measurement period”) in which the trading price per $1,000 principal amount of the 2020 Convertible Senior Notes for each trading day of the measurement period is less than 98% of the product of the last reported sale price of the Company’s common stock and the conversion rate on each such trading day; or (iii) upon the ~~occurrence~~achievement of ~~specified corporate events. On or after~~certain contingent market conditions, which were not met. After January 1, 2020, the 2020 Convertible Senior Notes ~~will be~~were convertible at any time until the second scheduled trading day immediately preceding the April 1, 2020 maturity date of the ~~notes. The~~ notes ~~will be convertible at a current conversion rate~~and holders of ~~6.4102 shares of Whiting’s common stock per $1,000~~$3 million aggregate principal amount of the notes, which is equivalent to a current conversion price of approximately $156.00. The conversion rate will be subject to adjustment in some events. In addition, following certain corporate events that occur prior to the maturity date, the Company will increase, in certain circumstances, the conversion rate for a holder who elects to convert its 2020 Convertible Senior Notes ~~in connection with~~timely elected to convert. Upon conversion, such ~~corporate event. As of September 30, 2019, none~~holders of the ~~contingent conditions allowing holders of the~~converted 2020 Convertible Senior Notes were entitled to ~~convert these notes had been met. The~~receive an insignificant cash payment on April 1, 2020, which the Company ~~has~~did not pay. As a result of such conversion the ~~option~~Company recognized a $3 million gain on extinguishment of debt for the three months ended March 31, 2020. Additionally, at maturity, the Company was obligated to ~~settle conversions of these notes with~~pay in cash ~~shares of common stock or a combination of cash and common stock at its election. The Company’s intent is to settle~~ the $187 million outstanding principal amount of the 2020 Convertible Senior Notes ~~in cash upon conversion. At maturity,~~that did not convert, which the Company ~~must settle all outstanding~~did not pay. Under the Bankruptcy Code, the holders of the 2020 Convertible Senior Notes ~~in cash.~~and the prior holders that converted their notes are stayed from taking any action against the Company as a result of the Company’s non-payment. Refer to “Chapter 11 Cases and Effect of Automatic Stay” above for more information.

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

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

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The 2020 Convertible Senior Notes consisted of the following at ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018~~2019 (in thousands):


	September 30,		December 31,		March 31,		December 31,
	2019		2018		2020		2019
Liability component
Principal	$	262,075	$	562,075	$	186,592	$	262,075
Less: unamortized note discount		(5,618)		(29,504)		-		(2,829)
Less: unamortized debt issuance costs		(439)		(2,340)		-		(220)
Net carrying value	$	256,018	$	530,231	$	186,592	$	259,026
Equity component ⁽¹⁾	$	128,452	$	136,522	$	125,009	$	128,452

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

~~The following table presents the interest~~Interest expense recognized on the 2020 Convertible Senior Notes related to the stated interest rate and amortization of the debt discount totaled $3 million and $7 million for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2020 and 2019, ~~and 2018 (in thousands):~~

Three Months Ended

Nine Months Ended

September 30,

September 30,

2019

2018

2019

2018
Interest expense on 2020 Convertible Senior Notes

$
7,611

$
7,335

$
22,678

$
21,774

respectively.

Security and Guarantees

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

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

6.5. ASSET RETIREMENT OBLIGATIONS

The Company’s asset retirement obligations represent the present value of estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage, and land restoration (including removal of certain onshore and offshore facilities in California) in accordance with applicable local, state and federal laws. The current portions as of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018~~2019 were $4 million and have been included in accrued liabilities and other in the consolidated balance sheets. The following table provides a reconciliation of the Company’s asset retirement obligations for the ~~nine~~three months ended ~~September 30, 2019~~March 31, 2020 (in thousands):


Asset retirement obligation at January 1, 2019	$	135,834
Asset retirement obligation at January 1, 2020			$	134,893
Additional liability incurred		2,032		27
Revisions to estimated cash flows		(7,511)		10
Accretion expense		8,680		3,027
Obligations on sold properties		(2,135)		(652)
Liabilities settled		(983)		(679)
Asset retirement obligation at September 30, 2019	$	135,917
Asset retirement obligation at March 31, 2020			$	136,626

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7.6. DERIVATIVE FINANCIAL INSTRUMENTS

The Company is exposed to certain risks relating to its ongoing business operations, and it uses derivative instruments to manage its commodity price risk. In addition, the Company periodically enters into contracts that contain embedded features which are required to be bifurcated and accounted for separately as derivatives.

Commodity Derivative Contracts—Historically, prices received for crude oil and natural gas production have been volatile because of supply and demand factors, worldwide political factors, general economic conditions and seasonal weather patterns. Whiting primarily enters into derivative contracts such as crude oil collars, swaps and options ~~as well as sales and delivery contracts,~~ 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 does not enter into derivative contracts for speculative or trading purposes.

Crude Oil Collars, Swaps and Options. Collars are designed to establish floor and ceiling prices on anticipated future oil or gas production, while swaps and options establish a fixed price for anticipated future oil or gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements.

The table below details the Company’s collar, swap and option derivatives entered into to hedge forecasted crude oil production revenues as of ~~September 30, 2019.~~March 31, 2020.

Derivative

Contracted Crude

Weighted Average NYMEX Price
Instrument

Period

Oil Volumes (Bbl)

for Crude Oil (per Bbl)
Swaps

Oct - Dec 2019

2,211,000

$61.02

Jan - Dec 2020

3,051,000

$57.95
Collars

Oct - Dec 2019

2,700,000

$52.56 - $75.17

Jan - Dec 2020

728,000

$55.00 - $67.33
Three-way collars ⁽¹⁾

Jan - Dec 2020

1,830,000

$45.00 - $55.00 - $65.00
Call option ⁽²⁾

Jan - Dec 2021

365,000

$65.00

Total

10,885,000


					Weighted Average Prices
Commodity	Settlement Period	Index	Derivative Instrument	Contracted Crude Oil Volumes (Bbl)	Swap Price	Sub-Floor	Floor	Ceiling
Crude Oil	2020	NYMEX WTI	Fixed Price Swaps	3,660,000	$54.97	-	-	-
Crude Oil	2020	NYMEX WTI	Two-way Collars	2,477,000	-	-	$55.11	$62.38
Crude Oil	2020	NYMEX WTI	Three-way Collars ⁽¹⁾	2,107,000	-	$43.31	$53.68	$63.06
Crude Oil	2021	NYMEX WTI	Three-way Collars ⁽¹⁾	1,825,000	-	$43.50	$53.50	$59.45
Crude Oil	2021	NYMEX WTI	Call Option ⁽²⁾	365,000	-	-	-	$65.00
			Total	10,434,000

(1)	The Company is contracted to pay deferred premiums related to certain three-way collars at each settlement date. The weighted average premium for all three-way collars was ~~$1.84~~$0.51 per Bbl as of ~~September 30, 2019.~~March 31, 2020.

(2)	This derivative instrument is a sold call option.

~~Crude Oil Sales~~Effect of Chapter 11 Cases—The commencement of the Chapter 11 Cases constitutes a termination event with respect to the Company’s derivative instruments, which permits the counterparties to such derivative instruments to terminate their outstanding hedges. Such termination events are not stayed under the Bankruptcy Code. During April 2020, certain of the lenders under the Credit Agreement elected to terminate their master ISDA agreements and ~~Delivery Contract.~~ outstanding hedges with the Company for aggregate settlement proceeds of $145 million. The ~~Company had a long-term crude oil sales and delivery contract~~proceeds from these terminations along with $13 million of March 2020 hedge settlement proceeds received in April 2020 were applied to the outstanding borrowings under the Credit Agreement. An additional $23 million of settlement proceeds from terminated derivative positions will be held in escrow until the completion of the Chapter 11 Cases. After the April 2020 terminations, the remaining active contracts consisted of swap contracts for ~~oil volumes produced from its Redtail field in Colorado. Whiting determined that this contract would not qualify~~639,000 Bbl for the ~~“normal purchase normal sale” exclusion and therefore reflected the contract~~remainder of 2020 at fair value in the consolidated financial statements prior to settlement. On February 1, 2018, Whiting paid $61 million to the counterparty to settle all future minimum volume commitments under this agreement. Accordingly, this crude oil sales and delivery contract was fully terminated, and the fair valuea weighted average price of ~~the corresponding derivative was therefore 0 as of that date.~~

~~Derivative Instrument Reporting~~—All derivative instruments are recorded in the consolidated financial statements at fair value, other than derivative instruments that meet the “normal purchase normal sale” exclusion or other derivative scope exceptions. The following tables summarize the effects of derivative instruments on the consolidated statements of operations for the three and nine months ended September 30, 2019 and 2018 (in thousands):

(Gain) Loss Recognized in Income
Not Designated as

Statement of Operations

Three Months Ended September 30,
ASC 815 Hedges

Classification

2019

2018
Commodity contracts

Derivative (gain) loss, net

$
(30,597)

$
21,063
Total

$
(30,597)

$
21,063

$58.63.

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Loss Recognized in Income
Not Designated as

Statement of Operations

Nine Months Ended September 30,
ASC 815 Hedges

Classification

2019

2018
Commodity contracts

Derivative (gain) loss, net

$
7,431

$
177,210
Total

$
7,431

$
177,210

Derivative Instrument Reporting—All derivative instruments are recorded in the condensed consolidated financial statements at fair value, other than derivative instruments that meet the “normal purchase normal sale” exclusion or other derivative scope exceptions. The following table summarizes the effects of derivative instruments on the condensed consolidated statements of operations for the three months ended March 31, 2020 and 2019 (in thousands):


		(Gain) Loss Recognized in Income
Not Designated as	Statement of Operations	Three Months Ended March 31,
ASC 815 Hedges	Classification	2020		2019
Commodity contracts	Derivative (gain) loss, net	$	(231,371)	$	62,905
Total		$	(231,371)	$	62,905

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


		September 30, 2019⁽¹⁾							March 31, 2020 ⁽¹⁾
						Net							Net
		Gross				Recognized			Gross				Recognized
		Recognized		Gross		Fair Value			Recognized		Gross		Fair Value
Not Designated as		Assets/		Amounts		Assets/			Assets/		Amounts		Assets/
ASC 815 Hedges	Balance Sheet Classification	Liabilities		Offset		Liabilities		Balance Sheet Classification	Liabilities		Offset		Liabilities
Derivative assets
Commodity contracts - current	Derivative assets	$	52,897	$	(7,859)	$	45,038	Derivative assets	$	216,285	$	(36,945)	$	179,340
Commodity contracts - non-current	Other long-term assets		4,757		(3,586)		1,171	Other long-term assets		23,499		(13,573)		9,926
Total derivative assets		$	57,654	$	(11,445)	$	46,209		$	239,784	$	(50,518)	$	189,266
Derivative liabilities
Commodity contracts - current	Accrued liabilities and other	$	7,859	$	(7,859)	$	-	Accrued liabilities and other	$	36,945	$	(36,945)	$	-
Commodity contracts - non-current	Other long-term liabilities		3,682		(3,586)		96	Other long-term liabilities		13,573		(13,573)		-
Total derivative liabilities		$	11,541	$	(11,445)	$	96		$	50,518	$	(50,518)	$	-


		December 31, 2018 ⁽¹⁾							December 31, 2019 ⁽¹⁾
						Net							Net
		Gross				Recognized			Gross				Recognized
		Recognized		Gross		Fair Value			Recognized		Gross		Fair Value
Not Designated as		Assets/		Amounts		Assets/			Assets/		Amounts		Assets/
ASC 815 Hedges	Balance Sheet Classification	Liabilities		Offset		Liabilities		Balance Sheet Classification	Liabilities		Offset		Liabilities
Derivative assets
Commodity contracts - current	Derivative assets	$	69,735	$	(1,393)	$	68,342	Derivative assets	$	75,654	$	(74,768)	$	886
Commodity contracts - non-current								Other long-term assets		5,648		(5,648)		-
Total derivative assets		$	69,735	$	(1,393)	$	68,342		$	81,302	$	(80,416)	$	886
Derivative liabilities
Commodity contracts - current	Accrued liabilities and other	$	1,393	$	(1,393)	$	-	Accrued liabilities and other	$	85,053	$	(74,768)	$	10,285
Commodity contracts - non-current								Other long-term liabilities		6,534		(5,648)		886
Total derivative liabilities		$	1,393	$	(1,393)	$	-		$	91,587	$	(80,416)	$	11,171

(1)

Because counterparties to the Company’s financial derivative contracts subject to master netting arrangements are lenders under ~~Whiting Oil and Gas’ credit agreement,~~the Credit Agreement, which eliminates its need to post or receive collateral associated with its derivative positions, 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

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lenders under ~~Whiting’s credit agreement.~~the Credit Agreement. The Company uses only ~~credit agreement~~Credit Agreement participants to hedge with, since these institutions are secured equally with the holders of Whiting’s bank debt, which eliminates the potential need to post collateral when Whiting is in a derivative liability position. As a result, the Company is not required to post letters of credit or corporate guarantees for its derivative counterparties in order to secure contract performance obligations.

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8.7. FAIR VALUE MEASUREMENTS

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

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

●

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

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

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

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

The Company’s senior notes are recorded at cost and the convertible senior notes are recorded at fair value at the date of issuance. The following table summarizes the fair values and carrying values of these instruments as of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018~~2019 (in thousands):


	September 30, 2019				December 31, 2018				March 31, 2020				December 31, 2019
	Fair		Carrying		Fair		Carrying		Fair		Carrying		Fair		Carrying
	Value ⁽¹⁾		Value ⁽²⁾		Value ⁽¹⁾		Value ⁽²⁾		Value ⁽¹⁾		Value ⁽²⁾		Value ⁽¹⁾		Value ⁽²⁾
1.25% Convertible Senior Notes due 2020	$	256,834	$	256,018	$	531,161	$	530,231	$	11,196	$	186,592	$	260,214	$	259,026
5.75% Senior Notes due 2021		802,151		846,827		829,929		870,545		52,219		772,386		732,995		772,080
6.25% Senior Notes due 2023		324,595		405,194		375,632		404,659		28,581		405,595		343,989		405,392
6.625% Senior Notes due 2026		680,000		988,002		865,000		986,886		67,500		988,779		681,250		988,387
Total	$	2,063,580	$	2,496,041	$	2,601,722	$	2,792,321	$	159,496	$	2,353,352	$	2,018,448	$	2,424,885

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

(2)	Carrying values are presented net of unamortized debt issuance costs and debt discounts or premiums.

The Company’s derivative financial instruments are recorded at fair value and include a measure of the Company’s own nonperformance risk or that of its counterparty, as appropriate. The following tables present information about the Company’s financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2019 and December 31, 2018, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values (in thousands):

2019

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Total Fair Value


Level 1

Level 2

Level 3

September 30, 2019
Financial Assets

Commodity derivatives – current

$
-

$
45,038

$
-

$
45,038
Commodity derivatives – non-current

-

1,171

-

1,171
Total financial assets

$
-

$
46,209

$
-

$
46,209
Financial Liabilities

Commodity derivatives – non-current

$
-

$
96

$
-

$
96
Total financial liabilities

$
-

$
96

$
-

$
96

The Company’s derivative financial instruments are recorded at fair value and include a measure of the Company’s own nonperformance risk or that of its counterparty, as appropriate. The following tables present information about the Company’s financial assets and liabilities measured at fair value on a recurring basis as of March 31, 2020 and December 31, 2019, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values (in thousands):


							Total Fair Value								Total Fair Value
	Level 1		Level 2		Level 3		December 31, 2018		Level 1		Level 2		Level 3		March 31, 2020
Financial Assets
Commodity derivatives – current	$	-	$	68,342	$	-	$	68,342	$	-	$	179,340	$	-	$	179,340
Commodity derivatives – non-current										-		9,926		-		9,926
Total financial assets	$	-	$	68,342	$	-	$	68,342	$	-	$	189,266	$	-	$	189,266


							Total Fair Value
	Level 1		Level 2		Level 3		December 31, 2019
Financial Assets
Commodity derivatives – current	$	-	$	886	$	-	$	886
Total financial assets	$	-	$	886	$	-	$	886
Financial Liabilities
Commodity derivatives – current	$	-	$	10,285	$	-	$	10,285
Commodity derivatives – non-current		-		886		-		886
Total financial liabilities	$	-	$	11,171	$	-	$	11,171

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 collars, swaps and options for crude oil. The Company’s collars, swaps and options 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.

In addition, the Company had a long-term crude oil sales and delivery contract, whereby it had committed to deliver certain fixed volumes of crude oil produced from its Redtail field in Colorado. Whiting determined that the contract did not meet the “normal purchase normal sale” exclusion, and therefore reflected this contract at fair value in its consolidated financial statements prior to settlement. This commodity derivative was valued based on a probability-weighted income approach which considered various assumptions, including quoted spot prices for commodities, market differentials for crude oil, U.S. Treasury rates and either the Company’s or the counterparty’s nonperformance risk, as appropriate. The assumptions used in the valuation of the crude oil sales and delivery contract included certain market differential metrics that were unobservable during the term of the contract. Such unobservable inputs were significant to the contract valuation methodology, and the contract’s fair value was therefore designated as Level 3 within the valuation hierarchy. On February 1, 2018, Whiting paid $61 million to the counterparty to settle all future minimum volume commitments under this agreement. Accordingly, this derivative was settled in its entirety as of that date.

~~Level 3 Fair Value Measurements~~—The following table presents a reconciliation of changes in the fair value of financial liabilities designated as Level 3 in the valuation hierarchy for the nine months ended September 30, 2018 (in thousands):


	~~Nine Months Ended~~
	~~September 30, 2018~~
~~Fair value liability, beginning of period~~	$	~~(63,278)~~
~~Unrealized gains on commodity derivative contracts included in earnings~~ ⁽¹⁾		~~2,242~~
~~Settlement of commodity derivative contracts~~		~~61,036~~
~~Transfers into (out of) Level 3~~		-
~~Fair value liability, end of period~~	$	-

~~(1)~~

~~Included in derivative (gain) loss, net in the consolidated statements of operations.~~

Non-recurring Fair Value Measurements—The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including proved property. These assets and liabilities are not measured at fair

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value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. The Company did 0tnot recognize any impairment write-downs with respect to its proved property during the ~~reporting~~three months ended March 31, 2019. The following table presents information about the Company’s non-financial assets measured at fair value on a non-recurring basis during the three months ended March 31, 2020, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values (in thousands):


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

(1)

During the first quarter of 2020, 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. The 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.

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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 quarter 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. The fair value was ascribed using income approach analyses based on the net discounted future cash flows from the producing properties and related assets. The discounted cash flows were based on management’s expectations for the future. Unobservable inputs included estimates of future oil and gas production from the Company’s reserve reports, commodity prices based on forward strip price curves (adjusted for basis differentials) as of March 31, 2020, operating and development costs, expected future development plans for the properties and a discount rate of 16% based on a weighted-average cost of capital (all of which were designated as Level 3 inputs within the fair value hierarchy). The impairment test indicated that a proved property impairment had occurred, and the Company therefore recorded a non-cash impairment charge to reduce the carrying value of the impaired properties to their fair value at March 31, 2020. Additional impairments may be recorded in future periods ~~presented.~~if commodity prices continue to deteriorate or further reductions to the development plans of the properties are indicated by market conditions.

9.8. REVENUE RECOGNITION

The Company recognizes revenue in accordance with FASB ASC Topic 606 – Revenue ~~Recognition~~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. The table below presents the disaggregation of revenue by product type for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2020 and 2019 ~~and 2018~~ (in thousands):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,				Three Months Ended March 31,
	2019		2018		2019		2018		2020		2019
OPERATING REVENUES
Oil sales	$	369,940	$	511,904	$	1,133,264	$	1,448,310	$	231,945	$	359,454
NGL and natural gas sales		5,951		54,791		58,380		159,871		12,901		30,035
Oil, NGL and natural gas sales	$	375,891	$	566,695	$	1,191,644	$	1,608,181	$	244,846	$	389,489

Whiting receives payment for product sales from one to three months after delivery. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in accounts receivable trade, net in the consolidated balance sheets. As of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, such receivable balances were ~~$149~~$75 million and ~~$165~~$161 million, respectively. Variances between the Company’s estimated revenue and actual payments are recorded in the month the payment is received, however, differences have been and are insignificant. Accordingly, the variable consideration is not constrained.

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.

9. SHAREHOLDERS’ EQUITY

NOL Rights Plan—As of December 31, 2019, the Company had federal net operating loss (“NOL”) carryforwards of $3.4 billion. The Company’s ability to use its NOLs would be substantially limited if it experiences an “ownership change” as defined in Section 382 of the Internal Revenue Code (“IRC”). A company generally experiences an ownership change if the percentage of its shares of stock owned by its “5-percent shareholders,” as such term is defined in Section 382 of the IRC, increases by more than 50% over a rolling three-year period.

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

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

The Board of Directors has the discretion to exempt certain transactions, persons or entities from the operation of the Rights Agreement and also has the ability to amend or terminate the Rights Agreement prior to a triggering event. Additionally, the Board of Directors may cause the Company to redeem the Rights in whole, but not in part, at a price of $0.001 per Right. The Rights will expire on the day following the certification of the voting results for Whiting’s 2021 annual meeting of shareholders unless Whiting’s shareholders ratify the Rights Agreement at or prior to such meeting, in which case the Rights Agreement will continue in effect until March 26, 2023 unless terminated earlier in accordance with its terms.

Final Order of the Bankruptcy Court—On April 1, 2020, the Bankruptcy Court entered a final order (i) approving notification and hearing procedures for certain transfers of and declarations of worthlessness with respect to common stock and (ii) granting related relief (as amended on April 24, 2020, the “Order”). The Order sets forth the procedures (including notice requirements) that certain shareholders and potential shareholders must comply with regarding transfers of, or declarations of worthlessness with respect to, the Company’s common stock (as defined in the Order), as well as certain obligations with respect to notifying the Company of current share ownership (the “Procedures”). The Procedures areintended to reduce the likelihood that changes in the Company’s investor base would limit its future use of its tax benefits. The terms and conditions of the Procedures were immediately effective and enforceable upon entry of the Order by the Bankruptcy Court.

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

10. STOCK-BASED COMPENSATION

Equity Incentive Plan—The Company maintains the Whiting Petroleum Corporation 2013 Equity Incentive Plan, as amended and restated (the “2013 Equity Plan”), which replaced the Whiting Petroleum Corporation 2003 Equity Incentive Plan (the “2003 Equity Plan”) and originally granted the authority to issue 1,325,000 shares of the Company’s common stock. During 2016, shareholders approved an amendment to the 2013 Equity Plan granting the authority to issue an additional 1,375,000 shares of the Company’s common stock. In May 2019, shareholders approved an additional amendment to the 2013 Equity Plan granting the authority to issue an additional 3,000,000 shares of the Company’s common stock. Upon shareholder approval of the 2013 Equity Plan, the 2003 Equity Plan was terminated. The 2003 Equity Plan continues to govern awards that were outstanding as of the date of its termination, which awards remain in effect pursuant to their terms. Any shares netted or forfeited under the 2003 Equity Plan and any shares forfeited under the 2013 Equity Plan will be available for future issuance under the 2013 Equity Plan. However, shares netted for tax withholding under the 2013 Equity Plan will be cancelled and will not be available for future issuance. Under the amended and restated 2013 Equity Plan, during any calendar year no officer or other key employee participant may be granted ~~during any calendar year~~ options or stock appreciation rights for more than 500,000 shares of common stock or more than 500,000 shares of restricted stock (“RSAs”), restricted stock units (“RSUs”), performance shares (“PSAs”), or performance share units (“PSUs”), the value of which is based on the fair market value of a share of common stock. In addition, no non-employee director participant may be granted during any calendar year options or stock appreciation

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rights for more than 25,000 shares of common stock, or more than 25,000 shares of RSAs or RSUs. As of ~~September 30, 2019, 3,686,957~~March 31, 2020, 3,884,911 shares of common stock remained available for grant under the 2013 Equity Plan.

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The Company grants service-based RSAs and RSUs to executive officers and employees, which generally vest ratably over a three-year service period. The Company also grants service-based RSAs to directors, which generally vest over a one-year service period. In addition, the Company grants PSAs and 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.

During the ~~nine~~three months ended ~~September 30,~~March 31, 2020 and 2019, 53,198 and ~~2018, 464,140 and 239,502~~326,737 shares, respectively, of service-based RSAs and RSUs were granted to executive officers and directors under the 2013 Equity Plan. The Company determines compensation expense for these share-settled awards using their fair value at the grant date, which is based on the closing bid price of the Company’s common stock on such date. The weighted average grant date fair value of service-based RSAs and RSUs was ~~$24.76~~$4.94 per share and ~~$32.27~~$29.80 per share for the ~~nine~~three months ended ~~September 30,~~March 31, 2020 and 2019, respectively. On March 31, 2020, all of the RSAs issued to executive officers in 2020 were forfeited and ~~2018, respectively.~~concurrently replaced with cash incentives. Refer to “2020 Compensation Adjustments” below for more information.

During the ~~nine~~three months ended ~~September 30, 2019 and 2018, 774,665 and 308,432~~March 31, 2020, 1,616,504 shares ~~respectively,~~ of service-based RSUs were granted to executive officers and employees under the 2013 Equity Plan. ~~These awards will be settled in cash and are recorded as a liability in the consolidated balance sheets.~~ The Company determines compensation expense for cash-settled RSUs using the fair value at the end of each reporting period, which is 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 ~~nine~~three months ended ~~September 30,~~March 31, 2020 and 2019, 1,665,153 and ~~2018, 347,493 and 220,451,~~317,512, respectively, of PSAs and PSUs subject to certain market-based vesting criteria were granted to executive officers under the 2013 Equity Plan. These market-based awards cliff vest on the third anniversary of the grant date, and the number of shares that will vest at the end of that three-year performance period is determined based on the rank of Whiting’s cumulative stockholder return compared to the stockholder return of a peer group of companies on each anniversary of the grant date over the three-year performance period. The number of awards earned could range from 0 up to 2 times the number of shares initially granted. However, awards earned up to the target shares granted (or 100%) will be settled in shares, while awards earned in excess of the target shares granted will be settled in cash. The cash-settled component of such awards is recorded as a liability in the consolidated balance sheets and will be remeasured at fair value using a Monte Carlo valuation model at the end of each reporting period. On March 31, 2020, all of the PSAs and PSUs issued to executive officers in 2020 were forfeited and concurrently replaced with cash incentives. Refer to “2020 Compensation Adjustments” below for more information.

For awards subject to market conditions, the grant date fair value is estimated using a Monte Carlo valuation model. The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility is calculated based on the historical volatility and implied volatility of Whiting’s common stock, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with the three-year vesting period. The key assumptions used in valuing these market-based awards were as follows:


	2019	2018	2020	2019
Number of simulations	2,500,000	2,500,000	2,500,000	2,500,000
Expected volatility	72.95%	72.80%	76.52%	72.95%
Risk-free interest rate	2.60%	2.12%	1.51%	2.60%
Dividend yield	—	—	—	—

The weighted average grant date fair value of the market-based awards that will be settled in shares, as determined by the Monte Carlo valuation model, was $4.31 per share and $25.97 per share in 2020 and ~~$27.28 per share~~2019, respectively.

2020 Compensation Adjustments. All of the RSAs, RSUs, PSAs and PSUs granted to executive officers in ~~2019~~2020 were forfeited on March 31, 2020 and ~~2018, respectively.~~were replaced with cash retention incentives. The cash retention incentives are subject to a service period and may be clawed back if an executive officer terminates employment for any reason other than a qualifying termination prior to the earlier of (i) the effective date of a plan of reorganization approved under chapter 11 of the Bankruptcy Code or (ii) March 30, 2021. The transactions were considered concurrent replacement of the stock compensation awards previously issued. As such, the $12 million fair value of the awards, consisting of the after-tax value of the cash incentives, was capitalized to prepaid expenses and other in the

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condensed consolidated balance sheet as of March 31, 2020 and will be amortized over the relevant service period. The difference between the cash and after-tax value of the cash retention incentives of approximately $9 million, which is not subject to the claw back provisions contained within the agreements, was expensed to general and administrative expenses in the condensed consolidated statement of operations for the three months ended March 31, 2020.

The following table shows a summary of the Company’s service-based and market-based awards activity for the ~~nine~~three months ended ~~September 30, 2019:~~March 31, 2020:


	Number of Awards		Weighted Average		Number of Awards		Weighted Average
	Service‑Based	Market-Based	Grant Date		Service‑Based	Market-Based	Grant Date
	RSAs & RSUs	PSAs & PSUs	Fair Value		RSAs & RSUs	PSAs & PSUs	Fair Value
Nonvested awards, January 1	554,527	503,696	$	34.94	467,502	448,387	$	28.28
Granted	464,140	347,493		24.67	53,198	1,665,153		4.33
Vested	(337,428)	(98,581)		32.82	(132,893)	-		32.97
Forfeited	(162,153)	(297,349)		32.97	(125,955)	(1,773,101)		7.54
Nonvested awards, September 30	519,086	455,259	$	28.26
Nonvested awards, March 31					261,852	340,439	$	24.33

There was no significant stock option activity during the ~~nine~~three months ended ~~September 30, 2019~~March 31, 2020 and ~~2018.~~2019.

~~Total stock compensation expense recognized for restricted stock was a benefit of $5 million for~~For the three months ended ~~September 30,~~March 31, 2020 and 2019, the Company recognized total stock compensation expense of ~~$7 million for the three months ended September 30, 2018 and expense of $6~~$1 million and ~~$18~~$6 million, ~~for the nine months ended September 30, 2019 and 2018,~~ respectively.

11. INCOME TAXES

Income tax expense during interim periods is based on applying an estimated annual effective income tax rate to year-to-date income, plus any significant unusual or infrequently occurring items which are recorded in the interim period. The provision for income taxes for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2020 and 2019 ~~and 2018~~ differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax income primarily due to (i) state income taxes and the ~~recognition~~effects of permanent taxable differences for the three months ended March 31, 2019 and (ii) a full valuation allowance ~~during~~in effect on the ~~second quarter of 2019 and (ii)~~Company’s U.S. deferred tax assets (“DTAs”), resulting in 0 income tax expense for the three ~~and nine~~ months ended ~~September 30, 2018, a full valuation allowance was already in effect, which reduced the Company’s net tax expense to 0.~~March 31, 2020.

In assessing the realizability of ~~deferred tax assets (“DTAs”),~~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 ~~December~~March 31, ~~2018, the Company had a valuation allowance totaling $152 million on a portion of its net DTAs, and as of September 30, 2019,~~2020, the Company had a full valuation allowance on its U.S. DTAs.

The computation of the annual estimated effective tax rate at each interim period requires certain estimates and significant judgment including, but not limited to, the expected operating income for the year, projections of the proportion of income earned and taxed in various jurisdictions, permanent and temporary differences, and the likelihood of recovering deferred tax assets 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.

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

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12. EARNINGS PER SHARE

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

Three Months Ended September 30,

Nine Months Ended September 30,


2019

2018

2019

2018
Basic Earnings (Loss) Per Share

Net income (loss)

$
(19,067)

$
121,400

$
(93,679)

$
138,532
Weighted average shares outstanding, basic

91,299

90,967

91,274

90,934
Earnings (loss) per common share, basic

$
(0.21)

$
1.33

$
(1.03)

$
1.52

Diluted Earnings (Loss) Per Share

Net income (loss)

$
(19,067)

$
121,400

$
(93,679)

$
138,532
Weighted average shares outstanding, basic

91,299

90,967

91,274

90,934
Service-based awards, market-based awards and stock options

-

856

-

928
Weighted average shares outstanding, diluted

91,299

91,823

91,274

91,862
Earnings (loss) per common share, diluted

$
(0.21)

$
1.32

$
(1.03)

$
1.51


	Three Months Ended March 31,
	2020		2019
Basic Loss Per Share
Net loss	$	(3,628,571)	$	(68,925)
Weighted average shares outstanding		91,390		91,235
Loss per common share	$	(39.70)	$	(0.76)

Diluted Loss Per Share
Net loss	$	(3,628,571)	$	(68,925)
Weighted average shares outstanding		91,390		91,235
Loss per common share	$	(39.70)	$	(0.76)

During the three months ended ~~September 30,~~March 31, 2020, the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes the anti-dilutive effect of 392,367 shares of service-based awards. In addition, the diluted earnings per share calculation for the three months ended March 31, 2020 excludes the effect of 39,660 common shares for stock options that were out-of-the-money as of March 31, 2020.

During the three months ended March 31, 2019, the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes the anti-dilutive effect of ~~35,433~~254,985 shares of service-based awards and ~~7,159~~235,174 shares of market-based awards. In addition, the diluted earnings per share calculation for the three months ended ~~September 30,~~March 31, 2019 excludes the effect of ~~43,367~~49,125 common shares for stock options that were out-of-the-money as of ~~September 30,~~March 31, 2019.

During the three months ended September 30, 2018, the diluted earnings per share calculation excludes the effect of 110,604 common shares for stock options that were out-of-the-money as of September 30, 2018.

During the nine months ended September 30, 2019, the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes the anti-dilutive effect of 344,419 shares of service-based awards and 64,407 shares of market-based awards. In addition, the diluted earnings per share calculation for the nine months ended September 30, 2019 excludes the effect of 46,095 common shares for stock options that were out-of-the money as of September 30, 2019.

~~During the nine months ended September 30, 2018, the diluted earnings per share calculation excludes the effect of 114,582 common shares for stock options that were out-of-the-money.~~

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

~~As discussed in the “Long-Term Debt” footnote, the~~The Company ~~has~~had the option to settle conversions of the 2020 Convertible Senior Notes with cash, shares of common stock or any combination thereof. ~~Based on~~As the ~~current~~ conversion ~~price, the entire outstanding principal amount~~value of the 2020 Convertible Senior Notes as of September 30, 2019 would be convertible into approximately 1.7 million shares of the Company’s common stock. However, the Company’s intent is to settle the principal amount of the notes in cash upon conversion. As a result, only the amount by which the conversion value exceeds the aggregate principal amount of the notes (the “conversion spread”) is considered in the diluted earnings per share computation under the treasury stock method. As of September 30, 2019 and 2018, the conversion value did not exceed the principal amount of the ~~notes. Accordingly,~~notes as of March 31, 2020 and 2019, there was no impact to diluted earnings per share or the related disclosures for those periods.

13. COMMITMENTS AND CONTINGENCIES

~~Pipeline Transportation Agreement~~Chapter 11 Proceedings—On April 1, 2020, the Debtors filed the Chapter 11 Cases seeking relief under the Bankruptcy Code. The Company expects to continue operations in the normal course for the duration of the Chapter 11 Cases. In addition, commencement of the ~~third quarter~~Chapter 11 Cases automatically stayed all of ~~2019,~~the proceedings and actions against the Company ~~entered into~~(other than regulatory enforcement matters), including those noted below. Refer to the “Basis of Presentation” footnote for more information about the Chapter 11 Cases.

Delivery Commitments—The Company has a ~~ship-or-pay agreement~~delivery contract that is tied to ~~transport crude~~ oil ~~from~~production in the Williston ~~Basin via certain pipelines for a term of seven years. Although minimum quantities are specified in the agreement,~~

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~~the actual oil volumes transported are variable over the term of the contract.~~Basin. The effective date of this contract is contingent upon the completion of certain related pipelines, which has been suspended due to current market conditions. Under the terms of the agreement, Whiting has committed to deliver 10 MBbl/d for a term of seven years. The Company believes its production and reserves are ~~currently expected~~sufficient to ~~be brought online in 2021. As of September 30, 2019, the Company estimated the minimum future commitments~~fulfill this delivery commitment, and therefore expects to avoid any payments for deficiencies under this ~~agreement to approximate $147 million which is based on~~contract. However, if completion of the ~~contractually stipulated per barrel fee and is~~pipelines does not occur by March 31, 2022, such date being subject to ~~adjustment during~~extension by force majeure until July 31, 2023, the ~~term of~~contract will terminate and Whiting will no longer be required to deliver the ~~contract.~~

committed volumes.

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. The Company is involved in litigation related to a payment arrangement with a third party which currently claims damages

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up to $41 million, as well as court costs and interest. ~~While~~As a result of the ~~Company believes that a loss contingency is reasonably possible,~~Chapter 11 Cases and the ~~possible loss or a range~~effect of ~~possible loss associated with this litigation cannot be reasonably estimated due to a number~~the automatic stay, the court closed the case as of ~~factors including, but not limited to, complex legal and factual matters, ongoing discovery and development of information important~~April 11, 2020, subject to the case being reopened upon motion of any party without prejudice for a period which shall continue until 30 days after the conclusion of the bankruptcy proceedings. Certain amounts were accrued in accrued liabilities and ~~potential defenses, among others. NaN amounts for loss contingencies associated with litigation, claims or assessments have been accrued~~other in the consolidated balance sheet as of ~~September 30, 2019 or~~ December 31, ~~2018.~~

~~14. RESTRUCTURING~~

~~On July 31,~~ 2019 ~~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. In connection with these activities, the Company incurred $8 million in net restructuring costs associated with one-time employee termination benefits. These restructuring costs are included in general and administrative expenses in the ~~condensed~~ consolidated ~~statements~~statement of ~~operations.~~

operations for the year ended December 31, 2019 based on the determination that it is probable that a loss has been incurred and can be reasonably estimated. The Company has not accrued any additional amounts as of March 31, 2020.

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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”), Whiting US Holding Company, Whiting Canadian Holding Company ULC, Whiting Resources Corporation and Whiting Programs, Inc. When the context requires, we refer to these entities separately. This document contains forward-looking statements, which give our current expectations or forecasts of future events. Please refer to “Forward-Looking Statements” at the end of this Item for an explanation of these types of statements.

Overview

We are an independent oil and gas company engaged in development, production, acquisition and exploration activities primarily in the Rocky Mountains region of the United States. Our current operations and capital programs are focused on organic drilling opportunities and on the development of previously acquired properties, specifically on projects that we believe provide the greatest potential for repeatable success and production growth, while selectively pursuing acquisitions that complement our existing core properties and exploring other basins where we can apply our existing knowledge and expertise to build production and add proved reserves.growth. During ~~2018,~~2019, we focused on ~~high-return projects in~~developing our asset portfolio that added production and reserves while generating free cash flows from operations. In 2019, we expect to continue to closely align our capital spending with cash flows generated from operations while focusing our development activities at our largestlarge resource play in the Williston Basin of North Dakota and ~~Montana.~~Montana, while closely aligning our capital spending with cash flows generated from operations. As a result of the sharp decline in commodity prices during the first quarter of 2020, we have significantly decreased our level of capital spending to more closely align with our reduced cash flows from operating activities and have focused our organic drilling operations on projects in our drilling inventory that provide the highest rate of return. We continually evaluate our property portfolio and sell properties when we believe that the sales price realized will provide an above average rate of return for the property or when the property no longer matches the profile of properties we desire to own. Refer to the “Acquisitions and Divestitures” footnote in the notes to condensed consolidated financial statements for more information on our recent acquisition and divestiture activity.

Our revenue, profitability and future growth rate depend on many factors which are beyond our control, such as oil and gas prices, economic, political and regulatory developments, competition from other sources of energy, and the other items discussed under the caption “Risk Factors” in Item 1A of this Quarterly Report on Form 10-Q and our Annual Report on Form 10-K for the period ended December 31, ~~2018.~~2019. 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 ~~2017:~~2018:


	2017								2018								2019						2018								2019								2020
	Q1		Q2		Q3		Q4		Q1		Q2		Q3		Q4		Q1		Q2		Q3		Q1		Q2		Q3		Q4		Q1		Q2		Q3		Q4		Q1
Crude oil	$	51.86	$	48.29	$	48.19	$	55.39	$	62.89	$	67.90	$	69.50	$	58.83	$	54.90	$	59.83	$	56.45	$	62.89	$	67.90	$	69.50	$	58.83	$	54.90	$	59.83	$	56.45	$	56.96	$	46.08
Natural gas	$	3.07	$	3.09	$	2.89	$	2.87	$	3.13	$	2.77	$	2.88	$	3.62	$	3.00	$	2.58	$	2.29	$	3.13	$	2.77	$	2.88	$	3.62	$	3.00	$	2.58	$	2.29	$	2.44	$	1.88

Oil prices declined sharply during the first quarter of 2020, dropping below $21.00 per Bbl in March 2020 and further dropping below negative $37.00 per Bbl in April 2020. This dramatic decline in pricing is primarily in response to Saudi Arabia’s announcement of plans to abandon previously agreed upon output restraints and the economic effects of the coronavirus (“COVID-19”) pandemic on the demand for oil and natural gas. Lower oil, NGL and natural gas prices may not only decrease our revenues on a per unit basis, but may also reduce the amount of oil and natural gas that we can produce economically and therefore potentially lower our oil and gas reserve quantities. Substantial and extended declines in oil, NGL and natural gas prices have resulted, and may result, in impairments of our proved oil and gas properties or undeveloped acreage (such as the impairments discussed below under the “Results of Operations”) and may materially and adversely affect our future business, financial condition, cash flows, results of operations, liquidity or ability to finance planned capital expenditures. In addition, lower commodity prices may reduce the amount of our borrowing base under our credit agreement, which is determined at the discretion of our lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders, as occurred with our most recent semi-annual redetermination where the borrowing base was lowered from $2.25 billion to $2.05 billion in October 2019. 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.

Recent Developments

Chapter 11 Cases. On April 1, 2020 (the “Petition Date”), Whiting and certain of its subsidiaries (the “Debtors”) commenced voluntary cases (the “Chapter 11 Cases”) under chapter 11 of the Bankruptcy Code.

On April 23, 2020 the Debtors entered into a restructuring support agreement (“RSA”) with certain holders of our senior notes to support a restructuring in accordance with the terms set forth in our chapter 11 plan of reorganization (the “Plan”). The Plan and the related disclosure statement were each filed with the Bankruptcy Court on April 23, 2020. We expect to continue operations in the normal course for the duration of the Chapter 11 Cases. To ensure ordinary course operations, we have obtained approval from the Bankruptcy

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Court for certain “first day” motions, including motions to obtain customary relief intended to assure our ability to continue our ordinary course operations after the filing date. In addition, we have received authority to use cash collateral of the lenders under Whiting Oil and Gas’ credit agreement (the “Credit Agreement”) on an interim basis. The final hearing on use of cash collateral is currently scheduled for May 29, 2020. For more information on the Chapter 11 Cases and related matters, refer to the “Basis of Presentation” and “Long-Term Debt” footnotes in the notes to the condensed consolidated financial statements.

Proved Undeveloped Reserves. As a result of lower crude oil, NGL and natural gas prices and a substantial reduction in our capital plan incorporated into our reserve estimates at March 31, 2020, our proved undeveloped reserves decreased from 126.6 MMBOE as of December 31, 2019 to 62.8 MMBOE as of March 31, 2020, which represents a 50% reduction between periods. Approximately 80% of this decrease in reserve volumes was the result of a change in the planned timing of the drilling and completion of PUD reserve locations outside of the SEC five-year window.

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

2020 Highlights and Future Considerations

Operational Highlights

Northern Rocky Mountains – Williston Basin

Our properties in the Williston Basin of North Dakota and Montana target the Bakken and Three Forks formations. Net production from the Williston Basin averaged ~~111.4~~100.2 MBOE/d for the ~~third~~first quarter of ~~2019,~~2020, representing ~~a 2%~~an 11% decrease from ~~113.2~~112.0 MBOE/d in the ~~second~~fourth quarter of 2019. First quarter 2020 production was negatively impacted by severe weather conditions and associated electric submersible pump failures on multiple high value wells. Across our acreage in the Williston Basin, we have implemented customized, right-sized completion designs which utilize the optimum volume of proppant, fluids, and frac stages to increase well performance while reducing cost. We have increased stages pumped per day by focusing on new technologies such as quick-install wellhead connections and frac plug innovations. We plan to continue to use right-sized completion design on future wells we drill, ~~in 2019,~~ while also utilizing state-of-the-art drilling rigs, high-torque mud motors and 3-D bit cutter technology to reduce time-on-location and total well cost. ~~As of September 30, 2019, we had four rigs active in the Williston Basin.~~ We drilled 28 wells and put ~~39 operated~~24 wells on production in this area during the ~~third~~first quarter of ~~2019.~~2020. As of March 31, 2020, we had three rigs active in the Williston Basin, however, as noted below in “Operational Response to Market Conditions,” we subsequently released all our drilling rigs during April 2020.

Central Rocky Mountains – Denver-Julesburg Basin

Our Redtail field in the Denver-Julesburg Basin (“DJ Basin”) in Weld County, Colorado targets the Niobrara and Codell/Fort Hays formations. Net production from the Redtail field averaged ~~11.2~~9.3 MBOE/d in the ~~third~~first quarter of ~~2019,~~2020, representing ~~a 15%~~an 11% decrease from ~~13.1~~10.4 MBOE/d in the ~~second~~fourth quarter of 2019. We have established production in the Niobrara “A”, “B” and “C” zones and the Codell/Fort Hays formations. ~~In late 2017, based on the comparative well performance results of the DJ Basin to the Williston Basin, our management decided to concentrate future~~We have maintained base production with improved artificial lift techniques and reductions in lease operating expenses. Future development activities in the Williston Basin. We completed 22 of our drilled uncompleted wells in our Redtail field during the first half of 2018 and we currently have no plans for additional development activity in this area. Future activity in our Redtail field is subject to market conditions.

Our Redtail gas plant processes the associated gas produced from our wells in this area, and has a current inlet capacity of 50 MMcf/d. As of ~~September 30, 2019,~~March 31, 2020, the plant was processing 2522 MMcf/d.

Operational Response to Market Conditions

As a result of the significant decline in crude oil prices in the first quarter of 2020 and continuing throughout April 2020, we temporarily suspended all drilling and completion activity and released all of our drilling rigs during April 2020, incurring insignificant early termination and demobilization fees. Additionally, we have reduced the number of workover rigs used on our wells. We expect this reduced activity will negatively impact our production across all of our properties for the remainder of 2020. Substantial and extended declines in crude oil prices may result in our decision to voluntarily curtail production on our existing wells in the future.

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Financing Highlights

In ~~September 2019,~~March 2020, we paid ~~$299~~$53 million to ~~complete a cash tender offer for $300~~repurchase $73 million aggregate principal amount of our ~~2020~~1.25% Convertible Senior Notes due April 1, 2020 (the “2020 Convertible Senior Notes”), which payment consisted of the ~~99.0%~~average 72.5% purchase price plus all accrued and unpaid interest on the notes.

~~In September 2019, we paid $24 million to repurchase $25~~ We financed the repurchases with borrowings under the Credit Agreement. Additionally, in March 2020, holders of $3 million aggregate principal amount of ~~our 2021~~2020 Convertible Senior Notes timely elected to convert. Upon such conversion, such holders of converted 2020 Convertible Senior Notes were entitled to receive an insignificant cash payment on April 1, 2020, which ~~payment consisted~~we did not pay in conjunction with the filing of the average 94.708% purchase price plus all accrued and unpaid interest on the notes. In October 2019, we paid an additional $72 million to repurchase $75 million aggregate principal amount of the 2021 Senior Notes, which payment consisted of the average 95.467% purchase price plus all accrued and unpaid interest on the notes.

~~We financed the tender offer and repurchases with borrowings under our credit agreement.~~Chapter 11 Cases. Refer to the ~~“Long Term~~“Long-Term Debt” footnote in the notes to the condensed consolidated financial statements for more information on these repurchases and conversions.

On April 1, 2020, in conjunction with the filing of the Chapter 11 Cases, we did not make the $187 million principal payment due on our 2020 Convertible Senior Notes. Any efforts to enforce payment obligations related to the acceleration of our debt have been automatically stayed as a result of the filing of the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. Refer to the “Long-Term Debt” footnote in the notes to the condensed consolidated financial statements for more information on the ~~tender offer~~Chapter 11 Cases and ~~repurchases.~~

~~In October 2019,~~ the borrowing base under our credit agreement was reduced from $2.25 billion to $2.05 billion in connection with the November 1, 2019 regular borrowing base redetermination, with no change to the aggregate commitments of $1.75 billion.automatic stay.

Acquisition and Divestiture Highlights

On ~~July 29, 2019,~~January 9, 2020, we completed the divestiture of our interests in ~~137~~30 non-operated, producing oil and gas wells and related undeveloped acreage located in McKenzie ~~Mountrail and Williams counties of~~County, North Dakota for aggregate sales proceeds of ~~$27~~$25 million (before closing adjustments).

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

~~On a combined basis, the~~The divested properties consisted of less than 1% of our estimated proved reserves as of December 31, ~~2018~~2019 and 1% of our ~~April 2019~~ average daily ~~production.~~

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~~Restructuring~~

~~On July~~production for the year ended December 31, 2019, we executed a workforce reduction as part of an organizational redesign and cost reduction strategy to better align our business with the current operating environment and drive long-term value. We expect the restructuring to result in annual cost savings of approximately $50 million, approximately 75% of which is general and administrative expense and 25% is lease operating expenses and exploration expense. We incurred a one-time net charge of $8 million during the third quarter of 2019 related to this restructuring.

2019.

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Results of Operations

~~Nine~~Three Months Ended ~~September 30, 2019~~March 31, 2020 Compared to ~~Nine~~Three Months Ended ~~September 30, 2018~~March 31, 2019


	Nine Months Ended September 30,				Three Months Ended March 31,
	2019		2018		2020		2019
Net production
Oil (MMBbl)		22.4		23.4		6.3		7.5
NGLs (MMBbl)		5.7		5.6		1.8		1.9
Natural gas (Bcf)		38.2		34.7		11.6		12.6
Total production (MMBOE)		34.5		34.8		10.0		11.6
Net sales (in millions)
Oil ⁽¹⁾	$	1,133.3	$	1,448.3	$	231.9	$	359.5
NGLs		34.8		114.0		10.9		12.9
Natural gas		23.5		45.9		2.0		17.1
Total oil, NGL and natural gas sales	$	1,191.6	$	1,608.2	$	244.8	$	389.5
Average sales prices
Oil (per Bbl) ⁽¹⁾	$	50.51	$	61.99	$	37.03	$	47.71
Effect of oil hedges on average price (per Bbl)		0.66		(6.01)		5.08		0.21
Oil after the effect of hedging (per Bbl)	$	51.17	$	55.98
Oil net of hedging (per Bbl)					$	42.11	$	47.92
Weighted average NYMEX price (per Bbl) ⁽²⁾	$	56.99	$	66.80	$	46.05	$	54.83
NGLs (per Bbl)	$	6.09	$	20.32	$	6.01	$	6.62
Natural gas (per Mcf)	$	0.62	$	1.32	$	0.17	$	1.36
Weighted average NYMEX price (per MMBtu) ⁽²⁾	$	2.62	$	2.93	$	1.88	$	3.00
Costs and expenses (per BOE)
Cost and expenses (per BOE)
Lease operating expenses	$	7.43	$	6.63	$	7.22	$	7.26
Transportation, gathering, compression and other	$	0.93	$	1.02	$	0.89	$	0.85
Production and ad valorem taxes	$	2.98	$	3.86	$	2.24	$	2.43
Depreciation, depletion and amortization	$	17.74	$	16.81	$	18.37	$	17.11
General and administrative	$	2.82	$	2.73	$	4.71	$	3.02

(1)	Before consideration of hedging transactions.

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

Oil, NGL and Natural Gas Sales. Our oil, NGL and natural gas sales revenue decreased ~~$417~~$145 million to ~~$1.2 billion~~$245 million when comparing the first ~~nine months~~quarter of ~~2019~~2020 to the same period in ~~2018. Sales~~2019. Changes in sales revenue ~~is a function~~between periods are due to changes in production sold and changes in average commodity prices realized (excluding the impacts of hedging). For the first quarter of 2020, decreases in total production accounted for approximately $63 million of the change in revenue and decreases in commodity prices realized accounted for approximately $82 million of the change in revenue when comparing to the first quarter of 2019.

Our oil, NGL and gas volumes ~~sold~~decreased 17%, 7% and ~~average commodity prices realized. Our oil volumes decreased 4% and our NGL and natural gas sales volumes increased 2% and 10%~~8%, respectively, between periods. The ~~oil~~ volume ~~decrease~~decreases between periods ~~was~~were primarily attributable to the impact of severe weather conditions and associated electric submersible pump failures on multiple high value wells in the Williston Basin in the first quarter of 2020, as well as normal field production decline primarily in the DJ Basin where we have ~~currently~~ ceased ~~our~~ development activity as well as infrastructure constraints in the Williston Basin and the impact of severe weather experienced in both the Williston Basin and the DJ Basin during the first nine months of 2019. This decrease wasuntil prices recover. These decreases were partially offset by increased production from new wells drilled and completed over the last twelve months in the Williston Basin which added 8,235 MBbl of oil production during the first nine months of 2019 as compared to the first nine months of 2018. The NGL volume increase between periods generally relates to new wells drilled and completed in the Williston Basin over the last twelve months, as well as additional volumes processed as more wells were connected to gas processing plants in the Williston Basin in an effort to increase our overall gas capture rate in this area and reduce flared volumes. Many of the new Williston Basin wells are in areas with higher gas-to-oil production ratios than previously drilled areas. These NGL volume increases were partially offset by normal field production decline across several of our areas. The gas volume increase between periods was primarily due to new wells drilled and completed at our Williston Basin and DJ Basin properties over the last twelve months which resulted in 10,585 MMcf and 750 MMcf, respectively,

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of additional gas volumes during the first nine months of 2019 as compared to the first nine months of 2018. These increases were partially offset by normal field production decline across several of our areas.Basin.

In addition to the above oil production-related decreases in net revenue, there were also decreases in the average sales price realized for oil, NGLs and natural gas in the first nine months of 2019 compared to 2018. Our average price for oil (before the effects of hedging), NGLs and natural gas decreased ~~19%~~22%, ~~70%~~9% and ~~53%~~88%, respectively. Our average sales price realized for oil is impacted by deficiency payments we were making under two physical delivery contracts at our Redtail field due to our inability to meet the minimum volume commitments under these contracts. During the nine months ended September 30, 2019 and 2018, our total average sales price realized for oil was $2.05 per Bbl lower and $1.17 per Bbl lower, respectively, as a result of these deficiency payments. On February 1, 2018, we paid $61 million to the counterparty to one of these Redtail delivery contracts to settle all future minimum volume commitments under the agreement. The remaining agreement will continue to negatively impact the price we receive for oil from our Redtail field through April 2020, when the contract terminates. Our average sales price realized for natural gas is impacted by rising market differentials as compared to NYMEX as well as high fixed third-party costs for transportation, gathering and compression services.

~~Lease Operating Expenses~~. Our lease operating expenses (“LOE”) during the first nine months of 2019 were $256 million, a $26 million increase over the same period in 2018. This increase was primarily due to new wells put on production in the Williston Basin during the past twelve months, as well as an increase in well workover activity between periods and rising costs of oilfield goods and services. These increases were partially offset by cost savings as a result of our company restructuring in July 2019 and cost reduction initiatives during the third quarter of 2019.

Our lease operating expenses on a BOE basis also increased when comparing the first nine months of 2019 to the same 2018 period. LOE per BOE amounted to $7.43 during the first nine months of 2019, which represents an increase of $0.80 per BOE (or 12%) from the first nine months of 2018. This increase was mainly due to the overall increase in LOE expense discussed above, as well as lower overall production volumes between periods.

~~Transportation, Gathering, Compression and Other.~~ Our transportation, gathering, compression and other expenses (“TGC”) during the first nine months of 2019 were $32 million, a $3 million decrease over the same period in 2018. This decrease was primarily due to lower realized NGL prices during the first nine months of 2019, which led to lower gas processing fees under our percentage-of-proceeds contracts as compared to the first nine months of 2018.

TGC per BOE also decreased when comparing the first nine months of 2019 to the same 2018 period. TGC per BOE amounted to $0.93 per BOE during the first nine months of 2019, which represents a decrease of $0.09 per BOE (or 9%) from the first nine months of 2018. This decrease was mainly due to the overall decrease in TGC expense discussed above, partially offset by lower overall production volumes between periods.

~~Production and Ad Valorem Taxes~~. Our production and ad valorem taxes during the first nine months of 2019 were $103 million, a $31 million decrease over the same period in 2018, which was primarily due to lower sales revenue between periods. Our production taxes, however, are generally calculated as a percentage of net sales revenue before the effects of hedging, and this percentage on a company-wide basis was 8.5% and 7.9% for the first nine months of 2019 and 2018, respectively. Our production tax rate for 2019 was higher than the rate for 2018 primarily due to our concentration of development over the past twelve months in the Williston Basin states of North Dakota and Montana, which have higher tax rates than Colorado where we have had limited development activity over the past twelve months. This increase in rate was partially offset by certain North Dakota wells receiving stripper well status, which reduces the tax rate from 10% to 5%.

~~Depreciation, Depletion and Amortization~~. Our depreciation, depletion and amortization (“DD&A”) expense increased $28 million in 2019 as compared to the first nine months of 2018. The components of our DD&A expense were as follows (in thousands):

Nine Months Ended September 30,

2019

2018
Depletion

$
599,320

$
571,121
Accretion of asset retirement obligations

8,680

8,365
Depreciation

4,166

4,733
Total

$
612,166

$
584,219

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DD&A increased between periods primarily due to $28 million in higher depletion expense, consisting of a $32 million increase related to a higher depletion rate between periods, partially offset a $4 million decrease due to lower overall production volumes during the first nine months of 2019. On a BOE basis, our overall DD&A rate of $17.74 for the first nine months of 2019 was 6% higher than the rate of $16.81 for the same period in 2018. The primary factors contributing to this higher DD&A rate were a recent shift in our development activity to areas with higher average historical DD&A rates and downward revisions to proved reserves over the last twelve months.

~~Exploration and Impairment Costs~~. Our exploration and impairment costs increased $2 million for the first nine months of 2019 as compared to the same period in 2018. The components of our exploration and impairment expense were as follows (in thousands):

Nine Months Ended September 30,

2019

2018
Exploration

$
28,316

$
15,940
Impairment

15,729

25,612
Total

$
44,045

$
41,552

Exploration costs increased $12 million during the first nine months of 2019 as compared to the same period in 2018 primarily due to increased deficiency fees paid under our produced water disposal agreement driven by reduced drilling and completion activity at our Redtail field during the past twelve months.

~~Impairment expense for the first nine months of 2019 and 2018 primarily relates to the amortization of leasehold costs associated with individually insignificant unproved properties.~~

~~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):~~

Nine Months Ended September 30,

2019

2018
General and administrative expenses

$
170,924

$
168,701
Reimbursements and allocations

(73,487)

(73,719)
General and administrative expenses, net

$
97,437

$
94,982

G&A expense, net, increased $2 million when comparing the first nine months of 2019 to the same 2018 period primarily due to an $8 million net charge related to our company restructuring, which was partially offset by savings from lower employee compensation costs post-restructuring. Refer to “Restructuring” for more information on this event.

G&A expense per BOE also increased when comparing the first nine months of 2019 to the same 2018 period. G&A expense per BOE amounted to $2.82 during the first nine months of 2019, which represents an increase of $0.09 per BOE (or 3%) from the first nine months of 2018. This increase was mainly due to lower overall production volumes between periods, as well as the overall increase in G&A expense discussed above.

~~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 making or receiving a payment to or from the counterparty. Derivative (gain) loss, net, amounted to a loss of $7 million and $177 million for the nine months ended September 30, 2019 and 2018, respectively. These losses are primarily related to our collar, swap and option commodity derivative contracts and resulted from the upward shift in the futures curve of forecasted commodity prices for crude oil during the respective periods.

~~Refer to Item 3, “Quantitative and Qualitative Disclosures about Market Risk”, for a list of our outstanding commodity derivative contracts as of September 30, 2019.~~

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

Nine Months Ended September 30,

2019

2018
Notes

$
111,679

$
115,109
Amortization of debt issue costs, discounts and premiums

23,707

22,976
Credit agreement

9,281

10,431
Other

607

1,042
Total

$
145,274

$
149,558

The decrease in interest expense of $4 million between periods was mainly attributable to lower interest costs incurred on our notes during the first nine months of 2019 as compared to the first nine months of 2018, resulting from the redemption of the 2019 Notes in January 2018 and the tender offer for the 2020 Convertible Notes and the repurchases of the 2021 Notes in September 2019. Refer to the “Long-Term Debt” footnote in the notes to condensed consolidated financial statements for more information on these debt transactions.

Our weighted average debt outstanding during the first nine months of 2019 was $2.9 billion versus $3.1 billion for the first nine months of 2018. Our weighted average effective cash interest rate was 5.5% during both the first nine months of 2019 and the first nine months of 2018.

~~Gain (Loss) on Extinguishment of Debt.~~ During the first nine months of 2019, we recognized a gain on extinguishment of debt of $5 million. In September 2019, we paid $299 million to purchase $300 million aggregate principal amount of the 2020 Convertible Senior Notes in a cash tender offer and recognized a $4 million gain on extinguishment of debt. Additionally, we paid $24 million to repurchase $25 million aggregate principal amount of the 2021 Senior Notes and recognized a $1 million gain on extinguishment of debt. During the first nine months of 2018, we redeemed all of the remaining $961 million aggregate principal amount of 2019 Senior Notes and recognized a $31 million loss on extinguishment of debt. Refer to the “Long-Term Debt” footnote in the notes to condensed consolidated financial statements for more information on these debt transactions.

~~Income Tax Benefit~~. Income tax benefit for the first nine months of 2019 totaled $1 million. As of December 31, 2017, we recorded a full valuation allowance on our deferred tax assets. Accordingly, we did not recognize any income tax expense or benefit during the first nine months of 2018. As a result of positive pre-tax income during 2018, we transitioned from a net deferred tax asset position to a net deferred tax liability position as of December 31, 2018, and we released the valuation allowance that was established in 2017. As a result of pre-tax losses for the first six months of 2019, we transitioned from a net deferred tax liability position to a net deferred tax asset position which resulted in the recognition of a full valuation allowance on our deferred tax assets again during the second quarter of 2019.

Our overall effective tax rate of 1.4% for the first nine months of 2019 was lower than the U.S. statutory income tax rate due to the recognition of a full valuation allowance during the second quarter of 2019.

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~~Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018~~

Three Months Ended

September 30,

2019

2018
Net production

Oil (MMBbl)

7.4

7.9
NGLs (MMBbl)

1.8

1.9
Natural gas (Bcf)

12.5

12.1
Total production (MMBOE)

11.4

11.8
Net sales (in millions)

Oil ⁽¹⁾

$
370.0

$
511.9
NGLs

5.6

42.5
Natural gas

0.3

12.3
Total oil, NGL and natural gas sales

$
375.9

$
566.7
Average sales prices

Oil (per Bbl) ⁽¹⁾

$
49.71

$
64.70
Effect of oil hedges on average price (per Bbl)

1.41

(7.88)
Oil net of hedging (per Bbl)

$
51.12

$
56.82
Weighted average NYMEX price (per Bbl) ⁽²⁾

$
56.43

$
69.52
NGLs (per Bbl)

$
3.07

$
22.22
Natural gas (per Mcf)

$
0.03

$
1.02
Weighted average NYMEX price (per MMBtu) ⁽²⁾

$
2.29

$
2.88
Cost and expenses (per BOE)

Lease operating expenses

$
7.51

$
6.31
Transportation, gathering, compression and other

$
0.98

$
1.08
Production and ad valorem taxes

$
3.10

$
4.22
Depreciation, depletion and amortization

$
18.58

$
16.64
General and administrative

$
2.63

$
2.69

~~(1)~~

~~Before consideration of hedging transactions.~~

~~(2)~~

~~Average NYMEX pricing weighted for monthly production volumes.~~

~~Oil, NGL and Natural Gas Sales~~. Our oil, NGL and natural gas sales revenue decreased $191 million to $376 million when comparing the third quarter of 2019 to the same period in 2018. Sales revenue is a function of oil, NGL and gas volumes sold and average commodity prices realized. Our oil and NGL volumes decreased 6% and 4%, respectively, and our natural gas sales volumes increased 4% between periods. The oil volume decrease between periods was primarily attributable to normal field production decline primarily in the DJ Basin, where we have currently ceased our development activity, as well as the impact of severe weather experienced in the Williston Basin during the third quarter of 2019. This decrease was partially offset by new wells drilled and completed over the last twelve months in the Williston Basin which added 3,000 MBbl of oil production during the third quarter of 2019 as compared to the third quarter of 2018. The NGL volume decrease between periods generally relates to normal field production decline across several of our areas, partially offset by new wells drilled and completed in the Williston Basin over the last twelve months as well as additional volumes processed as more wells were connected to gas processing plants in the Williston Basin in an effort to increase our overall gas capture rate in this area and reduce flared volumes. The gas volume increase between periods was primarily due to new wells drilled and completed at our Williston Basin properties over the last twelve months which resulted in 3,160 MMcf of additional gas volumes during the third quarter of 2019 as compared to the third quarter of 2018 as well as higher gas-to-oil production ratios than what was experienced in previously drilled areas. These increases were partially offset by normal field production decline across several of our areas.

~~Table of Contents~~

In addition to the above oil and NGL production-related decreases in net revenue, there were also decreases in the average sales price realized for oil, NGLs and natural gas in the third quarter of 2019 compared to 2018. Our average price for oil (before the effects of hedging), NGLs and natural gas decreased 23%, 86% and 97%, respectively. Our average sales price realized for oil is impacted by deficiency payments we were makingmade under a physical delivery contract at our Redtail field due to our inability to meet the minimum volume commitments under this contract. During the three months ended ~~September 30, 2019~~March 31, 2020 and ~~2018,~~ 2019,

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our total average sales price realized for oil was ~~$2.38~~$2.91 per Bbl lower and ~~$1.30~~$1.71 per Bbl lower, respectively, as a result of these deficiency payments. This agreement will continue to negatively impact the price we receive for oil from our Redtail field through April 2020, when the contract terminates. Our average sales price realized for natural gas is impacted by rising market differentials as compared to NYMEX as well as high fixed third-party costs for transportation, gathering and compression services.

Lease Operating Expenses. Our ~~LOE~~lease operating expenses (“LOE”) during the first quarter of 2020 were $72 million, a $12 million decrease over the same period in 2019. This decrease was primarily due to cost reduction initiatives implemented beginning in the third quarter of 2019, were $85 million, an $11 million increase over the same period in 2018. This increase was primarily due to new wells put on production in the Williston Basin during the past twelve months, as well aspartially offset by an increase in well workover activity between periods and rising costs of oilfield goods and services. These increases were partially offset by cost savings as a result of our company restructuring in July 2019 and cost reduction initiatives during the third quarter of 2019.periods.

Our lease operating expenses on a BOE basis also ~~increased~~decreased when comparing the ~~third~~first quarter of ~~2019~~2020 to the same ~~2018~~2019 period. LOE per BOE amounted to ~~$7.51~~$7.22 during the ~~third~~first quarter of ~~2019,~~2020, which represents ~~an increase of $1.20 per BOE (or 19%)~~a slight decrease from the ~~third~~first quarter of ~~2018.~~2019. This ~~increase~~decrease was mainly due to the overall ~~increase~~decrease in LOE expense discussed above ~~as well as~~partially offset by lower overall production volumes between periods.

Transportation, Gathering, Compression and Other. Our ~~TGC~~transportation, gathering, compression and other (“TGC”) expenses during the ~~third~~first quarter of 2020 were ~~$11~~$9 million, a ~~$2 million~~slight decrease over the same period in 2018. This decrease was primarily due to lower realized NGL prices during the third quarter of 2019, which led to lower gas processing fees under our percentage-of-proceeds contracts as compared to the third quarter of 2018.2019.

TGC per BOE, ~~also decreased~~however, increased when comparing the ~~third~~first quarter of ~~2019~~2020 to the same ~~2018~~2019 period. TGC per BOE amounted to ~~$0.98 per BOE~~$0.89 during the ~~third~~first quarter of ~~2019,~~2020, which represents a ~~$0.10~~$0.04 per BOE (or 9%5%) ~~decrease~~increase from the ~~third~~first quarter of ~~2018.~~2019. This ~~decrease~~increase was mainly due to ~~the decrease in TGC expense discussed above, partially offset by~~ lower overall production volumes between periods.

Production and Ad Valorem Taxes. Our production and ad valorem taxes during the ~~third~~first quarter of ~~2019~~2020 were ~~$35~~$22 million, a ~~$15~~$6 million decrease over the same period in ~~2018,~~2019, which was primarily due to lower sales revenue between periods. Our production taxes, however, are generally calculated as a percentage of net sales revenue before the effects of hedging, and this percentage on a company-wide basis was ~~9.1%~~8.8% and ~~8.2%~~7.5% for the ~~third~~first quarter of ~~2019~~2020 and ~~2018,~~2019, respectively. Our production tax rate for ~~2019~~2020 was higher than the rate for ~~2018~~2019 due to our concentration of development activity over the past twelve months in the Williston Basin states of North Dakota and Montana, which have higher tax rates than Colorado where we have had limited development activity over the past twelve months. This increase in rate was partially offset by certain North Dakota wells receiving stripper well status, which reduces the tax rate from 10% to 5%.

Depreciation, Depletion and Amortization. Our depletion, depreciation and amortization (“DD&A&A”) expense ~~increased~~decreased $14 million in ~~2019~~2020 as compared to the ~~third~~first quarter of ~~2018.~~2019. The components of our DD&A expense were as follows (in thousands):


	Three Months Ended
	September 30,				Three Months Ended March 31,
	2019		2018		2020		2019
Depletion	$	206,793	$	192,505	$	179,697	$	193,870
Accretion of asset retirement obligations		2,861		2,911		3,027		2,882
Depreciation		1,371		1,590		1,244		1,380
Total	$	211,025	$	197,006	$	183,968	$	198,132

DD&A ~~increased~~decreased between periods primarily due to $14 million in ~~higher~~lower depletion expense, consisting of a ~~$23 million increase related to a higher depletion rate between periods, partially offset by a $9~~$28 million decrease due to lower overall production volumes during the ~~third~~first quarter of ~~2019.~~2020, partially offset by a $14 million increase related to a higher depletion rate between periods. On a BOE basis, however, our overall DD&A rate of ~~$18.58~~$18.37 for the ~~third~~first quarter of ~~2019~~2020 was ~~12%~~7% higher than the rate of ~~$16.64~~$17.11 for the same period in ~~2018.~~2019. The primary ~~factors~~factor contributing to this higher DD&A rate ~~were a recent shift in our development activity to areas with higher average historical DD&A rates and~~was downward revisions to proved reserves over the last twelve months.

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Exploration and Impairment Costs. Our exploration and impairment costs ~~decreased $2 million~~increased $3.7 billion for the ~~third~~first quarter of ~~2019~~2020 as compared to the same period in ~~2018.~~2019. The components of our exploration and impairment expense were as follows (in thousands):


	Three Months Ended				Three Months Ended March 31,
	September 30,				2020		2019
	2019		2018
Impairment					$	3,745,092	$	9,843
Exploration	$	8,340	$	5,177		8,365		9,906
Impairment		2,550		7,302
Total	$	10,890	$	12,479	$	3,753,457	$	19,749

Exploration costs increased $3 million during the third quarter of 2019 as compared to the same period in 2018 primarily due to increased deficiency fees paid under our produced water disposal agreement driven by reduced drilling and completion activity at our Redtail field during the past twelve months.

Impairment expense for the ~~third~~first quarter of ~~2019~~2020 primarily related to (i) a $3.7 billion non-cash impairment charge for the partial write-down of proved oil and ~~2018~~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 the properties, and (ii) $12 million in impairment write-downs of undeveloped acreage costs for leases where we no longer have plans to drill. Impairment expense for the first quarter of 2019 primarily relates to the amortization of leasehold costs associated with individually insignificant unproved properties.

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


	Three Months Ended
	September 30,				Three Months Ended March 31,
	2019		2018		2020		2019
General and administrative expenses	$	53,473	$	55,866	$	63,912	$	59,484
Reimbursements and allocations		(23,583)		(23,965)		(16,745)		(24,510)
General and administrative expenses, net	$	29,890	$	31,901	$	47,167	$	34,974

G&A expense ~~net, decreased $2~~before reimbursement and allocations increased $4 million ~~when comparing~~during the first quarter of 2020 primarily due to (i) $14 million of expense related to cash retention incentives paid to executives and employees during the first quarter of 2020, (ii) $8 million of third-party advisory and legal fees incurred to prepare for the Chapter 11 Cases and (iii) $3 million of credit loss expense based on the status of certain receivables outstanding and expected future economic conditions. These increases were partially offset by cost reduction initiatives instituted as part of a company restructuring beginning in the third quarter of 2019, including $12 million in lower compensation costs, outside of the aforementioned retention incentives. The decrease in reimbursements and allocations for the first quarter of 2020 was the result of a lower number of field workers on Whiting-operated properties associated with reduced drilling activity.

Our G&A expenses on a BOE basis increased when comparing the first quarter of 2020 to the same ~~2018 period primarily due to lower employee compensation costs as a result of the company restructuring during the third quarter of~~ 2019 ~~partially offset by an $8 million one-time net charge related to the restructuring. Refer to “Restructuring” for more information on this event.~~

~~G&A expense per BOE also decreased when comparing the third quarter of 2019 to the same 2018~~ period. G&A expense per BOE amounted to ~~$2.63~~$4.71 during the ~~third~~first quarter of ~~2019,~~2020, which represents ~~a decrease~~an increase of ~~$0.06~~$1.69 per BOE (or 2%56%) from the ~~third~~first quarter of ~~2018.~~2019. This ~~decrease~~increase was mainly due to the overall ~~decrease~~increases in G&A expense discussed above, ~~partially offset by~~as well as lower overall production volumes between periods.

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 making or receiving a payment to or from the counterparty. Derivative (gain) loss, net, amounted to a gain of ~~$31~~$231 million and a loss of ~~$21~~$63 million for the three months ended ~~September 30,~~March 31, 2020 and 2019, ~~and 2018,~~ respectively. These gains and losses are primarily related to our collar, swap and option commodity derivative contracts and resulted from the downward and upward shifts, respectively, in the futures curve of forecasted commodity prices for crude oil during the respective periods.

~~Gain (Loss)~~For more information on ~~Extinguishment~~our outstanding derivatives refer to the “Derivative Financial Instruments” footnote in the notes to the condensed consolidated financial statements.

Table of ~~Debt.~~ Contents

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

Three Months Ended March 31,

2020

2019
Notes

$
34,840

$
37,256
Amortization of debt issue costs, discounts and premiums

4,536

7,818
Credit agreement

5,518

2,986
Other

356

39
Total

$
45,250

$
48,099
The decrease in interest expense of $3 million between periods was primarily attributable to lower interest costs incurred on our notes during the ~~third~~first quarter of ~~2019, we recognized a gain on extinguishment~~2020 compared to the first quarter of ~~debt of $5 million. In September 2019, we paid $299~~2019. The $2 million ~~to purchase~~decrease in note interest primarily resulted from (i) the tender offer for $300 million aggregate principal amount of ~~the~~ 2020 Convertible ~~Senior~~ Notes in ~~a cash tender offer and recognized a $4 million gain on extinguishment~~September 2019, (ii) the repurchase of ~~debt. Additionally, we paid $24 million to repurchase $25~~$100 million aggregate principal amount of the 2021 Senior Notes in September and October 2019 and (iii) the repurchase of $73 million aggregate principal amount of the 2020 Convertible Notes in March 2020. Refer to the “Long-Term Debt” footnote in the notes to the condensed consolidated financial statements for more information on these debt transactions.
Our weighted average debt outstanding during the first quarter of 2020 and 2019 was $2.9 billion. Our weighted average effective cash interest rate was 5.5% during the first quarter of 2020 and 2019.
Gain on Extinguishment of Debt. In March 2020, we paid $53 million to repurchase $73 million aggregate principal amount of our 2020 Convertible Senior Notes and recognized a $1$23 million gain on extinguishment of debt. Additionally, in March 2020, the holders of $3 million aggregate principal amount of our 2020 Convertible Senior Notes elected to convert. Upon conversion, such holders of the converted 2020 Convertible Senior Notes were entitled to receive an insignificant cash payment on April 1, 2020, which we did not pay in conjunction with the filing of the Chapter 11 Cases. As a result of such conversion we recognized a $3 million gain on extinguishment of debt for the three months ended March 31, 2020. Refer to the “Long-Term Debt” footnote in the notes to condensed consolidated financial statements for more information on ~~these debt transactions.~~
~~Refer to Item 3, “Quantitative~~this repurchase and ~~Qualitative Disclosures about Market Risk”, for a list~~conversion and the effect of ~~our outstanding commodity derivative contracts as~~the automatic stay issued in conjunction with the filing of ~~September 30, 2019.~~

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~~Interest Expense~~~~. Interest remained relatively consistent when comparing~~ the ~~third quarter of 2019 to the same period in 2018. The components of our interest expense were as follows (in thousands):~~

Three Months Ended

September 30,

2019

2018
Notes

$
37,165

$
37,257
Amortization of debt issue costs, discounts and premiums

7,973

7,634
Credit agreement

3,039

3,125
Other

270

312
Total

$
48,447

$
48,328
Our weighted average debt outstanding during the third quarter of 2019 was $2.9 billion versus $3.0 billion for the third quarter of 2018. Our weighted average effective cash interest rate was 5.5% during the third quarter of 2019 compared to 5.4% during the third quarter of 2018.Chapter 11 Cases.
Income Tax Benefit. As of December 31, 2017, we recorded a full valuation allowance on our deferred tax assets. Accordingly, we did not recognize any income tax expense or benefit during the third quarter of 2018. As a result of positive pre-tax income during 2018, we transitioned from a net deferred tax asset position to a net deferred tax liability position as of December 31, 2018, and we released the valuation allowance that was established in 2017. However, as a result of pre-tax losses for the first six months of 2019, we transitioned from a net deferred tax liability position to a net deferred tax asset position which resulted in the recognition of a full valuation allowance on our deferred tax assets ~~again~~ during the second quarter of 2019. As a result of the full valuation allowance on our U.S. deferred tax assets (“DTAs”) as of March 31, 2020, we did not recognize any income tax expense or benefit during the first quarter of 2020. Income tax benefit for the first quarter of 2019 totaled $25 million. Additionally, during the fourth quarter of 2019, we recognized $74 million of Canadian deferred tax expense associated with the outside basis difference in Whiting Canadian Holding Company ULC pursuant to ASC 740-30-25-17. During the three months ended March 31, 2020, $4 million of this Canadian deferred tax expense became current. Refer to the “Income Taxes” footnote in the notes to the condensed consolidated financial statements for more information on this deferred tax liability.
Our overall effective tax rate of 0% for the ~~third~~first quarter of ~~2019~~2020 was lower than the U.S. statutory income tax rate ~~due to~~as a result of the ~~recognition of a~~ full valuation allowance ~~during the second quarter of 2019.~~on our DTAs.
Liquidity and Capital Resources
Overview. At ~~September 30, 2019,~~March 31, 2020, we had no$566 million of cash on hand and ~~$4.2 billion~~$395 million of equity, while at December 31, ~~2018,~~2019, we had ~~$14~~$9 million of cash on hand and ~~$4.3~~$4.0 billion of equity. In March 2020, we took proactive steps to ensure we had sufficient liquidity to fund ongoing operations by drawing $650 million on the Credit Agreement.
One of the primary sources of variability in our cash flows from operating activities is commodity price volatility, which we partially mitigate through the use of commodity hedge contracts. Oil accounted for ~~65%~~63% and ~~67%~~65% of our total production in the first ~~nine months~~quarter of ~~2019~~2020 and ~~2018,~~2019, respectively. As a result, our operating cash flows are more sensitive to fluctuations in oil prices than they are to fluctuations in NGL or natural gas prices. As of ~~September 30, 2019,~~May 1, 2020, we had derivative contracts covering the sale of ~~approximately 67%~~5 MBbl of ~~our forecasted~~ oil ~~production volumes~~per day through June 2020 and 1 MBbl of oil per day for the remainder of ~~2019.~~2020. For ~~a list of all of~~more information on our outstanding derivatives ~~as of September 30, 2019,~~ refer to ~~Item 3, “Quantitative and Qualitative Disclosures about Market Risk”.~~the “Derivative Financial Instruments” footnote in the notes to the condensed consolidated financial statements.

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During the first ~~nine months~~quarter of ~~2019,~~2020, we generated ~~$521~~$37 million of cash provided by operating activities, a decrease of ~~$286~~$111 million from the same period in ~~2018.~~2019. Cash provided by operating activities decreased primarily due to lower realized sales prices and production volumes for oil, NGLs and natural gas, ~~and lower crude oil production volumes,~~ as well as higher ~~lease operating expenses, exploration costs and~~ cash G&A expenses. These negative factors were partially offset by ~~higher NGL and natural gas production volumes, a decrease~~an increase in cash settlements ~~paid~~received on our derivative contracts, ~~and~~ lower lease operating expenses, production and ad valorem taxes, cash interest expense, TGC and ~~TGC~~exploration costs during the first ~~nine months~~quarter of ~~2019~~2020 as compared to the same period in ~~2018.~~2019. Refer to “Results of Operations” for more information on the impact of volumes and prices on revenues and for more information on increases and decreases in certain expenses between periods.

During the first ~~nine months~~quarter of ~~2019,~~2020, cash flows from operating activities, $695 million of net borrowings under the Credit Agreement and proceeds from the sale of properties ~~cash on hand and $365 million of net borrowings under our credit agreement~~ were used to finance ~~$625~~$146 million of drilling and development expenditures ~~$8 million of other property and equipment~~ and the repurchase of ~~$300~~$73 million aggregate principal amount of 2020 Senior Convertible Notes, which resulted in $566 million of remaining cash on hand as of March 31, 2020.

Chapter 11 Cases and ~~$25~~Effect of Automatic Stay. On April 1, 2020, the Debtors filed for relief under chapter 11 of the Bankruptcy Code. The commencement of a voluntary proceeding in bankruptcy constitutes an immediate event of default under the Credit Agreement and the indentures governing our senior notes, resulting in the automatic and immediate acceleration of all of our outstanding debt. In conjunction with the filing of the Chapter 11 Cases, we did not make the $187 million ~~aggregate~~ principal ~~amount of 2021~~payment due on our 2020 Convertible Senior Notes.

~~Table~~ Any efforts to enforce payment obligations related to the acceleration of ~~Contents~~our debt have been automatically stayed as a result of the filing of the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. Refer to the “Basis of Presentation” footnote in the notes to the condensed consolidated financial statements for more information on the Chapter 11 Cases.

On April 23, 2020, the Debtors entered into the RSA with certain holders of our senior notes to support a restructuring in accordance with the terms set forth in our chapter 11 plan of reorganization (the “Plan”). As more fully disclosed in the “Basis of Presentation” footnote in the notes to the condensed consolidated financial statements, the Plan and the RSA contemplate a restructuring which would provide for the treatment of holders of certain claims and existing equity interests.

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

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

As a result of the Chapter 11 Cases, our total available liquidity as of March 31, 2020 consisted of our $566 million of cash on hand. We expect to continue using additional cash that will further reduce this liquidity. With the Bankruptcy Court’s authorization to use cash collateral under the Credit Agreement, we believe that we will have sufficient liquidity, including cash on hand and funds generated from ongoing operations, to fund anticipated cash requirements through the Chapter 11 Cases. As such, we expect to pay vendor and royalty obligations on a go-forward basis according to the terms of our current contracts and consistent with applicable court orders, if any, approving such payments.

Exploration and Development Expenditures. ~~The following table details our~~During the three months ended March 31, 2020 and 2019, we incurred $146 million and $219 million, respectively, of exploration and development (“E&D”) expenditures. Of these expenditures, 94% and 98%, respectively, were incurred ~~by core area (in thousands):~~in our large resource play in the Williston Basin of North Dakota and Montana, where we have focused our development in 2019 and the first quarter of 2020.

Nine Months Ended

September 30,

2019

2018
Northern Rocky Mountains

$
666,707

$
512,187
Central Rocky Mountains

246

80,060
Other ⁽¹⁾

8,599

5,425
Total incurred

$
675,552

$
597,672
~~(1)~~ ~~Other primarily includes non-core oil and gas properties located in Colorado, Mississippi, New Mexico, North Dakota, Texas and Wyoming.~~
We continually evaluate our capital needs and compare them to our capital resources. Our ~~2019~~2020 E&D budget ~~has a forecasted midpoint of $820~~is $215 million, which we expect to fund ~~substantially~~ with net cash provided by operating activities and cash on ~~hand. The forecasted midpoint of our 2019 E&D budget~~hand, and represents a ~~slight~~substantial decrease from the ~~$832~~ $778

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million incurred on E&D expenditures during ~~2018. We believe that should additional attractive acquisition opportunities arise or E&D expenditures exceed $820 million, we will be able~~2019. This reduced capital budget is in response to ~~finance additional~~the significantly lower crude oil prices experienced during the first quarter of 2020 and continuing into the second quarter and our plan to preserve our liquidity while improving capital ~~expenditures through agreements~~efficiency and continue aligning our capital spending with ~~industry partners, divestitures of certain oil and gas property interests, borrowings under our credit agreement or by accessing the capital markets.~~cash flows generated from operations. Our level of E&D expenditures is largely discretionary, although a portion of our E&D expenditures are for non-operated properties where we have limited control over the timing and amount of such expenditures, and the amount of funds we devote to any particular activity may increase or decrease significantly depending on commodity prices, cash flows, available opportunities and development results, among other factors. WeWith the Bankruptcy Court’s authorization to use cash collateral under the Credit Agreement, we believe that we have sufficient liquidity ~~and capital resources~~ to execute our business plan over the next 12 months and for the foreseeable future. With our expected cash flow streams, commodity price hedging strategies, current liquidity levels (including availability under our credit agreement), access to debt and equity markets and flexibility to modify future capital expenditure programs, we expect to be able to fund all planned capital programs and debt repayments, comply with our debt covenants, and meet other obligations that may arise from our oil and gas operations.months.

Credit Agreement. Whiting Oil and Gas, our wholly owned subsidiary, has a credit agreement with a syndicate of banks that ~~as of September 30, 2019~~ had a borrowing base of $2.05 billion and aggregate commitments of ~~$2.25 billion and~~ $1.75 billion ~~respectively.~~as of March 31, 2020. As of ~~September 30, 2019,~~March 31, 2020, we had ~~$1.4~~$1.07 billion ~~of available borrowing capacity under the credit agreement, which was net of $365 million~~ of borrowings outstanding under the Credit Agreement. As a result of the commencement of the Chapter 11 Cases, we are no longer in compliance with the covenants under the Credit Agreement and the lender’s commitments under the Credit Agreement have been terminated. We are therefore unable to make additional borrowings or issue additional letters of credit under the Credit Agreement.

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

Prior to default, a portion of the Credit Agreement in an aggregate amount not to exceed $50 million was available to issue letters of credit for the account of Whiting Oil and Gas or other designated subsidiaries of ours. As of March 31, 2020, $2 million in letters of credit ~~outstanding.~~were outstanding under the agreement.

The borrowing base under the ~~credit agreement~~Credit Agreement is determined at the discretion of ~~our~~the lenders, based on the collateral value of our proved reserves that have been mortgaged to such lenders, and is subject to regular redeterminations on May 1 and November 1 of each year, as well as special redeterminations described in the ~~credit agreement, in each case which may reduce~~Credit Agreement. Such redeterminations are not expected to occur for the ~~amount~~duration of the borrowing base. Upon a redetermination of our borrowing base, either on a periodic or special redetermination date, if borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of our debt outstanding under the credit agreement. In October 2019, the borrowing base under our credit agreement was reduced from $2.25 billion to $2.05 billion in connection with the November 1, 2019 regular borrowing base redetermination, with no change to the aggregate commitments of $1.75 billion.

A portion of the revolving credit facility in an aggregate amount not to exceed $50 million may be used to issue letters of credit, for the account of Whiting Oil and Gas or other designated subsidiaries of ours. As of September 30, 2019, $48 million was available for additional letters of credit under the agreement.Chapter 11 Cases.

The ~~credit agreement~~Credit Agreement provides for interest only payments until maturity, when the ~~credit agreement~~Credit Agreement expires and all outstanding borrowings are due. The credit agreement matures on April 12, 2023, provided that if at any time and for so long as any senior notes (other than the 2020 Convertible Senior Notes) have a maturity date prior to 91 days after April 12, 2023, the maturity date shall be the date that is 91 days prior to the maturity of such senior notes. Interest under the ~~credit agreement~~Credit Agreement accrues at our option at either (i) a base rate for a base rate loan plus a margin between 0.50% and 1.50% based on the ratio of outstanding borrowings to the borrowing base, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.5% per annum, or an adjusted LIBOR rate plus 1.0% per annum, or (ii) an adjusted LIBOR rate for a Eurodollar loan plus a margin ofbetween 1.50% and 2.50% based on the ratio of

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outstanding borrowings to the borrowing base. Additionally, we ~~also~~ incur commitment fees of 0.375% or 0.50% based on the ratio of outstanding borrowings to the borrowing base on the unused portion of the aggregate commitments of the lenders under the ~~credit agreement.~~Credit Agreement, which are included as a component of interest expense. At March 31, 2020, the weighted average interest rate on the outstanding principal balance under the Credit Agreement was 3.0%. During the chapter 11 proceedings, all amounts outstanding under the Credit Agreement with bear interest per annum at the applicable rate stated in the agreement plus a 2.0% default rate.

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

The ~~credit agreement~~Credit Agreement contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, enter into hedging contracts, incur liens and engage in certain other transactions without the prior consent of our lenders. Except for limited exceptions, the credit agreement also restricts our ability to make any dividend payments or distributions on our common stock. These restrictions apply to all of our restricted subsidiaries (as defined in the ~~credit agreement)~~Credit Agreement). ~~As of September 30, 2019, the credit agreement required~~

The Credit Agreement requires us, as of the last day of any quarter, to maintain the following ratios (as defined in the ~~credit agreement)~~Credit Agreement): (i) a consolidated current assets to consolidated current liabilities ratio (which includes an add back of the available borrowing capacity under the credit agreement) of not less than 1.0 to 1.0 and (ii) a total debt to the last four quarters’ EBITDAX ratio of not greater than 4.0 to 1.0. ~~We were in compliance with our covenants under the credit agreement as~~

Table of ~~September 30, 2019.~~ Contents

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

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

Senior Notes. In December 2017, we issued at par $1.0 billion of 6.625% Senior Notes due January 15, 2026 (the “2026 Senior Notes”). In March 2015, we issued at par $750 million of 6.25% Senior Notes due April 1, 2023 (the “2023 Senior Notes”). In September 2013, we issued at par ~~$1.1 billion of 5.0% Senior Notes due March 15, 2019 (the “2019 Senior Notes”) and~~ $800 million of 5.75% Senior Notes due March 15, 2021 and issued at 101% of par an additional $400 million of 5.75% Senior Notes due March 15, 2021 (collectively the “2021 Senior Notes” and together with the 2023 Senior Notes and the 2026 Senior Notes, the “Senior Notes”).

During 2016, we exchanged ~~(i) $139 million aggregate principal amount of our 2019 Senior Notes, (ii)~~ $326 million aggregate principal amount of our 2021 Senior Notes and ~~(iii)~~ $342 million aggregate principal amount of our 2023 Senior Notes for the same aggregate principal amount of convertible notes. Subsequently during 2016, all ~~$807~~$668 million aggregate principal amount of these convertible notes was converted into approximately ~~19.8~~16.3 million shares of our common stock pursuant to the terms of the notes.

~~Redemption~~The commencement of ~~2019~~a voluntary proceeding in bankruptcy constitutes an immediate event of default that automatically accelerated our obligations under the indentures governing our Senior Notes. ~~In January 2018, we paid $1.0 billion~~Any efforts to ~~redeem all~~enforce payment obligations related to the acceleration of our Senior Notes have been automatically stayed as a result of the ~~then outstanding $961 million aggregate principal amount of our 2019 Senior Notes, which payment consisted~~filing of the ~~102.976% redemption price plus all accrued~~Chapter 11 Cases, and ~~unpaid interest on~~ the ~~notes. We financed~~creditors’ rights of enforcement are subject to the ~~redemption with proceeds from~~applicable provisions of the ~~issuance of our 2026 Senior Notes and borrowings under our credit agreement.~~Bankruptcy Code.

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

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

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

2020 Convertible Senior Notes. In March 2015, we issued at par $1,250 million of ~~1.25%~~2020 Convertible Senior ~~Notes due April 2020 (the “2020 Convertible Senior Notes”).~~Notes. During 2016, we exchanged $688 million aggregate principal amount of our 2020 Convertible Senior Notes for the same aggregate principal amount of new mandatory convertible senior notes. Subsequently during 2016, all $688 million aggregate principal amount of these mandatory convertible senior notes was converted into approximately 17.8 million shares of our common stock pursuant to the terms of the notes.

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

~~The remaining $262~~In March 2020, we paid $53 million to repurchase $73 million aggregate principal amount of the 2020 Convertible Senior Notes, ~~outstanding as~~which payment consisted of ~~September 30, 2019 are convertible exclusively at~~ the ~~holder’s option.~~ average 72.5% purchase price plus all accrued and unpaid interest on the notes. We financed the repurchases with borrowings under the Credit Agreement.

Prior to January 1, 2020, the 2020 Convertible Senior Notes ~~will be~~were convertible ~~at the holder’s option~~ only ~~under the following circumstances: (i) during any calendar quarter commencing after the calendar quarter ending~~

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on June 30, 2015 (and only during such calendar quarter), if the last reported sale price of our common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day; (ii) during the five business day period after any five consecutive trading day period (the “measurement period”) in which the trading price per $1,000 principal amount of the 2020 Convertible Senior Notes for each trading day of the measurement period is less than 98% of the product of the last reported sale price of our common stock and the conversion rate on each such trading day; or (iii) upon the ~~occurrence~~achievement of ~~specified corporate events. On or after~~certain contingent market conditions, which were not met. After January 1, 2020, the 2020 Convertible Senior Notes ~~will be~~were convertible at any time until the second scheduled trading day immediately preceding the April 1, 2020 maturity date of the ~~notes. The~~ notes ~~will be convertible at a current conversion rate~~and holders of ~~6.4102 shares~~$3 million aggregate principal

Table of ~~our common stock per $1,000 principal~~ Contents

amount of the notes, which is equivalent to a current conversion price of approximately $156.00. The conversion rate will be subject to adjustment in some events. In addition, following certain corporate events that occur prior to the maturity date, we will increase, in certain circumstances, the conversion rate for a holder who elects to convert its 2020 Convertible Senior Notes ~~in connection with~~timely elected to convert. Upon conversion, such ~~corporate event. As of September 30, 2019, none~~holders of the ~~contingent conditions allowing holders of the~~converted 2020 Convertible Senior Notes were entitled to ~~convert these notes had been met. We have~~receive an insignificant cash payment on April 1, 2020, which we did not pay. Additionally, at maturity, we were obligated to pay in cash the ~~option to settle conversions of these notes with cash, shares of common stock or a combination of cash and common stock at our election. Our intent is to settle the~~$187 million outstanding principal amount of the 2020 Convertible Senior Notes ~~in cash upon conversion. At maturity,~~that did not convert, which we ~~must settle all outstanding~~did not pay. Under the Bankruptcy Code, the holders of the 2020 Convertible Senior Notes ~~in cash.~~

~~Note Covenants~~. ~~The indentures governing~~and the ~~Senior Notes restrict~~prior holders that converted their notes are stayed from taking any action against us from incurring additional indebtedness, subject to certain exceptions, unless our fixed charge coverage ratio (as defined in the indentures) is at least 2.0 to 1. If we were in violation of this covenant, then we may not be able to incur additional indebtedness, including under Whiting Oil and Gas’ credit agreement. Additionally, these indentures contain restrictive covenants that may limit our ability to, among other things, pay cash dividends, make certain other restricted payments, redeem or repurchase our capital stock, make investments or issue preferred stock, sell assets, consolidate, merge or transfer all or substantially all of the assets of ours and our restricted subsidiaries taken as a ~~whole, and enter into hedging contracts. These covenants may potentially limit the discretion~~result of our ~~management in certain respects. We were in compliance with these covenants as~~non-payment. Refer to “Chapter 11 Cases and Effect of ~~September 30, 2019. However, a substantial or extended decline in oil, NGL or natural gas prices may adversely affect our ability to comply with these covenants in the future.~~Automatic Stay” above for more information.

Contractual Obligations and Commitments

We have various contractual obligations in the normal course of our ~~operations~~operating and financing activities. For ~~further~~more information, ~~see~~refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contractual Obligations and Commitments” in our Annual Report on Form 10-K for the year ended December 31, ~~2018.~~2019. There have been no material changes to our obligations since ~~yearend 2018~~year-end 2019 except as ~~further~~ discussed below.

On April 1, 2020, we did not make the $187 million cash principal payment due on the 2020 Convertible Senior Notes. On the same date, the Debtors filed the Chapter 11 Cases in the Bankruptcy Court seeking relief under the Bankruptcy Code. The commencement of a voluntary proceeding in bankruptcy constitutes an immediate event of default under the Credit Agreement and the indentures governing our Senior Notes, resulting in the automatic and immediate acceleration of all of our outstanding debt. Any efforts to enforce such payment obligations were automatically stayed as a result of the filing of the Chapter 11 Cases and the creditors’ rights of enforcement in respect of the Senior Notes and the Credit Agreement are subject to the applicable provisions of the Bankruptcy Code. In addition, commencement of the ~~third quarter~~Chapter 11 Cases automatically stayed all of ~~2019,~~the proceedings and actions against us (other than regulatory enforcement matters). For a further discussion of the Chapter 11 Cases and related matters, refer to the “Basis of Presentation” and “Long-Term Debt” footnotes in the notes to the condensed consolidated financial statements.

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

Delivery Commitments. We have a ~~ship-or-pay agreement~~delivery contract that is tied to ~~transport crude~~ oil ~~from~~production in the Williston ~~Basin via certain pipelines for a term of seven years. Although minimum quantities are specified in the agreement, the actual oil volumes transported are variable over the term of the contract.~~Basin. The effective date of this contract is contingent upon the completion of certain related pipelines, the construction of which has been suspended due to current market conditions. Under the terms of the agreement, we have committed to deliver 10 MBbl/d for a term of seven years. We believe our production and reserves are ~~currently expected~~sufficient to ~~be brought online in 2021. As of September 30, 2019, we estimated the minimum future commitments~~fulfill this delivery commitment, and therefore expect to avoid any payments for deficiencies under this ~~agreement to approximate $147 million, which is based on~~contract. If completion of the ~~contractually stipulated per barrel fee and is~~pipelines does not occur by March 31, 2022, such date being subject to ~~adjustment during~~extension by force majeure until July 31, 2023, the ~~term of~~contract will terminate and we will no longer be required to deliver the ~~contract.~~

committed volumes.

Based on current oil and natural gas prices and anticipated levels of production, we believe that the estimated net cash generated from operations, together with cash on hand, ~~and amounts available under our credit agreement,~~ will be adequate to meet future liquidity needs, including ~~satisfying our financial obligations and~~ funding our operating, development and exploration activities.

~~New Accounting Pronouncements~~

For further information on the effects of recently adopted accounting pronouncements and the potential effects of new accounting pronouncements, refer to “Adopted and Recently Issued Accounting Pronouncements” within the “Basis of Presentation” footnote and the “Leases” footnote in the notes to 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, ~~2018.~~2019. The following is a material update to such critical accounting policies and estimates:

~~Leases.~~Reorganization Accounting. We have operating and finance leases for corporate and field offices, pipeline and midstream facilities, field and office equipment and automobiles. Right-of-use (“ROU”) assets and liabilities associated with these leases are recognized at the lease commencement date based on the present valueEffective April 1, 2020, as a result of the ~~lease payments over the lease term. ROU assets represent our right to use an underlying asset for the lease term, and lease liabilities represent our obligation to make lease payments.~~

Operating lease cost is recognized on a straight-line basis over the lease term. Finance lease cost is recognized based on the effective interest method for the lease liability and straight-line amortizationfiling of the ROU asset, resulting in more cost being recognized in earlier lease periods. All payments for short-term leases, including leases with a term of one month or less, are recognized in income or capitalizedChapter 11 Cases we began accounting and reporting according to the cost of oil and gas properties on a straight-line basis over the lease term. Additionally, any variable payments, which are generally related to the corresponding utilization of the asset, are recognized in the period in which the obligation was incurred.

~~We adopted~~ FASB ASC Topic ~~842~~852 – ~~Leases~~Reorganizations ~~effective January 1, 2019 using~~, which specifies the ~~modified retrospective approach. Refer~~accounting and financial reporting requirements for entities reorganizing through chapter 11 bankruptcy proceedings. These requirements include distinguishing transactions associated with the reorganization separate from activities related to ongoing operations of the ~~“Basis of Presentation” and “Leases” footnotes in the notes to the condensed consolidated financial statements for more information on this new accounting standard.~~business.

Effects of Inflation and Pricing

As commodity prices ~~have begun~~began to recover during 2018 and 2019 from previous lows, the cost of oil field goods and services ~~has~~ also ~~risen.~~rose. The oil and gas industry is very cyclical, and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts extreme pressure on the economic stability and pricing structure within the industry. Although commodity prices have

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declined sharply during the first part of 2020, these costs have not yet declined in response. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and not adjust downward in proportion to prices. Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, depletion expense, impairment assessments of oil and gas properties and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrow money and retain personnel. While we do not currently expect business costs to materially increase in the near term, higher demand in the industry could result in increases in the costs of materials, services and personnel.

Forward-Looking Statements

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

These risks and uncertainties include, but are not limited to: our ability to obtain Bankruptcy Court approval with respect to motions or other requests made to the Bankruptcy Court; our ability to confirm and consummate the Plan; the effects of the Chapter 11 Cases on our liquidity or results of operations or business prospects; the effects of the Chapter 11 Cases on our business and the interests of various constituents; the length of time that we will operate under chapter 11 protection; risks associated with third-party motions in the Chapter 11 Cases; declines in, or extended periods of low oil, NGL or natural gas prices; our level of success in exploration, development and production activities; risks related to our level of indebtedness, our ability to comply with debt covenants, ~~and~~ periodic redeterminations of the borrowing base under our credit ~~agreement; the geographic concentration of~~agreement and our ~~operations; the~~ ability to ~~achieve the benefits of~~generate sufficient cash flows from operations to service our organizational redesign and cost reduction strategy; impacts to financial statements as a result of impairment write-downs; federal and state initiatives relating to the regulation of hydraulic fracturing and air emissions; revisions to reserve estimates as a result of changes in commodity prices, regulation and other factors; adverse weather conditions that may negatively impact development or production activities; the timing of our exploration and development expenditures; inaccuracies of our reserve estimates or our assumptions underlying them; risks relating to any unforeseen liabilities of ours;indebtedness; our ability to generate sufficient cash flows from operations to meet the internally funded portion of our capital expenditures budget; our ability to obtain external capital to finance exploration and development operations; the impact of negative shifts in investor sentiment towards the oil and gas industry; impacts resulting from the allocation of resources among our ~~ability to successfully complete asset dispositions and~~strategic opportunities; the ~~risks~~

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~~related thereto; unforeseen underperformance of or liabilities associated with acquired properties; the impacts of hedging on our results of operations; failure~~geographic concentration of our ~~properties~~operations; impacts to ~~yield~~financial statements as a result of impairment write-downs and other cash and noncash charges; federal and state initiatives relating to the regulation of hydraulic fracturing and air emissions; revisions to reserve estimates as a result of changes in commodity prices, regulation and other factors; inaccuracies of our reserve estimates or our assumptions underlying them; the timing of our exploration and development expenditures; risks relating to decreases in our credit rating; our inability to access oil and gas markets due to market conditions or ~~gas in commercially viable quantities;~~operational impediments; market availability of, and risks associated with, transport of oil and gas; our ability to successfully complete asset dispositions and the risks related thereto; our ability to drill producing wells on undeveloped acreage prior to its lease expiration; shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs and completion services; weakened differentials impacting the price we receive for oil and natural gas; risks relating to any unforeseen liabilities of ours; the impacts of hedging on our results of operations; adverse weather conditions that may negatively impact development or production activities; uninsured or underinsured losses resulting from our oil and gas operations; lack of control over non-operated properties; failure of our ~~inability~~properties to ~~access~~yield oil ~~and~~or gas ~~markets due to market conditions or operational impediments;~~in commercially viable quantities; the impact and costs of compliance with laws and regulations governing our oil and gas operations; the potential impact of changes in laws that could have a negative effect on the oil and gas industry; impacts of local regulations, climate change issues, negative public perception of our industry and corporate governance standards; our ability to replace our oil and natural gas reserves; negative impacts from litigation and legal proceedings; unforeseen underperformance of or liabilities associated with acquired properties or other strategic partnerships or investments; competition in the oil and gas industry; any loss of our senior management or technical personnel; ~~competition in the oil and gas industry; cyber security~~cybersecurity attacks or failures of our telecommunication ~~systems;~~and other information technology infrastructure; and other risks described under the caption “Risk Factors” in Item 1A of this Quarterly Report on Form 10-Q and our Annual Report on Form 10-K for the period ended December 31, ~~2018.~~2019. 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 gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Crude oil and natural gas are commodities, and therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, NGLs and gas have been volatile, and these markets will likely continue to be volatile in the future. Based on production for the first nine of 2019, our income (loss) before income taxes for the nine months ended September 30, 2019 would have moved up or down $113 million for each 10% change in oil prices per Bbl, $3 million for each 10% change in NGL prices per Bbl and $2 million for each 10% change in natural gas prices per Mcf.
We periodically enter into derivative contracts to achieve a more predictable cash flow by reducing our exposure to oil and natural gas price volatility. Our derivative contracts have traditionally been costless collars and swaps, although we evaluate and have entered into other forms of derivative instruments as well. Currently, we do not apply hedge accounting, and therefore all changes in commodity derivative fair values are recorded immediately to earnings.
Crude Oil Collars, Swaps and Options. ~~The collared hedges~~Our hedging portfolio currently consists of collars, swaps and ~~options shown~~options. Refer to the “Derivative Financial Instruments” footnote in the ~~table below~~notes to the condensed consolidated financial statements for a description and list of our outstanding derivative contracts at March 31, 2020.
Our collars and options have the effect of providing a protective floor, unless pricing falls below the established floor or sub-floor, while allowing us to share in upward pricing movements. The fair value of our crude oil collars and options at September 30, 2019 was a net asset of $12 million. A hypothetical upward or downward shift of 10% per Bbl in the NYMEX forward curve for crude oil as of September 30, 2019 would cause a decrease of $12 million or an increase of $14 million, respectively, in this fair value asset.
~~The~~Our swap contracts ~~shown in the table below~~ entitle us to receive settlement from the counterparty in amounts, if any, by which the settlement price for the applicable calculation period is less than the fixed price, or to pay the counterparty if the settlement price for the applicable calculation period is more than the fixed price. The fair value of our ~~swaps~~derivative positions at ~~September 30, 2019~~March 31, 2020 was a net asset of ~~$34~~$189 million. A hypothetical upward or downward shift of 10% per Bbl in the NYMEX forward curve for crude oil as of ~~September 30, 2019~~March 31, 2020 would cause a decrease of $22 million or an increase ~~respectively,~~ of ~~$28~~$21 million, respectively, in this fair value asset.
While these ~~hedges,~~collars, options and fixed-price swaps are designed to decrease our exposure to downward price movements, they also have the effect of limiting the benefit of price increases above the ceiling with respect to the hedges and options and upward price movements generally with respect to the fixed-price swaps.

~~Table~~On April 1, 2020 we filed for relief under chapter 11 of ~~Contents~~

~~Our~~the Bankruptcy Code, which permitted the counterparties to our derivative instruments to terminate their outstanding ~~commodity derivative contracts as~~hedges, and certain of ~~September 30, 2019 are summarized below:~~our counterparties elected to exercise their right to terminate. Refer to the “Derivative Financial Instruments” footnote in the notes to the condensed consolidated financial statements for more information on these terminations, the effect such terminations will have on our cash flows, financial position and results of operations and other subsequent hedging activity.

Average

Weighted Average
Derivative

Monthly Volume

NYMEX Price
Instrument

Commodity

Period

(Bbl)

(Per Bbl)

Floor/Ceiling
Collars

Crude oil

10/2019 to 12/2019

900,000

$52.56/$75.17

Crude oil

01/2020 to 03/2020

121,333

$55.00/$67.33

Crude oil

04/2020 to 06/2020

121,333

$55.00/$67.33

Fixed Price
Swaps

Crude oil

10/2019 to 12/2019

737,000

$61.02

Crude oil

01/2020 to 03/2020

469,667

$58.27

Crude oil

04/2020 to 06/2020

424,667

$58.37

Crude oil

07/2020 to 09/2020

61,333

$55.33

Crude oil

10/2020 to 12/2020

61,333

$55.33

Floor/Floor/Ceiling
Three-way collars ⁽¹⁾

Crude oil

01/2020 to 03/2020

151,667

$45.00/$55.00/$65.00

Crude oil

04/2020 to 06/2020

151,667

$45.00/$55.00/$65.00

Crude oil

07/2020 to 09/2020

153,333

$45.00/$55.00/$65.00

Crude oil

10/2020 to 12/2020

153,333

$45.00/$55.00/$65.00

Strike Price
Call option ⁽²⁾

Crude oil

01/2021 to 03/2021

30,000

$65.00

Crude oil

04/2021 to 06/2021

30,333

$65.00

Crude oil

07/2021 to 09/2021

30,667

$65.00

Crude oil

10/2021 to 12/2021

30,667

$65.00
~~(1)~~ ~~We are contracted to pay deferred premiums related to certain three-way collars at each settlement date.The weighted average premium for all three-way collars was $1.84 per Bbl as of September 30, 2019.~~
~~(2)~~ ~~This derivative instrument is a sold call option.~~
Interest Rate Risk
~~Our quantitative and qualitative disclosures about~~Market risk is estimated as the change in fair value resulting from a hypothetical 100 basis point change in the interest rate ~~risk related~~on the outstanding balance under our credit agreement. Our credit agreement allows us to fix the interest rate for all or a portion of the principal balance for a period up to one month. To the extent that the interest rate is fixed, interest rate changes affect the instrument’s fair market value but do not impact results of operations or cash flows. Conversely, for the portion of the credit agreement that has a floating interest rate, interest rate changes will not affect the fair market value but will impact future results of operations and cash flows. At March 31, 2020, our outstanding principal balance under our credit agreement was $1.07 billion, and the weighted average interest rate on the outstanding principal balance was 3.0%. At March 31, 2020, the carrying amount approximated fair market value. Assuming a constant debt level of $1.07 billion, the cash flow impact resulting from a 100 basis point change in interest rates during periods when the interest rate is not fixed would be $7 million over a 12-month time period. Changes in interest rates do not affect the amount of interest we pay on our fixed-rate senior notes, ~~and convertible notes are included~~but changes in ~~Item 7A~~interest rates do affect the fair values of ~~our Annual Report on Form 10-K for the fiscal year ended December 31, 2018 and have not materially changed since that report was filed~~.these notes.

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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 Chairman, President and Chief Executive Officer and our Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of ~~September 30, 2019.~~March 31, 2020. Based upon their evaluation of these disclosure controls and procedures, the Chairman, President and Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures were effective as of ~~September 30, 2019~~March 31, 2020 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, 2019~~March 31, 2020 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
~~We are subject to litigation claims and governmental and regulatory proceedings arising~~The information contained in the ~~ordinary course of business. While the outcome of these lawsuits~~“Commitments and claims cannot be predicted with certainty, it is management’s opinion that the loss for any litigation matters and claims we are involved in that are reasonably possible to occur will not have a material adverse effect, individually orContingencies” footnote in the ~~aggregate, on our~~notes to the condensed consolidated financial ~~position, cash flows or results of operations.~~
Westatements under the headings “Chapter 11 Cases” and “Litigation” are involved in litigation related to a payment arrangement with a third party which currently claims damages up to $41 million, as well as court costs and interest. While the Company believes that a loss contingency is reasonably possible, the possible loss or a range of possible loss associated with this litigation cannot be reasonably estimated due to a number of factors including, but not limited to, complex legal and factual matters, ongoing discovery and development of information important to the case and potential defenses, among others. No amount of loss contingency associated with this litigation has been accrued as of September 30, 2019.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, ~~2018. No~~2019. The following is a material ~~change~~update to such risk factors:
We are subject to the risks and uncertainties associated with proceedings under chapter 11 of the Bankruptcy Code.
On April 1, 2020 (the “Petition Date”), Whiting and certain of its subsidiaries (the “Debtors”) commenced voluntary cases (the “Chapter 11 Cases”) under chapter 11 of the Bankruptcy Code. On April 23, 2020, the Debtors entered into a restructuring support agreement (the “RSA”) with certain holders of our senior notes to support a restructuring in accordance with the terms set forth in our chapter 11 plan of reorganization (the “Plan”). For the duration of our Chapter 11 Cases, our operations and our ability to develop and execute the business plan, as well as our continuation as a going concern, are subject to risks and uncertainties associated with bankruptcy. These risks include the following:
● our ability to execute, confirm and consummate the Plan as contemplated by the RSA with respect to the Chapter 11 Cases;
● the high costs of bankruptcy proceedings and related fees;
● our ability to obtain sufficient financing to allow us to emerge from bankruptcy and execute our business plan post-emergence;
● our ability to maintain our relationships with our suppliers, service providers, customers, employees and other third parties;
● our ability to maintain contracts that are critical to our operations;
● our ability to execute our business plan in the current depressed commodity price environment;
● our ability to attract, motivate and retain key employees;
● the ability of third parties to seek and obtain court approval to terminate contracts and other agreements with us;

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

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

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

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

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

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

A long period of operations under the Bankruptcy Court protection could have a material adverse effect on our business, financial condition, results of operations and liquidity. A prolonged period of operating under Bankruptcy Court protection may also make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, the longer the Chapter 11 Cases continue, the more likely it is that our customers and suppliers will lose confidence in our ability to reorganize our business successfully and will seek to establish alternative commercial relationships.

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

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

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

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

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

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

Although we have lowered our capital budget and reduced the scale of our operations significantly, our business remains capital intensive. In addition to the cash requirements necessary to fund ongoing operations, we have incurred, and expect to continue to incur, significant professional fees and other costs in connection with the Chapter 11 Cases. As of March 31, 2020, our total available liquidity, consisting of cash on hand, was $566 million. We expect to continue using additional cash that will further reduce this liquidity. With the Bankruptcy Court’s authorization to use cash collateral under the Credit Agreement, we believe that we will have sufficient liquidity, including cash on hand and funds generated from ongoing operations, to fund anticipated cash requirements through the Chapter 11 Cases. As such, we expect to pay vendor and royalty obligations on a go-forward basis according to the terms of our current contracts and consistent with applicable court orders, if any, approving such payments. However, there can be no assurance that our current liquidity will be sufficient to allow us to satisfy our obligations related to the Chapter 11 Cases or to pursue confirmation of the Plan. We can provide no assurance that we will be able to secure additional interim financing or exit financing sufficient to meet our liquidity needs or, if sufficient funds are available, offered to us on acceptable terms.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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●	the occurrence or threat of epidemic or pandemic diseases, such as the COVID-19 pandemic, or any government response to such occurrence or threat;

●	the actions of the Organization of Petroleum Exporting Countries (“OPEC”), including Saudi Arabia’s decision in March 2020 to abandon output restraints in response to Russia’s refusal to make production cuts;

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

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

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

●	developments of North American energy infrastructure;

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

●	the effects of global conservation and sustainability measures;

●	proximity and capacity of oil and natural gas pipelines and other transportation facilities;

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

●	weather conditions;

●	technological advances affecting energy consumption;

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

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

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

●	acts of terrorism;

●	the price and availability of alternative fuels; and

●	acts of force majeure.

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

Oil prices declined sharply during the first quarter of 2020, dropping below $21.00 per Bbl in March 2020 and further dropping to below negative $37.00 per Bbl in April 2020. This dramatic decline in pricing is primarily in response to Saudi Arabia’s announcement of plans to abandon previously agreed upon output restraints and the economic effects of the COVID-19 pandemic on the demand for oil and natural gas. Substantial and extended declines in oil, NGL and natural gas prices have resulted and may continue to result in impairments of our proved oil and gas properties or undeveloped acreage and may materially and adversely affect our future business,

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financial condition, cash flows, results of operations, liquidity or ability to finance planned capital expenditures. To the extent commodity prices received from production are insufficient to fund planned capital expenditures, we will be required to reduce spending or sell assets. Lower commodity prices may also make it more difficult for us to comply with the covenants and other restrictions in the agreements governing our debt as described under the risk factor entitled “The instruments governing our indebtedness contain various covenants limiting the discretion of our management in operating our business” in our Annual Report on Form 10-K for the period ended ~~September~~December 31, 2019.

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

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

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

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

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

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

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

As of December 31, 2019, we had U.S. federal NOLs of $3.4 billion, the majority of which will expire between 2023 and 2037, if not limited by triggering events prior to such time. Under the provisions of the Internal Revenue Code (“IRC”), changes in our ownership, in certain circumstances, will limit the amount of U.S. federal NOLs that can be utilized annually in the future to offset taxable income. In particular, Section 382 of the IRC imposes limitations on a company’s ability to use NOLs upon certain changes in such ownership. Calculations pursuant to Section 382 of the IRC can be very complicated and no assurance can be given that upon further analysis, our

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ability to take advantage of our NOLs may be limited to a greater extent than we currently anticipate. If we are limited in our ability to use our NOLs in future years in which we have taxable income, we will pay more taxes than if we were able to utilize our NOLs fully. We may experience ownership changes in the future as a result of subsequent shifts in our stock ownership that we cannot predict or control that could result in further limitations being placed on our ability to utilize our federal NOLs.

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

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

On April 14, 2020, we received written notification from the NYSE that we no longer satisfy the NYSE’s continued listing compliance standards because the average closing price of our common stock was below $1.00 over a 30 ~~2019.~~consecutive trading-day period. Under the NYSE’s rules, we have until December 23, 2020 to regain compliance with the minimum share price requirement. We can regain compliance at any time during the cure period if on the last trading day of any calendar month during the cure period, our common stock has a closing share price of at least $1.00 and an average closing share price of at least $1.00 over the 30 trading-day period ending on the last trading day of that month. Under NYSE rules, our common stock will continue to be listed on the NYSE during this cure period, subject to our compliance with other continued listing requirements. If we are unable to cure this deficiency within the cure period or we are unable to comply with other NYSE continued listing requirements, the NYSE might delist our common stock. At that time, we may appeal the NYSE’s staff’s delisting determination to a committee of the NYSE’s board of directors.

Delisting would have an adverse effect on the liquidity of our common stock and, as a result, the market price for our common stock might become more volatile. Delisting could also reduce the number of investors willing to hold or acquire our common stock and negatively impact our ability to access equity markets and obtain financing.
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
~~(4.1)~~(3.1)		~~First Amendment to Seventh Amended and~~ Restated ~~Credit Agreement, dated as~~Certificate of ~~September 13, 2019, among~~Incorporation of Whiting Petroleum Corporation ~~Whiting Oil and Gas Corporation, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent~~ [Incorporated by reference to Exhibit ~~4.1~~3.2 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on ~~September 16, 2019~~November 9, 2017 (File No. 001-31899)].

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

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

(10.1)		~~Executive Employment and Severance~~Section 382 Rights Agreement, dated as of March 26, 2020, between ~~Correne S. Loeffler and~~ Whiting Petroleum ~~Corporation, effective~~Company and Computershare Trust Company, N.A., as ~~of August 1, 2019~~rights agent. [Incorporated by reference to Exhibit ~~10.1 to~~4 of Whiting Petroleum Corporation’s Current Report on Form 8-K filed on ~~January 5, 2015~~March 27, 2020 (File No. 001-31899)].

(10.2)		~~Non-Competition and Non-Solicitation~~Restructuring Support Agreement, ~~between Michael J. Stevens and Whiting Petroleum Corporation effective as of August 1, 2019~~dated April 23, 2020 [Incorporated by reference to Exhibit ~~10.2~~10 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on ~~July 16, 2019~~April 24, 2020 (File No. 001-31899)].

(10.3)		Form of Retention Agreement for executive officers of Whiting Petroleum Corporation.

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

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

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

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

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

(101)		The following materials from Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q for the quarter ended ~~September 30, 2019~~March 31, 2020 are filed herewith, formatted in iXBRL (Inline Extensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets as of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, (ii) the Condensed Consolidated Statements of Operations for the Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2020 and 2019, ~~and 2018,~~ (iii) the Condensed Consolidated Statements of Cash Flows for the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2020 and 2019, ~~and 2018,~~ (iv) the Condensed Consolidated Statements of Equity for the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2020 and 2019 ~~and 2018~~ 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 67^th day of ~~November, 2019.~~May, 2020.


		WHITING PETROLEUM CORPORATION


	By	/s/ Bradley J. Holly
		Bradley J. Holly
		Chairman, President and Chief Executive Officer


	By	/s/ Correne S. Loeffler
		Correne S. Loeffler
		Chief Financial Officer


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

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Cash consideration	$	122,861

Fair value of assets acquired:
Accounts receivable trade, net	$	30
Prepaid expenses and other		43
Oil and gas properties, successful efforts method:
Proved oil and gas properties		106,860
Unproved oil and gas properties		21,769
Total fair value of assets acquired		128,702

Fair value of liabilities assumed:
Revenue and royalties payable		3,309
Asset retirement obligations		2,532
Total fair value of liabilities assumed		5,841

Total fair value of assets and liabilities acquired	$	122,861



Leases	Balance Sheet Classification	September 30, 2019

Operating Leases
Operating lease ROU assets	Other long-term assets	$	37,018
Accumulated depreciation	Other long-term assets		(8,060)
Operating lease ROU assets, net		$	28,958

Short-term operating lease obligations	Accrued liabilities and other	$	8,093
Long-term operating lease obligations	Operating lease obligations		33,596
Total operating lease obligations		$	41,689

Finance Leases
Finance lease ROU assets	Other property and equipment	$	35,227
Accumulated depreciation	Accumulated depreciation, depletion and amortization		(15,388)
Finance lease ROU assets, net		$	19,839

Short-term finance lease obligations	Accrued liabilities and other	$	5,200
Long-term finance lease obligations	Other long-term liabilities		17,060
Total finance lease obligations		$	22,260



Year ending December 31,	Operating Leases		Finance Leases
2019	$	3,038	$	1,788
2020		8,900		6,750
2021		6,670		5,520
2022		5,268		4,428
2023		4,600		3,563
Remaining		21,286		5,765
Total lease payments	$	49,762	$	27,814
Less imputed interest		(8,073)		(5,554)
Total discounted lease payments	$	41,689	$	22,260


			Pipeline		Automobile and
	Real Estate		Transportation		Equipment
Year ending December 31,	Leases		Agreement		Leases
2019	$	7,407	$	3,180	$	4,216
2020		4,770		3,180		3,422
2021		4,066		3,180		1,678
2022		4,188		3,180		488
2023		4,017		3,180		35
Remaining		25,140		5,565		-
Total lease payments	$	49,588	$	21,465	$	9,839


Derivative		Contracted Crude	Weighted Average NYMEX Price
Instrument	Period	Oil Volumes (Bbl)	for Crude Oil (per Bbl)
Swaps	Oct - Dec 2019	2,211,000	$61.02
	Jan - Dec 2020	3,051,000	$57.95
Collars	Oct - Dec 2019	2,700,000	$52.56 - $75.17
	Jan - Dec 2020	728,000	$55.00 - $67.33
Three-way collars ⁽¹⁾	Jan - Dec 2020	1,830,000	$45.00 - $55.00 - $65.00
Call option ⁽²⁾	Jan - Dec 2021	365,000	$65.00
	Total	10,885,000


		Loss Recognized in Income
Not Designated as	Statement of Operations	Nine Months Ended September 30,
ASC 815 Hedges	Classification	2019		2018
Commodity contracts	Derivative (gain) loss, net	$	7,431	$	177,210
Total		$	7,431	$	177,210


			Average	Weighted Average
Derivative			Monthly Volume	NYMEX Price
Instrument	Commodity	Period	(Bbl)	(Per Bbl)
				Floor/Ceiling
Collars	Crude oil	10/2019 to 12/2019	900,000	$52.56/$75.17
	Crude oil	01/2020 to 03/2020	121,333	$55.00/$67.33
	Crude oil	04/2020 to 06/2020	121,333	$55.00/$67.33

				Fixed Price
Swaps	Crude oil	10/2019 to 12/2019	737,000	$61.02
	Crude oil	01/2020 to 03/2020	469,667	$58.27
	Crude oil	04/2020 to 06/2020	424,667	$58.37
	Crude oil	07/2020 to 09/2020	61,333	$55.33
	Crude oil	10/2020 to 12/2020	61,333	$55.33

				Floor/Floor/Ceiling
Three-way collars ⁽¹⁾	Crude oil	01/2020 to 03/2020	151,667	$45.00/$55.00/$65.00
	Crude oil	04/2020 to 06/2020	151,667	$45.00/$55.00/$65.00
	Crude oil	07/2020 to 09/2020	153,333	$45.00/$55.00/$65.00
	Crude oil	10/2020 to 12/2020	153,333	$45.00/$55.00/$65.00


				Strike Price
Call option ⁽²⁾	Crude oil	01/2021 to 03/2021	30,000	$65.00
	Crude oil	04/2021 to 06/2021	30,333	$65.00
	Crude oil	07/2021 to 09/2021	30,667	$65.00
	Crude oil	10/2021 to 12/2021	30,667	$65.00