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		~~TABLE OF CONTENTS~~
Glossary of Certain Definitions			1
			PART I – FINANCIAL INFORMATION
Item 1.	Condensed Consolidated Financial Statements (Unaudited)	4 5
	Condensed Consolidated Balance Sheets as of ~~September~~June 30, ~~2017~~2020 and December 31, ~~2016~~2019	4 5
	Condensed Consolidated Statements of Operations for the Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2017~~2020 and ~~2016~~2019	5 6
	Condensed Consolidated Statements of Cash Flows for the ~~Nine~~Six Months Ended ~~September~~June 30, ~~2017~~2020 and ~~2016~~2019	6 7
	Condensed Consolidated Statements of Equity (Deficit) for the ~~Nine~~Six Months Ended ~~September~~June 30, ~~2017~~2020 and ~~2016~~2019	8 9
	Notes to Condensed Consolidated Financial Statements	9 10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25 30
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	41 45
Item 4.	Controls and Procedures	42 46
			PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	43 46
Item 1A.	Risk Factors	43 46
Item 6.	Exhibits	43 53

~~Glossary of Certain Definitions~~

GLOSSARY OF CERTAIN DEFINITIONS

Unless the context otherwise requires, the terms ~~“we”, “us”,~~“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.

~~“CO~~2” ~~Carbon dioxide.~~

“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.

“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.

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“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 ~~Bbl.~~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.

~~“plug-and-perf technology”~~ A horizontal well completion technique in which hydraulic fractures are performed in multiple stages, with each stage utilizing a bridge plug to divert fracture stimulation fluids through the casing perforations into the formation within that stage.

“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.

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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 (DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED BALANCE SHEETS (~~unaudited)~~(unaudited)

(in thousands, except share and per share data)

September 30,

December 31,

2017

2016
ASSETS

Current assets:

Cash and cash equivalents

$
11,172

$
55,975
Restricted cash

-

17,250
Accounts receivable trade, net

225,291

173,919
Prepaid expenses and other

32,734

26,312
Assets held for sale

-

349,146
Total current assets

269,197

622,602
Property and equipment:

Oil and gas properties, successful efforts method

12,797,474

13,230,851
Other property and equipment

134,502

134,638
Total property and equipment

12,931,976

13,365,489
Less accumulated depreciation, depletion and amortization

(4,734,351)

(4,222,071)
Total property and equipment, net

8,197,625

9,143,418
Other long-term assets

35,756

110,122
TOTAL ASSETS

$
8,502,578

$
9,876,142
LIABILITIES AND EQUITY

Current liabilities:

Accounts payable trade

$
65,016

$
32,126
Revenues and royalties payable

130,447

147,226
Accrued capital expenditures

107,706

56,830
Accrued interest

24,124

44,749
Accrued lease operating expenses

37,554

45,015
Accrued liabilities and other

23,066

63,538
Taxes payable

23,096

39,547
Derivative liabilities

25,145

17,628
Accrued employee compensation and benefits

23,297

31,134
Liabilities related to assets held for sale

-

538
Total current liabilities

459,451

478,331
Long-term debt

2,931,443

3,535,303
Deferred income taxes

162,054

475,689
Asset retirement obligations

157,298

168,504
Other long-term liabilities

76,359

69,123
Total liabilities

3,786,605

4,726,950
Commitments and contingencies

Equity:

Common stock, $0.001 par value, 600,000,000 shares authorized; 368,020,048 issued and 362,793,720 outstanding as of September 30, 2017 and 367,174,542 issued and 362,013,928 outstanding as of December 31, 2016

368

367
Additional paid-in capital

6,403,767

6,389,435
Accumulated deficit

(1,688,162)

(1,248,572)
Total Whiting shareholders' equity

4,715,973

5,141,230
Noncontrolling interest

-

7,962
Total equity

4,715,973

5,149,192
TOTAL LIABILITIES AND EQUITY

$
8,502,578

$
9,876,142


	June 30,		December 31,
	2020		2019
ASSETS
Current assets:
Cash and cash equivalents	$	492,088	$	8,652
Restricted cash		26,787		-
Accounts receivable trade, net		165,492		308,249
Prepaid expenses and other		28,692		14,082
Total current assets		713,059		330,983
Property and equipment:
Oil and gas properties, successful efforts method		4,820,221		12,812,007
Other property and equipment		173,877		178,689
Total property and equipment		4,994,098		12,990,696
Less accumulated depreciation, depletion and amortization		(2,016,619)		(5,735,239)
Total property and equipment, net		2,977,479		7,255,457
Other long-term assets		41,665		50,281
TOTAL ASSETS	$	3,732,203	$	7,636,721
LIABILITIES AND EQUITY (DEFICIT)
Current liabilities:
Current portion of long-term debt	$	912,259	$	-
Accounts payable trade		31,485		80,100
Revenues and royalties payable		136,401		202,010
Accrued capital expenditures		18,533		64,263
Accrued liabilities and other		48,830		85,007
Accrued lease operating expenses		28,446		38,262
Accrued interest		3,590		53,928
Taxes payable		12,265		26,844
Total current liabilities		1,191,809		550,414
Long-term debt		-		2,799,885
Asset retirement obligations		91,543		131,208
Operating lease obligations		-		31,722
Deferred income taxes		69,847		73,593
Other long-term liabilities		7,745		24,928
Total liabilities not subject to compromise		1,360,944		3,611,750
Liabilities subject to compromise		2,549,538		-
Total liabilities		3,910,482		3,611,750
Commitments and contingencies
Equity (Deficit):
Common stock, $0.001 par value, 225,000,000 shares authorized; 91,636,883 issued and 91,461,283 outstanding as of June 30, 2020 and 91,743,571 issued and 91,326,469 outstanding as of December 31, 2019		92		92
Additional paid-in capital		6,409,627		6,409,991
Accumulated deficit		(6,587,998)		(2,385,112)
Total equity (deficit)		(178,279)		4,024,971
TOTAL LIABILITIES AND EQUITY (DEFICIT)	$	3,732,203	$	7,636,721

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

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WHITING PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION)

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

(in thousands, except per share data)


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

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

Three Months Ended

Nine Months Ended

September 30,

September 30,

2017

2016

2017

2016
OPERATING REVENUES

Oil, NGL and natural gas sales

$
324,191

$
315,554

$
1,007,023

$
942,287
OPERATING EXPENSES

Lease operating expenses

90,615

87,982

267,277

307,530
Production taxes

27,499

26,372

86,621

79,125
Depreciation, depletion and amortization

212,846

284,569

673,288

900,877
Exploration and impairment

17,657

24,293

63,793

85,565
General and administrative

30,084

33,908

92,644

112,227
Derivative (gain) loss, net

30,867

(30,432)

47,281

(28,432)
Loss on sale of properties

398,752

189,934

401,050

193,729
Amortization of deferred gain on sale

(3,175)

(3,490)

(9,757)

(11,111)
Total operating expenses

805,145

613,136

1,622,197

1,639,510
LOSS FROM OPERATIONS

(480,954)

(297,582)

(615,174)

(697,223)
OTHER INCOME (EXPENSE)

Interest expense

(47,693)

(84,578)

(143,641)

(245,145)
Gain (loss) on extinguishment of debt

-

46,541

(1,540)

(42,236)
Interest income and other

(83)

115

970

1,146
Total other expense

(47,776)

(37,922)

(144,211)

(286,235)
LOSS BEFORE INCOME TAXES

(528,730)

(335,504)

(759,385)

(983,458)
INCOME TAX EXPENSE (BENEFIT)

Current

(3,161)

113

(6,367)

115
Deferred

(239,137)

357,438

(313,634)

182,286
Total income tax expense (benefit)

(242,298)

357,551

(320,001)

182,401
NET LOSS

(286,432)

(693,055)

(439,384)

(1,165,859)
Net loss attributable to noncontrolling interests

-

3

14

18
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS

$
(286,432)

$
(693,052)

$
(439,370)

$
(1,165,841)
LOSS PER COMMON SHARE

Basic

$
(0.79)

$
(2.47)

$
(1.21)

$
(4.92)
Diluted

$
(0.79)

$
(2.47)

$
(1.21)

$
(4.92)
WEIGHTED AVERAGE SHARES OUTSTANDING

Basic

362,794

280,418

362,713

237,100
Diluted

362,794

280,418

362,713

237,100

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

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WHITING PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(in thousands)


	Six Months Ended June 30,
	2020		2019
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(4,202,886)	$	(74,612)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		267,517		401,141
Deferred income tax benefit		(3,746)		(1,373)
Amortization of debt issuance costs, debt discount and debt premium		9,786		15,734
Stock-based compensation		3,401		8,617
Amortization of deferred gain on sale		(3,945)		(4,697)
(Gain) loss on sale of properties		(353)		1,086
Oil and gas property impairments		4,154,369		13,179
Gain on extinguishment of debt		(25,883)		-
Non-cash derivative (gain) loss		(178,525)		42,371
Non-cash reorganization items, net		38,145		-
Other, net		829		3,492
Changes in current assets and liabilities:
Accounts receivable trade, net		152,560		(1,813)
Prepaid expenses and other		(12,036)		3,453
Accounts payable trade and accrued liabilities		(51,783)		20,261
Revenues and royalties payable		(65,609)		(41,637)
Taxes payable		(14,579)		(3,269)
Net cash provided by operating activities		67,262		381,933
CASH FLOWS FROM INVESTING ACTIVITIES
Drilling and development capital expenditures		(223,905)		(425,349)
Acquisition of oil and gas properties		(351)		(4,507)
Other property and equipment		(423)		(8,233)
Proceeds from sale of properties		28,243		15,444
Net cash used in investing activities		(196,436)		(422,645)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under credit agreement		1,185,000		1,160,000
Repayments of borrowings under credit agreement		(490,000)		(1,120,000)
Repurchase of 1.25% Convertible Senior Notes due 2020		(52,890)		-
Restricted stock used for tax withholdings		(304)		(3,693)
Principal payments on finance lease obligations		(2,409)		(2,522)
Net cash provided by financing activities	$	639,397	$	33,785

				(Continued)

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WHITING PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(in thousands)

Nine Months Ended

September 30,

2017

2016
CASH FLOWS FROM OPERATING ACTIVITIES

Net loss

$
(439,384)

$
(1,165,859)
Adjustments to reconcile net loss to net cash provided by operating activities:

Depreciation, depletion and amortization

673,288

900,877
Deferred income tax expense (benefit)

(313,634)

182,286
Amortization of debt issuance costs, debt discount and debt premium

22,927

72,389
Stock-based compensation

19,051

19,512
Amortization of deferred gain on sale

(9,757)

(11,111)
Loss on sale of properties

401,050

193,729
Undeveloped leasehold and oil and gas property impairments

44,270

45,906
Exploratory dry hole costs

-

37
Loss on extinguishment of debt

1,540

42,236
Non-cash derivative loss

57,937

102,100
Other, net

(7,008)

(4,732)
Changes in current assets and liabilities:

Accounts receivable trade, net

(51,319)

119,622
Prepaid expenses and other

(6,441)

9,063
Accounts payable trade and accrued liabilities

(68,881)

(104,579)
Revenues and royalties payable

(16,782)

(41,336)
Taxes payable

(16,451)

(1,885)
Net cash provided by operating activities

290,406

358,255
CASH FLOWS FROM INVESTING ACTIVITIES

Drilling and development capital expenditures

(616,753)

(434,794)
Acquisition of oil and gas properties

(18,452)

(3,605)
Other property and equipment

(3,371)

(6,744)
Proceeds from sale of oil and gas properties

916,176

304,291
Net cash provided by (used in) investing activities

277,600

(140,852)
CASH FLOWS FROM FINANCING ACTIVITIES

Borrowings under credit agreement

1,630,000

1,050,000
Repayments of borrowings under credit agreement

(1,980,000)

(1,200,000)
Redemption of 6.5% Senior Subordinated Notes due 2018

(275,121)

-
Early conversion payments for New Convertible Notes

-

(41,919)
Debt issuance costs

-

(22,499)
Restricted stock used for tax withholdings

(4,938)

(709)
Net cash used in financing activities

$
(630,059)

$
(215,127)

(Continued)


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

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

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WHITING PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION)

~~CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)~~

~~(in thousands)~~

Nine Months Ended

September 30,

2017

2016
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH

$
(62,053)

$
2,276
CASH, CASH EQUIVALENTS AND RESTRICTED CASH

Beginning of period

73,225

16,053
End of period

$
11,172

$
18,329
NONCASH INVESTING ACTIVITIES

Accrued capital expenditures and accounts payable related to property additions

$
147,084

$
62,416
NONCASH FINANCING ACTIVITIES (1)

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

(Concluded)

~~(1)~~

Refer to the “Long-Term Debt” footnote in the notes to condensed consolidated financial statements for a discussion of (i) the Company’s exchange of senior notes and senior subordinated notes for convertible notes and the subsequent conversions of such notes, and (ii) the Company’s exchange of senior notes, convertible senior notes and senior subordinated notes for mandatory convertible notes and the subsequent conversions of such notes.

~~Table of Contents~~

~~WHITING PETROLEUM CORPORATION~~

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

(in thousands)



				Additional
	Common Stock			Paid-in		Accumulated		Total
	Shares	Amount		Capital		Deficit		Equity (Deficit)
BALANCES - January 1, 2019	92,067	$	92	$	6,414,170	$	(2,143,946)	$	4,270,316
Net loss	-		-		-		(68,925)		(68,925)
Restricted stock forfeited	(106)		-		-		-		-
Restricted stock used for tax withholdings	(130)		-		(3,693)		-		(3,693)
Stock-based compensation	-		-		4,651		-		4,651
BALANCES - March 31, 2019	91,831		92		6,415,128		(2,212,871)		4,202,349
Net loss	-		-		-		(5,687)		(5,687)
Restricted stock issued	63		-		-		-		-
Restricted stock forfeited	(3)		-		-		-		-
Stock-based compensation	-		-		3,965		-		3,965
BALANCES - June 30, 2019	91,891	$	92	$	6,419,093	$	(2,218,558)	$	4,200,627

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

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

Retained

Total

Additional

Earnings

Whiting

Common Stock

Paid-in

(Accumulated

Shareholders'

Noncontrolling

Total

Shares

Amount

Capital

Deficit)

Equity

Interest

Equity
BALANCES - January 1, 2016

206,441

$
206

$
4,659,868

$
90,530

$
4,750,604

$
7,984

$
4,758,588
Net loss

-

-

-

(1,165,841)

(1,165,841)

(18)

(1,165,859)
Issuance of common stock upon conversion of convertible notes

79,920

80

822,936

-

823,016

-

823,016
Reduction of equity component of 2020 Convertible Senior Notes upon extinguishment, net

-

-

(63,330)

-

(63,330)

-

(63,330)
Recognition of beneficial conversion features on convertible notes

-

-

232,801

-

232,801

-

232,801
Restricted stock issued

4,021

4

(4)

-

-

-

-
Restricted stock forfeited

(615)

-

-

-

-

-

-
Restricted stock used for tax withholdings

(90)

-

(709)

-

(709)

-

(709)
Stock-based compensation

-

-

19,512

-

19,512

-

19,512
BALANCES - September 30, 2016

289,677

$
290

$
5,671,074

$
(1,075,311)

$
4,596,053

$
7,966

$
4,604,019

BALANCES - January 1, 2017

367,175

$
367

$
6,389,435

$
(1,248,572)

$
5,141,230

$
7,962

$
5,149,192
Net loss

-

-

-

(439,370)

(439,370)

(14)

(439,384)
Conveyance of third party ownership interest in Sustainable Water Resources, LLC

-

-

-

-

-

(7,948)

(7,948)
Restricted stock issued

2,271

2

(2)

-

-

-

-
Restricted stock forfeited

(1,022)

(1)

1

-

-

-

-
Restricted stock used for tax withholdings

(404)

-

(4,938)

-

(4,938)

-

(4,938)
Stock-based compensation

-

-

19,051

-

19,051

-

19,051
Cumulative effect of change in accounting principle

-

-

220

(220)

-

-

-
BALANCES - September 30, 2017

368,020

$
368

$
6,403,767

$
(1,688,162)

$
4,715,973

$
-

$
4,715,973

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

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WHITING PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. BASIS OF PRESENTATION

Description of Operations—Whiting Petroleum Corporation, a Delaware corporation, is an independent oil and gas company engaged in the development, production, acquisition and exploration 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, ~~(formerly Kodiak Oil & Gas Corp., “Kodiak”),~~ Whiting Resources Corporation, Whiting Programs, Inc, Whiting Raven Colorado Corp. and Whiting ~~Programs, Inc.~~ND Sakakawea LLC.

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 Chapter 11 Cases are being administered jointly under the caption In re Whiting Petroleum Corporation, et al. Case No. 20-32021. 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.

On July 1, 2020, the Bankruptcy Court entered an order approving the Debtors’ disclosure statement, allowing for solicitation of the Debtors’ chapter 11 plan of reorganization (the “Plan”) to commence. A Bankruptcy Court hearing to consider confirmation of the Plan is scheduled to be held on August 10, 2020.

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

The Company has applied FASB ASC Topic 852 – Reorganizations (“ASC 852”) in preparing the condensed consolidated financial statements, which specifies the accounting and financial reporting requirements for entities reorganizing through chapter 11 bankruptcy proceedings. These requirements include distinguishing transactions associated with the reorganization separate from activities related to the ongoing operations of the business. Accordingly, pre-petition liabilities that may be impacted by the chapter 11 proceedings have been classified as liabilities subject to compromise on the condensed consolidated balance sheet as of June 30, 2020. Additionally, certain expenses, realized gains and losses and provisions for losses that are realized or incurred during the Chapter 11 Cases, including adjustments to the carrying value of certain indebtedness are recorded as reorganization items, net in the condensed consolidated statements of operations for the three and six months ended June 30, 2020. Refer to the “Chapter 11 Cases” footnote for more information on the events of the bankruptcy proceedings as well as the accounting and reporting impacts of the reorganization.

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

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

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

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

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

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, ~~2016.~~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 ~~2016~~2019 Annual Report on Form ~~10‑K.~~10-K.

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

~~Adopted~~Cash, Cash Equivalents and ~~Recently Issued Accounting Pronouncements~~Restricted Cash—Cash equivalents consist of demand deposits and highly liquid investments which have an original maturity of three months or less. Cash and cash equivalents potentially subject the Company to a concentration of credit risk as substantially all of its deposits held in financial institutions were in excess of the Federal Deposit Insurance Corporation (“FDIC”) insurance limits as of June 30, 2020 and December 31, 2019. The Company maintains its cash and cash equivalents in the form of money market and checking accounts with financial institutions that are also lenders under the Credit Agreement. The Company has not experienced any losses on its deposits of cash and cash equivalents.

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

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


	June 30,		December 31,
	2020		2019
Cash and cash equivalents	$	492,088	$	8,652
Restricted cash		26,787		-
Total cash, cash equivalents and restricted cash	$	518,875	$	8,652

Accounts Receivable Trade—Whiting’s accounts receivable trade consist mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates. The Company’s collection risk is inherently low based on the viability of its oil and gas purchasers as well as its general ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. The Company’s oil and gas receivables are generally collected within two months, and to date, the Company has not experienced material credit losses.

The Company routinely evaluates expected credit losses for all material trade and other receivables to determine if an allowance for credit losses is warranted. Expected credit losses are estimated based on (i) historic loss experience for pools of receivable balances with similar characteristics, (ii) the length of time balances have been outstanding and (iii) the economic status of each counterparty. These loss estimates are then adjusted for current and expected future economic conditions, which may include an assessment of the probability of non-payment, financial distress or expected future commodity prices and the impact that any current or future conditions could have on a counterparty’s credit quality and liquidity. As of June 30, 2020 and December 31, 2019, the Company had an allowance for credit losses of $11 million and $9 million, respectively.

2. CHAPTER 11 CASES

Plan of Reorganization under Chapter 11 of the Bankruptcy Code—On April 1, 2020, the Debtors commenced the Chapter 11 Cases as described in the “Basis of Presentation” footnote above. To ensure ordinary course operations, the Debtors have obtained approval from the Bankruptcy Court for certain “first day” motions, including motions to obtain customary relief intended to continue ordinary course operations after the Petition Date. In ~~May 2014,~~addition, the ~~FASB issued Accounting Standards Update No. 2014-09,~~ ~~Revenue from Contracts~~Debtors have received authority to use cash collateral of the lenders under the Credit Agreement on an interim basis.

On April 23, 2020, the Debtors entered into the RSA with ~~Customers~~ ~~(“ASU 2014‑09”~~certain holders of the Company’s senior notes to support a restructuring in accordance with the terms set forth in the Plan. The Plan and the related disclosure statement were each filed with 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.

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

Table of ~~ASU 2014-09~~Contents

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

Executory Contracts—Subject to certain exceptions, under the ~~principles~~Bankruptcy Code the Debtors may assume, assign or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and fulfillment of certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such contract and, subject to certain exceptions, relieves the Debtors from performing future obligations under such contract but entitles the counterparty or lessor to a pre-petition general unsecured claim for ~~recognizing revenue~~damages caused by such deemed breach. Alternatively, the assumption of an executory contract or unexpired lease requires the Debtors to cure existing monetary defaults under such executory contract or unexpired lease, if any, and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with the Debtors in this document, including where applicable quantification of the Company’s obligations under such executory or unexpired lease of the Debtors, is qualified by any overriding rejection rights the Company has under the Bankruptcy Code. On July 18, 2020, the Debtors filed their preliminary schedules of assumed and rejected executory contracts and unexpired leases with the Bankruptcy Court. The Debtors reserve all rights to ~~develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The FASB subsequently issued various ASUs which deferred~~further modify such schedules at any time prior to the effective date of ~~ASU 2014-09~~the Plan.

Liabilities Subject to Compromise—The accompanying condensed consolidated balance sheets include amounts classified as “liabilities subject to compromise,” which represent pre-petition liabilities that have been allowed, or that the Company anticipates will be allowed, as claims in the Chapter 11 Cases, although they may be settled for less. The Company will continue to evaluate these liabilities throughout the Chapter 11 Cases and ~~provided additional implementation guidance. ASU 2014-09~~adjust amounts as necessary. Such adjustments may be material.

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


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

(1)	Amount relates to an executory contract for certain offshore facilities in California.

Magnitude of Potential Claims—The Debtors have filed with the Bankruptcy Court schedules and ~~its amendments are effective for fiscal years,~~statements setting forth, among other things, the assets and ~~interim periods within those years, beginning after December 15, 2017. The standards permit retrospective application using either~~liabilities of each of the ~~following methodologies: (i) restatement~~Debtors. These schedules and statements may be subject to further amendment or modification after filing. Certain holders of ~~each prior reporting period presented or (ii) recognition~~pre-petition claims that are not governmental units were required to file proofs of ~~a cumulative-effect adjustment~~claim by the deadline for general claims, which was June 15, 2020.

The Debtors have received approximately 1,600 proofs of claim from third parties as of ~~the date of initial application. The Company plans~~July 31, 2020 for an amount totaling approximately $2.8 billion. Such amount includes duplicate claims across multiple debtor legal entities. These claims will be reconciled to ~~adopt these ASUs effective January 1, 2018 using the modified retrospective approach. The Company is~~amounts recorded in the ~~process of assessing its contracts with customers~~Company’s accounting records. Differences in amounts recorded and evaluating the effect of adopting these standards on its financial statements, accounting policies and internal controls. The adoption is not expected to have a significant impact on the Company’s net income or cash flows, however, the Company is currently evaluating the proper classification of certain pipeline gathering and transportation agreements as well as gas processing agreements to determine whether changes to total revenues and expensesclaims filed by creditors will be ~~necessary under~~investigated and resolved, including through the ~~new standards.~~filing of objections with the Bankruptcy Court, where appropriate. The Bankruptcy Court does not allow for claims that have been acknowledged as duplicates. In addition, the Company ~~is also currently assessing~~may ask the Bankruptcy Court to disallow claims that the Company believes have been later amended or superseded, are without merit, are overstated or should be disallowed for other reasons. As a result of this process, the Company may identify additional ~~disclosures~~liabilities that will need to be ~~required upon implementation~~recorded or reclassified to liabilities subject to compromise. In light of ~~these ASUs.~~the substantial number of claims filed, and expected to be filed, the claims resolution process may take considerable time to complete and likely will continue after the Debtors emerge from bankruptcy.

~~In February 2016,~~Interest Expense—The Company has discontinued recording interest on debt instruments classified as liabilities subject to compromise as of the ~~FASB issued Accounting Standards Update No. 2016-02,~~ ~~Leases~~ ~~(“ASU 2016-02”).~~Petition Date. The ~~objective of this ASU is~~contractual interest expense on liabilities subject to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 and should be applied using a modified retrospective approach. Early adoption is permitted. Although the Company is stillcompromise not accrued in the ~~process~~condensed consolidated statements of ~~evaluating~~operations was approximately $34 million for the ~~effect~~three months from the Petition Date through June 30, 2020.

Table of ~~adopting ASU 2016‑02,~~Contents

Reorganization Items, Net—The Company has incurred and will continue to incur significant costs as a direct result of the ~~adoption is expected~~Chapter 11 Cases subsequent to ~~result~~the Petition Date. These costs, which are expensed as incurred, are recorded in ~~(i) an increase~~reorganization items, net in the ~~assets and liabilities recorded on its~~Company’s condensed consolidated ~~balance sheet, (ii) an increase in depreciation, depletion and amortization expense and interest expense recorded on its consolidated statement~~statements of ~~operations, and (iii) additional disclosures. As~~operations. The following table summarizes the components of September 30, 2017, the Company had approximately $87 million of contractual obligations related to its non-cancelable leases, drilling rig contracts and pipeline transportation agreements, and it will evaluate those contracts as well as other existing arrangements to determine if they qualify for lease accounting under ASU 2016-02.

~~In March 2016, the FASB issued Accounting Standards Update No. 2016-09,~~ ~~Improvements to Employee Share-Based Payment Accounting~~ (“ASU 2016-09”). The objective of this ASU is to simplify several aspects of the accounting for employee share-based payment transactions, including income tax consequences, forfeitures, classification of awards as either equity or liabilities and classification in the statement of cash flows. Portions of this ASU must be applied prospectively while other portions may be applied either prospectively or retrospectively. ASU 2016-09 is effective for fiscal years, and interim periods within those fiscal years, beginning

~~Table of Contents~~

after December 15, 2016, and the Company adopted this standard on January 1, 2017. Upon adoption of ASU 2016-09, the Company (i) recorded $70 million of previously unrecognized excess tax benefits on a modified retrospective basis with a full valuation allowance, resulting in areorganization items, net cumulative-effect adjustment to retained earnings of zero, (ii) prospectively removed excess tax benefits from its calculation of diluted shares, which had no impact on the Company’s diluted earnings per share for the three and ~~nine~~six months ended ~~September~~June 30, 2017, and (iii) elected to account for forfeitures of share-based awards as they occur, rather than by applying an estimated forfeiture rate to determine compensation expense, the effect of which was recognized using a modified retrospective approach and resulted in an immaterial cumulative-effect adjustment to retained earnings and additional paid-in capital.2020 (in thousands):


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

(1)	As of June 30, 2020, $23 million of these fees are accrued and unpaid and are presented in accrued liabilities and other in the condensed consolidated balance sheet. The remaining $4 million represents cash charges for the three and six months ended June 30, 2020.

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

3. OIL AND GAS PROPERTIES

Net capitalized costs related to the Company’s oil and gas producing activities at ~~September~~June 30, ~~2017~~2020 and December 31, ~~2016~~2019 are as follows (in thousands):



	June 30,		December 31,
	2020		2019
Costs of completed wells and facilities	$	4,267,233	$	9,847,159
Proved leasehold costs		376,329		2,702,236
Unproved leasehold costs		90,561		103,278
Wells and facilities in progress		86,098		159,334
Total oil and gas properties, successful efforts method		4,820,221		12,812,007
Accumulated depletion		(1,936,121)		(5,656,929)
Oil and gas properties, net	$	2,884,100	$	7,155,078

September 30,

December 31,

2017

2016
Proved leasehold costs

$
2,658,889

$
3,330,928
Unproved leasehold costs

191,067

392,484
Costs of completed wells and facilities

9,432,776

9,016,472
Wells and facilities in progress

514,742

490,967
Total oil and gas properties, successful efforts method

12,797,474

13,230,851
Accumulated depletion

(4,676,819)

(4,170,237)
Oil and gas properties, net

$
8,120,655

$
9,060,614

The following table presents impairment expense for unproved properties for the three and six months ended June 30, 2020 and 2019, which is reported in exploration and impairment expense in the condensed consolidated statements of operations (in thousands):


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2020		2019		2020		2019
Impairment expense for unproved properties	$	132	$	2,308	$	12,483	$	5,830

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

3.4. ACQUISITIONS AND DIVESTITURES

~~2017~~2020 Acquisitions and Divestitures

On ~~September 1, 2017,~~January 9, 2020, the Company completed the ~~sale~~divestiture of its interests in ~~certain~~30 non-operated, producing oil and gas ~~properties~~wells and related undeveloped acreage located in ~~the Fort Berthold Indian Reservation area in Dunn and McLean counties of~~McKenzie County, North Dakota ~~as well as other related assets and liabilities, (the “FBIR Assets”)~~ for aggregate sales proceeds of ~~$500~~$25 million (before closing adjustments). ~~The sale was effective September1, 2017 and resulted in a pre-tax loss on sale of $402 million. The Company used the net proceeds from the sale to repay a portion of the debt outstanding under its credit agreement.~~

On January 1, 2017, the Company completed the sale of its 50% interest in the Robinson Lake gas processing plant located in Mountrail County, North Dakota and its 50% interest in the Belfield gas processing plant located in Stark County, North Dakota, as well as the associated natural gas, crude oil and water gathering systems, effective January 1, 2017, for aggregate sales proceeds of $375 million (before closing adjustments). The Company used the net proceeds from this transaction to repay a portion of the debt outstanding under its credit agreement.

~~The following table shows the components of assets and liabilities classified as held for sale as of December 31, 2016 (in thousands):~~



	~~Carrying Value as of~~
	~~December 31, 2016~~
~~Assets~~
~~Oil and gas properties, net~~	$	~~347,817~~
~~Other property and equipment, net~~		~~475~~
~~Total property and equipment, net~~		~~348,292~~
~~Other long-term assets~~		~~854~~
~~Total assets held for sale~~	$	~~349,146~~

~~Liabilities~~
~~Asset retirement obligations~~	$	~~131~~
~~Other long-term liabilities~~		~~407~~
~~Total liabilities related to assets held for sale~~	$	~~538~~

~~There were no significant acquisitions during the nine months ended September 30, 2017.~~

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~~2016 Acquisitions and Divestitures~~

In July 2016, the Company completed the sale of its interest in its enhanced oil recovery project in the North Ward Estes field in Ward and Winkler counties of Texas, including Whiting’s interest in certain CO2 properties in the McElmo Dome field in Colorado and certain other related assets and liabilities (the “North Ward Estes Properties”) for a cash purchase price of $300 million (before closing adjustments). The sale was effective July 1, 2016 and resulted in a pre-tax loss on sale of $187 million. The Company used the net proceeds from the sale to repay a portion of the debt outstanding under its credit agreement.

In addition to the cash purchase price, the buyer agreed to pay Whiting $100,000 for every $0.01 that, as of June 28, 2018, the average NYMEX crude oil futures contract price for each month from August 2018 through July 2021 is above $50.00/Bbl up to a maximum amount of $100 million (the “Contingent Payment”). The Company determined that this Contingent Payment was an embedded derivative and reflected it at fair value in the consolidated financial statements prior to settlement. On July 19, 2017, the buyer paid $35 million to Whiting to settle this Contingent Payment, resulting in a pre-tax gain of $3 million. Refer to the “Derivative Financial Instruments” and “Fair Value Measurements” footnotes for more information on this embedded derivative instrument.

There were no significant acquisitions during the ~~year~~six months ended ~~December 31, 2016.~~June 30, 2020.

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2019 Acquisitions and Divestitures

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

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

There were no significant acquisitions during the six months ended June 30, 2019.

5. LONG-TERM DEBT

Long-term debt, including the current portion, consisted of the following at ~~September~~June 30, ~~2017~~2020 and December 31, ~~2016~~2019 (in thousands):


	June 30,		December 31,
	2020		2019
Credit Agreement	$	912,259	$	375,000
1.25% Convertible Senior Notes due 2020		186,592		262,075
5.75% Senior Notes due 2021		773,609		773,609
6.25% Senior Notes due 2023		408,296		408,296
6.625% Senior Notes due 2026		1,000,000		1,000,000
Total principal		3,280,756		2,818,980
Unamortized debt discounts and premiums ⁽¹⁾		-		(2,575)
Unamortized debt issuance costs on notes ⁽¹⁾		-		(16,520)
Total debt, prior to reclassification to liabilities subject to compromise		3,280,756		2,799,885
Less amounts reclassified to liabilities subject to compromise ⁽²⁾		(2,368,497)		-
Total debt not subject to compromise ⁽³⁾		912,259		2,799,885
Less current portion of long-term debt ⁽⁴⁾		(912,259)		-
Total long-term debt	$	-	$	2,799,885

September 30,

December 31,

2017

2016
Credit agreement

$
200,000

$
550,000
6.5% Senior Subordinated Notes due 2018

-

275,121
5.0% Senior Notes due 2019

961,409

961,409
1.25% Convertible Senior Notes due 2020

562,075

562,075
5.75% Senior Notes due 2021

873,609

873,609
6.25% Senior Notes due 2023

408,296

408,296
Total principal

3,005,389

3,630,510
Unamortized debt discounts and premiums

(56,151)

(71,340)
Unamortized debt issuance costs on notes

(17,795)

(23,867)
Total long-term debt

$
2,931,443

$
3,535,303

(1)

As a result of the Chapter 11 Cases and the adoption of ASC 852, the Company wrote off all unamortized premium and issuance cost balances to reorganization items, net in the condensed consolidated statements of operations for the three and six months ended June 30, 2020. Refer to the “Chapter 11 Cases” footnote for more information.

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

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

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

Chapter 11 Cases and Effect of Automatic Stay

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

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

Credit Agreement

Whiting Oil and Gas, the Company’s wholly owned subsidiary, has a credit agreement with a syndicate of banks that ~~as of September 30, 2017~~ had a borrowing base of $2.05 billion and aggregate commitments of ~~$2.5 billion.~~$1.75 billion prior to default. As of ~~September~~June 30, ~~2017,~~2020, the Company had ~~$2.3 billion~~$912 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 lenders’ commitments under the Credit Agreement have been terminated. The Company is therefore unable to make additional borrowings or issue additional letters of credit under the Credit Agreement.

Prior to default, a portion of the Credit Agreement in an aggregate amount not to exceed $50 million was available ~~borrowing capacity, which was net~~to issue letters of ~~$200 million in borrowings~~credit for the account of Whiting Oil and $9Gas or other designated subsidiaries of the Company. As of June 30, 2020, $2 million in letters of credit ~~outstanding.~~were outstanding under the agreement.

~~The~~Prior to default, the borrowing base under the ~~credit agreement is~~Credit Agreement was 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 have not occurred and 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 2017, the borrowing base and aggregate commitments under the facility were reduced to $2.3 billion in connection with the November 1, 2017 regular borrowing base redetermination, and was primarily a result of the sale of the Company’s FBIR Assets on September 1, 2017.

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, 2017, $41 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 ~~December 2019,~~maturity, when the ~~credit agreement~~Credit Agreement expires and all outstanding borrowings are due. Interest under the ~~revolving credit facility~~Credit Agreement accrues at the Company’s option at either (i) a base rate for a base rate loan plus a margin between 0.50% and 1.50% based on the ~~margin in~~ratio of outstanding borrowings to the ~~table below,~~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 ~~margin in~~ratio of outstanding borrowings to the ~~table below. Additionally,~~borrowing base. Prior to the chapter 11 proceedings, the Company ~~incurs~~incurred commitment fees ~~as set forth in~~of 0.375% or 0.50% based on the ~~table below~~ratio of outstanding borrowings to the borrowing base on the unused portion of the aggregate commitments of the lenders under the ~~revolving credit facility,~~Credit Agreement, which ~~are~~were included as a component of interest expense.

During the chapter 11

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At~~September30,2017~~ proceedings, the commitment fee has been terminated and ~~December 31, 2016,~~instead all amounts outstanding under the Credit Agreement will bear interest per annum at the applicable rate stated in the agreement plus a 2.0% default rate. At June 30, 2020, the weighted average interest rate on the outstanding principal balance under the ~~credit agreement~~Credit Agreement was ~~3.2%~~4.7%.

Prior to default, the Credit Agreement had a maturity date of April 12, 2023, provided that if at any time and ~~4.0%, respectively.~~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.

Applicable

Applicable

Margin for Base

Margin for

Commitment
Ratio of Outstanding Borrowings to Borrowing Base

Rate Loans

Eurodollar Loans

Fee
Less than 0.25 to 1.0

1.00%

2.00%

0.50%
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0

1.25%

2.25%

0.50%
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0

1.50%

2.50%

0.50%
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0

1.75%

2.75%

0.50%
Greater than or equal to 0.90 to 1.0

2.00%

3.00%

0.50%

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. ~~However, the credit agreement permits the Company and certain of its subsidiaries to issue second lien indebtedness of up to $1.0 billion subject to certain conditions and limitations.~~ 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 Company’s restricted subsidiaries (as defined in the ~~credit agreement)~~Credit Agreement). As of ~~September~~June 30, ~~2017,~~2020, there were no0 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 ~~senior secured~~ debt to ~~the~~ last four quarters’ EBITDAX ratio of ~~less than 3.0 to 1.0 during the Interim Covenant Period (defined below), and thereafter a total debt to EBITDAX ratio of less~~not greater than 4.0 to ~~1.0, and (iii)~~1.0.

Under the Credit Agreement, a ~~ratio~~cross-default provision provides that a default under certain other debt of the ~~last four quarters’ EBITDAX to consolidated cash interest charges~~Company or certain of ~~not less than 2.25 to 1.0 during~~its subsidiaries in an aggregate principal amount exceeding $100 million may constitute an event of default under such Credit Agreement. Additionally, under the ~~Interim Covenant Period. Under~~indentures governing the ~~credit agreement,~~Company’s senior notes and senior convertible notes, a cross-default provision provides that a default under certain other debt of the ~~“Interim Covenant Period” is defined as the period from June 30, 2015 until the earlier~~Company or certain of ~~(i) April 1, 2018 or (ii) the commencement of~~its subsidiaries in an ~~investment-grade debt rating period (as defined~~aggregate principal amount exceeding $100 million (or $50 million in the ~~credit agreement). The Company was~~case of the senior notes due in ~~compliance with its covenants~~2021) may constitute an event of default under ~~the credit agreement as~~such indenture.

Table of ~~September 30, 2017.~~Contents

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 ~~and Senior Subordinated Notes~~

~~The following table summarizes the material terms of the Company’s senior notes and convertible senior notes outstanding at September 30, 2017.~~

2020

2019

Convertible

2021

2023

Senior Notes

Senior Notes

Senior Notes

Senior Notes
Outstanding principal (in thousands)

$
961,409

$
562,075

$
873,609

$
408,296
Interest rate

5.0%

1.25%

5.75%

6.25%
Maturity date

Mar 15, 2019

Apr 1, 2020

Mar 15, 2021

Apr 1, 2023
Interest payment dates

Mar 15, Sep 15

Apr 1, Oct 1

Mar 15, Sep 15

Apr 1, Oct 1
Make-whole redemption date (1)

Dec 15, 2018

N/A (2)

Dec 15, 2020

Jan 1, 2023

~~(1)~~

On or after these dates, the Company may redeem the applicable series of notes, in whole or in part, at a redemption price equal to 100% of the principal amount redeemed, together with accrued and unpaid interest up to the redemption date. At any time prior to these dates, the Company may redeem the notes at a redemption price that includes an applicable premium as defined in the indentures to such notes.

~~(2)~~

~~The indenture governing our 1.25% Convertible Senior Notes due 2020 does not allow for optional redemption by the Company prior to the maturity date.~~

Senior Notes ~~and Senior Subordinated Notes~~—~~In September 2010, the Company issued at par $350 million of 6.5% Senior Subordinated Notes due October 2018 (the “2018 Senior Subordinated Notes”).~~

In September 2013, the Company issued at par ~~$1.1 billion of 5.0% Senior Notes due March 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

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March 15, 2021 (collectively, the “2021 Senior Notes”). ~~The~~Prior to the Petition Date, the debt premium recorded in connection with the issuance of the 2021 Senior Notes ~~is being~~was amortized to interest expense over the term of the notes using the effective interest method, with an effective interest rate of 5.5% per annum. As a result of the Chapter 11 Cases and the adoption of ASC 852, the remaining unamortized premium balance was written off to reorganization items, net in the condensed consolidated statements of operations. Refer to the “Chapter 11 Cases” footnote for more information.

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

In December 2017, the Company issued at par $1.0 billion of 6.625% Senior Notes due January 15, 2026 (the “2026 Senior Notes” and together with the ~~2019~~2021 Senior Notes and ~~2021~~the 2023 Senior Notes, the “Senior Notes”).

~~Exchange of Senior Notes and Senior Subordinated Notes for Convertible Notes. On March 23,~~During 2016, the Company ~~completed the exchange of $477~~exchanged $326 million aggregate principal amount of 2021 Senior Notes and ~~2018 Senior Subordinated Notes, consisting of (i) $49~~$342 million aggregate principal amount of ~~its 2018~~2023 Senior ~~Subordinated~~ Notes ~~(ii) $97~~for the same aggregate principal amount of convertible notes. Subsequently during 2016, all $668 million aggregate principal amount of ~~its~~these convertible notes was converted into approximately 16.3 million shares of the Company’s common stock pursuant to the terms of the notes.

Repurchases of 2021 Senior Notes. In September 2019, ~~Senior Notes, (iii) $152~~the Company paid $24 million to repurchase $25 million aggregate principal amount of ~~its~~the 2021 Senior Notes, and (iv) $179 million aggregate principal amount of its 2023 Senior Notes, for $477 million aggregate principal amount of convertible senior notes and convertible senior subordinated notes (the “New Convertible Notes”). This exchange transaction was accounted for as an extinguishment of debt for each portionwhich payment consisted of the ~~Senior Notes~~average 94.708% purchase price plus all accrued and ~~2018 Senior Subordinated Notes that was exchanged.~~unpaid interest on the notes. The Company financed the repurchases with borrowings under the Credit Agreement. As a result ~~Whiting~~of the repurchases, the Company recognized a ~~$91~~$1 million gain on extinguishment of debt, which ~~was net of~~included a ~~$4 million~~ non-cash charge for the acceleration of unamortized debt issuance costs and debt premium on the ~~original~~ notes. ~~Each series of New Convertible Notes was recorded at fair value upon issuance, with~~

In October 2019, the ~~difference between the principal amount of the notes and their fair values, totaling $95~~Company paid an additional $72 million ~~recorded as a debt discount. The aggregate debt discount of $185 million recorded upon issuance of the New Convertible Notes also included $90 million related~~ to the fair value of the holders’ conversion options, which were embedded derivatives that met the criteria to be bifurcated from their host contracts and accounted for separately. Refer to the “Derivative Financial Instruments” and “Fair Value Measurements” footnotes for more information on these embedded derivatives.

~~During the second quarter of 2016, holders of the New Convertible Notes voluntarily converted all $477~~repurchase $75 million aggregate principal amount of the New Convertible Notes for approximately 41.8 million shares of the Company’s common stock. Upon conversion, the Company paid $46 million in cash consisting of early conversion payments to the holders of the notes, as well as all accrued and unpaid interest on such notes. As a result of the conversions, Whiting recognized a $188 million loss on extinguishment of debt, which consisted of a non-cash charge for the acceleration of unamortized debt issuance costs and debt discount on the notes. As of June 30, 2016, no New Convertible Notes remained outstanding.

~~Exchange of~~2021 Senior ~~Notes and Senior Subordinated Notes for Mandatory Convertible Notes.~~ On July 1, 2016, the Company completed the exchange of $405 million aggregate principal amount of Senior Notes and 2018 Senior Subordinated Notes for the same aggregate principal amount of new mandatory convertible senior notes and mandatory convertible senior subordinated notes. Refer to “Mandatory Convertible Notes” below for more information on these exchange transactions.

~~Redemption of 2018 Senior Subordinated Notes.~~ ~~On February 2, 2017,the Company paid $281 million to redeem all of the then outstanding $275 million aggregate principal amount of 2018 Senior Subordinated~~ Notes, which payment consisted of the ~~100% redemption~~average 95.467% purchase price plus all accrued and unpaid interest on the notes. The Company financed the ~~redemption~~repurchases with borrowings under ~~its credit agreement.~~the Credit Agreement. As a result of the ~~redemption, Whiting~~repurchases, the Company recognized a $2$3 million ~~loss~~gain on extinguishment of debt, which ~~consisted of~~included a ~~non-cash~~noncash charge for the acceleration of unamortized debt issuance costs and debt premium on the notes. As of ~~March 31, 2017, no 2018~~June 30, 2020, $774 million of 2021 Senior ~~Subordinated~~ 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. ~~On June 29,~~During 2016, the Company exchanged $129 million aggregate principal amount of its 2020 Convertible Senior Notes for the same aggregate principal amount of new mandatory convertible senior notes, and on July 1, 2016, the Company exchanged $559$688 million aggregate principal amount of its 2020 Convertible Senior Notes for the same aggregate principal amount of new mandatory convertible senior notes. ~~Refer to “Mandatory Convertible Notes” below for more information on these exchange transactions.~~

~~For the remaining $562~~Subsequently during 2016, all $688 million aggregate principal amount of ~~2020 Convertible Senior Notes outstanding as~~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 ~~30, 2017,~~2019, the Company ~~has the option~~paid $299 million to ~~settle conversions of these notes with~~complete a cash ~~shares of common stock or a combination of cash and common stock at its election. The Company’s intent is to settle the~~tender offer for $300 million aggregate principal amount of the 2020 Convertible Senior Notes, which payment consisted of the 99.0% purchase price plus all accrued and unpaid interest on the notes, which were allocated to the liability and equity components based on their relative fair values. The Company financed the tender offer with borrowings under the Credit Agreement. As a result of the tender offer, the Company recognized a $4 million gain on extinguishment of debt, which was net of a $7 million charge for the non-cash write-off of unamortized debt issuance costs and debt discount and a $1 million charge for transaction costs. In addition, the Company recorded an $8 million reduction to the equity component of the 2020 Convertible Senior Notes. There was 0 deferred tax impact associated with this reduction due to the full valuation allowance in ~~cash upon conversion.~~ effect as of September 30, 2019.

In March 2020, the Company paid $53 million to repurchase $73 million aggregate principal amount of the 2020 Convertible Senior Notes, which payment consisted of the average 72.5% purchase price plus all accrued and unpaid interest on the notes, which were allocated to the liability and equity components based on their relative fair values. The Company financed the repurchases with borrowings under the Credit Agreement. As a result of these repurchases, the Company recognized a $23 million gain on extinguishment

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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 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

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scheduled trading day immediately preceding the April 1, 2020 maturity date of the ~~notes. The~~ notes ~~will be convertible~~and holders of $3 million aggregate principal amount of 2020 Convertible Senior Notes timely elected to convert. Upon conversion, such holders of the converted 2020 Convertible Senior Notes were entitled to receive an insignificant cash payment on April 1, 2020, which the Company did not pay. As a result of such conversion the Company recognized a $3 million gain on extinguishment of debt for the six months ended June 30, 2020. Additionally, at ~~an initial conversion rate of 25.6410 shares of Whiting’s common stock per $1,000~~maturity, the Company was obligated to pay in cash the $187 million outstanding principal amount of the notes, which is equivalent to an initial conversion price of approximately $39.00. 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 such corporate event. As of September 30, 2017, none of~~that did not convert, which the ~~contingent conditions allowing~~Company did not pay. Under the Bankruptcy Code, the holders of the 2020 Convertible Senior Notes and the prior holders that converted their notes are stayed from taking any action against the Company as a result of the Company’s non-payment. Refer to ~~convert these notes had been met.~~“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.

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~~sheets and ~~are being~~were amortized to interest expense over the term of the notes using the effective interest method. Issuance costs attributable to the equity component were recorded as a charge to additional paid-in capital within shareholders’ equity.

The 2020 Convertible Senior Notes consisted of the following at ~~September~~June 30, ~~2017~~2020 and December 31, ~~2016~~2019 (in thousands):


	June 30,		December 31,
	2020		2019
Liability component
Principal	$	186,592	$	262,075
Less: unamortized note discount		-		(2,829)
Less: unamortized debt issuance costs		-		(220)
Net carrying value	$	186,592	$	259,026
Equity component ⁽¹⁾	$	125,009	$	128,452

September 30,

December 31,

2017

2016
Liability component

Principal

$
562,075

$
562,075
Less: unamortized note discount

(57,015)

(72,622)
Less: unamortized debt issuance costs

(4,633)

(5,988)
Net carrying value

$
500,427

$
483,465
Equity component (1)

$
136,522

$
136,522

(1)

~~(1)~~

Recorded in additional paid-in capital, net of $5 million of issuance costs and $50 million of deferred ~~taxes as of September 30, 2017 and December 31, 2016.~~

taxes.

The following table presents the interest expense recognized on the 2020 Convertible Senior Notes related to the stated interest rate and amortization of the debt discount for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 and ~~2016~~June 30, 2019 (in thousands):


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2020		2019		2020		2019
Interest expense on 2020 Convertible Senior Notes	$	-	$	7,574	$	3,463	$	15,068

Three Months Ended

Nine Months Ended

September 30,

September 30,

2017

2016

2017

2016
Interest expense on 2020 Convertible Senior Notes

$
7,032

$
6,745

$
20,876

$
36,068

~~Mandatory Convertible Notes~~—On June 29, 2016, the Company completed the exchange of $129 million aggregate principal amount of its 2020 Convertible Senior Notes for the same aggregate principal amount of new mandatory convertible notes, and on July 1, 2016, the Company completed the exchange of $964 million aggregate principal amount of Senior Notes, 2020 Convertible Senior Notes and 2018 Senior Subordinated Notes, consisting of (i) $26 million aggregate principal amount of 2018 Senior Subordinated Notes, (ii) $42 million aggregate principal amount of 2019 Senior Notes, (iii) $559 million aggregate principal amount of 2020 Convertible Senior Notes, (iv) $174 million aggregate principal amount of 2021 Senior Notes, and (v) $163 million aggregate principal amount of 2023 Senior Notes, for the same aggregate principal amount of new mandatory convertible notes (together the “Mandatory Convertible Notes”).

These transactions were accounted for as extinguishments of debt for the portions of Senior Notes, 2020 Convertible Senior Notes and 2018 Senior Subordinated Notes that were exchanged. As a result, Whiting recognized a $57 million gain on extinguishment of debt, which was net of a $113 million charge for the non-cash write-off of unamortized debt issuance costs, debt discounts and debt premium on the original notes. In addition, Whiting recorded a $63 million reduction to the equity component of the 2020 Convertible Senior

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Notes, which was net of deferred taxes. The Mandatory Convertible Notes were recorded at fair value upon issuance with the difference between the principal amount of the notes and their fair values, totaling $69 million, recorded as a debt discount. The Mandatory Convertible Notes contained contingent beneficial conversion features, the intrinsic value of which was recognized in additional paid-in capital at the time the contingency was resolved, resulting in an additional debt discount of $233 million. The aggregate debt discount of $302 million was being amortized to interest expense over the term of the notes using the effective interest method.

The July 1, 2016 note exchange transactions triggered an ownership shift as defined under Section 382 of the Internal Revenue Code due to the “deemed share issuance” that resulted from the note exchanges. This triggering event will limit the Company’s usage of certain of its net operating losses and tax credits in the future. Refer to the “Income Taxes” footnote for more information.

In July 2016, $333 million aggregate principal amount of the Mandatory Convertible Notes were converted into approximately 33.2 million shares of the Company’s common stock pursuant to the terms of the notes, and the Company paid $3 million in cash consisting of all accrued and unpaid interest on such notes. As a result of the conversions, Whiting recognized a $3 million gain on extinguishment of debt, which was net of a non-cash charge for the acceleration of unamortized debt issuance costs and debt discount on the notes.

In August 2016, the Company completed an induced exchange of $38 million aggregate principal amount of the Mandatory Convertible Notes for approximately 4.9 million shares of the Company’s common stock. As a result of the exchange, the Company (i) paid $1 million in cash consisting of all accrued and unpaid interest on such notes, (ii) recognized $4 million of debt inducement expense related to the fair value of the incremental shares issued in the inducement offer over the original conversion terms of the notes, which expense was included in (gain) loss on extinguishment of debt in the condensed consolidated statements of operations, and (iii) recognized a $14 million non-cash charge for the acceleration of unamortized debt discount on the notes, which was included in interest expense in the condensed consolidated statements of operations.

During the fourth quarter of 2016, the remaining $721 million aggregate principal amount of the Mandatory Convertible Notes were converted into approximately 77.6 million shares of the Company’s common stock pursuant to the terms of the notes. As of December 31, 2016, no Mandatory Convertible Notes remained outstanding.

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~~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. 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 ~~at September~~as of June 30, ~~2017~~2020 and December 31, ~~2016~~2019 were $5 million and $8$4 million, respectively, and have been included in accrued liabilities and other in the consolidated balance sheets. The following table provides a reconciliation of the Company’s asset retirement obligations for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 (in thousands):


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

(1)

~~Asset retirement obligation at January 1, 2017~~	$	~~177,004~~
~~Additional liability incurred~~		~~5,302~~
~~Revisions~~Refer to ~~estimated cash flows~~ ~~(1)~~		~~(21,219)~~
~~Accretion expense~~		~~10,502~~
~~Obligations~~the “Chapter 11 Cases” footnote for more information on ~~sold properties~~		~~(6,997)~~
~~Liabilities settled~~		~~(2,777)~~
~~Asset retirement obligation at September 30, 2017~~	$	~~161,815~~ liabilities subject to compromise.

~~(1)~~

Revisions to estimated cash flows during the nine months ended September 30, 2017 are attributable to decreases in the estimates of future costs required to plug and abandon wells in certain fields in the Northern Rocky Mountains.

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6.7. 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 ~~costless collars,~~and natural gas swaps and ~~sales and delivery contracts~~collars to achieve a more predictable cash flow by reducing its exposure to commodity price volatility, thereby ensuring adequate funding for the Company’s capital programs and facilitating the management of returns on drilling programs and acquisitions. The Company does not enter into derivative contracts for speculative or trading purposes.

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

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The table below details the Company’s ~~costless collar~~swap derivatives entered into to hedge forecasted crude oil and natural gas production revenues as of ~~September~~June 30, ~~2017.~~2020.

Commodity

Settlement Period

Index

Derivative Instrument

Total Volumes ⁽¹⁾

Units

Weighted Average Swap Price

Crude Oil

Crude Oil

2020

NYMEX WTI

Fixed Price Swaps

1,564,000

Bbl

$40.96

Crude Oil

2021

NYMEX WTI

Fixed Price Swaps

2,737,500

Bbl

$40.05

Total

4,301,500

Bbl

Natural Gas

Natural Gas

2021

NYMEX Henry Hub

Fixed Price Swaps

3,650,000

MMBtu

$2.60

(1)

		~~Whiting Petroleum Corporation~~

~~Derivative~~		~~Contracted Crude~~	~~Weighted Average NYMEX Price~~
~~Instrument~~	~~Period~~	~~Oil Volumes (Bbl)~~	~~Collar Ranges for Crude Oil (per Bbl)~~
~~Three-way collars~~ ~~(1) (2)~~	~~Oct - Dec 2017~~	~~3,750,000~~	~~$35.00 - $45.20 - $58.95~~
	~~Jan - Dec 2018~~	~~12,600,000~~	~~$36.67 - $46.67 - $56.95~~
~~Collars~~	~~Oct - Dec 2017~~	~~750,000~~	~~$53.00 - $70.44~~
	~~Total~~	~~17,100,000~~

~~(1)~~

A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The sold call establishes a maximum price (ceiling) Whiting will receive for the volumes under contract. The purchased put establishes a minimum price (floor), unless the market price 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.

~~(2)~~

Subsequent to ~~September~~June 30, ~~2017,~~2020, the Company entered into additional ~~three-way collar~~swap contracts for ~~2,400,000~~459,000 Bbl of crude oil volumes for the ~~year ended December 31, 2018.~~

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

~~Crude Oil Sales and Delivery Contract.~~ Effect of Chapter 11 Cases—The ~~Company has a long-term crude oil sales and delivery contract for oil volumes produced from its Redtail field in Colorado. Under the terms~~commencement of the ~~agreement, Whiting has committed~~Chapter 11 Cases constituted a termination event with respect to ~~deliver~~the Company’s derivative instruments, which permits the counterparties of such derivative instruments to terminate their outstanding hedges. Such termination events are not stayed under the Bankruptcy Code. During April 2020, certain ~~fixed volumes~~ of ~~crude oil through April 2020. The Company determined it was not probable that future oil production from its Redtail field would be sufficient~~the lenders under the Credit Agreement elected to ~~meet the minimum volume requirements specified in this contract; accordingly,~~terminate their master ISDA agreements and outstanding hedges with the Company ~~would not settle this contract through physical delivery~~for aggregate settlement proceeds of ~~crude oil volumes.~~$145 million. The proceeds from these terminations along with $13 million of March 2020 hedge settlement proceeds received in April 2020 were applied to the outstanding borrowings under the Credit Agreement. An additional $23 million of settlement proceeds from terminated derivative positions will be held in escrow until the completion of the Chapter 11 Cases and are recorded in restricted cash in the condensed consolidated balance sheet as of June 30, 2020. As a result Whiting determined that this contract would not qualify for the “normal purchase normal sale” exclusion and has therefore reflected the contract at fair value in the consolidated financial statements. As of September 30, 2017 and December 31, 2016, the estimated fair value of this derivative contract was a liability of $57 million and $9 million, respectively.

~~Embedded Derivatives~~—In March 2016, the Company issued convertible notes that contained debtholder conversion options which the Company determined were not clearly and closely related to the debt host contracts, and the Company therefore bifurcated these embedded features and reflected them at fair value in the consolidated financial statements. During the second quarter of 2016, the entire aggregate principal amount of these ~~notes was converted into shares~~terminations, all of the Company’s ~~common stock, and the fair value of these embedded derivatives as of September 30, 2017 and December 31, 2016 was therefore zero.~~

~~In July 2016, the Company entered into a purchase and sale agreement~~outstanding derivative contracts are concentrated with ~~the buyer of its North Ward Estes Properties, whereby the buyer agreed to pay Whiting additional proceeds of $100,000 for every $0.01 that,~~two counterparties as of June ~~28, 2018, the average NYMEX crude oil futures contract price for each month from August 2018 through July 2021 is above $50.00/Bbl up to a maximum amount~~30, 2020. Both of $100 million. The Company determined that this NYMEX-linked contingent payment was not clearly and closely related to the host contract, and the Company therefore bifurcated this embedded feature and reflected it at its estimated fair value of $51 millionthese counterparties are participants in the ~~consolidated financial statements as of December 31, 2016. On July 19, 2017, however, the buyer paid $35 million to Whiting to settle this NYMEX-linked contingent payment,~~Credit Agreement and ~~accordingly, the embedded derivative’s fair value was zero as of September 30, 2017.~~have investment-grade ratings from Moody’s and Standard & Poor’s.

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Derivative Instrument Reporting—All derivative instruments are recorded in the condensed consolidated financial statements at fair value, other than derivative instruments that meet the “normal purchase normal sale” exclusion or other derivative scope exceptions. The following tables summarize the effects of derivative instruments on the condensed consolidated statements of operations for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 and ~~2016~~2019 (in thousands):



		(Gain) Loss Recognized in Income

							(Gain) Loss Recognized in Income
Not Designated as	Statement of Operations	Nine Months Ended September 30,				Statements of Operations	Three Months Ended June 30,
ASC 815 Hedges	Classification	2017		2016		Classification	2020		2019
Commodity contracts	Derivative (gain) loss, net	$	28,572	$	27,663	Derivative (gain) loss, net	$	6,632	$	(24,877)
Embedded derivatives	Derivative (gain) loss, net		18,709		(56,095)
Total		$	47,281	$	(28,432)		$	6,632	$	(24,877)


		(Gain) Loss Recognized in Income
Not Designated as	Statements of Operations	Six Months Ended June 30,
ASC 815 Hedges	Classification	2020		2019
Commodity contracts	Derivative (gain) loss, net	$	(224,739)	$	38,028
Total		$	(224,739)	$	38,028

(Gain) Loss Recognized in Income
Not Designated as

Statement of Operations

Three Months Ended September 30,
ASC 815 Hedges

Classification

2017

2016
Commodity contracts

Derivative (gain) loss, net

$
30,867

$
(22,302)
Embedded derivatives

Derivative (gain) loss, net

-

(8,130)
Total

$
30,867

$
(30,432)

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, 2017 (1)

Net

Gross

Recognized

Recognized

Gross

Fair Value
Not Designated as

Assets/

Amounts

Assets/
ASC 815 Hedges

Balance Sheet Classification

Liabilities

Offset

Liabilities
Derivative assets

Commodity contracts - current

Prepaid expenses and other

$
25,150

$
(24,577)

$
573
Commodity contracts - non-current

Other long-term assets

10,810

(10,810)

-
Total derivative assets

$
35,960

$
(35,387)

$
573
Derivative liabilities

Commodity contracts - current

Derivative liabilities

$
49,722

$
(24,577)

$
25,145
Commodity contracts - non-current

Other long-term liabilities

45,571

(10,810)

34,761
Total derivative liabilities

$
95,293

$
(35,387)

$
59,906

December 31, 2016 (1)

Net

Gross

Recognized

Recognized

Gross

Fair Value
Not Designated as

Assets/

Amounts

Assets/
ASC 815 Hedges

Balance Sheet Classification

Liabilities

Offset

Liabilities
Derivative assets

Commodity contracts - current

Prepaid expenses and other

$
21,405

$
(21,405)

$
-
Commodity contracts - non-current

Other long-term assets

9,495

(9,495)

-
Embedded derivatives - non-current

Other long-term assets

50,632

-

50,632
Total derivative assets

$
81,532

$
(30,900)

$
50,632
Derivative liabilities

Commodity contracts - current

Derivative liabilities

$
39,033

$
(21,405)

$
17,628
Commodity contracts - non-current

Other long-term liabilities

19,724

(9,495)

10,229
Total derivative liabilities

$
58,757

$
(30,900)

$
27,857

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		June 30, 2020⁽¹⁾
						Net
		Gross				Recognized
		Recognized		Gross		Fair Value
Not Designated as		Assets/		Amounts		Assets/
ASC 815 Hedges	Balance Sheet Classification	Liabilities		Offset		Liabilities
Derivative assets
Commodity contracts - current	Prepaid expenses and other	$	3,714	$	(289)	$	3,425
Commodity contracts - non-current	Other long-term assets		77		(77)		-
Total derivative assets		$	3,791	$	(366)	$	3,425
Derivative liabilities
Commodity contracts - current	Accrued liabilities and other	$	1,730	$	(289)	$	1,441
Commodity contracts - non-current	Other long-term liabilities		943		(77)		866
Total derivative liabilities		$	2,673	$	(366)	$	2,307


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

(1)

~~(1)~~

Because substantially all of the 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 lenders under ~~Whiting’s credit agreement.~~the Credit Agreement. The Company uses ~~only credit agreement~~primarily 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.

7.8. 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.

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●

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. The Company reflects transfers between the three levels at the beginning of the reporting period in which the availability of observable inputs no longer justifies classification in the original level.

Cash, cash equivalents, restricted cash, accounts receivable and accounts payable are carried at cost, which approximates their fair value because of the short-term maturity of these instruments. The Company’s ~~credit agreement~~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 ~~and senior subordinated notes~~ are recorded at cost and the ~~Company’s~~ 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~~June 30, ~~2017~~2020 and December 31, ~~2016~~2019 (in thousands):


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

September 30, 2017

December 31, 2016

Fair

Carrying

Fair

Carrying

Value (1)

Value (2)

Value (1)

Value (2)
6.5% Senior Subordinated Notes due 2018

$
-

$
-

$
275,121

$
273,506
5.0% Senior Notes due 2019

961,409

958,176

961,409

956,607
1.25% Convertible Senior Notes due 2020

500,598

500,427

503,057

483,465
5.75% Senior Notes due 2021

860,505

869,073

868,149

868,460
6.25% Senior Notes due 2023

397,578

403,767

408,296

403,265
Total

$
2,720,090

$
2,731,443

$
3,016,032

$
2,985,303

(1)

~~(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)

~~(2)~~

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

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

The Company’s derivative financial instruments are recorded at fair value and include a measure of the Company’s own nonperformance risk or that of its counterparty, as appropriate. The following tables present information about the Company’s financial assets and

~~Table of Contents~~

liabilities measured at fair value on a recurring basis as of ~~September~~June 30, ~~2017~~2020 and December 31, ~~2016,~~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
	Level 1		Level 2		Level 3		June 30, 2020
Financial Assets
Commodity derivatives – current	$	-	$	3,425	$	-	$	3,425
Total financial assets	$	-	$	3,425	$	-	$	3,425
Financial Liabilities
Commodity derivatives – current	$	-	$	1,441	$	-	$	1,441
Commodity derivatives – non-current		-		866		-		866
Total financial liabilities	$	-	$	2,307	$	-	$	2,307

Total Fair Value

Level 1

Level 2

Level 3

September 30, 2017
Financial Assets

Commodity derivatives – current

$
-

$
573

$
-

$
573
Total financial assets

$
-

$
573

$
-

$
573
Financial Liabilities

Commodity derivatives – current

$
-

$
1,762

$
23,383

$
25,145
Commodity derivatives – non-current

-

1,370

33,391

34,761
Total financial liabilities

$
-

$
3,132

$
56,774

$
59,906

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							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

Total Fair Value

Level 1

Level 2

Level 3

December 31, 2016
Financial Assets

Embedded derivatives – non-current

$
-

$
50,632

$
-

$
50,632
Total financial assets

$
-

$
50,632

$
-

$
50,632
Financial Liabilities

Commodity derivatives – current

$
-

$
14,664

$
2,964

$
17,628
Commodity derivatives – non-current

-

3,979

6,250

10,229
Total financial liabilities

$
-

$
18,643

$
9,214

$
27,857

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

In addition, the Company has a long-term crude oil sales and delivery contract, whereby it has committed to deliver certain fixed volumes of crude oil through April 2020. Whiting has determined that the contract does not meet the “normal purchase normal sale” exclusion, and has therefore reflected this contract at fair value in its consolidated financial statements. This commodity derivative was valued based on a probability-weighted income approach which considers 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 include 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.

~~Embedded Derivatives~~. The Company had embedded derivatives related to its convertible notes that were issued in March 2016. The notes contained debtholder conversion options which the Company determined were not clearly and closely related to the debt host contracts and the Company therefore bifurcated these embedded features and reflected them at fair value in the consolidated financial statements. Prior to their settlements, the fair values of these embedded derivatives were determined using a binomial lattice model which considered various inputs including (i) Whiting’s common stock price, (ii) risk-free rates based on U.S. Treasury rates, (iii) recovery rates in the event of default, (iv) default intensity, and (v) volatility of Whiting’s common stock. The expected volatility and default intensity used in the valuation were unobservable in the marketplace and significant to the valuation methodology, and the embedded derivatives’ fair value was therefore designated as Level 3 in the valuation hierarchy. During the second quarter of 2016, the entire aggregate principal amount of these convertible notes was converted into shares of the Company’s common stock. Accordingly, the embedded derivatives were settled in their entirety as of June 30, 2016.

The Company had an embedded derivative related to its purchase and sale agreement with the buyer of the North Ward Estes Properties. The agreement included a Contingent Payment linked to NYMEX crude oil prices which the Company determined was not clearly and closely related to the host contract, and the Company therefore bifurcated this embedded feature and reflected it at fair value in the consolidated financial statements prior to settlement. The fair value of this embedded derivative was determined using a modified

~~Table of Contents~~

Black-Scholes swaption pricing model which considers various assumptions, including quoted forward prices for commodities, time value and volatility factors. These assumptions were observable in the marketplace throughout the full term of the financial instrument, could be derived from observable data or were supported by observable levels at which transactions are executed in the marketplace, and were therefore designated as Level 2 within the valuation hierarchy. The discount rate used in the fair value of this instrument included a measure of the counterparty’s nonperformance risk. On July 19, 2017, the buyer paid $35 million to Whiting in satisfaction of this Contingent Payment. Accordingly, the embedded derivative was settled in its entirety as of that date.

~~Level 3 Fair Value Measurements~~—A third-party valuation specialist is utilized to determine the fair value of the Company’s derivative instruments designated as Level 3. The Company reviews these valuations, including the related model inputs and assumptions, and analyzes changes in fair value measurements between periods. The Company corroborates such inputs, calculations and fair value changes using various methodologies, and reviews unobservable inputs for reasonableness utilizing relevant information from other published sources.

The following table presents a reconciliation of changes in the fair value of financial assets or liabilities designated as Level 3 in the valuation hierarchy for the three and nine months ended September 30, 2017 and 2016 (in thousands):

Three Months Ended

Nine Months Ended

September 30,

September 30,

2017

2016

2017

2016
Fair value liability, beginning of period

$
(61,952)

$
(9,884)

$
(9,214)

$
(4,027)
Recognition of embedded derivatives associated with convertible note issuances

-

-

-

(89,884)
Unrealized gains on embedded derivatives included in earnings (1)

-

-

-

47,965
Settlement of embedded derivatives upon conversion of convertible notes

-

-

-

41,919
Unrealized gains (losses) on commodity derivative contracts included in earnings (1)

5,178

288

(47,560)

(5,569)
Transfers into (out of) Level 3

-

-

-

-
Fair value liability, end of period

$
(56,774)

$
(9,596)

$
(56,774)

$
(9,596)

~~(1)~~

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

~~Quantitative Information about Level 3 Fair Value Measurements.~~ ~~The significant unobservable inputs used in the fair value measurement of the Company’s commodity derivative instrument designated as Level 3 are as follows:~~

~~Sensitivity to Changes in Significant Unobservable Inputs.~~ As presented above, the significant unobservable inputs used in the fair value measurement of Whiting’s commodity derivative contract are the market differentials for crude oil over the term of the contract. Significant increases or decreases in these unobservable inputs in isolation would result in a significantly lower or higher, respectively, fair value liability measurement.

Non-recurring Fair Value Measurements—The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including proved property. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. The Company did not recognize any impairment write-downs with respect to its proved property during the ~~2017 or 2016 reporting periods presented.~~

~~8. SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTEREST~~

~~Common Stock—In September 2017,~~three and six months ended June 30, 2019. The following tables present information about the Company’s non-financial assets measured at fair value on a non-recurring basis during the three and six months ended June 30, 2020, and indicate the fair value hierarchy of the valuation techniques utilized by the Company ~~announced~~to determine such fair values (in thousands):


									Loss (Before
	Net Carrying								Tax) Six
	Value as of								Months Ended
	March 31,		Fair Value Measurements Using						June 30,
	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, certain proved oil and gas properties across the Company’s Williston Basin resource play with a previous carrying amount of $4.5 billion were written down to their fair value as of March 31, 2020 of $816 million, resulting in a non-cash impairment charge of $3.7 billion, which was recorded within exploration and impairment expense. These impaired properties were written down due to a reduction in anticipated future cash flows primarily driven by an expectation of sustained depressed oil prices and a resultant decline in future development plans for the properties.


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

(2)

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

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depressed oil prices and a resultant decline in future development plans for the properties assessed during the second quarter of 2020.

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

9. REVENUE RECOGNITION

The Company recognizes revenue in accordance with FASB ASC Topic 606 – Revenue from Contracts with Customers (“ASC 606”). Revenue is recognized at the point in time at which the Company’s performance obligations under its commodity sales contracts are satisfied and control of the commodity is transferred to the customer. The Company has determined that its contracts for the sale of crude oil, unprocessed natural gas, residue gas and NGLs contain monthly performance obligations to deliver product at locations specified in the contract. Control is transferred at the delivery location, at which point the performance obligation has been satisfied and revenue is recognized. Fees included in the contract that are incurred prior to control transfer are classified as transportation, gathering, compression and other, and fees incurred after control transfers are included as a ~~reverse~~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 six months ended June 30, 2020 and 2019 (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
OPERATING REVENUES
Oil sales	$	91,904	$	403,870	$	323,849	$	763,324
NGL and natural gas sales ⁽¹⁾		(304)		22,394		12,597		52,429
Oil, NGL and natural gas sales	$	91,600	$	426,264	$	336,446	$	815,753

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

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 June 30, 2020 and December 31, 2019, such receivable balances were $54 million and $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.

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10. 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 ~~split~~owned by its “5-percent shareholders,” as such term is defined in Section 382 of ~~Whiting’s common stock at~~the IRC, increases by more than 50% over a ~~ratio ranging from any whole number between one-for-two~~rolling three-year period.

On March 26, 2020 the Company adopted a Section 382 Rights Agreement (the “Rights Agreement”) designed to ~~one-for-six, as determined by~~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 ~~reduction~~triggering event, which is defined in the ~~number~~Rights Agreement as close of ~~authorized shares~~business on the tenth day following the public announcement or public disclosure of ~~Whiting’s~~facts indicating that a person or group that already owns 4.9% or more of the Company’s common stock ~~as set~~(“acquiring person or group”) acquires additional shares. A triggering event entitles the registered holder to purchase from the Company one one-thousandth of a share of Series A Preferred Stock, par value of $0.001 per share, at a price of $7.00per 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 ~~chart below based on~~Order), as well as certain obligations with respect to notifying the ~~reverse~~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 ~~split ratio selected.~~

~~Table~~is null and void ab initio and (ii) the person or entity making such a declaration of ~~Contents~~



		~~Number of Shares of~~
~~Ratio~~		~~Common Stock Authorized~~
~~1:2~~		~~450,000,000~~
~~1:3~~		~~300,000,000~~
~~1:4~~		~~225,000,000~~
~~1:5~~		~~180,000,000~~
~~1:6~~		~~150,000,000~~

~~The Company will hold a special meeting of stockholders on November 8, 2017 to seek approval for the reverse stock split and authorized share reduction.~~

~~Noncontrolling Interest~~—The Company’s noncontrolling interest represented an unrelated third party’s 25% ownership interest in Sustainable Water Resources, LLC (“SWR”). During the third quarter of 2017, the third party’s ownership interest in SWR was assigned back to SWR. The~~table below summarizes the activity for the equity attributable~~worthlessness with respect to the ~~noncontrolling interest (in thousands):~~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.

Nine Months Ended

September 30,

2017

2016
Balance at beginning of period

$
7,962

$
7,984
Net loss

(14)

(18)
Conveyance of ownership interest

(7,948)

-
Balance at end of period

$
-

$
7,966

9.11. 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 ~~includes~~originally granted the authority to issue ~~10,800,000~~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

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under the 2013 Equity Plan will be cancelled and will not be available for future issuance. ~~On December 8, 2014, in conjunction with~~Under the ~~acquisition of Kodiak, the Company increased the number of shares issuable under the~~amended and restated 2013 Equity Plan, ~~by 978,161 shares to accommodate for the conversion of Kodiak’s outstanding equity awards to Whiting equity awards upon closing of the acquisition. Any shares netted~~during any calendar year no officer or ~~forfeited under this increased availability will be cancelled and will not be available for future issuance under the 2013 Equity Plan. Under the 2013 Equity Plan, no~~other key employee ~~or officer~~ participant may be granted options or stock appreciation rights for more than ~~900,000~~500,000 shares of common stock ~~stock appreciation rights relating to~~or more than ~~900,000 shares of common stock, more than 600,000~~500,000 shares of restricted stock ~~more than 600,000~~(“RSAs”), restricted stock units ~~more than 600,000~~(“RSUs”), performance shares (“PSAs”), or ~~more than 600,000~~ performance share units ~~during any calendar year.~~(“PSUs”), the value of which is based on the fair market value of a share of common stock. In addition, no non-employee director participant may be granted during any calendar year options or stock appreciation rights for more than ~~100,000~~25,000 shares of common stock, ~~stock appreciation rights relating to more than 100,000 shares of common stock, more than 100,000 shares of restricted stock,~~ or more than ~~100,000 restricted stock units during any calendar year.~~25,000 shares of RSAs or RSUs. As of ~~September~~June 30, ~~2017, 5,084,490~~2020, 3,886,734 shares of common stock remained available for grant under the 2013 Equity Plan.

~~Restricted Stock and Performance Shares~~—The Company ~~grants~~has granted service-based ~~restricted stock awards~~RSAs and RSUs to executive officers and employees, which generally vest ratably over a three-year service ~~period, and~~period. The Company has granted service-based RSAs to directors, which generally vest over a one-year service period. In addition, the Company ~~grants performance share awards~~has granted PSAs and PSUs to executive officers that are subject to market-based vesting criteria, ~~as well as~~which generally vest over a three-year service period. ~~Upon adoption of ASU 2016-09 on January 1, 2017, the~~The Company ~~elected to account~~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~~six months ended ~~September~~June 30, ~~2017~~2020 and ~~2016, 1,637,462~~2019, 53,198 and ~~2,952,193~~389,303 shares, respectively, of service-based ~~restricted stock~~RSAs and RSUs were granted to ~~employees,~~ 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, ~~fair value of restricted stock~~which is ~~determined~~ based on the closing bid price of the Company’s common stock on ~~the grant~~such date. The weighted average grant date fair value of ~~restricted stock~~service-based RSAs and RSUs was ~~$11.38~~$4.94 per share and ~~$6.95~~$27.97 per share for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 and ~~2016,~~2019, respectively. On March 31, 2020, all of the RSAs issued to executive officers in 2020 were forfeited and concurrently replaced with cash incentives. Refer to “2020 Compensation Adjustments” below for more information.

~~Table of Contents~~

~~In January 2017~~During the six months ended June 30, 2020 and ~~2016, 633,479~~2019, 1,616,504 and ~~1,073,143 performance~~308,432 shares, respectively, of service-based RSUs were granted to executive officers and employees under the 2013 Equity Plan. 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 six months ended June 30, 2020 and 2019, 1,665,153 and 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 ~~same~~ three-year performance period. The number of ~~shares~~awards earned could range from ~~zero~~0 up to ~~two~~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:

2017

2016
Number of simulations

2,500,000

2,500,000
Expected volatility

82.44%

60.8%
Risk-free interest rate

1.52%

1.13%
Dividend yield

-

-


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

The weighted average grant date fair value of the market-based awards that will be settled in shares, as determined by the Monte Carlo valuation model, was ~~$16.36~~$4.31 per share and ~~$6.39~~$25.97 per share in ~~January 2017~~2020 and ~~2016,~~2019, respectively.

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2020 Compensation Adjustments. All of the RSAs, RSUs, PSAs and PSUs granted to executive officers in 2020 were forfeited on March 31, 2020 and 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 condensed consolidated balance sheets as of March 31, 2020 and is being amortized over the relevant service period. Amortization of the fair value of these cash incentives totaled $7 million during the three and six months ended June 30, 2020 and is included in general and administrative expenses in the condensed consolidated statements of operations. 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 statements of operations during the first quarter of 2020.

The following table shows a summary of the Company’s ~~restricted stock~~service-based and ~~performance share~~market-based awards activity for the ~~nine~~six months ended ~~September~~June 30, ~~2017:~~2020:

Number of Shares

Weighted Average

Service-Based

Market-Based

Grant Date

Restricted Stock

Performance Shares

Fair Value
Nonvested awards, January 1, 2017

3,067,804

2,092,810

$
13.55
Granted

1,637,462

633,479

12.77
Vested

(1,182,970)

-

13.00
Forfeited

(245,732)

(776,525)

20.74
Nonvested awards, September 30, 2017

3,276,564

1,949,764

$
11.93

~~Stock Options—~~


	Number of Awards		Weighted Average
	Service‑Based	Market-Based	Grant Date
	RSAs & RSUs	PSAs & PSUs	Fair Value
Nonvested awards, January 1	467,502	448,387	$	28.28
Granted	53,198	1,665,153		4.33
Vested	(181,728)	-		27.52
Forfeited	(128,870)	(1,773,101)		7.53
Nonvested awards, June 30	210,102	340,439	$	25.45

There was no significant stock option activity during the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 and ~~2016.~~2019.

Total stock compensation expense recognized for restricted ~~shares~~stock was $1 million and ~~stock options was $6~~$4 million for ~~each of~~ the three months ended ~~September~~June 30, ~~2017~~2020 and ~~2016,~~2019, respectively, and ~~$19~~$2 million and ~~$20~~$10 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 and ~~2016,~~2019, respectively.

~~10.~~12. 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~~six months ended ~~September~~June 30, ~~2017~~2020 and ~~2016~~2019 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of ~~35%~~21% to pre-tax income primarily ~~because of~~due to (i) an alternative minimum tax refund received for the three months ended June 30, 2020, (ii) a full valuation allowance in effect on the Company’s U.S. deferred tax assets (“DTAs”) for the three months ended June 30, 2020 and June 30, 2019 and (iii) state income taxes and ~~estimated~~the effects of permanent ~~differences.~~ taxable differences for the six months ended June 30, 2019.

In ~~addition, during~~assessing the ~~third quarter~~realizability of ~~2016,~~DTAs, management considers whether it is more likely than not that some portion, or all, of the Company’s ~~note exchange transactions triggered an ownership shift within~~DTAs will not be realized. In making such determination, the ~~meaning~~Company considers all available positive and negative evidence, including future reversals of ~~Section 382~~temporary differences, tax-planning strategies and projected future taxable income and results of operations. If the ~~Internal Revenue Code due to the “deemed share issuance”~~Company concludes that ~~resulted from the note exchanges. The ownership shift will limit Whiting’s usage of certain~~it is more likely than not that some portion, or all, of its ~~net operating losses and~~DTAs will not be realized, the tax ~~credits in~~asset is reduced by a valuation allowance. The Company assesses the ~~future, and as~~appropriateness of its valuation allowance on a ~~result,~~quarterly basis. At June 30, 2020, the Company ~~recognized~~had a ~~non-cash charge of $454 million during the third quarter of 2016.~~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.

~~Upon adoption~~27

Table of ~~ASU 2016-09 on January 1, 2017,~~Contents

On March 26, 2020 the Company ~~recorded $70 million~~adopted a Rights Agreement and on April 1, 2020 the Bankruptcy Court entered an Order containing certain Procedures, each of ~~previously unrecognized excess tax benefits related~~which are intended to ~~stock-based compensation,~~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 ~~which a full valuation allowance was also recognized.~~more information on the Rights Agreement and the Order.

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~~11.~~13. EARNINGS PER SHARE

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


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

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

Three Months Ended

Nine Months Ended

September 30,

September 30,

2017

2016

2017

2016
Basic Loss Per Share

Net loss attributable to common shareholders

$
(286,432)

$
(693,052)

$
(439,370)

$
(1,165,841)
Weighted average shares outstanding

362,794

280,418

362,713

237,100
Loss per common share

$
(0.79)

$
(2.47)

$
(1.21)

$
(4.92)

Diluted Loss Per Share

Adjusted net loss attributable to common shareholders

$
(286,432)

$
(693,052)

$
(439,370)

$
(1,165,841)
Weighted average shares outstanding

362,794

280,418

362,713

237,100
Loss per common share

$
(0.79)

$
(2.47)

$
(1.21)

$
(4.92)

During the ~~three months ended September 30, 2017,~~periods presented, the Company had a net loss and therefore the diluted earnings per share ~~calculation for that period excludes~~calculations exclude the anti-dilutive effect of ~~242,748~~(i) 270,058 shares of service-based ~~restricted stock~~awards for the three months ended June 30, 2020, (ii) 182,583 shares of service-based awards and ~~3,513 stock options.~~96,241 shares of market-based awards for the three months ended June 30, 2019, (iii) 342,299 shares of service-based awards for the six months ended June 30, 2020, and (iv) 293,305 shares of service-based awards and 206,475 market-based awards for the six months ended June 30, 2019. In addition, the diluted earnings per share ~~calculation~~calculations exclude the effect of (i) 28,505 and 31,805 common shares for the three and six months ended ~~September~~June 30, ~~2017 excludes the effect of 3,553,915 common shares~~2020, respectively, for stock options that were out-of-the-money ~~and 889,354 shares of restricted stock that did not meet its market-based vesting criteria~~ as of ~~September~~June 30, ~~2017.~~

~~During the three months ended September 30, 2016, the Company had a net loss~~2020 and ~~therefore the diluted earnings per share calculation for that period excludes the anti-dilutive effect of (i) 81,549,680~~(ii) 46,396 and 46,502 common shares issuable for convertible notes prior to their conversions under the if-converted method, (ii) 1,240,145 shares of service-based restricted stock, and (iii) 4,448 stock options. In addition, the diluted earnings per share calculation for the three and six months ended ~~September~~June 30, ~~2016 excludes the effect of 2,090,383 common shares~~2019, respectively, for stock options that were out-of-the-money ~~and 897,005 shares of restricted stock that did not meet its market-based vesting criteria~~ as of ~~September~~June 30, ~~2016.~~

During the nine months ended September 30, 2017, the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes the anti-dilutive effect of 1,881,532 shares of service-based restricted stock and 4,435 stock options. In addition, the diluted earnings per share calculation for the nine months ended September 30, 2017 excludes the effect of 2,079,183 common shares for stock options that were out-of-the-money and 563,739 shares of restricted stock that did not meet its market-based vesting criteria as of September 30, 2017.

During the nine months ended September 30, 2016, the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes the anti-dilutive effect of (i) 35,560,679 shares issuable for convertible notes prior to their conversions under the if-converted method, (ii) 1,351,434 shares of service-based restricted stock, and (iii) 4,573 stock options. In addition, the diluted earnings per share calculation for the nine months ended September 30, 2016 excludes the effect of 2,065,797 common shares for stock options that were out-of-the-money and 523,351 shares of restricted stock that did not meet its market-based vesting criteria as of September 30, 2016.2019.

Refer to the “Stock-Based Compensation” footnote for ~~further~~more information on the Company’s ~~restricted stock~~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 upon conversion. Based on~~thereof. As the ~~initial~~ conversion ~~price, the entire outstanding principal amount~~value of the 2020 Convertible Senior Notes as of September 30, 2017 would be convertible into approximately 14.4 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, 2017 and 2016, the conversion value did not exceed the principal amount of the ~~notes. Accordingly,~~notes for any time during the conversion period ending April 1, 2020, there was no impact to diluted earnings per share or the related disclosures for ~~those periods.~~the periods ending June 30, 2020 and 2019.

~~12.~~14. COMMITMENTS AND CONTINGENCIES

~~Upon~~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 Chapter 11 Cases automatically stayed all of the proceedings and actions against the Company (other than regulatory enforcement matters), including those noted below. In addition, the filing of the Chapter 11 Cases may allow the Company to assume, assign or reject certain commitments, including executory contracts. Refer to the “Chapter 11 Cases” footnote for more information.

Delivery Commitments—The Company had a delivery contract tied to its oil production in the Williston Basin. The effective date of this contract was contingent upon the completion of certain related pipelines, the ~~Dakota Access Pipeline on June 1, 2017, the Company’s physical delivery contract for the delivery~~construction of ~~fixed volumes of crude oil from Whiting’s Sanish field in Mountrail County, North Dakota became effective.~~which has not yet commenced. Under the terms of the agreement, Whiting ~~has~~was committed to deliver 1510 MBbl/d for a term of seven ~~years, or pay~~years. In July 2020, the Company elected to terminate the agreement and is 0 longer required to deliver the 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 ~~deficiency fee equal to $7.00 per undelivered~~loss contingency for these lawsuits and claims when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. While the outcome of these lawsuits and claims cannot be predicted with certainty,

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it is the opinion of the Company’s management that the loss for any litigation matters and claims that are reasonably possible to occur will not have a material adverse effect, individually or in the aggregate, on its consolidated financial position, cash flows or results of operations.

~~Bbl.~~ The Company ~~believes its production and reserves are sufficient~~was involved in litigation related to ~~fulfill this delivery commitment, and therefore expects to avoid any payments for deficiencies under this contract.~~

~~Additionally,~~a payment arrangement with a third party. In June 2020, the Company ~~has two physical delivery contracts tied to crude oil production at Whiting’s Redtail field~~and the third party reached a settlement agreement resulting in ~~Weld County, Colorado. As~~the Company paying the third party a settlement amount of ~~September 30, 2017, these two contracts had remaining delivery commitments~~$14 million. Certain amounts were recognized in accrued liabilities and other in the consolidated balance sheets as of ~~5.1 MMBbl~~December 31, 2019 and general and administrative expenses in the consolidated statements of ~~crude oil~~operations for the ~~remainder of 2017 and 21.5 MMBbl, 23.3 MMBbl and 6.6 MMBbl of crude oil for the years~~year ended December 31, ~~2018 through 2020, respectively. The Company has~~2019 as it was determined that ~~it is not probable that future oil production from its Redtail field will be sufficient to meet the minimum volume requirements specified in these physical delivery contracts, and~~a loss as a result of this litigation was probable. The Company recorded $3 million of additional litigation settlement expense in general and administrative expenses in the ~~Company expects to make periodic deficiency payments~~condensed consolidated statements of operations for ~~any shortfalls in delivering the minimum committed volumes. During~~ the three and ~~nine~~six months ended ~~September~~June 30, ~~2017, total deficiency payments under these contracts amounted~~2020 upon settling this litigation. Upon settlement, the Company agreed to ~~$17 million and $52 million, respectively.~~indemnify a party involved in the litigation for any further claims resulting from the matters involved in the case up to $25 million. This indemnity will terminate on the later of: (i) June 30, 2021 or (ii) the date on which the statute of limitations for the relevant claims expires. The Company ~~recognizes~~does not expect to pay additional amounts to this party as a result of this indemnity, and thus has not recorded any ~~monthly deficiency payments in~~liability related to the ~~period in which the underdelivery takes place and the related liability has been incurred.~~indemnity as of June 30, 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”,~~“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, ~~(formerly Kodiak Oil & Gas Corp., “Kodiak”),~~ Whiting Resources Corporation Whiting Programs, Inc, Whiting Raven Colorado Corp. and Whiting ~~Programs, Inc.~~ND Sakakawea LLC. 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~~the cost-efficient operation of our existing properties to generate the greatest value to our stakeholders based on the ~~development of previously acquired properties, specifically~~current and expected commodity price environment. During 2019, we focused on ~~projects that we believe provide~~developing our large resource play in the greatest potential for repeatable success and production growth, while selectively pursuing acquisitions that complement our existing core properties. As a result of lower crude oil prices during 2015 and 2016, we significantly reduced our level of capital spending and focused our drilling activity on projects that provide the highest rate of return. During 2017, we shifted our focus to adding production and reserves through the strategic deployment of capital at our Williston Basin ~~properties~~of North Dakota and ~~Redtail field,~~Montana, while ~~more~~ closely aligning our capital spending with cash flows generated from operations. ~~In addition,~~As a result of the sharp decline in commodity prices during the first half of 2020, we have significantly decreased our level of capital spending to more closely align with our reduced cash flows from operating activities and have focused our capital program on projects that are expected to maximize value to our stakeholders. We continually evaluate our property portfolio and sell properties when we believe that the sales price realized will provide an above average rate of return for the property or when the property no longer matches the profile of properties we desire to ~~own, such as the asset sales discussed below under “Acquisition and Divestiture Highlights” and in~~own. Refer to the “Acquisitions and Divestitures” footnote in the notes to condensed consolidated financial ~~statements.~~statements for more information on our recent acquisition and divestiture activity.

Our revenue, profitability, ~~and~~ future growth rate and cash flows depend on many factors which are beyond our control, such as oil and gas prices, economic, political and regulatory developments, the financial condition of our industry partners, competition from other sources of energy, and the other items discussed under the caption “Risk Factors” in Item 1A of this Quarterly Report on Form 10-Q and our Annual Report on Form 10-K for the period ended December 31, ~~2016.~~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 ~~2015:~~2018:


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

2015

2016

2017

Q1

Q2

Q3

Q4

Q1

Q2

Q3

Q4

Q1

Q2

Q3
Crude oil

$
48.57

$
57.96

$
46.44

$
42.17

$
33.51

$
45.60

$
44.94

$
49.33

$
51.86

$
48.29

$
48.19
Natural gas

$
2.99

$
2.61

$
2.74

$
2.17

$
2.06

$
1.98

$
2.93

$
2.98

$
3.07

$
3.09

$
2.89

Oil prices declined sharply during the first half 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 was 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~~expenditures or ability to emerge from bankruptcy (as discussed below under our credit agreement, which is determined at the discretion of our lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders. Upon a redetermination, if borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of the debt outstanding under our credit agreement.“Recent Developments”). Alternatively, higher oil prices may result in significant mark-to-market losses being incurred on our commodity-based derivatives.

~~2017~~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. On July 1, 2020, the Bankruptcy Court entered an

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order approving the Debtors’ disclosure statement, allowing for solicitation of the Plan to commence. A Bankruptcy Court hearing to consider confirmation of the Plan is scheduled to be held on August 10, 2020. 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 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”). For more information on the Chapter 11 Cases and related matters, refer to the “Basis of Presentation,” “Chapter 11 Cases” and “Long-Term Debt” footnotes in the notes to the condensed consolidated financial statements.

Proved Undeveloped Reserves. As a result of lower crude oil, NGL and natural gas prices and a substantial reduction in our capital plan incorporated into our reserve estimates at June 30, 2020, our proved undeveloped reserves decreased from 126.6 MMBOE as of December 31, 2019 to 37.3 MMBOE as of June 30, 2020, which represents a 71% reduction between periods. Approximately 83% of this decrease in reserve volumes was the result of a change in the planned timing of the drilling and completion of PUD reserve locations outside of the SEC five-year window.

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

2020 Highlights and Future Considerations

Operational Highlights

Operational Response to Market Conditions

As a result of the significant decline in crude oil prices in the first half of 2020, we temporarily suspended all drilling and completion activity and released all of our drilling rigs during April 2020, incurring insignificant early termination and demobilization fees. Additionally, we curtailed production from certain of our producing wells, reduced the number of workover rigs used on our wells, deferred the completions of certain wells and delayed placing certain completed wells online during portions of the second quarter. We expect this reduced activity will negatively impact our production across all of our properties for the remainder of 2020. Substantial and extended declines in crude oil prices may result in our decision to voluntarily curtail production or reduce workover activity on our existing wells in the future.

Northern Rocky Mountains – 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 ~~102.0~~89.3 MBOE/d for the ~~third~~second quarter of ~~2017,~~2020, representing ~~a 3%~~an 11% decrease from ~~105.5~~100.2 MBOE/d in the ~~second~~first quarter of ~~2017.~~2020. Second quarter 2020 production was negatively impacted by production curtailments and higher downtime as a result of a reduction in workover rigs in April and May 2020, as well as the decisions to defer completions of certain wells and delay placing certain completed wells online. Across our acreage in the Williston Basin, we have implemented ~~new~~customized, right-sized completion designs which utilize ~~cemented liners, plug-and-perf~~the optimum volume of proppant, fluids, and frac stages to increase well performance while reducing cost and utilize state-of-the-art drilling rigs, high torque mud motors and 3-D bit cutter technology ~~significantly higher sand volumes,~~to reduce time-on-location and total well costs. We have increased stages pumped per day by focusing on new ~~diversion technology~~technologies such as quick-install wellhead connections and ~~both hybrid and slickwater fracture stimulation methods, which have resulted in improved initial production rates. As of September 30, 2017, we had four rigs active in the Williston Basin, and we~~frac plug innovations. We plan to continue to ~~operate four rigs in this area for~~use right-sized completion design on future wells we complete during the remainder of the year. We ~~anticipate having an inventory of approximately 50~~ drilled ~~uncompleted~~3 wells and put 12 wells on production in this area atduring the ~~end~~second quarter of ~~2017.~~2020. As noted above in “Operational Response to Market Conditions,” we released all of our drilling rigs during April 2020.

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

Our Redtail field in the ~~Denver Julesburg~~Denver-Julesburg Basin (“DJ Basin”) in Weld County, Colorado targets the Niobrara and Codell/Fort Hays formations. Net production from the Redtail field averaged ~~11.8 MBOE/d in the third quarter of 2017, representing a 78% increase from 6.6~~9.0 MBOE/d in the second quarter of ~~2017.~~2020, representing a 3% decrease from 9.3 MBOE/d for the first quarter of 2020. We have established production in the Niobrara ~~“A”,~~“A,” “B” and “C” zones and the

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Codell/Fort Hays formations. We have ~~implemented a new wellbore configuration~~maintained base production with improved artificial lift techniques and reductions in ~~this area, which significantly reduces drilling times. In response~~lease operating expenses. Future development activity in our Redtail field is subject to low commodity prices, we suspended completion operations in this area beginning in the second quarter of 2016, however, we resumed completion activity during the first quarter of 2017 and added a second completion crew in April. During the third quarter of 2017, we completed and brought on production a significant portion of our drilled uncompleted well inventory from yearend 2016, and we anticipate having an inventory of approximately 39 drilled uncompleted wells in this area at the end of 2017. 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~~June 30, ~~2017,~~2020, the plant was processing ~~over 17~~24 MMcf/d.

Financing Highlights

~~On February 2, 2017,~~In March 2020, we paid ~~$281~~$53 million to ~~redeem all of the remaining $275~~repurchase $73 million aggregate principal amount of our ~~2018~~1.25% Convertible Senior ~~Subordinated~~ Notes due April 1, 2020 (the “2020 Convertible Senior Notes”), which payment consisted of the ~~100% redemption~~average 72.5% purchase price plus all accrued and unpaid interest on the notes. We financed the ~~redemption~~repurchases with borrowings under the Credit Agreement. Additionally, in March 2020, holders of $3 million aggregate principal amount of 2020 Convertible Senior Notes timely elected to convert. Upon such conversion, such holders of converted 2020 Convertible Senior Notes were entitled to receive an insignificant cash payment on April 1, 2020, which we did not pay in conjunction with the filing of the Chapter 11 Cases. Refer to the “Chapter 11 Cases” and “Long-Term Debt” footnotes in the notes to the condensed consolidated financial statements for more information on these repurchases and conversions.

On April 1, 2020, in conjunction with the filing of the Chapter 11 Cases, we did not make the $187 million principal payment due on our ~~credit agreement.~~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 ~~this financing transaction.~~the Chapter 11 Cases and the automatic stay.

On September 7, 2017, we announced our plans to effect a reverse stock split of our common stock at a ratio ranging from any whole number between one-for-two to one-for-six, as determined by our Board of Directors, and a reduction in the number of authorized shares of our common stock based on the reverse stock split ratio selected. There will be a special meeting of stockholders on November 8, 2017 to seek approval for the reverse stock split and authorized share reduction. Refer to the “Shareholders’ Equity and Noncontrolling Interest” footnote in the notes to condensed consolidated financial statements for more information.

In October 2017, the borrowing base and aggregate commitments under our credit agreement were reduced from $2.5 billion to $2.3 billion in connection with the November 1, 2017 regular borrowing base redetermination, and was primarily the result of the sale of our Fort Berthold Indian Reservation area assets on September 1, 2017, as discussed below under “Acquisition and Divestiture Highlights”. All other terms of the credit agreement remain unchanged.

Acquisition and Divestiture Highlights

On January ~~1, 2017,~~9, 2020, we completed the ~~sale~~divestiture of our ~~50% interest~~interests in ~~the Robinson Lake~~30 non-operated, producing oil and gas ~~processing plant~~wells and related undeveloped acreage located in ~~Mountrail~~McKenzie County, North Dakota and our 50% interest in the Belfield gas processing plant located in Stark County, North Dakota, as well as the associated natural gas, crude oil and water gathering systems, effective January 1, 2017, for aggregate sales proceeds of ~~$375 million (before closing adjustments). We used the net proceeds from this transaction to repay a portion of the debt outstanding under our credit agreement.~~

On July 19, 2017, the buyer of our North Ward Estes properties paid us $35 million to settle a contingent payment associated with the original purchase and sale agreement, which sale closed in July 2016. This settlement resulted in a pre-tax gain of $3 million. Refer to the “Acquisitions and Divestitures” footnote in the notes to condensed consolidated financial statements for more information on this transaction.

On September 1, 2017, we completed the sale of our interests in certain producing oil and gas properties located in the Fort Berthold Indian Reservation area in Dunn and McLean counties of North Dakota, as well as other related assets and liabilities, (the “FBIR Assets”) for aggregate sales proceeds of $500$25 million (before closing adjustments). The ~~sale was effective September 1, 2017~~divested properties consisted of less than 1% of our estimated proved reserves as of December 31, 2019 and ~~resulted in a pre-tax loss on sale~~1% of ~~$402 million. We used~~our average daily production for the ~~net proceeds from~~year ended December 31, 2019.

Dakota Access Pipeline

On March 25, 2020, the ~~sale~~U.S. District Court for D.C. found that the U.S. Army Corps of Engineers had violated the National Environmental Policy Act when it granted an easement relating to ~~repay~~ a portion of the ~~debt outstanding under~~Dakota Access Pipeline (“DAPL”) because it had failed to conduct an environmental impact statement; as a result, in an order issued July 6, 2020, the court directed that the DAPL be shut down and emptied of oil by August 5, 2020. On August 5, 2020, the U.S. Court of Appeals for the D.C. Circuit granted a stay of the portion of the order directing shut down of the DAPL. The stay allows the DAPL to continue to operate until a further ruling is made. It is possible the DAPL may be required to be shut down as a result of such litigation. The disruption of transportation as a result of the DAPL being shut down could negatively impact our ~~credit agreement. The properties spanned~~ability to achieve the most favorable prices for our crude oil production. In August, we expect to transport approximately ~~29,600 net developed acres and consisted of estimated proved reserves of 32 MMBOE as of December 31, 2016, representing 5%~~30% of our ~~proved reserves as~~crude oil volumes through the DAPL. To mitigate any potential impact of ~~that date. The FBIR Assets generated 7% (or 8.3 MBOE/d) of~~an unfavorable ruling, we are coordinating with our ~~August 2017 average daily production.~~midstream partners to source transportation alternatives.

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Results of Operations

~~Nine~~Six Months Ended ~~September~~June 30, ~~2017~~2020 Compared to ~~Nine~~Six Months Ended ~~September~~June 30, ~~2016~~2019


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

Nine Months Ended

September 30,

2017

2016
Net production

Oil (MMBbl)

21.3

26.4
NGLs (MMBbl)

5.0

5.0
Natural gas (Bcf)

30.2

31.2
Total production (MMBOE)

31.3

36.6
Net sales (in millions)

Oil (1)

$
887.1

$
864.6
NGLs

67.1

38.5
Natural gas

52.8

39.2
Total oil, NGL and natural gas sales

$
1,007.0

$
942.3
Average sales prices

Oil (per Bbl) (1)

$
41.73

$
32.70
Effect of oil hedges on average price (per Bbl)

0.50

4.93
Oil net of hedging (per Bbl)

$
42.23

$
37.63
Weighted average NYMEX price (per Bbl) (2)

$
49.51

$
40.84
NGLs (per Bbl)

$
13.33

$
7.78
Natural gas (per Mcf)

$
1.75

$
1.25
Weighted average NYMEX price (per MMBtu) (2)

$
3.01

$
2.30
Costs and expenses (per BOE)

Lease operating expenses

$
8.53

$
8.40
Production taxes

$
2.76

$
2.16
Depreciation, depletion and amortization

$
21.49

$
24.61
General and administrative

$
2.96

$
3.07

(1)

~~(1)~~

Before consideration of hedging transactions.

(2)

~~(2)~~

Average NYMEX pricing weighted for monthly production volumes.

Oil, NGL and Natural Gas Sales. Our oil, NGL and natural gas sales revenue ~~increased $65~~decreased $479 million to ~~$1.0 billion~~$336 million when comparing the first ~~nine months~~half of ~~2017~~2020 to the same period in ~~2016. 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 half of 2020, decreases in total production accounted for approximately $168 million of the change in revenue and decreases in commodity prices realized accounted for approximately $311 million of the change in revenue when comparing to the first half of 2019.

Our oil, NGL and gas volumes ~~sold~~decreased 21%, 11% and ~~average commodity prices realized. Our oil and natural gas sales volumes decreased 20% and 3%~~12%, respectively, ~~while our NGL sales volumes remained consistent~~ between periods. The ~~oil~~ volume ~~decrease~~decreases between periods ~~was~~were primarily attributable to (i) production curtailment, additional downtime on certain wells due to a reduced workover rig count and the decisions to defer completions of certain wells and delay placing certain completed wells online for a portion of the second quarter as described in “Operational Response to Market Conditions” above, (ii) the impact of severe weather conditions and associated electric submersible pump failures on multiple high value wells in the Williston Basin in the first quarter of 2020 and (iii) normal field production decline across several of our areas resulting from reduced drilling and completion activity during 2016 and the first nine months of 2017 in response to the depressed commodity price environment. In addition, we completed certain oil and gas property divestitures during 2016 and 2017, which negatively impacted oil production in the first nine months of 2017 by 1,775 MBbl.decline. These decreases were partially offset by increased production from new wells drilled and completed over the last twelve months in the Williston ~~Basin and DJ Basin which added 4,475 MBbl and 565 MBbl, respectively,~~Basin.

Table of oil production during the first nine months of 2017 as compared to the first nine months of 2016. The gas volume decrease between periods was primarily due to normal field production decline across several of our areas, as well as 2016 and 2017 property divestitures which negatively impacted gas production in the first nine months of 2017 by 550 MMcf. These decreases were partially offset by new wells drilled and completed at our Williston Basin and DJ Basin properties which resulted in 6,610 MMcf and 330 MMcf, respectively, of additional gas volumes during the first nine months of 2017 as compared to the first nine months of 2016.Contents

~~These overall production-related decreases in net revenue were offset by increases in the average sales price realized for oil, NGLs and natural gas in the first nine months of 2017 compared to 2016.~~ Our average price for oil (before the effects of hedging), NGLs and natural gas ~~increased 28%~~decreased 46%, ~~71%~~57% and ~~40%~~93%, ~~respectively, between periods.~~respectively. Our average sales price realized for oil iswas impacted by deficiency payments we ~~are making~~made under ~~two~~a physical delivery ~~contracts~~contract at our Redtail field due to our inability to meet the minimum volume commitments under ~~these contracts.~~this contract. During the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 and ~~2016,~~2019, our total average sales price realized for oil was ~~$2.46~~$2.05 per Bbl lower and ~~$1.12~~$1.89 per Bbl lower, respectively, as a result of these deficiency payments. ~~These~~

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~~agreements~~This contract terminated in April 2020 and will not continue to negatively impact the price we receive for oil from our Redtail field ~~through April 2020, when the contracts terminate. Refer to the “Commitments and Contingencies” footnote~~ in the ~~notes~~future. Our average sales price realized for NGLs and natural gas during the first half of 2020 was negatively impacted by rising market differentials as compared to ~~condensed consolidated financial statements~~market indices as well as high fixed third-party costs for ~~more information on these physical delivery contracts~~transportation, gathering and ~~the related deficiency payments.~~compression services.

Lease Operating Expenses. Our lease operating expenses (“LOE”) during the first ~~nine months~~half of ~~2017~~2020 were ~~$267~~$126 million, a ~~$40~~$45 million decrease over the same period in ~~2016.~~2019. This decrease was primarily due to ~~a decline~~(i) ongoing cost reduction initiatives which were implemented beginning in the ~~costs~~third quarter of ~~oilfield goods~~2019, (ii) increased saltwater disposal income and ~~services resulting from the general downturn~~(iii) a decrease in ~~the oil and gas industry, as~~ well ~~as cost reduction measures we have implemented and the elimination of $14 million of LOE attributable to properties that we divested during 2016 and the first nine months of 2017.~~workover activity between periods.

Our lease operating expenses on a BOE basis ~~however, increased~~also decreased when comparing the first ~~nine months~~half of ~~2017~~2020 to the same ~~2016~~2019 period. LOE per BOE amounted to ~~$8.53~~$6.61 during the first ~~nine months~~half of ~~2017,~~2020, which represents ~~an increase~~a decrease of ~~$0.13~~$0.78 per BOE (or 2%11%) from the first ~~nine months~~half of ~~2016.~~2019. This ~~increase~~decrease was mainly due to ~~lower overall production volumes between periods, partially offset by~~ the overall decrease in LOE expense discussed ~~above.~~above partially offset by lower overall production volumes between periods.

~~Production Taxes~~.Transportation, Gathering, Compression and Other. Our ~~production taxes~~transportation, gathering, compression and other (“TGC”) expenses during the first ~~nine months~~half of ~~2017~~2020 were ~~$87~~$18 million, a $7$3 million ~~increase~~decrease over the same period in ~~2016,~~2019. TGC per BOE, however, increased slightly when comparing the first half of 2020 to the same 2019 period. These changes were primarily due to lower production volumes during the period.

Production and Ad Valorem Taxes. Our production and ad valorem taxes during the first half of 2020 were $31 million, a $37 million decrease over the same period in 2019, which ~~increase~~ was primarily due to ~~higher oil, NGL and natural gas~~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 ~~remained relatively consistent at 8.6%~~was 8.7% and ~~8.4%~~8.3% for the first ~~nine~~half of 2020 and 2019, respectively. Our production tax rate for 2020 was higher than the rate for 2019 due to our concentration of development activity over the past twelve months in the Williston Basin states of ~~2017~~North Dakota and ~~2016, respectively.~~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 applicable tax rate from 10% to 5%.

Depreciation, Depletion and Amortization. Our depletion, depreciation ~~depletion~~ and amortization (“DD&A”) expense decreased ~~$228~~$134 million in ~~2017~~2020 as compared to the first ~~nine months~~half of ~~2016.~~2019. The components of our DD&A expense were as follows (in thousands):



	Nine Months Ended
	September 30,
	2017		2016

					Six Months Ended June 30,
					2020		2019
Depletion	$	657,152	$	884,017	$	258,894	$	392,527
Accretion of asset retirement obligations						6,107		5,819
Depreciation		5,634		6,348		2,516		2,795
Accretion of asset retirement obligations		10,502		10,512
Total	$	673,288	$	900,877	$	267,517	$	401,141

DD&A decreased between periods primarily due to ~~$227~~$134 million in lower depletion expense, consisting of a ~~$117 million decrease related to a lower depletion rate between periods and a $110~~$56 million decrease due to lower overall production volumes during the first ~~nine months~~half of ~~2017.~~2020, as well as a $78 million decrease related to a lower depletion rate between periods. On a BOE basis, our overall DD&A rate of ~~$21.49~~$14.07 for the first ~~nine months~~half of ~~2017~~2020 was ~~13%~~19% lower than the rate of ~~$24.61~~$17.33 for the same period in ~~2016.~~2019. The primary factors contributing to this lower DD&A rate were ~~(i) an increase~~impairment write-downs on proved oil and gas properties in the Williston Basin recognized in the first quarter of 2020 and downward revisions to proved ~~and proved developed~~ reserves over the last twelve months, ~~(excluding the effect~~which were largely driven by lower commodity prices.

Table of divestitures) mainly due to higher average oil and natural gas prices used to calculate our reserves, as well as upward performance revisions, extensions and discoveries in our Williston Basin area, and (ii) the impact of property divestitures over the past twelve months. These factors that positively impacted our DD&A rate were partially offset by $721 million in drilling and development expenditures over the past twelve months.Contents

Exploration and Impairment Costs. Our exploration and impairment costs ~~decreased $22 million~~increased $4 billion for the first ~~nine months~~half of ~~2017~~2020 as compared to the same period in ~~2016.~~2019. The components of our exploration and impairment expense were as follows (in thousands):

Nine Months Ended

September 30,

2017

2016
Exploration

$
19,523

$
39,659
Impairment

44,270

45,906
Total

$
63,793

$
85,565

~~Exploration costs decreased $20 million during the first nine months of 2017 as compared to the same period in 2016 primarily due to $18 million of lower rig termination fees incurred between periods.~~


	Six Months Ended June 30,
	2020		2019
Impairment	$	4,154,369	$	13,179
Exploration		20,244		19,976
Total	$	4,174,613	$	33,155

Impairment expense for the first ~~nine months~~half of ~~2017~~2020 primarily related to (i) $4 billion in non-cash impairment charges for the partial write-down of proved oil and ~~2016~~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 half of 2019 primarily ~~related~~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):

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	Nine Months Ended
	September 30,
	2017		2016

					Six Months Ended June 30,
					2020		2019
General and administrative expenses	$	170,884	$	203,454	$	111,772	$	117,451
Reimbursements and allocations		(78,240)		(91,227)		(36,469)		(49,904)
General and administrative expenses, net	$	92,644	$	112,227	$	75,303	$	67,547

G&A expense before ~~reimbursements~~reimbursement and allocations decreased ~~$33~~$6 million during the first ~~nine months~~half of ~~2017 as compared to the same period in 2016~~2020 primarily due to cost reduction initiatives instituted as part of a company restructuring beginning in the third quarter of 2019, including $24 million in lower compensation costs between periods. These decreases were partially offset by (i) additional expense related to executive and employee ~~compensation. Employee compensation decreased $31~~cash retention incentives during the first half of 2020 of $11 million, (ii) third-party advisory and legal fees incurred prior to the Petition Date to prepare for the ~~first nine months~~Chapter 11 Cases of ~~2017 as compared~~$8 million and (iii) $3 million of additional expenses related to ~~the same period in 2016 primarily due to reductions in personnel over the past twelve months.~~a litigation settlement. The decrease in reimbursements and allocations for the first ~~nine months~~half of ~~2017~~2020 was the result of a lower number of field workers on Whiting-operated properties associated with reduced drilling ~~activity,~~activity.

Our G&A expenses on a BOE basis increased when comparing the first half of 2020 to the same 2019 period. G&A expense per BOE amounted to $3.96 during the first half of 2020, which represents an increase of $1.04 per BOE (or 36%) from the first half of 2019. This increase was mainly due to the overall decreases in reimbursements and allocations discussed above, as well as ~~property divestitures~~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 $225 million and a loss of $38 million for the six months ended June 30, 2020 and 2019, 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 and natural gas during the respective periods.

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

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


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

The decrease in interest expense of $35 million between periods was primarily attributable to lower interest costs incurred on our notes and lower amortization of debt issue costs, discounts and premiums during the first half of 2020 compared to the first half of 2019. Upon the filing of the Chapter 11 Cases on April 1, 2020, we discontinued accruing interest on our Senior Notes, which resulted in a $40 million decrease in note interest between periods. Additionally, the remaining unamortized debt issuance costs and premiums associated with our Senior Notes were written off to reorganization items, net in conjunction with the filing of the Chapter 11 Cases, resulting in a $6 million decrease in amortization expense during the first half of 2020 compared to the first half of 2019. Refer to the “Chapter 11 Cases” and “Long-Term Debt” footnotes in the condensed consolidated financial statements for more information.

The decrease in note interest and amortization of debt issue costs, discounts and premiums was partially offset by a $10 million increase in interest incurred on the Credit Agreement between periods due to a higher average outstanding balance as well as an additional 2% default interest rate charged on borrowings outstanding for the duration of the Chapter 11 Cases. Our weighted average borrowings outstanding during the first half of 2020 were $710 million compared to $104 million for the first half of 2019.

Our weighted average debt outstanding during the first half of 2020 was $3.1 billion versus $2.9 billion for the first half of 2019. Our weighted average effective cash interest rate was 3.3% during the first half of 2020 compared to 5.5% during the first half of 2019, primarily due to the discontinuation of interest expense on our Senior Notes beginning in April 2020.

Gain on Extinguishment of Debt. In March 2020, we paid $53 million to repurchase $73 million aggregate principal amount of our 2020 Convertible Senior Notes and recognized a $23 million gain on extinguishment of debt. 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 six months ended June 30, 2020. Refer to the “Long-Term Debt” footnote in the notes to condensed consolidated financial statements for more information on this repurchase and conversion and the effect of the automatic stay issued in conjunction with the filing of the Chapter 11 Cases.

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

Income Tax Benefit. As a result of pre-tax losses for the first six months of 2019, we transitioned from a net deferred tax liability position to a net deferred tax asset position which resulted in the recognition of a full valuation allowance on our deferred tax assets (“DTAs”) during the second quarter of 2019. Additionally, during the fourth quarter of 2019, we recognized $74 million of Canadian deferred tax expense associated with the outside basis difference in Whiting Canadian Holding Company ULC pursuant to ASC 740-30-25-17. During the six months ended June 30, 2020, $4 million of this Canadian deferred tax expense became current. Refer to the “Income Taxes” footnote in the notes to the consolidated financial statements of 2019 Annual Report on Form 10-K for more information on this deferred tax liability. As a result of the full valuation allowance on our U.S. DTAs as of June 30, 2020, we did not recognize any U.S. income tax expense or benefit during the first half of 2020, outside of a $1 million alternative minimum tax refund received during the period. Income tax expense (benefit) for the first half of 2019 totaled to a benefit of $1 million and related primarily to the recognition of a full valuation allowance during the second quarter of 2019 as a result of pre-tax losses.

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

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Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019


	Three Months Ended June 30,
	2020		2019
Net production
Oil (MMBbl)		5.5		7.5
NGLs (MMBbl)		1.6		1.9
Natural gas (Bcf)		10.9		13.0
Total production (MMBOE)		9.0		11.6
Net sales (in millions)
Oil ⁽¹⁾	$	91.9	$	403.9
NGLs		0.4		16.3
Natural gas		(0.7)		6.1
Total oil, NGL and natural gas sales	$	91.6	$	426.3
Average sales prices
Oil (per Bbl) ⁽¹⁾	$	16.57	$	54.14
Effect of oil hedges on average price (per Bbl)		2.59		0.38
Oil net of hedging (per Bbl)	$	19.16	$	54.52
Weighted average NYMEX price (per Bbl) ⁽²⁾	$	27.31	$	59.73
NGLs (per Bbl)	$	0.23	$	8.43
Natural gas (per Mcf)	$	(0.06)	$	0.47
Weighted average NYMEX price (per MMBtu) ⁽²⁾	$	1.66	$	2.58
Cost and expenses (per BOE)
Lease operating expenses	$	5.92	$	7.52
Transportation, gathering, compression and other	$	1.01	$	0.96
Production and ad valorem taxes	$	0.94	$	3.41
Depreciation, depletion and amortization	$	9.29	$	17.55
General and administrative	$	3.13	$	2.82

(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 $335 million to $92 million when comparing the second quarter of 2020 to the same period in 2019. Changes in sales revenue between periods are due to changes in production sold and changes in average commodity prices realized (excluding the impacts of hedging). For the second quarter of 2020, decreases in total production accounted for approximately $107 million of the change in revenue and decreases in commodity prices realized accounted for approximately $228 million of the change in revenue when comparing to the second quarter of 2019.

Our oil, NGL and gas volumes decreased 26%, 16% and 16%, respectively, between periods. The volume decreases between periods were primarily attributable to production curtailment, additional downtime on certain wells due to reduced workover rig count and the decisions to defer completions of certain wells and delay placing certain completed wells online for a portion of the second quarter as described in “Operational Response to Market Conditions” above, as well as normal field production decline. These decreases were partially offset by increased production from new wells drilled and completed over the ~~past~~last twelve ~~months.~~months in the Williston Basin.

Our ~~general~~average price for oil (before the effects of hedging), NGLs and ~~administrative~~natural gas decreased 69%, 97% and 113%, respectively. Our average sales price realized for oil was impacted by deficiency payments we made under a physical delivery contract at our Redtail field due to our inability to meet the minimum volume commitments under this contract. During the three months ended June 30, 2020 and 2019, our total average sales price realized for oil was $1.07 per Bbl lower and $2.07 per Bbl lower, respectively, as a result of these deficiency payments. This contract terminated in April 2020 and will not continue to negatively impact the price we receive for oil from our Redtail field in the future. Our average sales price realized for NGLs and natural gas for the second quarter of 2020 was negatively

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impacted by rising market differentials as compared to market indices as well as high fixed third-party costs for transportation, gathering and compression services. These third-party costs sometimes exceed the ultimate price we receive for our natural gas and accordingly can result in negative gas revenues, which occurred in the second quarter of 2020. While these negative gas prices adversely affect our gas revenues, we have continued to produce our wells in order to sell oil, to meet lease and regulatory requirements and to sell NGLs derived from the processing of associated gas.

Lease Operating Expenses. Our LOE during the second quarter of 2020 were $53 million, a $34 million decrease over the same period in 2019. This decrease was primarily due to ongoing cost reduction initiatives which were implemented beginning in the third quarter of 2019, increased saltwater disposal income received between periods and a decrease in well workover activity between periods.

Our lease operating expenses on a BOE basis also decreased when comparing the ~~first nine months~~second quarter of ~~2017~~2020 to the same ~~2016~~2019 period. ~~G&A expense~~LOE per BOE amounted to ~~$2.96~~$5.92 during the ~~first nine months~~second quarter of ~~2017,~~2020, which represents a decrease of ~~$0.11~~$1.60 per BOE (or 4%21%) decrease from the ~~first nine months~~second quarter of ~~2016.~~2019. This decrease was mainly due to ~~lower employee compensation,~~the overall decrease in LOE expense discussed above partially offset by lower overall production volumes between periods.

Transportation, Gathering, Compression and Other. Our TGC expenses during the second quarter of 2020 were $9 million, a $2 million decrease over the same period in 2019. TGC per BOE, however, increased slightly when comparing the second quarter of 2020 to the same 2019 period. These changes were primarily due to lower production volumes during the period.

Production and Ad Valorem Taxes. Our production and ad valorem taxes during the second quarter of 2020 were $8 million, a $31 million decrease over the same period in 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 8.5% and 9.0% for the second quarter of 2020 and 2019, respectively. Our production tax rate for 2020 was lower than the rate for 2019 due to certain North Dakota wells receiving stripper well status, which reduces the applicable tax rate from 10% to 5%.

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


	Three Months Ended June 30,
	2020		2019
Depletion	$	79,198	$	198,656
Accretion of asset retirement obligations		3,079		2,937
Depreciation		1,272		1,416
Total	$	83,549	$	203,009

DD&A decreased between periods primarily due to $119 million in lower depletion expense, consisting of a $23 million decrease due to lower overall production volumes during the second quarter of 2020, as well as a $96 million decrease related to a lower depletion rate between periods. On a BOE basis, however, our overall DD&A rate of $9.29 for the second quarter of 2020 was 47% lower than the rate of $17.55 for the same period in 2019. The primary factors contributing to this lower DD&A rate were impairment write-downs on proved oil and gas properties in the Williston Basin recognized in the first quarter of 2020 and downward revisions to proved reserves over the last twelve months, which were largely driven by lower commodity prices.

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


	Three Months Ended June 30,
	2020		2019
Impairment	$	409,277	$	3,336
Exploration		11,879		10,070
Total	$	421,156	$	13,406

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

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oil prices and a resultant decline in future development plans for the properties. Impairment expense for the second quarter of 2019 primarily relates to the amortization of leasehold costs associated with individually insignificant unproved properties.

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


	Three Months Ended June 30,
	2020		2019
General and administrative expenses	$	47,859	$	57,966
Reimbursements and allocations		(19,723)		(25,393)
General and administrative expenses, net	$	28,136	$	32,573

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

Our G&A expenses on a BOE basis, however, increased when comparing the second quarter of 2020 to the same 2019 period. G&A expense per BOE amounted to $3.13 during the second quarter of 2020, which represents an increase of $0.31 per BOE (or 11%) from the second quarter of 2019. This increase was mainly due to lower overall production volumes between periods.

Derivative (Gain) Loss, Net.Our commodity derivative contracts ~~and embedded derivatives~~ 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 ~~$47~~$7 million and a gain of $25 million for the ~~nine~~three months ended ~~September~~June 30, ~~2017, which consisted of a $48 million fair value loss on~~2020 and 2019, respectively. These gains and losses are primarily related to our ~~long-term crude oil sales~~collar, swap and ~~delivery contract and a $19 million fair value loss on embedded derivatives, partially offset by a $20 million gain on our costless collar~~option commodity derivative contracts ~~resulting~~and resulted from the upward and downward ~~shift~~shifts, respectively, in the futures curve of forecasted commodity prices ~~(“forward price curve”)~~ for crude oil ~~from January 1, 2017 (or~~and natural gas during the ~~2017 date~~respective periods.

For more information on ~~which new contracts were entered into)~~our outstanding derivatives refer to ~~September 30, 2017. Derivative (gain) loss, net amounted to a gain of $28 million for~~ the nine months ended September 30, 2016, which consisted of a $56 million fair value gain on embedded derivatives, partially offset by a $28 million loss on commodity derivative contracts resulting from the upward shift“Derivative Financial Instruments” footnote in the ~~same forward price curve from January 1, 2016 (or~~notes to the ~~2016 date on which prior year contracts were entered into) to September 30, 2016.~~condensed consolidated financial statements.

~~Refer to Item 3, “Quantitative and Qualitative Disclosures about Market Risk”, for a list of our outstanding commodity derivative contracts as of October 11, 2017.~~

~~Loss on Sale of Properties.~~ During the first nine months of 2017, we sold our interests in the FBIR Assets for net cash proceeds of $501 million, which resulted in a pre-tax loss on sale of $402 million. During the first nine months of 2016, we sold our interests in the North Ward Estes properties for net cash proceeds of $295 million, which resulted in a pre-tax loss on sale of $188 million as of September 30, 2016. There were no other property divestitures resulting in a significant gain or loss on sale during the first nine months of 2017 or 2016.

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



	Nine Months Ended
	September 30,
	2017		2016

					Three Months Ended June 30,
					2020		2019
Credit agreement					$	10,977	$	3,256
Amortization of debt issue costs, discounts and premiums						5,250		7,915
Other						198		300
Notes	$	99,675	$	145,653		-		37,257
Amortization of debt issue costs, discounts and premiums		22,927		72,389
Credit agreement		20,054		25,655
Other		1,046		1,570
Capitalized interest		(61)		(122)
Total	$	143,641	$	245,145	$	16,425	$	48,728

The decrease in interest expense of ~~$102~~$32 million between periods was ~~mainly~~primarily attributable to ~~a decrease in amortization of debt issue costs, discounts and premiums and~~ lower interest costs incurred on our notes during the ~~first nine months~~second quarter of ~~2017 as~~2020 compared to the ~~first nine months~~same period of 2016. The decrease in amortization of debt issue costs, discounts and premiums of $49 million was due to (i) a $29 million decrease in debt discount and debt issue cost amortization related to the exchange and subsequent conversion to common stock of $1.6 billion of notes during 2016, (ii) a non-cash charge of $14 million for the acceleration of unamortized debt discounts in connection with the August 2016 induced exchange of a portion of our Mandatory Convertible Notes, and (iii) a $6 million non-cash charge for the acceleration of unamortized debt issuance costs in connection with a reduction2019. Upon filing of the ~~aggregate commitments under~~Chapter 11 Cases on April 1, 2020, we discontinued accruing interest on our ~~credit agreement~~Senior Notes, which resulted in ~~March 2016. The $46~~a $37 million decrease in note interest ~~was due to (i) the conversions of the New Convertible Notes in May 2016 and~~

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the Mandatory Convertible Notes in the second half of 2016, resulting in a $34 million decrease in note interest during the first nine months of 2017, and (ii) the redemption of the 2018 Senior Subordinated Notes in February 2017, resulting in a $12 million decrease between periods. Refer to the “Chapter 11 Cases” and “Long-Term Debt” footnotes in the condensed consolidated financial statements for more information.

The decrease in note interest was partially offset by an $8 million increase in interest incurred on the Credit Agreement between periods due to a higher average outstanding balance as well as an additional 2% default interest rate charged on borrowings outstanding for the duration of the Chapter 11 Cases. Our weighted average borrowings outstanding during the second quarter of 2020 were $930 million compared to $118 million for the second quarter of 2019.

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

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

~~Our weighted average debt outstanding during the first nine months~~Income Tax Benefit. As a result of ~~2017 was $3.3 billion versus $5.2 billion~~pre-tax losses for the first ~~nine~~six months of ~~2016. Our weighted average effective cash interest rate was 4.8% during the first nine months of 2017 compared to 4.4% for the first nine months of 2016.~~

~~Gain (Loss) on Extinguishment of Debt.~~ ~~During the first nine months of 2017,~~2019, we redeemed all of the remaining $275 million aggregate principal amount of 2018 Senior Subordinated Notes and recognized a $2 million loss on extinguishment of debt. During the first nine months of 2016, we recognizedtransitioned from a net ~~loss~~deferred tax liability position to a net deferred tax asset position which resulted in the recognition of a full valuation allowance on ~~extinguishment of debt of $42 million. In March 2016, we completed the exchange of $477 million aggregate principal amount of~~ our ~~senior notes and senior subordinated notes for the same aggregate principal amount of New Convertible Notes, and recognized a $91 million gain on extinguishment of debt. Subsequently,~~deferred tax assets (“DTAs”) during the second quarter of ~~2016, the holders~~2019. As a result of the ~~New Convertible Notes voluntarily converted all $477~~full valuation allowance on our U.S. DTAs as of June 30, 2020, we did not recognize any U.S. income tax expense or benefit during the second quarter of 2020 outside of a $1 million ~~aggregate principal amount of~~alternative minimum tax refund received during the New Convertible Notes for approximately 41.8 million shares of our common stock, and we recognized a $188 million loss on extinguishment of debt upon conversion. In June and July 2016, we completed the exchange of $1.1 billion aggregate principal amount of our senior notes, convertible senior notes and senior subordinated notes for the same aggregate principal amount of Mandatory Convertible Notes, and recognized a $57 million gain on extinguishment of debt. Subsequently in July 2016, $333 million aggregate principal amount of the Mandatory Convertible Notes were converted into approximately 33.2 million shares of our common stock, and we recognized a $3 million gain on extinguishment of debt upon conversion. In August 2016, we induced the exchange of an additional $38 million aggregate principal amount of the Mandatory Convertible Notes for approximately 4.9 million shares of our common stock, and we recognized $4 million of debt inducement expense. Refer to the “Long-Term Debt” footnote in the notes to condensed consolidated financial statements for more information on these debt transactions.

period. Income ~~Tax Expense (Benefit). Income tax benefit for the first nine months of 2017 totaled $320 million as compared to $182 million of income~~ tax expense for the ~~first nine months of 2016, a decrease of $502 million that was mainly related to (i) a $454 million non-cash charge in the third~~second quarter of ~~2016 resulting from an ownership shift as defined under Section 382~~2019 totaled $23 million, primarily due to the recognition of the Internal Revenue Code which will limit our usage of certain net operating losses and tax credits in the future, as discussed in the “Income Taxes” footnote in the notes to condensed consolidated financial statements, (ii) $77 million of permanent tax differences recognizeda full valuation allowance during the first nine months of 2016 associated with the issuance and subsequent conversion of the New Convertible Notes and the Mandatory Convertible Notes, and (iii) the partial release of a valuation allowance on net operating losses totaling $41 million in connection with the sale of the FBIR Assets in the thirdsecond quarter of ~~2017. These decreases in income tax expense were partially offset by $224 million in lower~~2019 as a result of pre-tax ~~loss between periods.~~losses during the period.

Our overall effective tax ~~rates~~rate of 0.2% for the ~~periods ending September 30, 2017 and 2016 differ from~~second quarter of 2020 was lower than the U.S. statutory income tax rate primarily due to the effects of state income taxes and permanent taxable differences. Excluding the impact of the Section 382 limitation discussed above, our overall effective tax rate increased from 27.7% for the first nine months of 2016 to 42.1% for the first nine months of 2017. This increase is mainly the result of (i) $77 million of permanent tax differences recognized during the first nine months of 2016 associated with the issuance and subsequent conversion of the New Convertible Notes and the Mandatory Convertible Notes, and (ii) the partial release of a valuation allowance on net operating losses totaling $41 million in connection with the sale of the FBIR Assets in the third quarter of 2017.

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~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016~~

Three Months Ended

September 30,

2017

2016
Net production

Oil (MMBbl)

7.1

7.8
NGLs (MMBbl)

1.8

1.6
Natural gas (Bcf)

10.2

9.9
Total production (MMBOE)

10.5

11.0
Net sales (in millions)

Oil (1)

$
289.4

$
283.8
NGLs

21.3

14.0
Natural gas

13.5

17.8
Total oil, NGL and natural gas sales

$
324.2

$
315.6
Average sales prices

Oil (per Bbl) (1)

$
41.03

$
36.58
Effect of oil hedges on average price (per Bbl)

0.66

5.30
Oil net of hedging (per Bbl)

$
41.69

$
41.88
Weighted average NYMEX price (per Bbl) (2)

$
48.24

$
44.93
NGLs (per Bbl)

$
12.06

$
8.65
Natural gas (per Mcf)

$
1.32

$
1.79
Weighted average NYMEX price (per MMBtu) (2)

$
2.89

$
2.93
Cost and expenses (per BOE)

Lease operating expenses

$
8.61

$
7.98
Production taxes

$
2.61

$
2.39
Depreciation, depletion and amortization

$
20.23

$
25.80
General and administrative

$
2.86

$
3.07

~~(1)~~

~~Before consideration of hedging transactions.~~

~~(2)~~

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

~~Oil, NGL and Natural Gas Sales~~. Our oil, NGL and natural gas sales revenue increased $9 million to $324 million when comparing the third quarter of 2017 to the same period in 2016. Sales revenue is a function of oil, NGL and gas volumes sold and average commodity prices realized. Our oil sales volumes decreased 9%, while our NGL and natural gas sales volumes increased 9% and 3%, respectively, between periods. The oil volume decrease between periods was primarily attributable to normal field production decline across several of our areas resulting from reduced drilling and completion activity during the second half of 2016 and the first nine months of 2017 in response to the depressed commodity price environment. In addition, we completed certain oil and gas property divestitures during the second half of 2016 and 2017, which negatively impacted oil production in the third quarter of 2017 by 385 MBbl. These decreases were partially offset by new wells drilled and completed in the Williston Basin and DJ Basin which added 1,700 MBbl and 530 MBbl, respectively, of oil production during the third quarter of 2017 as compared to the third quarter of 2016. The NGL volume increase between periods was primarily due to new wells drilled and completed in the Williston Basin, partially offset by normal field production decline. The gas volume increase between periods was primarily due to new wells drilled and completed at our Williston Basin and DJ Basin properties which resulted in 2,465 MMcf and 215 MMcf, respectively, of additional gas volumes during the third quarter of 2017 as compared to the third quarter of 2016. These increases were partially offset by normal field production decline across several of our areas, as well as 2016 and 2017 property divestitures which negatively impacted gas production in the third quarter of 2017 by 185 MMcf.

The overall production-related decrease in net revenue was offset by increases in the average sales price realized for oil and NGLs. Our average price for oil (before the effects of hedging) and NGLs increased 12% and 39%, respectively, between periods. These increases were partially offset by a decrease in the average sales price realized for natural gas of 26% in the third quarter of 2017 compared to 2016. Our average sales price realized for oil is impacted by deficiency payments we are 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 three months ended September 30, 2017 and 2016, our total average sales price realized for oil was $2.46 per Bbl lower and $1.59 per Bbl lower,

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~~respectively,~~ as a result of ~~these deficiency payments. These agreements will continue to negatively impact~~ the price we receive for oil from our Redtail field through April 2020, when the contracts terminate. Refer to the “Commitments and Contingencies” footnote in the notes to condensed consolidated financial statements for more information on these physical delivery contracts and the related deficiency payments.

~~Lease Operating Expenses~~. Our LOE during the third quarter of 2017 were $91 million, a $3 million increase over the same period in 2016. This increase was primarily due to new wells put on production in the DJ Basin and Williston Basin during 2017, largely offset by a decline in the costs of oilfield goods and services resulting from the general downturn in the oil and gas industry, as well as cost reduction measures we have implemented.

Our lease operating expenses on a BOE basis also increased when comparing the third quarter of 2017 to the same 2016 period. LOE per BOE amounted to $8.61 during the third quarter of 2017, which represents an increase of $0.63 per BOE (or 8%) from the third quarter of 2016. This increase was mainly due to lower overall production volumes between periods.

~~Production Taxes~~. Our production taxes during the third quarter of 2017 were $27 million, a $1 million increase over the same period in 2016. 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 remained relatively consistent at 8.5% and 8.4% for the third quarter of 2017 and 2016, respectively.

~~Depreciation, Depletion and Amortization. Our DD&A expense decreased $72 million in 2017 as compared to the third quarter of 2016. The components of our DD&A expense were as follows (in thousands):~~

Three Months Ended

September 30,

2017

2016
Depletion

$
207,555

$
279,169
Depreciation

1,898

2,120
Accretion of asset retirement obligations

3,393

3,280
Total

$
212,846

$
284,569

DD&A decreased between periods due to $72 million in lower depletion expense, consisting of a $62 million decrease related to a lower depletion rate between periods and a $10 million decrease due to lower overall production volumes during the third quarter of 2017. On a BOE basis, our overall DD&A rate of $20.23 for the third quarter of 2017 was 22% lower than the rate of $25.80 for the same period in 2016. The primary factors contributing to this lower DD&A rate were (i) an increase to proved and proved developed reserves over the last twelve months (excluding the effect of divestitures) mainly due to higher average oil and natural gas prices used to calculate our reserves, as well as upward performance revisions, extensions and discoveries in our Williston Basin area, and (ii) the impact of property divestitures over the past twelve months. These factors that positively impacted our DD&A rate were partially offset by $721 million in drilling and development expenditures over the past twelve months.

~~Exploration and Impairment Costs~~. Our exploration and impairment costs decreased $7 million for the third quarter of 2017 as compared to the same period in 2016. The components of our exploration and impairment expense were as follows (in thousands):

Three Months Ended

September 30,

2017

2016
Exploration

$
7,033

$
8,747
Impairment

10,624

15,546
Total

$
17,657

$
24,293

~~Impairment expense for the third quarter of 2017 and 2016 primarily related to the amortization of leasehold costs associated with individually insignificant unproved properties.~~

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

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Three Months Ended

September 30,

2017

2016
General and administrative expenses

$
56,061

$
62,251
Reimbursements and allocations

(25,977)

(28,343)
General and administrative expenses, net

$
30,084

$
33,908

G&A expense before reimbursements and allocations decreased $6 million during the third quarter of 2017 as compared to the same period in 2016 primarily due to lower employee compensation. Employee compensation decreased $8 million for the third quarter of 2017 as compared to the same period in 2016 primarily due to reductions in personnel over the past twelve months.

Our general and administrative expenses on a BOE basis also decreased when comparing the third quarter of 2017 to the same 2016 period. G&A expense per BOE amounted to $2.86 during the third quarter of 2017, which represents a decrease of $0.21 per BOE (or 7%) from the third quarter of 2016. This decrease was mainly due to lower employee compensation, partially offset by lower overall production volumes between periods.

~~Derivative (Gain) Loss, Net.~~ Our commodity derivative contracts and embedded derivatives 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 $31 million for the three months ended September 30, 2017, which consisted of a $36 million loss on our costless collar commodity derivative contracts resulting from the upward shift in the forward price curve for crude oil from July 1, 2017 (or the 2017 date on which new contracts were entered into) to September 30, 2017, partially offset by a $5 million fair value gain on our long-term crude oil sales and delivery contract. Derivative (gain) loss, net amounted to a gain of $30 million for the three months ended September 30, 2016, which consisted of a $22 million gain on commodity derivative contracts resulting from the downward shift in the same forward price curve from July 1, 2016 (or the 2016 date on which prior year contracts were entered into) to September 30, 2016, as well as an $8 million fair value gain on embedded derivatives.

~~Refer to Item 3, “Quantitative and Qualitative Disclosures about Market Risk”, for a list of our outstanding commodity derivative contracts as of October 11, 2017.~~

~~Loss on Sale of Properties.~~ During the third quarter of 2017, we sold our interests in the FBIR Assets for net cash proceeds of $501 million, which resulted in a pre-tax loss on sale of $402 million. During the third quarter of 2016, we sold our interests in the North Ward Estes properties for net cash proceeds of $295 million, which resulted in a pre-tax loss on sale of $188 million as of September 30, 2016. There were no other property divestitures resulting in a significant gain or loss on sale during the third quarter of 2017 or 2016.

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

Three Months Ended

September 30,

2017

2016
Notes

$
32,712

$
42,749
Amortization of debt issue costs, discounts and premiums

7,705

33,439
Credit agreement

6,969

8,060
Other

343

358
Capitalized interest

(36)

(28)
Total

$
47,693

$
84,578

The decrease in interest expense of $37 million between periods was mainly attributable to a decrease in amortization of debt issue costs, discounts and premiums and lower interest costs incurred on our notes during the third quarter of 2017 as compared to the third quarter of 2016. The decrease in amortization of debt issue costs, discounts and premiums of $26 million was primarily due to (i) a non-cash charge of $14 million for the acceleration of unamortized debt discounts in connection with the August 2016 induced exchange of a portion of our Mandatory Convertible Notes, and (ii) a $12 million decrease in debt discount and debt issue cost amortization related to the exchange and subsequent conversion to common stock of $1.1 billion of Mandatory Convertible Notes during 2016. The $10 million decrease in note interest was due to (i) the conversions of the Mandatory Convertible Notes in the second half of 2016, resulting in a $6 million decrease in note interest during the third quarter of 2017, and (ii) the redemption of the 2018 Senior Subordinated Notes in February 2017, resulting in a $4 million decrease between periods. Refer to the “Long-Term Debt” footnote in the notes to condensed consolidated financial statements for more information on these debt transactions.

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Our weighted average debt outstanding during the third quarter of 2017 was $3.3 billion versus $4.6 billion for the third quarter of 2016. Our weighted average effective cash interest rate was 4.8% during the third quarter of 2017 compared to 4.4% for the third quarter of 2016.

~~Gain (Loss) on Extinguishment of Debt.~~ We did not recognize any gain or loss on extinguishment of debt during the third quarter of 2017. During the third quarter of 2016, we recognized a net gain on extinguishment of debt of $47 million. In July 2016, we completed the exchange of $964 million aggregate principal amount of our senior notes, convertible senior notes and senior subordinated notes for the same aggregate principal amount of Mandatory Convertible Notes, and recognized a $48 million gain on extinguishment of debt. Subsequently in July 2016, $333 million aggregate principal amount of the Mandatory Convertible Notes were converted into approximately 33.2 million shares of our common stock, and we recognized a $3 million gain on extinguishment of debt upon conversion. In August 2016, we induced the exchange of an additional $38 million aggregate principal amount of the Mandatory Convertible Notes for approximately 4.9 million shares of our common stock, and we recognized $4 million of debt inducement expense. Refer to the “Long-Term Debt” footnote in the notes to condensed consolidated financial statements for more information on these debt transactions.

~~Income Tax Expense (Benefit)~~. Income tax benefit for the third quarter of 2017 totaled $242 million as compared to $358 million of income tax expense for the third quarter of 2016, a decrease of $600 million that was mainly related to (i) a $454 million non-cash charge in the third quarter of 2016 resulting from an ownership shift as defined under Section 382 of the Internal Revenue Code which will limit our usage of certain net operating losses and tax credits in the future, as discussed in the “Income Taxes” footnote in the notes to condensed consolidated financial statements, (ii) $193 million in higher pre-tax loss between periods, (iii) the partial release of afull valuation allowance on net operating losses totaling $41 million in connection with the sale of the FBIR Assets in the third quarter of 2017, and (iv) $20 million of permanent tax differences recognized during the third quarter of 2016 associated with the issuance and subsequent conversion of the Mandatory Convertible Notes during that period.

~~Our effective tax rates for the periods ending September 30, 2017 and 2016 differ from the~~our U.S. statutory income tax rate primarily due to the effects of state income taxes and permanent taxable differences. Excluding the impact of the Section 382 limitation discussed above, our overall effective tax rate increased from 28.9% for the third quarter of 2016 to 45.8% for the third quarter of 2017. This increase is mainly the result of (i) the partial release of a valuation allowance on net operating losses totaling $41 million in connection with the sale of the FBIR Assets in the third quarter of 2017, and (ii) $20 million of permanent tax differences recognized during the third quarter of 2016 associated with the issuance and subsequent conversion of the Mandatory Convertible Notes during that period.DTAs.

Liquidity and Capital Resources

Overview. At ~~September~~June 30, ~~2017,~~2020, we had ~~$11~~$492 million of unrestricted cash on hand and $178 million of shareholders’ deficit, while at December 31, 2019, we had $9 million of cash on hand and ~~$4.7~~$4.0 billion of ~~equity, while at December 31, 2016,~~equity. In March 2020, we took proactive steps to ensure we had ~~$56~~sufficient liquidity to fund ongoing operations during the Chapter 11 Cases by drawing $650 million ~~of cash~~ on ~~hand and $5.1 billion of equity.~~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 ~~68%~~62% and ~~72%~~65% of our total production in the first ~~nine months~~half of ~~2017~~2020 and ~~2016,~~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 ~~October 11, 2017,~~July 31, 2020, we had crude oil derivative contracts covering the sale of ~~approximately 59%~~17,000 Bbl, 18,000 Bbl and 5,000 Bbl of ~~our forecasted~~ oil ~~production volumes~~per day for the remainder of ~~2017. For a list of all of our outstanding derivatives as of October 11, 2017, refer to Item 3, “Quantitative~~2020, 2021 and ~~Qualitative Disclosures about Market Risk”.~~

~~During~~ the first nine months of ~~2017,~~2022, respectively. Additionally, we had natural gas derivative contracts covering the sale of 24,000 MMBtu, 50,000 MMBtu and 30,000 MMBtu of natural gas per day through the remainder of 2020, 2021 and the first nine months of 2022, respectively. For more information on our outstanding derivatives refer to the “Derivative Financial Instruments” footnote in the notes to the condensed consolidated financial statements.

During the first half of 2020, we generated ~~$290~~$67 million of cash provided by operating activities, a decrease of ~~$68~~$315 million from the same period in ~~2016.~~2019. Cash provided by operating activities decreased primarily due to lower crude oil and natural gas production volumes and a decrease in cash settlements received on our derivative contracts, as well as higher production taxes during the first nine months of 2017. These negative factors were partially offset by higher realized sales prices and production volumes for oil, NGLs and natural gas, as well as higher cash G&A and reorganization expenses. These negative factors were partially offset by an increase in cash settlements received on our derivative contracts, lower lease operating expenses, production and ad valorem taxes, cash interest expense ~~lease operating expenses, exploration~~and TGC costs ~~and general and administrative expenses~~ during the first ~~nine months~~half of ~~2017~~2020 as compared to the same period in ~~2016.~~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~~half of ~~2017,~~2020, cash flows from operating activities, ~~and cash on hand plus $916~~$695 million inof net borrowings under the Credit Agreement and proceeds from the sale of ~~oil and gas~~ properties were used to finance ~~$617~~$224 million of drilling and development expenditures ~~$350~~and the repurchase of $73 million aggregate principal amount of 2020 Senior Convertible Notes, which resulted in $492 million of ~~net repayments~~remaining unrestricted cash on hand as of June 30, 2020.

Chapter 11 Cases and Effect of Automatic Stay. On April 1, 2020, the Debtors filed for relief under ~~our credit agreement, the redemption~~chapter 11 of the ~~remaining $275~~Bankruptcy Code. The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under the Credit Agreement and the indentures governing our senior notes, resulting in the automatic and immediate acceleration of all of our outstanding debt. 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

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Bankruptcy Code. Refer to the “Basis of Presentation” and “Chapter 11 Cases” footnotes 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” and “Chapter 11 Cases” footnotes 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 at June 30, 2020 consisted of our unrestricted $492 million of ~~2018 Senior Subordinated Notes~~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 ~~$18 million~~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 ~~oil~~our current contracts and ~~gas property acquisitions.~~ consistent with applicable court orders, if any, approving such payments.

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Exploration and Development Expenditures. ~~The following table details our~~During the six months ended June 30, 2020 and 2019, we incurred $179 million and $451 million, respectively, of exploration and development (“E&D”) expenditures. Of these expenditures, 95% and 99%, 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 half of 2020.

Nine Months Ended

September 30,

2017

2016
Northern Rocky Mountains

$
465,789

$
242,701
Central Rocky Mountains

269,361

152,542
Permian Basin (1)

-

33,264
Other (2)

6,522

3,138
Total incurred

$
741,672

$
431,645

~~(1)~~

~~In July 2016, we sold our enhanced oil recovery project at North Ward Estes.~~

~~(2)~~

~~Other primarily includes non-core oil and gas properties located in Colorado, Mississippi, North Dakota, Texas and Wyoming.~~

We continually evaluate our capital needs and compare them to our capital resources. Our ~~current 2017 exploration and development (“~~2020 E~~&D”)~~&D budget is ~~$950~~$215 million, which we expect to fund ~~substantially~~ with net cash provided by operating activities ~~proceeds~~and cash on hand and represents a substantial decrease from ~~property divestitures or borrowings under our credit facility. The 2017 E&D budget represents an increase over~~ the ~~$554~~$778 million incurred on E&D expenditures during ~~2016. We believe that should additional attractive acquisition opportunities arise or E&D expenditures exceed $950 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 half of 2020 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, 2017~~ had a borrowing base of $2.05 billion and aggregate commitments of ~~$2.5 billion.~~$1.75 billion prior to default. As of ~~September~~June 30, ~~2017,~~2020, we had ~~$2.3 billion~~$912 million of borrowings outstanding under the Credit Agreement. As a result of the commencement of the Chapter 11 Cases, we are no longer in compliance with the covenants under the Credit Agreement and the lenders' commitments under the Credit Agreement have been terminated. We are therefore unable to make additional borrowings or issue additional letters of credit under the Credit Agreement.

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

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Prior to default, a portion of the Credit Agreement in an aggregate amount not to exceed $50 million was available ~~borrowing capacity, which was net~~to issue letters of ~~$200 million in borrowings~~credit for the account of Whiting Oil and $9Gas or other designated subsidiaries of ours. As of June 30, 2020, $2 million in letters of credit ~~outstanding.~~were outstanding under the agreement.

~~The~~Prior to default, the borrowing base under the ~~credit agreement is~~Credit Agreement was 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 have not occurred and are not expected to occur for the ~~amount~~duration of the borrowing base. Because oil and gas prices are principal inputs into the valuation of our reserves, if current or projected oil and gas prices decline from their current levels, our borrowing base could be reduced at the next redetermination date or during future redeterminations. 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 2017, the borrowing base and aggregate commitments under the facility were reduced to $2.3 billion in connection with the November 1, 2017 regular borrowing base redetermination, and was primarily the result of the sale of our FBIR Assets on September 1, 2017.

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, 2017, $41 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 ~~December 2019,~~maturity, when the ~~credit agreement~~Credit Agreement expires and all outstanding borrowings are due. Interest under the ~~revolving credit facility~~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 ~~margin in~~ratio of outstanding borrowings to the ~~table below,~~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 ~~margin in~~ratio of outstanding borrowings to the ~~table below. Additionally,~~borrowing base. Prior to the chapter 11 proceedings, we ~~also incur~~incurred commitment fees ~~as set forth in~~of 0.375% or 0.50% based on the ~~table below~~ratio of outstanding borrowings to the borrowing base on the unused portion of the aggregate commitments of the lenders under the ~~revolving credit facility.~~Credit Agreement. During the chapter 11 proceedings, the commitment fee has been terminated and instead all amounts outstanding under the Credit Agreement will bear interest per annum at the applicable rate stated in the agreement plus a 2.0% default rate. At June 30, 2020, the weighted average interest rate on the outstanding principal balance under the Credit Agreement was 4.7%.

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

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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. ~~However, the credit agreement permits us and certain of our subsidiaries to issue second lien indebtedness of up to $1.0 billion subject to certain conditions and limitations.~~ 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).

The ~~credit agreement~~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 ~~senior secured~~ debt to the last four quarters’ EBITDAX ratio of ~~less than 3.0 to 1.0 during the Interim Covenant Period (defined below), and thereafter a total debt to EBITDAX ratio of less~~not greater than 4.0 to 1.0, and (iii) a ratio of the last four quarters’ EBITDAX to consolidated cash interest charges of not less than 2.25 to 1.0 during the Interim Covenant Period. Under the credit agreement, the “Interim Covenant Period” is defined as the period from June 30, 2015 until the earlier of (i) April 1, 2018 or (ii) the commencement of an investment-grade debt rating period (as defined in the credit agreement). We were in compliance with our covenants under the credit agreement as of September 30, 2017. 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.1.0.

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 ~~and~~due January 15, 2026 (the “2026 Senior ~~Subordinated Notes~~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 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 ~~2019~~2026 Senior Notes, the “Senior Notes”). ~~In September 2010, we issued at par $350 million of 6.5% Senior Subordinated Notes due October 2018 (the “2018 Senior Subordinated Notes”).~~

~~Exchange of Senior Notes and Senior Subordinated Notes for Convertible Notes.~~During 2016, we exchanged ~~(i) $75 million aggregate principal amount of our 2018 Senior Subordinated Notes, (ii) $139 million aggregate principal amount of our 2019 Senior Notes, (iii)~~ $326 million aggregate principal amount of our 2021 Senior Notes and ~~(iv)~~ $342 million aggregate principal amount of our 2023 Senior Notes for the same aggregate principal amount of convertible notes. Subsequently during 2016, all ~~$882~~$668 million aggregate principal amount of these convertible notes was converted into approximately ~~86.4~~16.3 million shares of our common stock pursuant to the terms of the notes.

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

~~Redemption~~Repurchases of ~~2018~~2021 Senior ~~Subordinated~~ Notes. ~~On February 2, 2017,~~In September 2019, we paid ~~$281~~$24 million to ~~redeem all of the then outstanding $275~~repurchase $25 million aggregate principal amount of ~~our 2018~~the 2021 Senior ~~Subordinated~~ Notes, which payment consisted of the ~~100% redemption~~average 94.708% purchase price plus all accrued and unpaid interest on the notes. We financed the ~~redemption~~repurchases with cash and borrowings under the Credit Agreement. As of September 30, 2019, $849 million of 2021 Senior Notes remained outstanding.

In October 2019, we paid an additional $72 million to repurchase $75 million aggregate principal amount of the 2021 Senior Notes, which payment consisted of the average 95.467% purchase price plus all accrued and unpaid interest on the notes. We financed the repurchases with borrowings under ~~our credit agreement.~~the Credit Agreement. As of ~~March 31, 2017, no 2018~~October 4, 2019, $774 million of 2021 Senior ~~Subordinated~~ 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 ~~71.1~~17.8 million shares of our common stock pursuant to the terms of the notes.

~~For the remaining $562~~In September 2019, we paid $299 million to complete a cash tender offer for $300 million aggregate principal amount of 2020 Convertible Senior Notes, we have 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 principal amount of the 2020 Convertible Senior Notes, inwhich 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 ~~upon conversion.~~ and borrowings under the Credit Agreement.

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

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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~~and holders of $3 million aggregate principal amount of 2020 Convertible Senior Notes timely elected to convert. Upon conversion, such holders of the converted 2020 Convertible Senior Notes were entitled to receive an insignificant cash payment on April 1, 2020, which we did not pay. Additionally, at ~~an initial conversion rate of 25.6410 shares of our common stock per $1,000~~maturity, we were obligated to pay in cash the $187 million outstanding principal amount of the notes, which is equivalent to an initial conversion price of approximately $39.00. The conversion rate will be subject to adjustment in some events, including if stockholders authorize the proposed reverse stock split at our November 8, 2017 special meeting, and our Board of Directors subsequently implements it. 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 such corporate event. As of September 30, 2017, none of~~that did not convert, which we did not pay. Under the ~~contingent conditions allowing~~Bankruptcy Code, the holders of the 2020 Convertible Senior Notes ~~to convert these~~and the prior holders that converted their notes ~~had been met.~~

~~Note Covenants.~~ ~~The indentures governing the Senior Notes restrict~~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, 2017. 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

~~Schedule~~We have various contractual obligations in the normal course of ~~Contractual Obligations. The following table summarizes~~ our ~~obligations~~operating and commitments as of September 30, 2017 to make future payments under certain contracts, aggregated by category of contractual obligation, for the time periods specified below. This table does not include amounts payable under contracts where we cannot predict with accuracy the amount and timing of such payments, including any amounts we may be obligated to pay under our derivative contracts, as such payments are dependent upon the price of crude oil in effect at the time of settlement, and any penalties that may be incurred for underdelivery under our physical delivery contracts.financing activities. For ~~further~~more information, ~~on these contracts~~ refer to ~~the “Derivative~~“Management’s Discussion and Analysis of Financial ~~Instruments” footnote in the notes to consolidated financial statements~~Condition and ~~“Delivery~~Results of Operations – Contractual Obligations and Commitments” in ~~Item 2 of~~ our Annual Report on Form 10-K for the ~~period~~year ended December 31, ~~2016.~~2019. There have been no material changes to our obligations since year-end 2019 except as discussed below.

Payments due by period

(in thousands)

Less than 1

More than 5
Contractual Obligations

Total

year

1-3 years

3-5 years

years
Long-term debt (1)

$
3,005,389

$
-

$
1,723,484

$
873,609

$
408,296
Cash interest expense on debt (2)

442,973

149,808

206,485

73,921

12,759
Asset retirement obligations (3)

161,815

4,517

29,683

7,446

120,169
Water disposal agreement (4)

125,605

17,880

40,200

38,154

29,371
Purchase obligations (5)

24,882

7,656

15,312

1,914

-
Pipeline transportation agreements (6)

57,356

9,284

18,866

16,383

12,823
Drilling rig contracts (7)

12,968

12,129

839

-

-
Leases (8)

16,589

7,504

8,935

150

-
Total

$
3,847,577

$
208,778

$
2,043,804

$
1,011,577

$
583,418

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

~~(1)~~

~~Long-term debt consists of the principal amounts of the Senior Notes and the 2020 Convertible Senior Notes, as well as the outstanding borrowings under our credit agreement.~~

~~(2)~~

Cash interest expense on the Senior Notes is estimated assuming no principal repayment until the due dates of the instruments. Cash interest expense on the 2020 Convertible Senior Notes is estimated assuming no principal repayments or conversions prior to maturity. Cash interest expense on the credit agreement is estimated assuming no principal borrowings or repayments through the December 2019 instrument due date and a fixed interest rate of 3.7%.

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

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

Delivery Commitments. We had a delivery contract tied to our oil production in the Williston Basin. The effective date of this contract was contingent upon the completion of certain related pipelines, the construction of which has not yet commenced. Under the terms of the agreement, we were committed to deliver 10 MBbl/d for a term of seven years. In July 2020, we elected to terminate the agreement and are no longer required to deliver the committed volumes.

~~(3)~~

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

~~(4)~~

We have one water disposal agreement which expires in 2024, whereby we have contracted for the transportation and disposal of the produced water from our Redtail field. Under the terms of the agreement, we are obligated to provide a minimum volume of produced water or else pay for any deficiencies at the price stipulated in the contract. The obligations reported above represent our minimum financial commitments pursuant to the terms of this contract, however, our actual expenditures under this contract may exceed the minimum commitments presented above.

~~(5)~~

We have one take-or-pay purchase agreement which expires in 2020, whereby we have committed to buy certain volumes of water for use in the fracture stimulation process on wells we complete in our Redtail field. Under the terms of the agreement, we are obligated to purchase a minimum volume of water or else pay for any deficiencies at the price stipulated in the contract. The purchasing obligations reported above represent our minimum financial commitments pursuant to the terms of this contract, however, our actual expenditures under this contract may exceed the minimum commitments presented above.

~~(6)~~

We have three pipeline transportation agreements with two different suppliers, expiring in 2022, 2024 and 2025. Under two of these contracts, we have committed to pay fixed monthly reservation fees on dedicated pipelines from our Redtail field for natural gas and NGL transportation capacity, plus a variable charge based on actual transportation volumes. The remaining contract contains a commitment to transport a minimum volume of crude oil via a certain oil gathering system or else pay for any deficiencies at a price stipulated in the contract. The obligations reported above represent our minimum financial commitments pursuant to the terms of these contracts, however, our actual expenditures under these contracts may exceed the minimum commitments presented above.

~~(7)~~

As of September 30, 2017, we had two drilling rigs under long-term contracts expiring in 2018. As of September 30, 2017, early termination of these contracts would require termination penalties of $8 million, which would be in lieu of paying the remaining drilling commitments under these contracts. The obligations reported above represent our minimum financial commitments pursuant to the terms of these contracts, however, our actual expenditures under these contracts may exceed the minimum commitments presented above.

~~(8)~~

We lease 222,900 square feet of administrative office space in Denver, Colorado under an operating lease arrangement expiring in 2019, 44,500 square feet of office space in Midland, Texas expiring in 2020, and 36,500 square feet of office space in Dickinson, North Dakota expiring in 2020. We have sublet the majority of our office space in Midland, Texas to a third party for the remaining lease term. The offsetting rental income has not been included in the table above.

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 in the notes to condensed consolidated financial statements.

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~~10-K for the fiscal year ended December 31, ~~2016.~~2019. The following is a material update to such critical accounting policies and estimates:

~~Derivative and Embedded Derivative Instruments~~. 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. We do not currently apply hedge accounting to any of our outstanding derivative instruments, andReorganization Accounting. Effective April 1, 2020, as a result ~~all changes in derivative fair values are recognized currently in earnings.~~

~~We determine~~of the ~~recorded amounts~~filing of ~~our derivative instruments measured at fair value utilizing third-party valuation specialists. We review these valuations, including~~ the ~~related model inputs~~Chapter 11 Cases we began accounting and ~~assumptions,~~reporting according to FASB ASC Topic 852 – Reorganizations, which specifies the accounting and ~~analyze changes in fair value measurements between periods. We corroborate such inputs, calculations and fair value changes using various methodologies, and review unobservable inputs~~financial reporting requirements for ~~reasonableness utilizing relevant information~~entities reorganizing through chapter 11 bankruptcy proceedings. These requirements include distinguishing transactions associated with the reorganization separate from other published sources. When available, we utilize counterparty valuations to assess the reasonableness of our valuations. The values we report in our financial statements change as the assumptions used in these valuations are revised to reflect changes in market conditions (particularly those for oil and natural gas futures) or other factors, many of which are beyond our control.

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We periodically enter into commodity derivative contracts to manage our exposure to oil and natural gas price volatility. We primarily utilize costless collars which are generally placed with major financial institutions, as well as swaps and crude oil sales and delivery contracts. We use hedging to help ensure that we have adequate funding for our capital programs and manage returns on our drilling programs and acquisitions. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. While the use of these hedging arrangements limits the downside risk of adverse price movements, it may also limit future revenues from favorable price movements. The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. We evaluate the ability of our counterparties to perform at the inception of a hedging relationship and on a periodic basis as appropriate.

We value our costless collars and swaps using industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and contractual prices for the underlying instruments, as well as other relevant economic measures. We value our long-term crude oil sales and delivery contracts based on a probability-weighted income approach which considers various assumptions, including quoted spot prices for commodities, market differentials for crude oil and U.S. Treasury rates. The discount rates used in the fair values of these instruments include a measure of nonperformance risk by the counterparty or us, as appropriate.

In addition, we evaluate the terms of our convertible debt and other contracts, if any, to determine whether they contain embedded components that are required to be bifurcated and accounted for separately as derivative financial instruments.

~~We valued the embedded derivatives~~activities related to our convertible notes using a binomial lattice model which considered various inputs including (i) our common stock price, (ii) risk-free rates based on U.S. Treasury rates, (iii) recovery rates in the event of default, (iv) default intensity and (v) volatility of our common stock.

~~We also had an embedded derivative related to our purchase and sale agreement with the buyer~~ongoing operations of the North Ward Estes properties, which included a contingent payment linked to NYMEX crude oil prices. Prior to settlement of the contingent payment in July 2017, we valued this embedded derivative using a modified Black-Scholes swaption pricing model which considered various assumptions, including quoted forward prices for commodities, time value and volatility factors. The discount rate used in the fair value of this instrument included a measure of the counterparty’s nonperformance risk.business.

Effects of Inflation and Pricing

As ~~a result~~commodity prices began to recover during 2018 and 2019 from previous lows, the cost of ~~the sustained depressed commodity price environment during 2016 and continuing into 2017, we have experienced lower costs due to a decrease in demand for~~ oil field ~~products~~goods and ~~services.~~services also rose. The oil and gas industry is very cyclical, and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts extreme pressure on the economic stability and pricing structure within the industry. Although commodity prices have declined 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”,~~“expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe” or “should” or the negative thereof or variations thereon or similar terminology are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements.

These risks and uncertainties include, but are not limited to: our ability to obtain Bankruptcy Court approval with respect to motions or other requests made to the Bankruptcy Court; our ability to confirm and consummate the Plan; the effects of the Chapter 11 Cases on our liquidity or results of operations or business prospects; the effects of the Chapter 11 Cases on our business and the interests of

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various constituents; the length of time that we will operate under chapter 11 protection; risks associated with third-party motions in the Chapter 11 Cases; 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; impacts to financial statements as a result of impairment write-downs; our ability to successfully complete asset dispositions~~agreement and the risks related thereto; 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; our ability to generate sufficient cash

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flows from operations to service our indebtedness; our ability to generate sufficient cash flows from operations to meet the internally funded portion of our capital expenditures budget; our ability to obtain external capital to finance exploration and development operations; our inability to access oil and gas markets due to market conditions or operational impediments, including any court rulings which may result in the inability to transport oil on the Dakota Access Pipeline; the impact of negative shifts in investor sentiment towards the oil and gas industry; impacts resulting from the allocation of resources among our strategic opportunities; the geographic concentration of our operations; impacts to financial statements as a result of impairment write-downs and other cash and noncash charges; federal and state initiatives relating to the regulation of hydraulic fracturing and air emissions; ~~unforeseen underperformance~~revisions to reserve estimates as a result of ~~or liabilities associated with acquired properties; the impacts of hedging on our results of operations; failure~~changes in commodity prices, regulation and other factors; inaccuracies of our ~~properties~~reserve estimates or our assumptions underlying them; the timing of our exploration and development expenditures; risks relating to ~~yield oil or gas~~decreases in ~~commercially viable quantities;~~our credit rating; 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; ~~our ability to replace our oil and natural gas reserves; any loss of our senior management or technical personnel; competition in the oil and gas industry;~~ the potential impact of changes in laws ~~including tax reform,~~ that could have a negative effect on the oil and gas industry; ~~cyber security~~impacts of local regulations, climate change issues, negative public perception of our industry and corporate governance standards; our ability to replace our oil and natural gas reserves; negative impacts from litigation and legal proceedings; unforeseen underperformance of or liabilities associated with acquired properties or other strategic partnerships or investments; competition in the oil and gas industry; any loss of our senior management or technical personnel; cybersecurity attacks or failures of our telecommunication ~~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~~10-K for the period ended December 31, ~~2016.~~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 months of 2017, our income (loss) before income taxes for the nine months ended September 30, 2017 would have moved up or down $89 million for each 10% change in oil prices per Bbl, $7 million for each 10% change in NGL prices per Bbl and $5 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 ~~Costless Collars.~~~~The collared hedges shown~~and Natural Gas Swaps. Our hedging portfolio currently consists crude oil and natural gas swaps. Refer to the “Derivative Financial Instruments” footnote in the ~~table below have~~notes to the ~~effect~~condensed consolidated financial statements for a description and list of ~~providing a protective floor while allowing~~our outstanding derivative contracts at June 30, 2020.

Our swap contracts entitle us to ~~share~~receive settlement from the counterparty in ~~upward pricing movements. The three-way collars, however, do not provide complete protection against declines in crude oil prices due~~amounts, if any, by which the settlement price for the applicable calculation period is less than the fixed price, or to pay the ~~fact that when~~counterparty if the ~~market~~settlement price ~~falls below~~for the ~~sub-floor,~~applicable calculation period is more than the minimum price we would receive would be NYMEX plus the difference between the floor and the sub-floor. While these hedges are designed to reduce our exposure to price decreases, they also have the effect of limiting the benefit of price increases above the ceiling.fixed price. The fair value of ~~these commodity~~our oil derivative ~~instruments~~positions at ~~September~~June 30, ~~2017~~2020 was a net ~~liability~~asset of $3$1 million. A hypothetical upward or downward shift of 10% per Bbl in the NYMEX forward curve for crude oil as of ~~September~~June 30, ~~2017~~2020 would cause a decrease or increase of $17 million in this fair value asset. The fair value of our natural gas contracts was a net liability of $40,000. A hypothetical upward or downward shift of 10% per MMBtu in the NYMEX forward curve for natural gas as of June 30, 2020 would cause an increase ~~of $51 million~~ or a decrease of ~~$41~~$1 million ~~respectively,~~ in this fair value liability.

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While these 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.

~~Our~~On April 1, 2020 we filed for relief under chapter 11 of the Bankruptcy Code, which permitted the counterparties of our derivative instruments to terminate their outstanding ~~commodity derivative contracts as~~hedges, and certain of ~~October 11, 2017 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.



~~Derivative~~			~~Monthly Volume~~	~~Weighted Average~~
~~Instrument~~	~~Commodity~~	~~Period~~	~~(Bbl)~~	~~NYMEX Sub-Floor/Floor/Ceiling~~
~~Three-way collars~~ ~~(1)~~	~~Crude oil~~	~~10/2017 to 12/2017~~	~~1,250,000~~	~~$35.00/$45.20/$58.95~~
	~~Crude oil~~	~~01/2018 to 03/2018~~	~~1,250,000~~	~~$36.60/$46.60/$56.94~~
	~~Crude oil~~	~~04/2018 to 06/2018~~	~~1,250,000~~	~~$36.60/$46.60/$56.94~~
	~~Crude oil~~	~~07/2018 to 09/2018~~	~~1,250,000~~	~~$36.60/$46.60/$56.94~~
	~~Crude oil~~	~~10/2018 to 12/2018~~	~~1,250,000~~	~~$36.60/$46.60/$56.94~~
~~Collars~~	~~Crude oil~~	~~10/2017 to 12/2017~~	~~250,000~~	~~$53.00/$70.44~~

~~(1)~~

A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The sold call establishes a maximum price (ceiling) we will receive for the volumes under contract. The purchased put establishes a minimum price (floor), unless the market price 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.

Interest Rate Risk

~~Our quantitative and qualitative disclosures about interest rate~~Market risk ~~related to our credit agreement are included~~is estimated as the change in ~~Item 7A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2016 and have not materially changed since that report was filed.~~

~~In March 2015, we issued 1.25% Convertible Senior Notes due April 2020 (the “2020 Convertible Senior Notes”). As~~fair value resulting from a hypothetical 100 basis point change in the interest rate on ~~these notes~~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, ~~at 1.25%, we are~~interest rate changes affect the instrument’s fair market value but do not ~~subject to any direct risk~~impact results of ~~loss related to fluctuations~~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 June 30, 2020, our outstanding principal balance under our credit agreement was $912 million, and the weighted average interest rate on the outstanding principal balance was 4.7%. At June 30, 2020, the carrying amount approximated fair market value. Assuming a constant debt level of $912 million, the cash flow impact resulting from a 100 basis point change in interest ~~rates. However,~~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, but changes in interest rates do affect the fair value of this debt instrument, which could impact the amount of gain or loss that we recognize in earnings upon conversion of the notes. Refer to the “Long-Term Debt” and “Fair Value Measurements” footnotes in the notes to condensed consolidated financial statements for more information on the material terms and fair values of ~~the 2020 Convertible Senior Notes.~~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 ~~Senior Vice President and~~ Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of ~~September~~June 30, ~~2017.~~2020. Based upon their evaluation of these disclosure controls and procedures, the Chairman, President and Chief Executive Officer and the ~~Senior Vice President and~~ Chief Financial Officer concluded that the disclosure controls and procedures were effective as of ~~September~~June 30, ~~2017~~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~~June 30, ~~2017~~2020 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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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.~~

~~After~~statements under the closing of the Kodiak acquisition in December 2014, the U.S. Environmental Protection Agency (the “EPA”) contacted us to discuss Kodiak’s responses to a June 2014 information request from the EPA under Section 114(a) of the Federal Clean Air Act, as amended (the “CAA”). In addition, in July 2015headings “Chapter 11 Cases” and March 2016, we received information requests from the EPA under Section 114(a) of the CAA. The information requests relate to tank batteries used in our Williston Basin operations and our compliance with certain regulatory requirements at those locations for the control of air pollutant emissions from those facilities. We have responded to the EPA’s July 2015 and March 2016 information requests, and such responses were also provided to the North Dakota Department of Health (the “NDDoH”), with whom the EPA was coordinating in making the requests.

In connection with the above EPA inquiries, we entered into a settlement with the NDDoH that became effective in November 2016. This settlement addressed approximately 94% of our North Dakota properties owned at the time but did not address our operations on the Fort Berthold Indian Reservation in North Dakota, over which the EPA has sole authority to enforce CAA violations. On September 1, 2017, we completed the sale of our interests in all Fort Berthold Indian Reservation properties that we previously obtained from Kodiak. We“Litigation” are ~~currently engaged in settlement negotiations with the EPA concerning alleged violations of applicable regulations~~incorporated herein by ~~Kodiak prior to its acquisition, and by us after we acquired the subject properties.~~reference.

We are also currently engaged in discussions with the Colorado Department of Public Health and Environment (the “CDPHE”) concerning certain equipment used in our Redtail facilities and our compliance with various air permits and applicable federal and state air quality laws and regulations over the control of air pollutant emissions from those facilities. We and the CDPHE are currently negotiating the terms of a settlement agreement to resolve this matter.

Item 1A. Risk Factors

Risk factors relating to us are contained in Item 1A of our Annual Report on Form ~~10‑K~~10-K for the fiscal year ended December 31, ~~2016. No~~2019. The following is a material ~~change~~update to such risk factors:

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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;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

The pursuit of the Chapter 11 Cases has ~~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.

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.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

●	the effects of global conservation and sustainability measures;

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

●	weather conditions;

●	technological advances affecting energy consumption;

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

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

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

●	acts of terrorism;

●	the price and availability of alternative fuels; and

●	acts of force majeure.

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

Oil prices declined sharply during the first quarter of 2020, dropping below $21.00 per Bbl in March 2020 and further dropping to below negative $37.00 per Bbl in April 2020. This dramatic decline in pricing was primarily in response to Saudi Arabia’s announcement of plans to abandon previously agreed upon output restraints and the economic effects of the COVID-19 pandemic on the demand for oil and natural gas. Substantial and extended declines in oil, NGL and natural gas prices have resulted and may continue to result in impairments of our proved oil and gas properties or undeveloped acreage and may materially and adversely affect our future business, financial condition, cash flows, results of operations, liquidity or ability to finance planned capital expenditures. To the extent commodity prices received from production are insufficient to fund planned capital expenditures, we will be required to reduce spending or sell assets. Lower commodity prices may also make it more difficult for us to comply with the covenants and other restrictions in the agreements governing our debt as described under the risk factor entitled “The instruments governing our indebtedness contain various covenants limiting the discretion of our management in operating our business” in our Annual Report on Form 10-K for the period ended ~~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, which the World Health Organization declared a pandemic in March 2020. The outbreak of communicable diseases, or the perception that such an outbreak could occur, could result in a widespread public health crisis that could adversely affect the economies and financial markets of many countries, resulting in an economic downturn that would negatively impact the demand for oil and natural gas products. Furthermore, uncertainty regarding the impact and length of any outbreak of pandemic or contagious disease, including COVID-19, could lead to increased volatility in oil and natural gas prices. The occurrence or continuation of any of these events could lead to decreased revenues and limit our ability to execute on our business plan, which could adversely affect our business, financial condition, results of operations and cash flows.

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

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

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

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

On March 25, 2020, the U.S. District Court for D.C. found that the U.S. Army Corps of Engineers had violated the National Environmental Policy Act when it granted an easement relating to a portion of the DAPL because it had failed to conduct an environmental impact statement; as a result, in an order issued July 6, 2020, the court directed that the DAPL be shut down and emptied of oil by August 5, 2020. On August 5, 2020, the U.S. Court of Appeals for the D.C. Circuit granted a stay of the portion of the order directing shut down of the DAPL. The stay allows the DAPL to continue to operate until a further ruling is made. We cannot provide any assurance as to the ultimate outcome of the litigation and it is possible the DAPL may be required to be shut down as a result of such litigation. In August, we expect to transport approximately 30% of our crude oil volumes through the DAPL. The disruption of transportation as a result of the DAPL being shut down could negatively impact our ability to achieve the most favorable prices for our crude oil production, which could have a material adverse effect on our business, financial condition, results of operations or cash flows.

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

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

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

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

On April 14, 2020, we received written notification from the NYSE that we did not satisfy the NYSE’s continued listing compliance standards because the average closing price of our common stock was below $1.00 over a 30 ~~2017.~~consecutive trading-day period. On July 1, 2020 we received written notification from the NYSE that we regained compliance with the minimum share price requirement. Although we are currently in compliance with the minimum share price requirement, there is no assurance we will be in compliance in the future. If we are not in compliance with such requirement in the future, the NYSE might delist our common stock. Delisting would have an adverse effect on the liquidity of our common stock and, as a result, the market price for our common stock might become more volatile. Delisting could also reduce the number of investors willing to hold or acquire our common stock and negatively impact our ability to access equity markets and obtain financing.

Item 6. Exhibits

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

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EXHIBIT INDEX

Exhibit Number		Exhibit Description
~~Exhibit~~ ~~Number~~(3.1)	~~Exhibit Description~~
~~(2.1)~~	~~Purchase and Sale Agreement, dated August 14, 2017, by and among~~Restated Certificate of Incorporation of Whiting ~~Resources~~Petroleum Corporation ~~RimRock Oil & Gas Williston, LLC, Whiting Oil and Gas Corporation and RimRock Oil & Gas Williston Resources, Inc., effective as of September 1, 2017~~ [Incorporated by reference to Exhibit ~~2.1~~3.2 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on ~~September 6,~~November 9, 2017 (File No. 001-31899)]. *
~~(31.1)~~
(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)].

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

(10.1)		Restructuring Support Agreement, dated April 23, 2020 [Incorporated by reference to Exhibit 10 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on April 24, 2020 (File No. 001-31899)].

(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 ~~Senior Vice President and~~ 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 ~~Senior Vice President and~~ 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~~10-Q for the quarter ended ~~September~~June 30, ~~2017~~2020 are filed herewith, formatted in ~~XBRL (Extensible~~iXBRL (Inline Extensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets as of ~~September~~June 30, ~~2017~~2020 and December 31, ~~2016,~~2019, (ii) the Condensed Consolidated Statements of Operations for the Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2017~~2020 and ~~2016,~~2019, (iii) the Condensed Consolidated Statements of Cash Flows for the ~~Nine~~Six Months Ended ~~September~~June 30, ~~2017~~2020 and ~~2016,~~2019, (iv) the Condensed Consolidated Statements of Equity (Deficit) for the ~~Nine~~Six Months Ended ~~September~~June 30, ~~2017~~2020 and ~~2016~~2019 and (v) Notes to Condensed Consolidated Financial Statements. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the iXBRL document.
*	~~Certain schedules and exhibits have been omitted and Whiting agrees to furnish supplementally to~~
(104)		Cover Page Interactive Data File (formatted as Inline XBRL) – The cover page interactive data file does not appear in the ~~Securities and Exchange Commission a copy of any omitted schedule or exhibit upon request.~~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 266^thday of ~~October, 2017.~~August, 2020.


		WHITING PETROLEUM CORPORATION
		~~WHITING PETROLEUM CORPORATION~~


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


	By	/s/ ~~Michael J. Stevens~~Correne S. Loeffler
		~~Michael J. Stevens~~Correne S. Loeffler
		~~Senior Vice President and~~ Chief Financial Officer


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


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

1700 ~~Broadway,~~Lincoln Street, Suite ~~2300~~4700 Denver, Colorado		~~80290‑2300~~80203-4547
(Address of principal executive offices)		(Zip code)


Large accelerated filer	☒		Smaller reporting company	☐☒
Accelerated filer	☐		Emerging growth company	☐
Non-accelerated filer	☐	~~(Do not check if a smaller reporting company)~~


	WHITING PETROLEUM CORPORATION
	~~Commission file number:~~ ~~001‑31899~~ ~~WHITING PETROLEUM CORPORATION~~
	(Exact name of registrant as specified in its charter)

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



	September 30,		December 31,
	2017		2016
ASSETS
Current assets:
Cash and cash equivalents	$	11,172	$	55,975
Restricted cash		-		17,250
Accounts receivable trade, net		225,291		173,919
Prepaid expenses and other		32,734		26,312
Assets held for sale		-		349,146
Total current assets		269,197		622,602
Property and equipment:
Oil and gas properties, successful efforts method		12,797,474		13,230,851
Other property and equipment		134,502		134,638
Total property and equipment		12,931,976		13,365,489
Less accumulated depreciation, depletion and amortization		(4,734,351)		(4,222,071)
Total property and equipment, net		8,197,625		9,143,418
Other long-term assets		35,756		110,122
TOTAL ASSETS	$	8,502,578	$	9,876,142
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable trade	$	65,016	$	32,126
Revenues and royalties payable		130,447		147,226
Accrued capital expenditures		107,706		56,830
Accrued interest		24,124		44,749
Accrued lease operating expenses		37,554		45,015
Accrued liabilities and other		23,066		63,538
Taxes payable		23,096		39,547
Derivative liabilities		25,145		17,628
Accrued employee compensation and benefits		23,297		31,134
Liabilities related to assets held for sale		-		538
Total current liabilities		459,451		478,331
Long-term debt		2,931,443		3,535,303
Deferred income taxes		162,054		475,689
Asset retirement obligations		157,298		168,504
Other long-term liabilities		76,359		69,123
Total liabilities		3,786,605		4,726,950
Commitments and contingencies
Equity:
Common stock, $0.001 par value, 600,000,000 shares authorized; 368,020,048 issued and 362,793,720 outstanding as of September 30, 2017 and 367,174,542 issued and 362,013,928 outstanding as of December 31, 2016		368		367
Additional paid-in capital		6,403,767		6,389,435
Accumulated deficit		(1,688,162)		(1,248,572)
Total Whiting shareholders' equity		4,715,973		5,141,230
Noncontrolling interest		-		7,962
Total equity		4,715,973		5,149,192
TOTAL LIABILITIES AND EQUITY	$	8,502,578	$	9,876,142



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2017		2016		2017		2016
OPERATING REVENUES
Oil, NGL and natural gas sales	$	324,191	$	315,554	$	1,007,023	$	942,287
OPERATING EXPENSES
Lease operating expenses		90,615		87,982		267,277		307,530
Production taxes		27,499		26,372		86,621		79,125
Depreciation, depletion and amortization		212,846		284,569		673,288		900,877
Exploration and impairment		17,657		24,293		63,793		85,565
General and administrative		30,084		33,908		92,644		112,227
Derivative (gain) loss, net		30,867		(30,432)		47,281		(28,432)
Loss on sale of properties		398,752		189,934		401,050		193,729
Amortization of deferred gain on sale		(3,175)		(3,490)		(9,757)		(11,111)
Total operating expenses		805,145		613,136		1,622,197		1,639,510
LOSS FROM OPERATIONS		(480,954)		(297,582)		(615,174)		(697,223)
OTHER INCOME (EXPENSE)
Interest expense		(47,693)		(84,578)		(143,641)		(245,145)
Gain (loss) on extinguishment of debt		-		46,541		(1,540)		(42,236)
Interest income and other		(83)		115		970		1,146
Total other expense		(47,776)		(37,922)		(144,211)		(286,235)
LOSS BEFORE INCOME TAXES		(528,730)		(335,504)		(759,385)		(983,458)
INCOME TAX EXPENSE (BENEFIT)
Current		(3,161)		113		(6,367)		115
Deferred		(239,137)		357,438		(313,634)		182,286
Total income tax expense (benefit)		(242,298)		357,551		(320,001)		182,401
NET LOSS		(286,432)		(693,055)		(439,384)		(1,165,859)
Net loss attributable to noncontrolling interests		-		3		14		18
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(286,432)	$	(693,052)	$	(439,370)	$	(1,165,841)
LOSS PER COMMON SHARE
Basic	$	(0.79)	$	(2.47)	$	(1.21)	$	(4.92)
Diluted	$	(0.79)	$	(2.47)	$	(1.21)	$	(4.92)
WEIGHTED AVERAGE SHARES OUTSTANDING
Basic		362,794		280,418		362,713		237,100
Diluted		362,794		280,418		362,713		237,100

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



						Retained		Total
				Additional		Earnings		Whiting
	Common Stock			Paid-in		(Accumulated		Shareholders'		Noncontrolling		Total
	Shares	Amount		Capital		Deficit)		Equity		Interest		Equity
BALANCES - January 1, 2016	206,441	$	206	$	4,659,868	$	90,530	$	4,750,604	$	7,984	$	4,758,588
Net loss	-		-		-		(1,165,841)		(1,165,841)		(18)		(1,165,859)
Issuance of common stock upon conversion of convertible notes	79,920		80		822,936		-		823,016		-		823,016
Reduction of equity component of 2020 Convertible Senior Notes upon extinguishment, net	-		-		(63,330)		-		(63,330)		-		(63,330)
Recognition of beneficial conversion features on convertible notes	-		-		232,801		-		232,801		-		232,801
Restricted stock issued	4,021		4		(4)		-		-		-		-
Restricted stock forfeited	(615)		-		-		-		-		-		-
Restricted stock used for tax withholdings	(90)		-		(709)		-		(709)		-		(709)
Stock-based compensation	-		-		19,512		-		19,512		-		19,512
BALANCES - September 30, 2016	289,677	$	290	$	5,671,074	$	(1,075,311)	$	4,596,053	$	7,966	$	4,604,019

BALANCES - January 1, 2017	367,175	$	367	$	6,389,435	$	(1,248,572)	$	5,141,230	$	7,962	$	5,149,192
Net loss	-		-		-		(439,370)		(439,370)		(14)		(439,384)
Conveyance of third party ownership interest in Sustainable Water Resources, LLC	-		-		-		-		-		(7,948)		(7,948)
Restricted stock issued	2,271		2		(2)		-		-		-		-
Restricted stock forfeited	(1,022)		(1)		1		-		-		-		-
Restricted stock used for tax withholdings	(404)		-		(4,938)		-		(4,938)		-		(4,938)
Stock-based compensation	-		-		19,051		-		19,051		-		19,051
Cumulative effect of change in accounting principle	-		-		220		(220)		-		-		-
BALANCES - September 30, 2017	368,020	$	368	$	6,403,767	$	(1,688,162)	$	4,715,973	$	-	$	4,715,973

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



	Applicable	Applicable
	Margin for Base	Margin for	Commitment
Ratio of Outstanding Borrowings to Borrowing Base	Rate Loans	Eurodollar Loans	Fee
Less than 0.25 to 1.0	1.00%	2.00%	0.50%
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0	1.25%	2.25%	0.50%
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0	1.50%	2.50%	0.50%
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0	1.75%	2.75%	0.50%
Greater than or equal to 0.90 to 1.0	2.00%	3.00%	0.50%



			2020
	2019		Convertible		2021		2023
	Senior Notes		Senior Notes		Senior Notes		Senior Notes
Outstanding principal (in thousands)	$	961,409	$	562,075	$	873,609	$	408,296
Interest rate		5.0%		1.25%		5.75%		6.25%
Maturity date		Mar 15, 2019		Apr 1, 2020		Mar 15, 2021		Apr 1, 2023
Interest payment dates		Mar 15, Sep 15		Apr 1, Oct 1		Mar 15, Sep 15		Apr 1, Oct 1
Make-whole redemption date (1)		Dec 15, 2018		N/A (2)		Dec 15, 2020		Jan 1, 2023



		September 30, 2017 (1)
						Net
		Gross				Recognized
		Recognized		Gross		Fair Value
Not Designated as		Assets/		Amounts		Assets/
ASC 815 Hedges	Balance Sheet Classification	Liabilities		Offset		Liabilities
Derivative assets
Commodity contracts - current	Prepaid expenses and other	$	25,150	$	(24,577)	$	573
Commodity contracts - non-current	Other long-term assets		10,810		(10,810)		-
Total derivative assets		$	35,960	$	(35,387)	$	573
Derivative liabilities
Commodity contracts - current	Derivative liabilities	$	49,722	$	(24,577)	$	25,145
Commodity contracts - non-current	Other long-term liabilities		45,571		(10,810)		34,761
Total derivative liabilities		$	95,293	$	(35,387)	$	59,906



		December 31, 2016 (1)
						Net
		Gross				Recognized
		Recognized		Gross		Fair Value
Not Designated as		Assets/		Amounts		Assets/
ASC 815 Hedges	Balance Sheet Classification	Liabilities		Offset		Liabilities
Derivative assets
Commodity contracts - current	Prepaid expenses and other	$	21,405	$	(21,405)	$	-
Commodity contracts - non-current	Other long-term assets		9,495		(9,495)		-
Embedded derivatives - non-current	Other long-term assets		50,632		-		50,632
Total derivative assets		$	81,532	$	(30,900)	$	50,632
Derivative liabilities
Commodity contracts - current	Derivative liabilities	$	39,033	$	(21,405)	$	17,628
Commodity contracts - non-current	Other long-term liabilities		19,724		(9,495)		10,229
Total derivative liabilities		$	58,757	$	(30,900)	$	27,857



	September 30, 2017				December 31, 2016
	Fair		Carrying		Fair		Carrying
	Value (1)		Value (2)		Value (1)		Value (2)
6.5% Senior Subordinated Notes due 2018	$	-	$	-	$	275,121	$	273,506
5.0% Senior Notes due 2019		961,409		958,176		961,409		956,607
1.25% Convertible Senior Notes due 2020		500,598		500,427		503,057		483,465
5.75% Senior Notes due 2021		860,505		869,073		868,149		868,460
6.25% Senior Notes due 2023		397,578		403,767		408,296		403,265
Total	$	2,720,090	$	2,731,443	$	3,016,032	$	2,985,303



							Total Fair Value
	Level 1		Level 2		Level 3		September 30, 2017
Financial Assets
Commodity derivatives – current	$	-	$	573	$	-	$	573
Total financial assets	$	-	$	573	$	-	$	573
Financial Liabilities
Commodity derivatives – current	$	-	$	1,762	$	23,383	$	25,145
Commodity derivatives – non-current		-		1,370		33,391		34,761
Total financial liabilities	$	-	$	3,132	$	56,774	$	59,906


	Number of Shares		Weighted Average
	Service-Based	Market-Based	Grant Date
	Restricted Stock	Performance Shares	Fair Value
Nonvested awards, January 1, 2017	3,067,804	2,092,810	$	13.55
Granted	1,637,462	633,479		12.77
Vested	(1,182,970)	-		13.00
Forfeited	(245,732)	(776,525)		20.74
Nonvested awards, September 30, 2017	3,276,564	1,949,764	$	11.93



	2015								2016								2017
	Q1		Q2		Q3		Q4		Q1		Q2		Q3		Q4		Q1		Q2		Q3
Crude oil	$	48.57	$	57.96	$	46.44	$	42.17	$	33.51	$	45.60	$	44.94	$	49.33	$	51.86	$	48.29	$	48.19
Natural gas	$	2.99	$	2.61	$	2.74	$	2.17	$	2.06	$	1.98	$	2.93	$	2.98	$	3.07	$	3.09	$	2.89



	Payments due by period
		(in thousands)
			Less than 1						More than 5
Contractual Obligations	Total		year		1-3 years		3-5 years		years
Long-term debt (1)	$	3,005,389	$	-	$	1,723,484	$	873,609	$	408,296
Cash interest expense on debt (2)		442,973		149,808		206,485		73,921		12,759
Asset retirement obligations (3)		161,815		4,517		29,683		7,446		120,169
Water disposal agreement (4)		125,605		17,880		40,200		38,154		29,371
Purchase obligations (5)		24,882		7,656		15,312		1,914		-
Pipeline transportation agreements (6)		57,356		9,284		18,866		16,383		12,823
Drilling rig contracts (7)		12,968		12,129		839		-		-
Leases (8)		16,589		7,504		8,935		150		-
Total	$	3,847,577	$	208,778	$	2,043,804	$	1,011,577	$	583,418

~~Derivative Instrument~~

~~Valuation Technique~~

~~Unobservable Input~~

~~Amount~~

~~Commodity derivative contract~~

~~Probability-weighted income approach~~

~~Market differential for crude oil~~

~~$3.93 - $4.83 per Bbl~~