UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2019

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

For the transition period from _______________ to _______________

Commission file number: 001-31899


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


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

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

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

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


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

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

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

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


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

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

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

Number of shares of the registrant’s common stock outstanding at October 30, 2019: 91,299,706 shares.

TABLE OF CONTENTS

Glossary of Certain Definitions		1
PART I – FINANCIAL INFORMATION
Item 1.	Condensed Consolidated Financial Statements (Unaudited)	4
	Condensed Consolidated Balance Sheets as of September 30, 2019 and December 31, 2018	4
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2019 and 2018	5
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2019 and 2018	6
	Condensed Consolidated Statements of Equity for the Nine Months Ended September 30, 2019 and 2018	8
	Notes to Condensed Consolidated Financial Statements	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	43
Item 4.	Controls and Procedures	45
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	45
Item 1A.	Risk Factors	45
Item 6.	Exhibits	45

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GLOSSARY OF CERTAIN DEFINITIONS

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

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

“ASC” Accounting Standards Codification.

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

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

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

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

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

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

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

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

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

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

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

“FASB” Financial Accounting Standards Board.

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

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

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

“ISDA” International Swaps and Derivatives Association, Inc.

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

“LIBOR” London interbank offered rate.

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

“MBbl/d” One MBbl per day.

“MBOE” One thousand BOE.

“MBOE/d” One MBOE per day.

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

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

“MMBOE” One million BOE.

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

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

“MMcf/d” One MMcf per day.

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

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

“NGL” Natural gas liquid.

“NYMEX” The New York Mercantile Exchange.

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

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

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

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

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

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

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

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

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

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

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

“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.

“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 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.

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

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PART I – FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements

WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (unaudited)

(in thousands, except share and per share data)


	September 30,		December 31,
	2019		2018
ASSETS
Current assets:
Cash and cash equivalents	$	-	$	13,607
Accounts receivable trade, net		294,422		294,468
Derivative assets		45,038		68,342
Prepaid expenses and other		15,854		22,009
Total current assets		355,314		398,426
Property and equipment:
Oil and gas properties, successful efforts method		12,717,762		12,195,659
Other property and equipment		176,705		134,212
Total property and equipment		12,894,467		12,329,871
Less accumulated depreciation, depletion and amortization		(5,528,511)		(5,003,509)
Total property and equipment, net		7,365,956		7,326,362
Other long-term assets		53,611		34,785
TOTAL ASSETS	$	7,774,881	$	7,759,573
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	256,018	$	-
Accounts payable trade		52,054		42,520
Revenues and royalties payable		200,174		228,284
Accrued capital expenditures		130,017		73,178
Accrued liabilities and other		65,048		69,013
Accrued interest		33,383		55,080
Accrued lease operating expenses		47,077		37,499
Taxes payable		22,742		31,357
Total current liabilities		806,513		536,931
Long-term debt		2,605,023		2,792,321
Asset retirement obligations		132,381		131,544
Operating lease obligations		33,596		-
Deferred income taxes		-		1,373
Other long-term liabilities		27,411		27,088
Total liabilities		3,604,924		3,489,257
Commitments and contingencies
Equity:
Common stock, $0.001 par value, 225,000,000 shares authorized; 91,761,220 issued and 91,299,706 outstanding as of September 30, 2019 and 92,067,216 issued and 91,018,692 outstanding as of December 31, 2018		92		92
Additional paid-in capital		6,407,490		6,414,170
Accumulated deficit		(2,237,625)		(2,143,946)
Total equity		4,169,957		4,270,316
TOTAL LIABILITIES AND EQUITY	$	7,774,881	$	7,759,573

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

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WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)

(in thousands, except per share data)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
OPERATING REVENUES
Oil, NGL and natural gas sales	$	375,891	$	566,695	$	1,191,644	$	1,608,181
OPERATING EXPENSES
Lease operating expenses		85,320		74,690		256,384		230,434
Transportation, gathering, compression and other		11,176		12,842		32,145		35,450
Production and ad valorem taxes		35,220		49,989		102,796		133,991
Depreciation, depletion and amortization		211,025		197,006		612,166		584,219
Exploration and impairment		10,890		12,479		44,045		41,552
General and administrative		29,890		31,901		97,437		94,982
Derivative (gain) loss, net		(30,597)		21,063		7,431		177,210
Loss on sale of properties		595		230		1,681		1,716
Amortization of deferred gain on sale		(2,266)		(2,870)		(6,963)		(8,699)
Total operating expenses		351,253		397,330		1,147,122		1,290,855
INCOME FROM OPERATIONS		24,638		169,365		44,522		317,326
OTHER INCOME (EXPENSE)
Interest expense		(48,447)		(48,328)		(145,274)		(149,558)
Gain (loss) on extinguishment of debt		4,598		-		4,598		(31,968)
Interest income and other		144		363		1,102		2,732
Total other expense		(43,705)		(47,965)		(139,574)		(178,794)
INCOME (LOSS) BEFORE INCOME TAXES		(19,067)		121,400		(95,052)		138,532
INCOME TAX BENEFIT
Deferred income tax benefit		-		-		(1,373)		-
NET INCOME (LOSS)	$	(19,067)	$	121,400	$	(93,679)	$	138,532
INCOME (LOSS) PER COMMON SHARE
Basic	$	(0.21)	$	1.33	$	(1.03)	$	1.52
Diluted	$	(0.21)	$	1.32	$	(1.03)	$	1.51
WEIGHTED AVERAGE SHARES OUTSTANDING
Basic		91,299		90,967		91,274		90,934
Diluted		91,299		91,823		91,274		91,862

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

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WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(in thousands)


	Nine Months Ended September 30,
	2019		2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(93,679)	$	138,532
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		612,166		584,219
Deferred income tax benefit		(1,373)		-
Amortization of debt issuance costs, debt discount and debt premium		23,707		22,976
Stock-based compensation		5,086		10,243
Amortization of deferred gain on sale		(6,963)		(8,699)
Loss on sale of properties		1,681		1,716
Oil and gas property impairments		15,729		25,612
(Gain) loss on extinguishment of debt		(4,598)		31,968
Non-cash derivative loss		22,228		36,585
Payment for settlement of commodity derivative contract		-		(61,036)
Other, net		1,141		(102)
Changes in current assets and liabilities:
Accounts receivable trade, net		(4,076)		(32,919)
Prepaid expenses and other		4,998		3,418
Accounts payable trade and accrued liabilities		(18,397)		31,990
Revenues and royalties payable		(28,110)		12,810
Taxes payable		(8,615)		9,723
Net cash provided by operating activities		520,925		807,036
CASH FLOWS FROM INVESTING ACTIVITIES
Drilling and development capital expenditures		(624,707)		(579,746)
Acquisition of oil and gas properties		(5,955)		(140,427)
Other property and equipment		(7,525)		(543)
Proceeds from sale of properties		66,738		3,284
Net cash used in investing activities		(571,449)		(717,432)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under credit agreement		1,980,000		1,672,265
Repayments of borrowings under credit agreement		(1,615,000)		(1,622,265)
Redemption of 5.0% Senior Notes due 2019		-		(990,023)
Repurchase of 1.25% Convertible Senior Notes due 2020		(297,000)		-
Repurchase of 5.75% Senior Notes due 2021		(23,461)		-
Debt issuance costs		(36)		(10,709)
Restricted stock used for tax withholdings		(3,696)		(4,064)
Principal payments on finance lease obligations		(3,890)		-
Net cash provided by (used in) financing activities	$	36,917	$	(954,796)

				(Continued)

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WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(in thousands)


	Nine Months Ended September 30,
	2019		2018
NET CHANGE IN CASH AND CASH EQUIVALENTS	$	(13,607)	$	(865,192)
CASH AND CASH EQUIVALENTS
Beginning of period		13,607		879,379
End of period	$	-	$	14,187
NONCASH INVESTING ACTIVITIES
Accrued capital expenditures and accounts payable related to property additions	$	147,295	$	88,880

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

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WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (unaudited)

(in thousands)



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

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
Net loss	-		-		-		(19,067)		(19,067)
Adjustment to equity component of 2020 Convertible Senior Notes upon partial extinguishment	-		-		(8,070)		-		(8,070)
Restricted stock issued	45		-		-		-		-
Restricted stock forfeited	(175)		-		-		-		-
Restricted stock used for tax withholdings	-		-		(3)		-		(2)
Stock-based compensation	-		-		(3,530)		-		(3,531)
BALANCES - September 30, 2019	91,761	$	92	$	6,407,490	$	(2,237,625)	$	4,169,957

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

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WHITING PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. BASIS OF PRESENTATION

Description of Operations—Whiting Petroleum Corporation, a Delaware corporation, is an independent oil and gas company engaged in the development, production, acquisition and exploration of crude oil, NGLs and natural gas primarily in the Rocky Mountains region of the United States. Unless otherwise specified or the context otherwise requires, all references in these notes to “Whiting” or the “Company” are to Whiting Petroleum Corporation and its consolidated subsidiaries, Whiting Oil and Gas Corporation (“Whiting Oil and Gas”), Whiting US Holding Company, Whiting Canadian Holding Company ULC, Whiting Resources Corporation and Whiting Programs, Inc.

Condensed Consolidated Financial Statements—The unaudited condensed consolidated financial statements include the accounts of Whiting Petroleum Corporation and its consolidated subsidiaries. Investments in entities which give Whiting significant influence, but not control, over the investee are accounted for using the equity method. Under the equity method, investments are stated at cost plus the Company’s equity in undistributed earnings and losses. All intercompany balances and transactions have been eliminated upon consolidation. These financial statements have been prepared in accordance with GAAP and the SEC rules and regulations for interim financial reporting. In the opinion of management, the accompanying financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim results. However, operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. The condensed consolidated financial statements and related notes included in this Quarterly Report on Form 10-Q should be read in conjunction with Whiting’s consolidated financial statements and related notes included in the Company’s Annual Report on Form 10-K for the period ended December 31, 2018. Except as disclosed herein, there have been no material changes to the information disclosed in the notes to consolidated financial statements included in the Company’s 2018 Annual Report on Form 10-K.

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

Adopted and Recently Issued Accounting Pronouncements—In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (“ASU 2016-02”). The objective of this ASU is to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. The FASB subsequently issued various ASUs which provided additional implementation guidance, and these ASUs collectively make up FASB ASC Topic 842 – Leases (“ASC 842”). ASC 842 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. The standard permits retrospective application through recognition of a cumulative-effect adjustment at the beginning of either the earliest reporting period presented or the period of adoption. The Company adopted ASC 842 effective January 1, 2019 using the modified retrospective method as of the adoption date. Whiting has completed the assessment of its existing accounting policies and documentation, implementation of lease accounting software and enhancement of its internal controls. Adoption of the standard resulted in the recognition of additional lease assets and liabilities on Whiting’s consolidated balance sheet as well as additional disclosures. The adoption did not have a material impact to the Company’s consolidated statement of operations. Refer to the “Leases” footnote for further information on the Company’s implementation of this standard.

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2. OIL AND GAS PROPERTIES

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



	September 30,		December 31,
	2019		2018
Costs of completed wells and facilities	$	9,687,669	$	9,182,384
Proved leasehold costs		2,704,913		2,729,593
Wells and facilities in progress		219,340		160,995
Unproved leasehold costs		105,840		122,687
Total oil and gas properties, successful efforts method		12,717,762		12,195,659
Accumulated depletion		(5,449,887)		(4,937,579)
Oil and gas properties, net	$	7,267,875	$	7,258,080

3. ACQUISITIONS AND DIVESTITURES

2019 Acquisitions and Divestitures

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

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

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

2018 Acquisitions and Divestitures

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

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

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Cash consideration	$	122,861

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

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

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

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

4. LEASES

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

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

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



Leases	Balance Sheet Classification	September 30, 2019

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

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

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

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

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



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

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

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


	Three Months Ended		Nine Months Ended
	September 30, 2019		September 30, 2019
Operating lease cost	$	3,375	$	9,128

Finance lease cost:
Amortization of ROU assets	$	1,470	$	4,248
Interest on lease liabilities		498		1,522
Total finance lease cost	$	1,968	$	5,770

Short-term lease payments	$	182,455	$	527,518
Variable lease payments	$	11,437	$	22,212

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

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


	Three Months Ended		Nine Months Ended
	September 30, 2019		September 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	3,528	$	8,943
Operating cash flows from finance leases	$	517	$	1,538
Financing cash flows from finance leases	$	1,368	$	3,890

ROU assets obtained in exchange for new operating lease obligations	$	18,647	$	18,658
ROU assets obtained in exchange for new finance lease obligations	$	1,635	$	2,971

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



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

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

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


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

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5. LONG-TERM DEBT

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


	September 30,		December 31,
	2019		2018
Credit agreement	$	365,000	$	-
1.25% Convertible Senior Notes due 2020		262,075		562,075
5.75% Senior Notes due 2021		848,837		873,609
6.25% Senior Notes due 2023		408,296		408,296
6.625% Senior Notes due 2026		1,000,000		1,000,000
Total principal		2,884,208		2,843,980
Unamortized debt discounts and premiums		(5,284)		(28,994)
Unamortized debt issuance costs on notes		(17,883)		(22,665)
Total debt		2,861,041		2,792,321
Less current portion of long-term debt		(256,018)		-
Total long-term debt	$	2,605,023	$	2,792,321

Credit Agreement

Whiting Oil and Gas, the Company’s wholly owned subsidiary, has a credit agreement with a syndicate of banks that as of September 30, 2019 had a borrowing base of $2.25 billion and aggregate commitments of $1.75 billion. As of September 30, 2019, the Company had $1.4 billion of available borrowing capacity under the credit agreement, which was net of $365 million of borrowings outstanding and $2 million in letters of credit outstanding.

The borrowing base under the credit agreement is determined at the discretion of the lenders, based on the collateral value of the Company’s proved reserves that have been mortgaged to such lenders, and is subject to regular redeterminations on May 1 and November 1 of each year, as well as special redeterminations described in the credit agreement, in each case which may reduce the amount of the borrowing base. Upon a redetermination of the borrowing base, either on a periodic or special redetermination date, if borrowings in excess of the revised borrowing capacity were outstanding, the Company could be forced to immediately repay a portion of its debt outstanding under the credit agreement. In October 2019, the borrowing base under the credit agreement was reduced to $2.05 billion in connection with the semi-annual regular borrowing base redetermination, with no change to the aggregate commitments of $1.75 billion.

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

The credit agreement provides for interest only payments until maturity, when the credit agreement expires and all outstanding borrowings are due. The credit agreement matures on April 12, 2023, provided that if at any time and for so long as any senior notes (other than the 2020 Convertible Senior Notes) have a maturity date prior to 91 days after April 12, 2023, the maturity date shall be the date that is 91 days prior to the maturity of such senior notes. Interest under the credit agreement 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 ratio of outstanding borrowings to the borrowing base, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.5% per annum, or an adjusted LIBOR rate plus 1.0% per annum, or (ii) an adjusted LIBOR rate for a Eurodollar loan plus a margin between 1.50% and 2.50% based on the ratio of outstanding borrowings to the borrowing base. Additionally, the Company incurs commitment fees of 0.375% or 0.50% based on the ratio of outstanding borrowings to the borrowing base on the unused portion of the aggregate commitments of the lenders under the credit agreement, which are included as a component of interest expense. At September 30, 2019, the weighted average interest rate on the outstanding principal balance under the credit agreement was 3.6%.

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

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

The obligations of Whiting Oil and Gas under the 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 and has pledged the stock of its subsidiaries as security for its guarantee.

Senior Notes and Convertible Senior Notes

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

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

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

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

Redemption of 2019 Senior Notes. In January 2018, the Company paid $1.0 billion to redeem all of the remaining $961 million aggregate principal amount of the 2019 Senior Notes, which payment consisted of the 102.976% redemption price plus all accrued and unpaid interest on the notes. The Company financed the redemption with proceeds from the issuance of the 2026 Senior Notes and borrowings under its credit agreement. As a result of the redemption, the Company recognized a $31 million loss on extinguishment of debt, which included the redemption premium and a non-cash charge for the acceleration of unamortized debt issuance costs on the notes. As of March 31, 2018, no 2019 Senior Notes remained outstanding.

Repurchases of 2021 Senior Notes. In September 2019, the Company paid $24 million to repurchase $25 million aggregate principal amount of the 2021 Senior Notes, which payment consisted of the average 94.708% purchase price plus all accrued and unpaid interest on the notes. The Company financed the repurchases with borrowings under its credit agreement. As a result of the repurchases, the Company recognized a $1 million gain on extinguishment of debt, which included a non-cash charge for the acceleration of unamortized debt issuance costs and debt premium on the notes. As of September 30, 2019, $849 million of 2021 Senior Notes remained outstanding.

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

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

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

In September 2019, the Company paid $299 million to complete a cash tender offer for $300 million aggregate principal amount of the 2020 Convertible Senior Notes, which payment consisted of the 99.0% purchase price plus all accrued and unpaid interest on the notes, which were allocated to the liability and equity components based on their relative fair values. The Company financed the tender offer with borrowings under its credit agreement. 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 no deferred tax impact associated with this reduction due to the full valuation allowance in effect as of September 30, 2019.

The remaining $262 million aggregate principal amount of 2020 Convertible Senior Notes outstanding as of September 30, 2019 are convertible exclusively at the holder’s option. Prior to January 1, 2020, the 2020 Convertible Senior Notes will be 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 of specified corporate events. On or after January 1, 2020, the 2020 Convertible Senior Notes will be convertible at any time until the second scheduled trading day immediately preceding the April 1, 2020 maturity date of the notes. The notes will be convertible at a current conversion rate of 6.4102 shares of Whiting’s common stock per $1,000 principal amount of the notes, which is equivalent to a current conversion price of approximately $156.00. The conversion rate will be subject to adjustment in some events. In addition, following certain corporate events that occur prior to the maturity date, the Company will increase, in certain circumstances, the conversion rate for a holder who elects to convert its 2020 Convertible Senior Notes in connection with such corporate event. As of September 30, 2019, none of the contingent conditions allowing holders of the 2020 Convertible Senior Notes to convert these notes had been met. The Company has the option to settle conversions of these notes with cash, shares of common stock or a combination of cash and common stock at its election. The Company’s intent is to settle the principal amount of the 2020 Convertible Senior Notes in cash upon conversion. At maturity, the Company must settle all outstanding 2020 Convertible Senior Notes in cash.

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

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


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

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

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2019		2018		2019		2018
Interest expense on 2020 Convertible Senior Notes	$	7,611	$	7,335	$	22,678	$	21,774

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

6. ASSET RETIREMENT OBLIGATIONS

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


Asset retirement obligation at January 1, 2019	$	135,834
Additional liability incurred		2,032
Revisions to estimated cash flows		(7,511)
Accretion expense		8,680
Obligations on sold properties		(2,135)
Liabilities settled		(983)
Asset retirement obligation at September 30, 2019	$	135,917

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

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

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


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

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

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

Crude Oil Sales and Delivery Contract. The Company had a long-term crude oil sales and delivery contract for oil volumes produced from its Redtail field in Colorado. Whiting determined that this contract would not qualify for the “normal purchase normal sale” exclusion and therefore reflected the contract at fair value in the consolidated financial statements prior to settlement. On February 1, 2018, Whiting paid $61 million to the counterparty to settle all future minimum volume commitments under this agreement. Accordingly, this crude oil sales and delivery contract was fully terminated, and the fair value of the corresponding derivative was therefore zero as of that date.

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


		(Gain) Loss Recognized in Income
Not Designated as	Statement of Operations	Three Months Ended September 30,
ASC 815 Hedges	Classification	2019		2018
Commodity contracts	Derivative (gain) loss, net	$	(30,597)	$	21,063
Total		$	(30,597)	$	21,063

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

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


		September 30, 2019⁽¹⁾
						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	Derivative assets	$	52,897	$	(7,859)	$	45,038
Commodity contracts - non-current	Other long-term assets		4,757		(3,586)		1,171
Total derivative assets		$	57,654	$	(11,445)	$	46,209
Derivative liabilities
Commodity contracts - current	Accrued liabilities and other	$	7,859	$	(7,859)	$	-
Commodity contracts - non-current	Other long-term liabilities		3,682		(3,586)		96
Total derivative liabilities		$	11,541	$	(11,445)	$	96


		December 31, 2018 ⁽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	Derivative assets	$	69,735	$	(1,393)	$	68,342
Total derivative assets		$	69,735	$	(1,393)	$	68,342
Derivative liabilities
Commodity contracts - current	Accrued liabilities and other	$	1,393	$	(1,393)	$	-
Total derivative liabilities		$	1,393	$	(1,393)	$	-

(1)

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

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8. FAIR VALUE MEASUREMENTS

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

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

●

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

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

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

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

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


	September 30, 2019				December 31, 2018
	Fair		Carrying		Fair		Carrying
	Value ⁽¹⁾		Value ⁽²⁾		Value ⁽¹⁾		Value ⁽²⁾
1.25% Convertible Senior Notes due 2020	$	256,834	$	256,018	$	531,161	$	530,231
5.75% Senior Notes due 2021		802,151		846,827		829,929		870,545
6.25% Senior Notes due 2023		324,595		405,194		375,632		404,659
6.625% Senior Notes due 2026		680,000		988,002		865,000		986,886
Total	$	2,063,580	$	2,496,041	$	2,601,722	$	2,792,321

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

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

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

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							Total Fair Value
	Level 1		Level 2		Level 3		September 30, 2019
Financial Assets
Commodity derivatives – current	$	-	$	45,038	$	-	$	45,038
Commodity derivatives – non-current		-		1,171		-		1,171
Total financial assets	$	-	$	46,209	$	-	$	46,209
Financial Liabilities
Commodity derivatives – non-current	$	-	$	96	$	-	$	96
Total financial liabilities	$	-	$	96	$	-	$	96


							Total Fair Value
	Level 1		Level 2		Level 3		December 31, 2018
Financial Assets
Commodity derivatives – current	$	-	$	68,342	$	-	$	68,342
Total financial assets	$	-	$	68,342	$	-	$	68,342

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

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

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

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


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

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

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

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value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. The Company did not recognize any impairment write-downs with respect to its proved property during the reporting periods presented.

9. REVENUE RECOGNITION

The Company recognizes revenue in accordance with FASB ASC Topic 606 – Revenue Recognition (“ASC 606”). Revenue is recognized at the point in time at which the Company’s performance obligations under its commodity sales contracts are satisfied and control of the commodity is transferred to the customer. The Company has determined that its contracts for the sale of crude oil, unprocessed natural gas, residue gas and NGLs contain monthly performance obligations to deliver product at locations specified in the contract. Control is transferred at the delivery location, at which point the performance obligation has been satisfied and revenue is recognized. Fees included in the contract that are incurred prior to control transfer are classified as transportation, gathering, compression and other, and fees incurred after control transfers are included as a reduction to the transaction price. The transaction price at which revenue is recognized consists entirely of variable consideration based on quoted market prices less various fees and the quantity of volumes delivered. The table below presents the disaggregation of revenue by product type for the three and nine months ended September 30, 2019 and 2018 (in thousands):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2019		2018		2019		2018
OPERATING REVENUES
Oil sales	$	369,940	$	511,904	$	1,133,264	$	1,448,310
NGL and natural gas sales		5,951		54,791		58,380		159,871
Oil, NGL and natural gas sales	$	375,891	$	566,695	$	1,191,644	$	1,608,181

Whiting receives payment for product sales from one to three months after delivery. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in accounts receivable trade, net in the consolidated balance sheets. As of September 30, 2019 and December 31, 2018, such receivable balances were $149 million and $165 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.

10. STOCK-BASED COMPENSATION

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

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

The Company grants service-based RSAs and RSUs to executive officers and employees, which generally vest ratably over a three-year service period. The Company also grants service-based RSAs to directors, which generally vest over a one-year service period. In addition, the Company grants PSAs and PSUs to executive officers that are subject to market-based vesting criteria, which generally vest over a three-year service period. The Company accounts for forfeitures of awards granted under these plans as they occur in determining compensation expense. The Company recognizes compensation expense for all awards subject to market-based vesting conditions regardless of whether it becomes probable that these conditions will be achieved or not, and compensation expense for share-settled awards is not reversed if vesting does not actually occur.

During the nine months ended September 30, 2019 and 2018, 464,140 and 239,502 shares, respectively, of service-based RSAs and RSUs were granted to executive officers and directors under the 2013 Equity Plan. The Company determines compensation expense for these share-settled awards using their fair value at the grant date, which is based on the closing bid price of the Company’s common stock on such date. The weighted average grant date fair value of service-based RSAs and RSUs was $24.76 per share and $32.27 per share for the nine months ended September 30, 2019 and 2018, respectively.

During the nine months ended September 30, 2019 and 2018, 774,665 and 308,432 shares, respectively, of service-based RSUs were granted to employees under the 2013 Equity Plan. These awards will be settled in cash and are recorded as a liability in the consolidated balance sheets. The Company determines compensation expense for cash-settled RSUs using the fair value at the end of each reporting period, which is based on the closing bid price of the Company’s common stock on such date.

During the nine months ended September 30, 2019 and 2018, 347,493 and 220,451, respectively, of PSAs and PSUs subject to certain market-based vesting criteria were granted to executive officers under the 2013 Equity Plan. These market-based awards cliff vest on the third anniversary of the grant date, and the number of shares that will vest at the end of that three-year performance period is determined based on the rank of Whiting’s cumulative stockholder return compared to the stockholder return of a peer group of companies on each anniversary of the grant date over the three-year performance period. The number of awards earned could range from zero up to two 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.

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


	2019	2018
Number of simulations	2,500,000	2,500,000
Expected volatility	72.95%	72.80%
Risk-free interest rate	2.60%	2.12%
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 $25.97 per share and $27.28 per share in 2019 and 2018, respectively.

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


	Number of Awards		Weighted Average
	Service‑Based	Market-Based	Grant Date
	RSAs & RSUs	PSAs & PSUs	Fair Value
Nonvested awards, January 1	554,527	503,696	$	34.94
Granted	464,140	347,493		24.67
Vested	(337,428)	(98,581)		32.82
Forfeited	(162,153)	(297,349)		32.97
Nonvested awards, September 30	519,086	455,259	$	28.26

There was no significant stock option activity during the nine months ended September 30, 2019 and 2018.

Total stock compensation expense recognized for restricted stock was a benefit of $5 million for the three months ended September 30, 2019, expense of $7 million for the three months ended September 30, 2018 and expense of $6 million and $18 million for the nine months ended September 30, 2019 and 2018, respectively.

11. INCOME TAXES

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

In assessing the realizability of deferred tax assets (“DTAs”), management considers whether it is more likely than not that some portion, or all, of the Company’s DTAs will not be realized. In making such determination, the Company considers all available positive and negative evidence, including future reversals of temporary differences, tax-planning strategies and projected future taxable income and results of operations. If the Company concludes that it is more likely than not that some portion, or all, of its DTAs will not be realized, the tax asset is reduced by a valuation allowance. The Company assesses the appropriateness of its valuation allowance on a quarterly basis. At December 31, 2018, the Company had a valuation allowance totaling $152 million on a portion of its net DTAs, and as of September 30, 2019, the Company had a full valuation allowance on its DTAs.

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

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12. EARNINGS PER SHARE

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Basic Earnings (Loss) Per Share
Net income (loss)	$	(19,067)	$	121,400	$	(93,679)	$	138,532
Weighted average shares outstanding, basic		91,299		90,967		91,274		90,934
Earnings (loss) per common share, basic	$	(0.21)	$	1.33	$	(1.03)	$	1.52

Diluted Earnings (Loss) Per Share
Net income (loss)	$	(19,067)	$	121,400	$	(93,679)	$	138,532
Weighted average shares outstanding, basic		91,299		90,967		91,274		90,934
Service-based awards, market-based awards and stock options		-		856		-		928
Weighted average shares outstanding, diluted		91,299		91,823		91,274		91,862
Earnings (loss) per common share, diluted	$	(0.21)	$	1.32	$	(1.03)	$	1.51

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

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

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

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

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

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

13. COMMITMENTS AND CONTINGENCIES

Pipeline Transportation Agreement—In the third quarter of 2019, the Company entered into a ship-or-pay agreement to transport crude oil from the Williston Basin via certain pipelines for a term of seven years. Although minimum quantities are specified in the agreement,

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the actual oil volumes transported are variable over the term of the contract. The effective date of this contract is contingent upon the completion of certain related pipelines, which are currently expected to be brought online in 2021. As of September 30, 2019, the Company estimated the minimum future commitments under this agreement to approximate $147 million which is based on the contractually stipulated per barrel fee and is subject to adjustment during the term of the contract.

Litigation—The Company is subject to litigation, claims and governmental and regulatory proceedings arising in the ordinary course of business. The Company accrues a loss contingency for these lawsuits and claims when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. While the outcome of these lawsuits and claims cannot be predicted with certainty, it is the opinion of the Company’s management that the loss for any litigation matters and claims that are reasonably possible to occur will not have a material adverse effect, individually or in the aggregate, on its consolidated financial position, cash flows or results of operations. The Company is involved in litigation related to a payment arrangement with a third party which currently claims damages up to $41 million, as well as court costs and interest. While the Company believes that a loss contingency is reasonably possible, the possible loss or a range of possible loss associated with this litigation cannot be reasonably estimated due to a number of factors including, but not limited to, complex legal and factual matters, ongoing discovery and development of information important to the case and potential defenses, among others. No amounts for loss contingencies associated with litigation, claims or assessments have been accrued as of September 30, 2019 or December 31, 2018.

14. RESTRUCTURING

On July 31, 2019, the Company executed a workforce reduction as part of an organizational redesign and cost reduction strategy to better align its business with the current operating environment and drive long-term value. In connection with these activities, the Company incurred $8 million in net restructuring costs associated with one-time employee termination benefits. These restructuring costs are included in general and administrative expenses in the condensed consolidated statements of operations.

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

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

Overview

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

Our revenue, profitability and future growth rate depend on many factors which are beyond our control, such as oil and gas prices, economic, political and regulatory developments, competition from other sources of energy, and the other items discussed under the caption “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the period ended December 31, 2018. Oil and gas prices historically have been volatile and may fluctuate widely in the future. The following table highlights the quarterly average NYMEX price trends for crude oil and natural gas prices since the first quarter of 2017:


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

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 and may materially and adversely affect our future business, financial condition, cash flows, results of operations, liquidity or ability to finance planned capital expenditures. In addition, lower commodity prices may reduce the amount of our borrowing base under our credit agreement, which is determined at the discretion of our lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders, as occurred with our most recent semi-annual redetermination where the borrowing base was lowered from $2.25 billion to $2.05 billion in October 2019. Upon a redetermination, if borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of the debt outstanding under our credit agreement. Alternatively, higher oil prices may result in significant mark-to-market losses being incurred on our commodity-based derivatives.

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2019 Highlights and Future Considerations

Operational Highlights

Northern Rocky Mountains – Williston Basin

Our properties in the Williston Basin of North Dakota and Montana target the Bakken and Three Forks formations. Net production from the Williston Basin averaged 111.4 MBOE/d for the third quarter of 2019, representing a 2% decrease from 113.2 MBOE/d in the second quarter of 2019. Across our acreage in the Williston Basin, we have implemented customized, right-sized completion designs which utilize the optimum volume of proppant, fluids, and frac stages to increase well performance while reducing cost. We plan to continue to use right-sized completion design on wells we drill in 2019, while also utilizing state-of-the-art drilling rigs, high-torque mud motors and 3-D bit cutter technology to reduce time-on-location and total well cost. As of September 30, 2019, we had four rigs active in the Williston Basin. We put 39 operated wells on production in this area during the third quarter of 2019.

Central Rocky Mountains – Denver-Julesburg Basin

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

Our Redtail gas plant processes the associated gas produced from our wells in this area, and has a current inlet capacity of 50 MMcf/d. As of September 30, 2019, the plant was processing 25 MMcf/d.

Financing Highlights

In September 2019, we paid $299 million to complete a cash tender offer for $300 million aggregate principal amount of our 2020 Convertible Senior Notes, which payment consisted of the 99.0% purchase price plus all accrued and unpaid interest on the notes.

In September 2019, we paid $24 million to repurchase $25 million aggregate principal amount of our 2021 Senior Notes, which payment consisted of the average 94.708% purchase price plus all accrued and unpaid interest on the notes. In October 2019, we paid an additional $72 million to repurchase $75 million aggregate principal amount of the 2021 Senior Notes, which payment consisted of the average 95.467% purchase price plus all accrued and unpaid interest on the notes.

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

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

Acquisition and Divestiture Highlights

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

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

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

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Restructuring

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

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Results of Operations

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018


	Nine Months Ended September 30,
	2019		2018
Net production
Oil (MMBbl)		22.4		23.4
NGLs (MMBbl)		5.7		5.6
Natural gas (Bcf)		38.2		34.7
Total production (MMBOE)		34.5		34.8
Net sales (in millions)
Oil ⁽¹⁾	$	1,133.3	$	1,448.3
NGLs		34.8		114.0
Natural gas		23.5		45.9
Total oil, NGL and natural gas sales	$	1,191.6	$	1,608.2
Average sales prices
Oil (per Bbl) ⁽¹⁾	$	50.51	$	61.99
Effect of oil hedges on average price (per Bbl)		0.66		(6.01)
Oil after the effect of hedging (per Bbl)	$	51.17	$	55.98
Weighted average NYMEX price (per Bbl) ⁽²⁾	$	56.99	$	66.80
NGLs (per Bbl)	$	6.09	$	20.32
Natural gas (per Mcf)	$	0.62	$	1.32
Weighted average NYMEX price (per MMBtu) ⁽²⁾	$	2.62	$	2.93
Costs and expenses (per BOE)
Lease operating expenses	$	7.43	$	6.63
Transportation, gathering, compression and other	$	0.93	$	1.02
Production and ad valorem taxes	$	2.98	$	3.86
Depreciation, depletion and amortization	$	17.74	$	16.81
General and administrative	$	2.82	$	2.73

(1)	Before consideration of hedging transactions.

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

Oil, NGL and Natural Gas Sales. Our oil, NGL and natural gas sales revenue decreased $417 million to $1.2 billion when comparing the first nine months of 2019 to the same period in 2018. Sales revenue is a function of oil, NGL and gas volumes sold and average commodity prices realized. Our oil volumes decreased 4% and our NGL and natural gas sales volumes increased 2% and 10%, respectively, between periods. The oil volume decrease between periods was primarily attributable to normal field production decline primarily in the DJ Basin, where we have currently ceased our development activity, as well as infrastructure constraints in the Williston Basin and the impact of severe weather experienced in both the Williston Basin and the DJ Basin during the first nine months of 2019. This decrease was partially offset by new wells drilled and completed over the last twelve months in the Williston Basin which added 8,235 MBbl of oil production during the first nine months of 2019 as compared to the first nine months of 2018. The NGL volume increase between periods generally relates to new wells drilled and completed in the Williston Basin over the last twelve months, as well as additional volumes processed as more wells were connected to gas processing plants in the Williston Basin in an effort to increase our overall gas capture rate in this area and reduce flared volumes. Many of the new Williston Basin wells are in areas with higher gas-to-oil production ratios than previously drilled areas. These NGL volume increases were partially offset by normal field production decline across several of our areas. The gas volume increase between periods was primarily due to new wells drilled and completed at our Williston Basin and DJ Basin properties over the last twelve months which resulted in 10,585 MMcf and 750 MMcf, respectively,

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

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

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

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

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

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

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

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


	Nine Months Ended September 30,
	2019		2018
Depletion	$	599,320	$	571,121
Accretion of asset retirement obligations		8,680		8,365
Depreciation		4,166		4,733
Total	$	612,166	$	584,219

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

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


	Nine Months Ended September 30,
	2019		2018
Exploration	$	28,316	$	15,940
Impairment		15,729		25,612
Total	$	44,045	$	41,552

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

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

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


	Nine Months Ended September 30,
	2019		2018
General and administrative expenses	$	170,924	$	168,701
Reimbursements and allocations		(73,487)		(73,719)
General and administrative expenses, net	$	97,437	$	94,982

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

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

Derivative (Gain) Loss, Net. Our commodity derivative contracts are marked to market each quarter with fair value gains and losses recognized immediately in earnings as derivative (gain) loss, net. Cash flow, however, is only impacted to the extent that settlements under these contracts result in making or receiving a payment to or from the counterparty. Derivative (gain) loss, net, amounted to a loss of $7 million and $177 million for the nine months ended September 30, 2019 and 2018, respectively. These losses are primarily related to our collar, swap and option commodity derivative contracts and resulted from the upward shift in the futures curve of forecasted commodity prices for crude oil during the respective periods.

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

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


	Nine Months Ended September 30,
	2019		2018
Notes	$	111,679	$	115,109
Amortization of debt issue costs, discounts and premiums		23,707		22,976
Credit agreement		9,281		10,431
Other		607		1,042
Total	$	145,274	$	149,558

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

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

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

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

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

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


	Three Months Ended
	September 30,
	2019		2018
Net production
Oil (MMBbl)		7.4		7.9
NGLs (MMBbl)		1.8		1.9
Natural gas (Bcf)		12.5		12.1
Total production (MMBOE)		11.4		11.8
Net sales (in millions)
Oil ⁽¹⁾	$	370.0	$	511.9
NGLs		5.6		42.5
Natural gas		0.3		12.3
Total oil, NGL and natural gas sales	$	375.9	$	566.7
Average sales prices
Oil (per Bbl) ⁽¹⁾	$	49.71	$	64.70
Effect of oil hedges on average price (per Bbl)		1.41		(7.88)
Oil net of hedging (per Bbl)	$	51.12	$	56.82
Weighted average NYMEX price (per Bbl) ⁽²⁾	$	56.43	$	69.52
NGLs (per Bbl)	$	3.07	$	22.22
Natural gas (per Mcf)	$	0.03	$	1.02
Weighted average NYMEX price (per MMBtu) ⁽²⁾	$	2.29	$	2.88
Cost and expenses (per BOE)
Lease operating expenses	$	7.51	$	6.31
Transportation, gathering, compression and other	$	0.98	$	1.08
Production and ad valorem taxes	$	3.10	$	4.22
Depreciation, depletion and amortization	$	18.58	$	16.64
General and administrative	$	2.63	$	2.69

(1)	Before consideration of hedging transactions.

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

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

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In addition to the above oil and NGL production-related decreases in net revenue, there were also decreases in the average sales price realized for oil, NGLs and natural gas in the third quarter of 2019 compared to 2018. Our average price for oil (before the effects of hedging), NGLs and natural gas decreased 23%, 86% and 97%, respectively. Our average sales price realized for oil is impacted by deficiency payments we were making under a physical delivery contract at our Redtail field due to our inability to meet the minimum volume commitments under this contract. During the three months ended September 30, 2019 and 2018, our total average sales price realized for oil was $2.38 per Bbl lower and $1.30 per Bbl lower, respectively, as a result of these deficiency payments. This agreement will continue to negatively impact the price we receive for oil from our Redtail field through April 2020, when the contract terminates. Our average sales price realized for natural gas is impacted by rising market differentials as compared to NYMEX as well as high fixed third-party costs for transportation, gathering and compression services.

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

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

Transportation, Gathering, Compression and Other. Our TGC expenses during the third quarter were $11 million, a $2 million decrease over the same period in 2018. This decrease was primarily due to lower realized NGL prices during the third quarter of 2019, which led to lower gas processing fees under our percentage-of-proceeds contracts as compared to the third quarter of 2018.

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

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

Depreciation, Depletion and Amortization. Our DD&A expense increased $14 million in 2019 as compared to the third quarter of 2018. The components of our DD&A expense were as follows (in thousands):


	Three Months Ended
	September 30,
	2019		2018
Depletion	$	206,793	$	192,505
Accretion of asset retirement obligations		2,861		2,911
Depreciation		1,371		1,590
Total	$	211,025	$	197,006

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

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


	Three Months Ended
	September 30,
	2019		2018
Exploration	$	8,340	$	5,177
Impairment		2,550		7,302
Total	$	10,890	$	12,479

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

Impairment expense for the third quarter of 2019 and 2018 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
	September 30,
	2019		2018
General and administrative expenses	$	53,473	$	55,866
Reimbursements and allocations		(23,583)		(23,965)
General and administrative expenses, net	$	29,890	$	31,901

G&A expense, net, decreased $2 million when comparing the third quarter of 2019 to the same 2018 period primarily due to lower employee compensation costs as a result of the company restructuring during the third quarter of 2019, partially offset by an $8 million one-time net charge related to the restructuring. Refer to “Restructuring” for more information on this event.

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

Derivative (Gain) Loss, Net. Our commodity derivative contracts are marked to market each quarter with fair value gains and losses recognized immediately in earnings as derivative (gain) loss, net. Cash flow, however, is only impacted to the extent that settlements under these contracts result in making or receiving a payment to or from the counterparty. Derivative (gain) loss, net, amounted to a gain of $31 million and a loss of $21 million for the three months ended September 30, 2019 and 2018, respectively. These gains and losses are primarily related to our collar, swap and option commodity derivative contracts and resulted from the downward and upward shifts, respectively, in the futures curve of forecasted commodity prices for crude oil during the respective periods.

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

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

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


	Three Months Ended
	September 30,
	2019		2018
Notes	$	37,165	$	37,257
Amortization of debt issue costs, discounts and premiums		7,973		7,634
Credit agreement		3,039		3,125
Other		270		312
Total	$	48,447	$	48,328

Our weighted average debt outstanding during the third quarter of 2019 was $2.9 billion versus $3.0 billion for the third quarter of 2018. Our weighted average effective cash interest rate was 5.5% during the third quarter of 2019 compared to 5.4% during the third quarter of 2018.

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

Our overall effective tax rate of 0% for the third quarter of 2019 was lower than the U.S. statutory income tax rate due to the recognition of a full valuation allowance during the second quarter of 2019.

Liquidity and Capital Resources

Overview. At September 30, 2019, we had no cash on hand and $4.2 billion of equity, while at December 31, 2018, we had $14 million of cash on hand and $4.3 billion of equity.

One of the primary sources of variability in our cash flows from operating activities is commodity price volatility, which we partially mitigate through the use of commodity hedge contracts. Oil accounted for 65% and 67% of our total production in the first nine months of 2019 and 2018, respectively. As a result, our operating cash flows are more sensitive to fluctuations in oil prices than they are to fluctuations in NGL or natural gas prices. As of September 30, 2019, we had derivative contracts covering the sale of approximately 67% of our forecasted oil production volumes for the remainder of 2019. For a list of all of our outstanding derivatives as of September 30, 2019, refer to Item 3, “Quantitative and Qualitative Disclosures about Market Risk”.

During the first nine months of 2019, we generated $521 million of cash provided by operating activities, a decrease of $286 million from the same period in 2018. Cash provided by operating activities decreased primarily due to lower realized sales prices for oil, NGLs and natural gas and lower crude oil production volumes, as well as higher lease operating expenses, exploration costs and cash G&A expenses. These negative factors were partially offset by higher NGL and natural gas production volumes, a decrease in cash settlements paid on our derivative contracts, and lower production and ad valorem taxes, cash interest expense and TGC during the first nine months of 2019 as compared to the same period in 2018. 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 of 2019, cash flows from operating activities, proceeds from the sale of properties, cash on hand and $365 million of net borrowings under our credit agreement were used to finance $625 million of drilling and development expenditures, $8 million of other property and equipment and the repurchase of $300 million aggregate principal amount of 2020 Senior Convertible Notes and $25 million aggregate principal amount of 2021 Senior Notes.

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Exploration and Development Expenditures. The following table details our exploration and development (“E&D”) expenditures incurred by core area (in thousands):


	Nine Months Ended
	September 30,
	2019		2018
Northern Rocky Mountains	$	666,707	$	512,187
Central Rocky Mountains		246		80,060
Other ⁽¹⁾		8,599		5,425
Total incurred	$	675,552	$	597,672

(1)	Other primarily includes non-core oil and gas properties located in Colorado, Mississippi, New Mexico, North Dakota, Texas and Wyoming.

We continually evaluate our capital needs and compare them to our capital resources. Our 2019 E&D budget has a forecasted midpoint of $820 million, which we expect to fund substantially with net cash provided by operating activities and cash on hand. The forecasted midpoint of our 2019 E&D budget represents a slight decrease from the $832 million incurred on E&D expenditures during 2018. We believe that should additional attractive acquisition opportunities arise or E&D expenditures exceed $820 million, we will be able to finance additional capital expenditures through agreements with industry partners, divestitures of certain oil and gas property interests, borrowings under our credit agreement or by accessing the capital markets. 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. 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.

Credit Agreement. Whiting Oil and Gas, our wholly owned subsidiary, has a credit agreement with a syndicate of banks that as of September 30, 2019 had a borrowing base and aggregate commitments of $2.25 billion and $1.75 billion, respectively. As of September 30, 2019, we had $1.4 billion of available borrowing capacity under the credit agreement, which was net of $365 million of borrowings outstanding and $2 million in letters of credit outstanding.

The borrowing base under the credit agreement is determined at the discretion of our 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 the amount of the borrowing base. Upon a redetermination of our borrowing base, either on a periodic or special redetermination date, if borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of our debt outstanding under the credit agreement. In October 2019, the borrowing base under our credit agreement was reduced from $2.25 billion to $2.05 billion in connection with the November 1, 2019 regular borrowing base redetermination, with no change to the aggregate commitments of $1.75 billion.

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

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outstanding borrowings to the borrowing base. Additionally, we also incur commitment fees of 0.375% or 0.50% based on the ratio of outstanding borrowings to the borrowing base on the unused portion of the aggregate commitments of the lenders under the credit agreement.

The credit agreement contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, enter into hedging contracts, incur liens and engage in certain other transactions without the prior consent of our lenders. Except for limited exceptions, the credit agreement 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). As of September 30, 2019, the credit agreement required us, as of the last day of any quarter, to maintain the following ratios (as defined in the credit agreement): (i) a consolidated current assets to consolidated current liabilities ratio (which includes an add back of the available borrowing capacity under the credit agreement) of not less than 1.0 to 1.0 and (ii) a total debt to the last four quarters’ EBITDAX ratio of not greater than 4.0 to 1.0. We were in compliance with our covenants under the credit agreement as of September 30, 2019. For further information on the loan security related to our credit agreement, refer to the “Long-Term Debt” footnote in the notes to condensed consolidated financial statements.

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

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

Redemption of 2019 Senior Notes. In January 2018, we paid $1.0 billion to redeem all of the then outstanding $961 million aggregate principal amount of our 2019 Senior Notes, which payment consisted of the 102.976% redemption price plus all accrued and unpaid interest on the notes. We financed the redemption with proceeds from the issuance of our 2026 Senior Notes and borrowings under our credit agreement.

Repurchases of 2021 Senior Notes. In September 2019, we paid $24 million to repurchase $25 million aggregate principal amount of the 2021 Senior Notes, which payment consisted of the average 94.708% purchase price plus all accrued and unpaid interest on the notes. We financed the repurchases with cash and borrowings under our credit agreement. 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. As of October 4, 2019, $774 million of 2021 Senior Notes remained outstanding.

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

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

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on June 30, 2015 (and only during such calendar quarter), if the last reported sale price of our common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day; (ii) during the five business day period after any five consecutive trading day period (the “measurement period”) in which the trading price per $1,000 principal amount of the 2020 Convertible Senior Notes for each trading day of the measurement period is less than 98% of the product of the last reported sale price of our common stock and the conversion rate on each such trading day; or (iii) upon the occurrence of specified corporate events. On or after January 1, 2020, the 2020 Convertible Senior Notes will be convertible at any time until the second scheduled trading day immediately preceding the April 1, 2020 maturity date of the notes. The notes will be convertible at a current conversion rate of 6.4102 shares of our common stock per $1,000 principal amount of the notes, which is equivalent to a current conversion price of approximately $156.00. The conversion rate will be subject to adjustment in some events. In addition, following certain corporate events that occur prior to the maturity date, 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, 2019, none of the contingent conditions allowing holders of the 2020 Convertible Senior Notes to convert these notes had been met. 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 in cash upon conversion. At maturity, we must settle all outstanding 2020 Convertible Senior Notes in cash.

Note Covenants. The indentures governing the Senior Notes restrict 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 of our management in certain respects. We were in compliance with these covenants as of September 30, 2019. However, a substantial or extended decline in oil, NGL or natural gas prices may adversely affect our ability to comply with these covenants in the future.

Contractual Obligations and Commitments

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

In the third quarter of 2019, we entered into a ship-or-pay agreement to transport crude oil from the Williston Basin via certain pipelines for a term of seven years. Although minimum quantities are specified in the agreement, the actual oil volumes transported are variable over the term of the contract. The effective date of this contract is contingent upon the completion of certain related pipelines, which are currently expected to be brought online in 2021. As of September 30, 2019, we estimated the minimum future commitments under this agreement to approximate $147 million, which is based on the contractually stipulated per barrel fee and is subject to adjustment during the term of the contract.

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

New Accounting Pronouncements

For further information on the effects of recently adopted accounting pronouncements and the potential effects of new accounting pronouncements, refer to “Adopted and Recently Issued Accounting Pronouncements” within the “Basis of Presentation” footnote and the “Leases” footnote in the notes to condensed consolidated financial statements.

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Critical Accounting Policies and Estimates

Information regarding critical accounting policies and estimates is contained in Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2018. The following is a material update to such critical accounting policies and estimates:

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

We adopted FASB ASC Topic 842 – Leases effective January 1, 2019 using the modified retrospective approach. Refer to the “Basis of Presentation” and “Leases” footnotes in the notes to the condensed consolidated financial statements for more information on this new accounting standard.

Effects of Inflation and Pricing

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

Forward-Looking Statements

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

These risks and uncertainties include, but are not limited to: 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, ability to comply with debt covenants and periodic redeterminations of the borrowing base under our credit agreement; the geographic concentration of our operations; the ability to achieve the benefits of our organizational redesign and cost reduction strategy; impacts to financial statements as a result of impairment write-downs; federal and state initiatives relating to the regulation of hydraulic fracturing and air emissions; revisions to reserve estimates as a result of changes in commodity prices, regulation and other factors; adverse weather conditions that may negatively impact development or production activities; the timing of our exploration and development expenditures; inaccuracies of our reserve estimates or our assumptions underlying them; risks relating to any unforeseen liabilities of ours; 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 ability to successfully complete asset dispositions and the risks

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related thereto; unforeseen underperformance of or liabilities associated with acquired properties; the impacts of hedging on our results of operations; failure of our properties to yield oil or gas in commercially viable quantities; availability of, and risks associated with, transport of oil and gas; 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; uninsured or underinsured losses resulting from our oil and gas operations; our inability to access oil and gas markets due to market conditions or operational impediments; the impact and costs of compliance with laws and regulations governing our oil and gas operations; the potential impact of changes in laws that could have a negative effect on the oil and gas industry; our ability to replace our oil and natural gas reserves; negative impacts from litigation and legal proceedings; any loss of our senior management or technical personnel; competition in the oil and gas industry; cyber security attacks or failures of our telecommunication systems; and other risks described under the caption “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the period ended December 31, 2018. We assume no obligation, and disclaim any duty, to update the forward-looking statements in this Quarterly Report on Form 10-Q.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

The price we receive for our oil, NGL and gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Crude oil and natural gas are commodities, and therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, NGLs and gas have been volatile, and these markets will likely continue to be volatile in the future. Based on production for the first nine of 2019, our income (loss) before income taxes for the nine months ended September 30, 2019 would have moved up or down $113 million for each 10% change in oil prices per Bbl, $3 million for each 10% change in NGL prices per Bbl and $2 million for each 10% change in natural gas prices per Mcf.

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

Crude Oil Collars, Swaps and Options. The collared hedges and options shown in the table below have the effect of providing a protective floor while allowing us to share in upward pricing movements. The fair value of our crude oil collars and options at September 30, 2019 was a net asset of $12 million. A hypothetical upward or downward shift of 10% per Bbl in the NYMEX forward curve for crude oil as of September 30, 2019 would cause a decrease of $12 million or an increase of $14 million, respectively, in this fair value asset.

The swap contracts shown in the table below entitle us to receive settlement from the counterparty in amounts, if any, by which the settlement price for the applicable calculation period is less than the fixed price, or to pay the counterparty if the settlement price for the applicable calculation period is more than the fixed price. The fair value of our swaps at September 30, 2019 was a net asset of $34 million. A hypothetical upward or downward shift of 10% per Bbl in the NYMEX forward curve for crude oil as of September 30, 2019 would cause a decrease or increase, respectively, of $28 million in this fair value asset.

While these hedges, options and fixed-price swaps are designed to decrease our exposure to downward price movements, they also have the effect of limiting the benefit of price increases above the ceiling with respect to the hedges and options and upward price movements generally with respect to the fixed-price swaps.

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Our outstanding commodity derivative contracts as of September 30, 2019 are summarized below:


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

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

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


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

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

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

Interest Rate Risk

Our quantitative and qualitative disclosures about interest rate risk related to our credit agreement, senior notes and convertible notes are included in Item 7A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2018 and have not materially changed since that report was filed.

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Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures. In accordance with Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), our management evaluated, with the participation of our Chairman, President and Chief Executive Officer and our Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of September 30, 2019. Based upon their evaluation of these disclosure controls and procedures, the Chairman, President and Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures were effective as of September 30, 2019 to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure.

Changes in internal control over financial reporting. There was no change in our internal control over financial reporting that occurred during the quarter ended September 30, 2019 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

We are subject to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business. While the outcome of these lawsuits 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 or in the aggregate, on our consolidated financial position, cash flows or results of operations.

We are involved in litigation related to a payment arrangement with a third party which currently claims damages up to $41 million, as well as court costs and interest. While the Company believes that a loss contingency is reasonably possible, the possible loss or a range of possible loss associated with this litigation cannot be reasonably estimated due to a number of factors including, but not limited to, complex legal and factual matters, ongoing discovery and development of information important to the case and potential defenses, among others. No amount of loss contingency associated with this litigation has been accrued as of September 30, 2019.

Item 1A. Risk Factors

Risk factors relating to us are contained in Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2018. No material change to such risk factors has occurred during the nine months ended September 30, 2019.

Item 6. Exhibits

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

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EXHIBIT INDEX

Exhibit Number		Exhibit Description
(4.1)		First Amendment to Seventh Amended and Restated Credit Agreement, dated as of September 13, 2019, among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent [Incorporated by reference to Exhibit 4.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on September 16, 2019 (File No. 001-31899)].

(10.1)		Executive Employment and Severance Agreement, between Correne S. Loeffler and Whiting Petroleum Corporation, effective as of August 1, 2019 [Incorporated by reference to Exhibit 10.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on January 5, 2015 (File No. 001-31899)].

(10.2)		Non-Competition and Non-Solicitation Agreement, between Michael J. Stevens and Whiting Petroleum Corporation effective as of August 1, 2019 [Incorporated by reference to Exhibit 10.2 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on July 16, 2019 (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 Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.

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

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

(101)		The following materials from Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2019 are filed herewith, formatted in iXBRL (Inline Extensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets as of September 30, 2019 and December 31, 2018, (ii) the Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2019 and 2018, (iii) the Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2019 and 2018, (iv) the Condensed Consolidated Statements of Equity for the Nine Months Ended September 30, 2019 and 2018 and (v) Notes to Condensed Consolidated Financial Statements. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the iXBRL document.

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

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on this 6^th day of November, 2019.


		WHITING PETROLEUM CORPORATION


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


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


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