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WLL Whiting Petroleum

Filed: 4 Aug 21, 4:49pm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2021

or

        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

Graphic

WHITING PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Delaware

    

20-0098515

(State or other jurisdiction
of incorporation or organization)

(I.R.S. Employer
Identification No.)

1700 Lincoln Street, Suite 4700
Denver, Colorado

80203-4547

(Address of principal executive offices)

(Zip code)

(303) 837-1661

(Registrant’s telephone number, including area code)

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

Common Stock, $0.001 par value

WLL

New York Stock Exchange

(Title of each class)

(Trading symbol)

(Name of each exchange on which registered)

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

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

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

Large accelerated filer

Smaller reporting company

Accelerated filer

Emerging growth company

Non-accelerated filer

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

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

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

Number of shares of the registrant’s common stock outstanding at July 28, 2021: 39,117,950 shares.

GLOSSARY OF CERTAIN DEFINITIONS

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

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

“ASC” Accounting Standards Codification.

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

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

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

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

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

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

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

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

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

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

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

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

“FASB” Financial Accounting Standards Board.

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

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

1

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

“ISDA” International Swaps and Derivatives Association, Inc.

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

“LIBOR” London interbank offered rate.

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

“MBbl/d” One MBbl per day.

“MBOE” One thousand BOE.

“MBOE/d” One MBOE per day.

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

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

“MMBOE” One million BOE.

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

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

“MMcf/d” One MMcf per day.

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

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

“NGL” Natural gas liquid.

“NYMEX” The New York Mercantile Exchange.

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

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

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

2

“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:

a.The area identified by drilling and limited by fluid contacts, if any, and
b.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:

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

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

“proved undeveloped reserves” or “PUDs” Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.  Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.  Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time.  Under no circumstances shall estimates of proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

“reasonable certainty” If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered.  If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate.  A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical and geochemical) engineering, and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.

“reserves” Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

“reservoir” A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

3

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

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

“SEC” The United States Securities and Exchange Commission.

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

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

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

4

PART I – FINANCIAL INFORMATION

Item 1.    Condensed Consolidated Financial Statements

WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (unaudited)

(in thousands, except share and per share data)

Successor

June 30,

December 31,

2021

2020

ASSETS

Current assets:

Cash, cash equivalents and restricted cash

$

19,053

$

28,367

Accounts receivable trade, net

214,223

142,830

Prepaid expenses and other

14,740

19,224

Total current assets

248,016

190,421

Property and equipment:

Oil and gas properties, successful efforts method

1,929,550

1,812,601

Other property and equipment

68,443

74,064

Total property and equipment

1,997,993

1,886,665

Less accumulated depreciation, depletion and amortization

(177,084)

(73,869)

Total property and equipment, net

1,820,909

1,812,796

Other long-term assets

39,189

40,723

TOTAL ASSETS

$

2,108,114

$

2,043,940

LIABILITIES AND EQUITY

Current liabilities:

Accounts payable trade

$

51,786

$

23,697

Revenues and royalties payable

191,248

151,196

Accrued capital expenditures

22,877

20,155

Accrued liabilities and other

35,143

42,007

Accrued lease operating expenses

28,642

23,457

Taxes payable

16,712

11,997

Derivative liabilities

265,130

49,485

Total current liabilities

611,538

321,994

Long-term debt

115,000

360,000

Asset retirement obligations

93,276

91,864

Operating lease obligations

16,265

17,415

Long-term derivative liabilities

89,354

9,750

Other long-term liabilities

12,909

14,113

Total liabilities

938,342

815,136

Commitments and contingencies

Equity:

Successor common stock, $0.001 par value, 500,000,000 shares authorized; 39,091,073 issued and outstanding as June 30, 2021 and 38,051,125 issued and outstanding as of December 31, 2020

39

38

Additional paid-in capital

1,193,095

1,189,693

Accumulated earnings (deficit)

(23,362)

39,073

Total equity

1,169,772

1,228,804

TOTAL LIABILITIES AND EQUITY

$

2,108,114

$

2,043,940

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

5

WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)

(in thousands, except per share data)

Successor

Predecessor

Three Months Ended June 30, 2021

Three Months Ended June 30, 2020

OPERATING REVENUES

Oil, NGL and natural gas sales

$

349,983

$

91,600

Purchased gas sales

1,663

-

Total operating revenues

351,646

91,600

OPERATING EXPENSES

Lease operating expenses

64,182

53,242

Transportation, gathering, compression and other

7,443

9,044

Purchased gas expense

1,178

-

Production and ad valorem taxes

25,669

8,419

Depreciation, depletion and amortization

51,618

83,549

Exploration and impairment

2,047

421,156

General and administrative

11,995

28,136

Derivative loss, net

255,409

6,632

(Gain) loss on sale of properties

(10,110)

511

Amortization of deferred gain on sale

-

(1,908)

Total operating expenses

409,431

608,781

LOSS FROM OPERATIONS

(57,785)

(517,181)

OTHER INCOME (EXPENSE)

Interest expense

(3,981)

(16,425)

Other income

277

76

Reorganization items, net

-

(41,813)

Total other expense

(3,704)

(58,162)

LOSS BEFORE INCOME TAXES

(61,489)

(575,343)

INCOME TAX BENEFIT

Current

-

(1,028)

Total income tax benefit

-

(1,028)

NET LOSS

$

(61,489)

$

(574,315)

LOSS PER COMMON SHARE

Basic

$

(1.57)

$

(6.28)

Diluted

$

(1.57)

$

(6.28)

WEIGHTED AVERAGE SHARES OUTSTANDING

Basic

39,067

91,429

Diluted

39,067

91,429

(Continued)

6

WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)

(in thousands, except per share data)

Successor

Predecessor

Six Months Ended June 30, 2021

Six Months Ended June 30, 2020

OPERATING REVENUES

Oil, NGL and natural gas sales

$

654,662

$

336,446

Purchased gas sales

4,375

-

Total operating revenues

659,037

336,446

OPERATING EXPENSES

Lease operating expenses

123,521

125,582

Transportation, gathering, compression and other

14,471

18,007

Purchased gas expense

3,080

-

Production and ad valorem taxes

49,819

30,842

Depreciation, depletion and amortization

105,347

267,517

Exploration and impairment

4,669

4,174,613

General and administrative

22,286

75,303

Derivative (gain) loss, net

402,102

(224,739)

Gain on sale of properties

(10,110)

(353)

Amortization of deferred gain on sale

-

(3,945)

Total operating expenses

715,185

4,462,827

LOSS FROM OPERATIONS

(56,148)

(4,126,381)

OTHER INCOME (EXPENSE)

Interest expense

(9,084)

(61,675)

Gain on extinguishment of debt

-

25,883

Other income

2,797

72

Reorganization items, net

-

(41,813)

Total other expense

(6,287)

(77,533)

LOSS BEFORE INCOME TAXES

(62,435)

(4,203,914)

INCOME TAX EXPENSE (BENEFIT)

Current

-

2,718

Deferred

-

(3,746)

Total income tax benefit

-

(1,028)

NET LOSS

$

(62,435)

$

(4,202,886)

LOSS PER COMMON SHARE

Basic

$

(1.61)

$

(45.98)

Diluted

$

(1.61)

$

(45.98)

WEIGHTED AVERAGE SHARES OUTSTANDING

Basic

38,883

91,409

Diluted

38,883

91,409

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

(Concluded)

7

WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(in thousands)

Successor

Predecessor

   

Six Months Ended June 30, 2021

 

  

Six Months Ended June 30, 2020

CASH FLOWS FROM OPERATING ACTIVITIES

Net loss

$

(62,435)

$

(4,202,886)

Adjustments to reconcile net loss to net cash provided by operating activities:

Depreciation, depletion and amortization

105,347

267,517

Deferred income tax benefit

-

(3,746)

Amortization of debt issuance costs, debt discount and debt premium

1,773

9,786

Stock-based compensation

4,764

3,401

Amortization of deferred gain on sale

-

(3,945)

Gain on sale of properties

(10,110)

(353)

Oil and gas property impairments

2,691

4,154,369

Gain on extinguishment of debt

-

(25,883)

Non-cash derivative (gain) loss

295,249

(178,525)

Non-cash reorganization items, net

-

38,145

Other, net

(3,670)

829

Changes in current assets and liabilities:

Accounts receivable trade, net

(69,957)

152,560

Prepaid expenses and other

4,484

(12,036)

Accounts payable trade and accrued liabilities

23,536

(51,783)

Revenues and royalties payable

40,052

(65,609)

Taxes payable

4,715

(14,579)

Net cash provided by operating activities

336,439

67,262

CASH FLOWS FROM INVESTING ACTIVITIES

Drilling and development capital expenditures

(103,379)

(223,905)

Acquisition of oil and gas properties

(509)

(351)

Other property and equipment

490

(423)

Proceeds from sale of properties

6,442

28,243

Net cash used in investing activities

(96,956)

(196,436)

CASH FLOWS FROM FINANCING ACTIVITIES

Borrowings under Credit Agreement

590,000

-

Repayments of borrowings under Credit Agreement

(835,000)

-

Borrowings under Predecessor Credit Agreement

-

1,185,000

Repayments of borrowings under Predecessor Credit Agreement

-

(490,000)

Repurchase of 1.25% Convertible Senior Notes due 2020

-

(52,890)

Principal payments on finance lease obligations

(2,436)

(2,409)

Restricted stock used for tax withholdings

(1,361)

(304)

Net cash provided by (used in) financing activities

$

(248,797)

$

639,397

(Continued)

8

WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(in thousands)

Successor

Predecessor

   

Six Months Ended June 30, 2021

 

 

Six Months Ended June 30, 2020

NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH

$

(9,314)

$

510,223

CASH, CASH EQUIVALENTS AND RESTRICTED CASH

Beginning of period

28,367

8,652

End of period

$

19,053

$

518,875

SUPPLEMENTAL CASH FLOW DISCLOSURES

Interest paid, net of amounts capitalized

$

6,189

$

72,199

Cash paid for reorganization items

$

396

$

3,668

NONCASH INVESTING ACTIVITIES

Accrued capital expenditures and accounts payable related to property additions

$

26,935

$

38,504

NONCASH FINANCING ACTIVITIES

Derivative termination settlement payments used to repay borrowings under Predecessor Credit Agreement

$

-

$

157,741

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

(Concluded)

9

WHITING PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (unaudited)

(in thousands)

Additional

Accumulated

Common Stock

Paid-in

Earnings

Total

Shares

Amount

Capital

(Deficit)

Equity

BALANCES - January 1, 2020 (Predecessor)

91,744

$

92

$

6,409,991

$

(2,385,112)

$

4,024,971

Net loss

-

-

-

(3,628,571)

(3,628,571)

Adjustment to equity component of Convertible Senior Notes upon extinguishment

-

-

(3,461)

-

(3,461)

Restricted stock issued

185

-

-

-

-

Restricted stock forfeited

(238)

-

-

-

-

Restricted stock used for tax withholdings

(54)

-

(304)

-

(304)

Stock-based compensation

-

-

2,068

-

2,068

BALANCES - March 31, 2020 (Predecessor)

91,637

92

6,408,294

(6,013,683)

394,703

Net loss

-

-

-

(574,315)

(574,315)

Stock-based compensation

-

-

1,333

-

1,333

BALANCES - June 30, 2020 (Predecessor)

91,637

$

92

$

6,409,627

$

(6,587,998)

$

(178,279)

BALANCES - January 1, 2021 (Successor)

38,051

$

38

$

1,189,693

$

39,073

$

1,228,804

Net loss

-

-

-

(946)

(946)

Common stock issued in settlement of bankruptcy claims

949

1

(1)

-

-

Restricted stock issued

95

-

-

-

-

Restricted stock used for tax withholdings

(41)

-

(1,357)

-

(1,357)

Stock-based compensation

-

-

2,309

-

2,309

BALANCES - March 31, 2021 (Successor)

39,054

39

1,190,644

38,127

1,228,810

Net loss

-

-

-

(61,489)

(61,489)

Restricted stock issued

37

-

-

-

-

Restricted stock used for tax withholdings

-

-

(4)

-

(4)

Stock-based compensation

-

-

2,455

-

2,455

BALANCES - June 30, 2021 (Successor)

39,091

$

39

$

1,193,095

$

(23,362)

$

1,169,772

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

10

WHITING PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1.          BASIS OF PRESENTATION

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

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

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

During the Predecessor YTD Period, the Company applied ASC 852 in preparing the condensed consolidated financial statements, which requires distinguishing transactions associated with the reorganization separate from activities related to the ongoing operations of the business.  Accordingly, certain expenses, realized gains and losses and provisions for losses that were realized or incurred during the Chapter 11 Cases, including adjustments to the carrying value of certain indebtedness, were recorded as reorganization items, net in the condensed consolidated statements of operations for the Predecessor periods.  Refer to the “Chapter 11 Emergence” footnote for more information on the events of the bankruptcy proceedings as well as the accounting and reporting impacts of the reorganization during the Predecessor YTD Period.

Condensed Consolidated Financial Statements—The unaudited condensed consolidated financial statements include the accounts of Whiting Petroleum Corporation and its consolidated subsidiaries.  Investments in entities which give Whiting significant influence, but not control, over the investee are accounted for using the equity method.  Under the equity method, investments are stated at cost plus the Company’s equity in undistributed earnings and losses.  All intercompany balances and transactions have been eliminated upon consolidation.  These financial statements have been prepared in accordance with GAAP and the SEC rules and regulations for interim financial reporting.  In the opinion of management, the accompanying financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim results.  However, 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

11

for the period ended December 31, 2020.  Except as disclosed herein, there have been no material changes to the information disclosed in the notes to consolidated financial statements included in the Company’s Annual Report on Form 10-K for the period ending December 31, 2020.

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

Cash, Cash Equivalents and Restricted CashCash equivalents consist of demand deposits and highly liquid investments which have an original maturity of three months or less.  Cash and cash equivalents potentially subject the Company to a concentration of credit risk as substantially all of its deposits held in financial institutions were in excess of the Federal Deposit Insurance Corporation insurance limits as of June 30, 2021 and December 31, 2020.  The Company maintains its cash and cash equivalents in the form of money market and checking accounts with financial institutions that are also lenders under the Successor’s credit agreement.  The Company has not experienced any losses on its deposits of cash and cash equivalents.

Restricted cash as of June 30, 2021 and December 31, 2020 consist of funds remaining in a professional fee escrow account that were reserved to pay certain professional fees upon emergence from the Chapter 11 Cases.  

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

Successor

June 30,

December 31,

2021

2020

Cash and cash equivalents

$

16,652

$

25,607

Restricted cash

2,401

2,760

Total cash, cash equivalents and restricted cash

$

19,053

$

28,367

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

The Company routinely evaluates expected credit losses for all material trade and other receivables to determine if an allowance for credit losses is warranted.  Expected credit losses are estimated based on (i) historic loss experience for pools of receivable balances with similar characteristics, (ii) the length of time balances have been outstanding and (iii) the economic status of each counterparty.  These loss estimates are then adjusted for current and expected future economic conditions, which may include an assessment of the probability of non-payment, financial distress or expected future commodity prices and the impact that any current or future conditions could have on a counterparty’s credit quality and liquidity.  As of June 30, 2021 and December 31, 2020 (Successor), the Company had immaterial allowances for credit losses.

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2.          CHAPTER 11 EMERGENCE

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

On the Emergence Date and pursuant to the Plan:

(1)The Company amended and restated its certificate of incorporation and bylaws.
(2)The Company constituted a new Successor board of directors.
(3)The Company appointed a new Chief Executive Officer and a new Chief Financial Officer.
(4)The Company issued:
36,817,630 shares of the Successor’s common stock pro rata to holders of the Predecessor’s senior notes,
1,233,495 shares of the Successor’s common stock pro rata to holders of the Predecessor’s common stock,
4,837,387 Series A Warrants to purchase the same number of shares of the Successor’s common stock pro rata to holders of the Predecessor’s common stock and
2,418,840 Series B Warrants to purchase the same number of shares of the Successor’s common stock pro rata to holders of the Predecessor’s common stock.

The Company also reserved 3,070,201 shares of the Successor’s common stock for potential future distribution to certain general unsecured claimants whose claim values were pending resolution in the Bankruptcy Court.  In February 2021, the Company issued 948,897 shares out of this reserve to a general unsecured claimant in full settlement of such claimant’s claims pending before the Bankruptcy Court and for rejection damages relating to an executory contract.  Any remaining reserved shares that are not distributed to resolve pending claims will be cancelled.  In addition, 4,035,885 shares have been reserved for distribution under the Company’s 2020 equity incentive plan, as further detailed in the “Stock-Based Compensation” footnote below.  

(5)Whiting Petroleum Corporation, as parent guarantor, and Whiting Oil and Gas, as borrower, entered into a reserves-based credit agreement with a syndicate of banks (the “Credit Agreement”) with initial aggregate commitments in the amount of $750 million, with the ability to increase the aggregate commitments by up to an additional $750 million, subject to certain conditions.  Refer to the “Long-Term Debt” footnote for more information on the Credit Agreement.  The Company utilized borrowings from the Credit Agreement and cash on hand to repay all borrowings and accrued interest outstanding on its pre-emergence credit facility (the “Predecessor Credit Agreement”) as of the Emergence Date, and the Predecessor Credit Agreement terminated on that date.
(6)The holders of trade claims, administrative expense claims, other secured claims and other priority claims received payment in full in cash upon emergence or through the ordinary course of business after the Emergence Date.

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

13

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

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

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

3.         FRESH START ACCOUNTING

Fresh Start—In connection with the Company’s emergence from bankruptcy and in accordance with ASC 852, the Company qualified for and adopted fresh start accounting on the Emergence Date.  Upon application of fresh start accounting, the Company allocated its reorganization value to its individual assets based on their estimated fair values in conformity with FASB ASC Topic 820 – Fair Value Measurement (“ASC 820”) and FASB ASC Topic 805 – Business Combinations.  The reorganization value represents the fair value of the Successor’s assets before considering certain liabilities and is intended to represent the approximate amount a willing buyer would pay for the Company’s assets immediately after reorganization.

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

Reorganization Items, Net—Any expenses, gains and losses that were realized or incurred between the Petition Date and the Emergence Date and as a direct result of the Chapter 11 Cases were recorded in reorganization items, net in the Company’s condensed consolidated statements of operations.  The following table summarizes the components of reorganization items, net for the three and six months ended June 30, 2020 (in thousands):

Predecessor

Three and Six Months Ended

June 30, 2020

Legal and professional advisory fees

$

26,668

Write-off of unamortized debt issuance costs and premium (1)

15,145

Total reorganization items, net

$

41,813

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

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4.          OIL AND GAS PROPERTIES

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

Successor

June 30,

December 31,

    

2021

2020

Proved oil and gas properties

$

1,781,723

$

1,701,163

Unproved leasehold costs

101,477

105,073

Wells and facilities in progress

46,350

6,365

Total oil and gas properties, successful efforts method

1,929,550

1,812,601

Accumulated depletion

(170,435)

(71,064)

Oil and gas properties, net

$

1,759,115

$

1,741,537

Impairment expense for unproved properties was $1 million and $2 million for the three and six months ended June 30, 2021 (Successor), respectively.  Impairment expense for unproved properties was immaterial for the three months ended June 30, 2020 (Predecessor) and $12 million for the six months ended June 30, 2020 (Predecessor).  Impairment expense for unproved properties is reported in exploration and impairment expense in the condensed consolidated statements of operations.

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

5.          ACQUISITIONS AND DIVESTITURES

2021 Acquisitions and Divestitures

There were no significant acquisitions or divestitures during the six months ended June 30, 2021.

Refer to the “Subsequent Events” footnote for information on acquisition and divestiture activity subsequent to June 30, 2021.

2020 Acquisitions and Divestitures

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

There were no significant acquisitions during the six months ended June 30, 2020.

6.          LONG-TERM DEBT

Long-term debt, consisting entirely of borrowings outstanding under the Company’s Credit Agreement, totaled $115 million and $360 million at June 30, 2021 and December 31, 2020, respectively.

Credit Agreement (Successor)

On the Emergence Date, Whiting Petroleum Corporation, as parent guarantor, and Whiting Oil and Gas, as borrower, entered into the Credit Agreement, a reserves-based credit facility, with a syndicate of banks.  As of June 30, 2021, the Credit Agreement had a borrowing base and aggregate commitments of $750 million.  As of June 30, 2021, the Company had $633 million of available borrowing capacity under the Credit Agreement, which was net of $115 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 April 1 and October 1 of each year, as well as special redeterminations described in the Credit Agreement, in each case which may increase or

15

decrease the amount of the borrowing base.  In April 2021, the Company’s borrowing base and aggregate commitments of $750 million were reaffirmed in connection with our regular borrowing base redetermination.  Asset sales that materially impact the value of the Company’s proved reserves may result in a reduction of the borrowing base.  However, the Company can increase the aggregate commitments by up to an additional $750 million, subject to certain conditions.  

A portion of the borrowing base in an aggregate amount not 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 June 30, 2021, $48 million was available for additional letters of credit under the Credit Agreement.

The Credit Agreement provides for interest only payments until maturity on April 1, 2024, when the agreement terminates and all outstanding borrowings are due.  In addition, the Credit Agreement provides for certain mandatory prepayments, including a provision pursuant to which, if the Company’s cash balances are in excess of approximately $75 million during any given week, such excess must be utilized to repay borrowings under the Credit Agreement.  Interest under the Credit Agreement accrues at the Company’s option at either (i) a base rate for a base rate loan plus a margin between 1.75% and 2.75% based on the ratio of outstanding borrowings and letters of credit to the lower of the current borrowing base or total commitments, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.5% per annum, or an adjusted LIBOR plus 1.0% per annum, or (ii) an adjusted LIBOR for a eurodollar loan plus a margin between 2.75% and 3.75% based on the ratio of outstanding borrowings and letters of credit to the lower of the current borrowing base or total commitments.  Additionally, the Company incurs commitment fees of 0.5% on the unused portion of the aggregate commitments of the lenders under the Credit Agreement, which are included as a component of interest expense.  At June 30, 2021, the weighted average interest rate on the outstanding principal balance under the Credit Agreement was 4.1%.

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 prior to September 1, 2021, and thereafter only to the extent that the Company has distributable free cash flow and (i) has at least 20% of available borrowing capacity, (ii) has a consolidated net leverage ratio of less than or equal to 2.0 to 1.0, (iii) does not have a borrowing base deficiency and (iv) is not in default under the Credit Agreement. These restrictions apply to all of the Company’s restricted subsidiaries and are calculated in accordance with definitions contained in the Credit Agreement. The Credit Agreement requires the Company, as of the last day of any quarter, to maintain commodity hedges covering a minimum of 65% of its projected production for the succeeding twelve months, and 35% of its projected production for the next succeeding twelve months, both as reflected in the reserves report most recently provided by the Company to the lenders under the Credit Agreement.  The Company is also limited to hedging a maximum of 85% of its production from proved reserves.  The Credit Agreement requires the Company to maintain the following ratios: (i) a consolidated current assets to consolidated current liabilities ratio of not less than 1.0 to 1.0 and (ii) a total debt to last four quarters’ EBITDAX ratio of not greater than 3.5 to 1.0.  As of June 30, 2021, the Company was in compliance with the covenants under the Credit Agreement.

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

Senior Notes and Convertible Senior Notes (Predecessor)

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

In March 2020, the Company paid $53 million to repurchase $73 million aggregate principal amount of the Convertible Senior Notes, which payment consisted of the average 72.5% purchase price plus all accrued and unpaid interest on the notes, which were allocated to the liability and equity components based on their relative fair values.  The Company financed the repurchases with borrowings under the Predecessor Credit Agreement.  As a result of these repurchases, the Company recognized a $23 million gain on extinguishment of debt during the Predecessor Period, which was net of a $0.2 million charge for the non-cash write-off of unamortized debt issuance costs

16

and debt discount.  In addition, the Company recorded a $3 million reduction to the equity component of the Convertible Senior Notes.  There was no deferred tax impact associated with this reduction due to the full valuation allowance in effect as of March 31, 2020.

7.          ASSET RETIREMENT OBLIGATIONS

The Company’s asset retirement obligations represent the present value of estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws and the terms of the Company’s lease agreements.  The current portions as of June 30, 2021 and December 31, 2020 (Successor) were $6 million, and have been included in accrued liabilities and other in the condensed consolidated balance sheets.  The following table provides a reconciliation of the Company’s asset retirement obligations for the six months ended June 30, 2021 (in thousands):

Asset retirement obligation at January 1, 2021 (Successor)

$

98,130

Additional liability incurred

773

Revisions to estimated cash flows

8,354

Accretion expense

4,412

Obligations on sold properties

(9,654)

Liabilities settled

(2,492)

Asset retirement obligation at June 30, 2021 (Successor)

$

99,523

8.          DERIVATIVE FINANCIAL INSTRUMENTS

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

Commodity Derivative ContractsHistorically, prices received for crude oil, natural gas and natural gas liquids production have been volatile because of supply and demand factors, worldwide political factors, general economic conditions and seasonal weather patterns.  Whiting primarily enters into derivative contracts such as crude oil, natural gas and natural gas liquids swaps, collars, basis swaps and differential swaps to achieve a more predictable cash flow by reducing its exposure to commodity price volatility, thereby ensuring adequate funding for the Company’s capital programs and facilitating the management of returns on drilling programs and acquisitions.  The Company also enters into derivative contracts to maintain its compliance with certain minimum hedging requirements contained in the Credit Agreement.  Refer to the “Long-Term Debt” footnote for a detailed discussion of the minimum and maximum hedging requirements of the Credit Agreement.  The Company does not enter into derivative contracts for speculative or trading purposes.

Crude Oil, Natural Gas and Natural Gas Liquids Swaps and Collars, Natural Gas Basis Swaps and Crude Oil Differential Swaps.  Swaps establish a fixed price for anticipated future oil, gas or NGL production, while collars are designed to establish floor and ceiling prices on anticipated future oil or gas production.  Natural gas basis swaps and crude oil differential swaps mitigate risk associated with anticipated future production by establishing a fixed differential between NYMEX prices and the referenced index price.  While the use of these derivative instruments limits the downside risk of adverse price movements, it may also limit future income from favorable price movements.  

17

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

Weighted Average

Settlement Period

Index

Derivative Instrument

Total Volumes

Units

Swap Price

Floor

Ceiling

Crude Oil

2021

NYMEX WTI

Fixed Price Swaps

3,588,000

Bbl

$45.40

-

-

2021

NYMEX WTI

Two-way Collars

3,162,000

Bbl

-

$41.64

$50.50

Q1 2022

NYMEX WTI

Fixed Price Swaps

630,000

Bbl

$54.30

-

-

2022

NYMEX WTI

Two-way Collars

9,559,000

Bbl

-

$43.22

$53.70

Q1-Q2 2023

NYMEX WTI

Two-way Collars

3,259,500

Bbl

-

$46.79

$59.37

Total

20,198,500

Crude Oil Differentials (1)

2021

UHC Clearbrook to NYMEX

Fixed Price Swaps

76,500

Bbl

-$1.95

-

-

Total

76,500

Natural Gas

2021

NYMEX Henry Hub

Fixed Price Swaps

8,970,000

MMBtu

$2.81

-

-

2021

NYMEX Henry Hub

Two-way Collars

5,520,000

MMBtu

-

$2.60

$2.79

Q1-Q3 2022

NYMEX Henry Hub

Fixed Price Swaps

5,259,000

MMBtu

$2.68

-

-

2022

NYMEX Henry Hub

Two-way Collars

10,720,000

MMBtu

-

$2.35

$2.85

Q1-Q2 2023

NYMEX Henry Hub

Two-way Collars

4,975,000

MMBtu

-

$2.37

$2.91

Total

35,444,000

Natural Gas Basis (2)

2021

NNG Ventura to NYMEX

Fixed Price Swaps

3,680,000

MMBtu

-$0.18

-

-

Q1-Q2 2022

NNG Ventura to NYMEX

Fixed Price Swaps

3,530,000

MMBtu

$0.14

-

-

Q1-Q2 2023

NNG Ventura to NYMEX

Fixed Price Swaps

4,740,000

MMBtu

$0.07

-

-

Total

11,950,000

NGL - Propane

2021

Mont Belvieu

Fixed Price Swaps

19,320,000

Gallons

$0.78

-

-

Q1 2022

Mont Belvieu

Fixed Price Swaps

3,780,000

Gallons

$0.81

-

-

Total

23,100,000

(1)The weighted average price associated with the crude oil differential swaps shown in the table above represents the average fixed differential to NYMEX as stated in the related contracts, which is compared to the NE2 Canadian Monthly Index for UHC Clearbrook (“UHC Clearbrook”) for each period.  If NYMEX combined with the fixed differential as stated in each contract is higher than the UHC Clearbrook index price at any settlement date, the Company receives the difference.  Conversely, if the UHC Clearbrook index price is higher than NYMEX combined with the fixed differential, the Company pays the difference.
(2)The weighted average price associated with the natural gas basis swaps shown in the table above represents the average fixed differential to NYMEX as stated in the related contracts, which is compared to the Northern Natural Gas Ventura Index (“NNG Ventura”) for each period.  If NYMEX combined with the fixed differential as stated in each contract is higher than the NNG Ventura index price at any settlement date, the Company receives the difference.  Conversely, if the NNG Ventura index price is higher than NYMEX combined with the fixed differential, the Company pays the difference.

Effect of Chapter 11 Cases—The commencement of the Chapter 11 Cases constituted a termination event with respect to the Company’s derivative instruments, which permitted the counterparties of such derivative instruments to terminate their outstanding hedges.  Such termination events are not stayed under the Bankruptcy Code.  During April 2020, certain of the lenders under the Predecessor Credit Agreement elected to terminate their master ISDA agreements and outstanding hedges with the Company for aggregate settlement proceeds of $145 million.  The proceeds from these terminations along with $13 million of March 2020 hedge settlement proceeds received in April 2020 were applied to the outstanding borrowings under the Predecessor Credit Agreement.  An additional $23 million of settlement proceeds from terminated derivative positions were held in escrow until the completion of the Chapter 11 Cases.

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

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

June 30, 2021 (1)

Net

Gross

Recognized

Recognized

Gross

Fair Value

Not Designated as 

Assets/

Amounts

Assets/

ASC 815 Hedges

    

Balance Sheet Classification

    

Liabilities

    

Offset

    

Liabilities

Derivative assets

Commodity contracts - current

Prepaid expenses and other

$

7,001

$

(7,001)

$

-

Commodity contracts - non-current

Other long-term assets

21,324

(21,324)

-

Total derivative assets

$

28,325

$

(28,325)

$

-

Derivative liabilities

Commodity contracts - current

Derivative liabilities

$

272,131

$

(7,001)

$

265,130

Commodity contracts - non-current

Long-term derivative liabilities

110,678

(21,324)

89,354

Total derivative liabilities

$

382,809

$

(28,325)

$

354,484

December 31, 2020 (1)

Net

Gross

Recognized

Recognized

Gross

Fair Value

Not Designated as 

Assets/

Amounts

Assets/

ASC 815 Hedges

    

Balance Sheet Classification

    

Liabilities

    

Offset

    

Liabilities

Derivative assets

Commodity contracts - current

Prepaid expenses and other

$

14,287

$

(14,287)

$

-

Commodity contracts - non-current

Other long-term assets

19,991

(19,991)

-

Total derivative assets

$

34,278

$

(34,278)

$

-

Derivative liabilities

Commodity contracts - current

Derivative liabilities

$

63,772

$

(14,287)

$

49,485

Commodity contracts - non-current

Long-term derivative liabilities

29,741

(19,991)

9,750

Total derivative liabilities

$

93,513

$

(34,278)

$

59,235

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

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

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9.          FAIR VALUE MEASUREMENTS

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

Level 1:  Quoted Prices in Active Markets for Identical Assets – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
Level 2:  Significant Other Observable Inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
Level 3:  Significant Unobservable Inputs – inputs to the valuation methodology are unobservable and significant to the fair value measurement.

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

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

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

Total Fair Value

    

Level 1

    

Level 2

    

Level 3

    

June 30, 2021

Financial Liabilities

Commodity derivatives – current

$

-

$

265,130

$

-

$

265,130

Commodity derivatives – non-current

-

89,354

-

89,354

Total financial liabilities

$

-

$

354,484

$

-

$

354,484

Total Fair Value

    

Level 1

    

Level 2

    

Level 3

    

December 31, 2020

Financial Liabilities

Commodity derivatives – current

$

-

$

49,485

$

-

$

49,485

Commodity derivatives – non-current

-

9,750

-

9,750

Total financial liabilities

$

-

$

59,235

$

-

$

59,235

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

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

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Non-recurring Fair Value MeasurementsThe Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including proved property.  These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances.  The Company did not recognize any impairment write-downs with respect to its proved property during the Successor YTD Period.  The following tables present information about the Company’s non-financial assets measured at fair value on a non-recurring basis during the Predecessor YTD Period and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values (in thousands):

Predecessor

Net Carrying

Value as of

Loss (Before Tax)

March 31,

Fair Value Measurements Using

Three Months Ended

    

2020

    

Level 1

    

Level 2

    

Level 3

    

March 31, 2020

Proved property (1)

$

816,234

$

-

$

-

$

816,234

$

3,732,096

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

Predecessor

Net Carrying

Value as of

Loss (Before Tax)

June 30,

Fair Value Measurements Using

Six Months Ended

    

2020

    

Level 1

    

Level 2

    

Level 3

    

June 30, 2020

Proved property (2)

$

85,418

$

-

$

-

$

85,418

$

409,079

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

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

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10.          REVENUE RECOGNITION

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

Successor

Predecessor

OPERATING REVENUES

Three Months Ended June 30, 2021

Three Months Ended June 30, 2020

Oil sales

$

308,417

$

91,904

NGL and natural gas sales (1)

41,566

(304)

Oil, NGL and natural gas sales

349,983

91,600

Purchased gas sales

1,663

-

Total operating revenues

$

351,646

$

91,600

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

Successor

Predecessor

    

Six Months Ended June 30, 2021

Six Months Ended June 30, 2020

OPERATING REVENUES

Oil sales

$

565,126

$

323,849

NGL and natural gas sales

89,536

12,597

Oil, NGL and natural gas sales

654,662

336,446

Purchased gas sales

4,375

-

Total operating revenues

$

659,037

$

336,446

Whiting receives payment for product sales from one to three months after delivery.  At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in accounts receivable trade, net in the condensed consolidated balance sheets.  As of June 30, 2021 and December 31, 2020 (Successor), such receivable balances were $132 million and $88 million, respectively.  Variances between the Company’s estimated revenue and actual payments are recorded in the month the payment is received, but differences have been and are insignificant.  Accordingly, the variable consideration is not constrained.

The Company has elected to utilize the practical expedient in ASC 606 that states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation.  Under the Company’s contracts, each monthly delivery of product represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

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11.        SHAREHOLDERS’ EQUITY

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

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

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

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

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

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

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

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

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

23

12.        STOCK-BASED COMPENSATION

Equity Incentive Plan—As discussed in the “Chapter 11 Emergence” footnote, on the Emergence Date and pursuant to the terms of the Plan, all of the Predecessor’s common stock and any unvested awards based on such common stock were cancelled and holders were issued an aggregate of 1,233,495 shares of Successor common stock on a pro rata basis.  On September 1, 2020, the Successor’s board of directors adopted the Whiting Petroleum Corporation 2020 Equity Incentive Plan (the “2020 Equity Plan”), which replaced the Predecessor’s equity plan (the “Predecessor Equity Plan”).  The 2020 Equity Plan provides the authority to issue 4,035,885 shares of the Successor’s common stock.  Any shares forfeited under the 2020 Equity Plan will be available for future issuance under the 2020 Equity Plan.  However, shares netted for tax withholding under the 2020 Equity Plan will be cancelled and will not be available for future issuance.  Under the 2020 Equity Plan, during any calendar year no non-employee director participant may be granted awards having a grant date fair value in excess of $500,000.  As of June 30, 2021, 3,029,358 shares of common stock remained available for grant under the 2020 Equity Plan.

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

Successor Awards

During September and October 2020, 89,021 shares of service-based RSUs were granted to executive officers and directors under the 2020 Equity Plan.  The Company determines compensation expense for these share-settled awards using their fair value at the grant date based on the closing bid price of the Company’s common stock on such date.  The weighted average grant date fair value of these RSUs was $17.47 per share.

In September 2020, 189,900 shares of market-based RSUs were granted to executive officers under the 2020 Equity Plan.  The awards will vest upon the Successor’s common stock trading for 20 consecutive trading days above a certain daily volume weighted average price (“VWAP”) as follows: 50% will vest if the VWAP exceeds $32.57 per share, an additional 25% if the daily VWAP exceeds $48.86 per share and the final 25% if the daily VWAP exceeds $65.14 per share.  The Company recognizes compensation expense based on the fair value as determined by a Monte Carlo valuation model (the “Monte Carlo Model”) over the expected vesting period, which is estimated to be between 1.8 and 3.8 years.  The weighted average grant date fair value of these RSUs was $6.54 per share.  More information on the inputs of the Monte Carlo Model are explained below.  During the six months ended June 30, 2021, the first 50% of these awards vested as the Company’s VWAP exceeded $32.57 per share for 20 consecutive trading days during the period.  Subsequent to June 30, 2021, an additional 25% of these awards vested as the Company’s VWAP exceeded $48.86 per share for 20 consecutive trading days.

During the six months ended June 30, 2021, 358,123 shares of service-based RSUs were granted to executive officers and employees under the 2020 Equity Plan, which vest ratably over either a two or three-year service period.  Additionally, during the six months ended June 30, 2021, 117,607 shares of service-based RSUs were granted to executive officers under the 2020 Equity Plan, which cliff vest on the fifth anniversary of the grant date.  Finally, during the six months ended June 30, 2021, 23,730 shares of service-based RSUs were granted to directors under the 2020 Equity Plan, which vest ratably over a one-year period.  The Company determines compensation expense for these share-settled awards using their fair value at the grant date, which is based on the closing bid price of the Company’s common stock on such date.  The weighted average grant date fair value of serviced-based RSUs was $23.74 per share for the six months ended June 30, 2021.

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

24

of awards earned could range from 0 up to 2 times the number of shares initially granted, all of which will be settled in shares.  The weighted average grant date fair value of the market-based awards was $29.32 per share and $32.33 per share for the ATSR and RTSR awards, respectively, as determined by the Monte Carlo Model, which is described further below.

For awards subject to market conditions, the grant date fair value is estimated using the Monte Carlo Model, which is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment.  Expected volatility for the market-based RSUs was calculated based on the observed volatility of peer public companies.  Expected volatility for the market-based PSUs was calculated based on the historical and implied volatility of Whiting’s common shares (adjusted for the impacts of the Chapter 11 Cases).  The risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with the vesting period for the relevant award.  The key assumptions used in valuing these market-based awards were as follows:

2020

2021

    

RSUs

    

PSUs

Number of simulations

 

100,000

 

500,000

Expected volatility

 

40%

81%

Risk-free interest rate

 

0.66%

0.17%

Dividend yield

 

0

 

0

The following table shows a summary of the Company’s service-based and market-based awards activity for the six months ended June 30, 2021:

Number of Awards

Weighted Average

ServiceBased

Market-Based

Market-Based

Grant Date

    

RSUs

    

RSUs

    

PSUs

    

Fair Value

Nonvested awards, January 1

 

89,021

 

189,900

-

$

10.03

Granted

 

499,460

 

-

232,150

 

25.99

Vested

 

(36,959)

 

(94,950)

-

 

9.61

Forfeited

 

(4,004)

 

-

-

 

22.46

Nonvested awards, June 30

 

547,518

 

94,950

232,150

$

23.38

The Company recognized $2 million and $5 million in stock-based compensation expense during the three and six months ended June 30, 2021, respectively.

Predecessor Awards

During the six months ended June 30, 2020, 53,198 shares of share-settled, service-based RSAs and RSUs were granted to executive officers and directors under the Predecessor Equity Plan.  The Company determined compensation expense for these awards using their fair value at the grant date, which was based on the closing bid price of the Company’s common stock on such date.  The weighted average grant date fair value of these service-based RSAs and RSUs was $4.94 per share for the six months ended June 30, 2020.  On March 31, 2020, all of the RSAs issued to executive officers in 2020 were forfeited and concurrently replaced with cash incentives.  Refer to “2020 Compensation Adjustments” below for more information.

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

During the six months ended June 30, 2020, 1,665,153 shares of PSAs and PSUs subject to certain market-based vesting criteria were granted to executive officers under the Predecessor Equity Plan.  These market-based awards were to cliff vest on the third anniversary of the grant date, however, on March 31, 2020, all of the PSAs and PSUs issued to executive officers in 2020 were forfeited and concurrently replaced with cash incentives.  Refer to “2020 Compensation Adjustments” below for more information.  The weighted average grant date fair value of the market-based awards that were to be settled in shares, as determined by the Monte Carlo valuation

25

model, was $4.31 per share in 2020.  The cash-settled component of such awards was recorded as a liability in the consolidated balance sheets and was remeasured at fair value using a Monte Carlo valuation model at the end of each reporting period.

The Company recognized $1 million and $2 million in total stock-based compensation expense during the three and six months ended June 30, 2020, respectively.

2020 Compensation Adjustments.  All of the RSAs, RSUs, PSAs and PSUs granted to executive officers in 2020 under the Predecessor Equity Plan were forfeited on March 31, 2020 and were replaced with cash retention incentives.  The cash retention incentives were subject to a service period and were subject to claw back provisions if an executive officer terminated employment for any reason other than a qualifying termination prior to the earlier of (i) the effective date of a plan of reorganization approved under chapter 11 of the Bankruptcy Code or (ii) March 30, 2021.  The transactions were considered concurrent replacements of the stock compensation awards previously issued.  As such, the $12 million fair value of the awards, consisting of the after-tax value of the cash incentives, was amortized over the period from the Petition Date to the Emergence Date.  Amortization of the fair value of these cash incentives totaled $7 million during the three and six months ended June 30, 2020 and is included in general and administrative expenses in the Predecessor’s condensed consolidated statements of operations.  The difference between the cash and after-tax value of the cash retention incentives of approximately $9 million, which was not subject to the claw back provisions contained within the agreements, was expensed to general and administrative expenses in the Predecessor’s condensed consolidated statements of operations during the first quarter of 2020.

13.        INCOME TAXES

Income tax expense during interim periods is based on applying an estimated annual effective income tax rate to year-to-date income, plus any significant unusual or infrequently occurring items which are recorded in the interim period.  The provisions for income taxes for the three and six months ended June 30, 2021 (Successor) and June 30, 2020 (Predecessor) differ from the amounts that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax income primarily due to a full valuation allowance in effect on the Company’s U.S. deferred tax assets (“DTAs”), resulting in 0 U.S. income tax expense recognized for the periods presented, outside of a $1 million alternative minimum tax refund received during the first quarter of 2020, and an effective U.S. tax rate of 0%.  Additionally, during the second quarter of 2020, $4 million of Canadian deferred tax expense became current.

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

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

Internal Revenue Code (“IRC”) Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change.  As a result of the chapter 11 reorganization and related transactions, the Successor experienced an ownership change within the meaning of IRC Section 382 on the Emergence Date.  This ownership change subjected certain of the Company’s tax attributes to an IRC Section 382 limitation.  The ownership changes and resulting annual limitation will result in the expiration of net operating loss carryforwards (“NOLs”) or other tax attributes otherwise available, with a corresponding decrease in the Company’s valuation allowance.  

The Company estimates that it has federal NOLs of $3.1 billion as of December 31, 2020, which are subject to limitation under IRC Section 382.  The Company currently estimates that approximately $2.3 billion of these federal NOLs will expire before they are able to be used.  The remaining non-expiring NOLs remain subject to a full valuation allowance.  These estimates are subject to revision through the filing of the tax return for the year ending December 31, 2020.

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14.       EARNINGS PER SHARE

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

Successor

Predecessor

Three Months Ended June 30, 2021

Three Months Ended June 30, 2020

Basic and diluted loss per share

Net loss

$

(61,489)

$

(574,315)

Weighted average shares outstanding, basic and diluted

39,067

91,429

Loss per common share, basic and diluted

$

(1.57)

$

(6.28)

Successor

Predecessor

Six Months Ended June 30, 2021

Six Months Ended June 30, 2020

Basic and diluted loss per share

Net loss

$

(62,435)

$

(4,202,886)

Weighted average shares outstanding, basic and diluted

38,883

91,409

Loss per common share, basic and diluted

$

(1.61)

$

(45.98)

Successor

During the Successor Period, the diluted earnings per share calculations exclude the effect of 4,837,376 common shares for Series A Warrants and 2,418,832 common shares for Series B Warrants that were out-of-the-money as of June 30, 2021, as well as 2,121,304 contingently issuable shares related to the settlement of general unsecured claims associated with the Chapter 11 Cases, as all necessary conditions had not been met to be considered dilutive shares as of June 30, 2021.  Further, during the three and six months ended June 30, 2021, the Company had net losses and therefore the diluted earnings per share calculations for those periods exclude the anti-dilutive effect of (i) 345,272 shares of service-based awards and 195,854 shares of market-based awards for the three months ended June 30, 2021 and (ii) 314,524 shares of service-based awards and 202,643 shares of market-based awards for the six months ended June 30, 2021.  Finally, the diluted earnings per share calculations for the three and six months ended June 30, 2021 also exclude 94,950 shares of market-based awards that did not meet the market-based vesting criteria as of June 30, 2021.

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

Predecessor

During the three and six months ended June 30, 2020, the Company had net losses and therefore the diluted earnings per share calculations for those periods exclude the anti-dilutive effect of 270,058 and 342,299 shares, respectively, of service-based awards.  In addition, the diluted earnings per share calculations for the three and six months ended June 30, 2020 exclude the effect of 28,505 and 31,805 common shares, respectively, for stock options that were out-of-the-money as of June 30, 2020.

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

15.       COMMITMENTS AND CONTINGENCIES

Chapter 11 CasesOn April 1, 2020, the Debtors filed the Chapter 11 Cases seeking relief under the Bankruptcy Code.  The filing of the Chapter 11 Cases allowed the Company to, upon approval of the Bankruptcy Court, assume, assign or reject certain contractual commitments, including certain executory contracts.  Refer to the “Chapter 11 Emergence” footnote for more information.  Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such contract and, subject to certain exceptions, relieves the Company from performing future obligations under such contract but entitles the counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach.  The claims resolution process is ongoing and certain of

27

these claims remain subject to the jurisdiction of the Bankruptcy Court.  To the extent that these Bankruptcy Court proceedings result in unsecured claims being allowed against the Company, such claims will be satisfied through the issuance of shares of the Successor’s common stock.  As a result, the Company has not established material liabilities in connection with these claims.  

However, it is reasonably possible that as a result of the legal proceedings associated with the bankruptcy claims administration process or the matter detailed below, the Bankruptcy Court may rule, or it may be determined, that (i) the applicable contracts cannot be rejected, or (ii) a claim is not a general unsecured claim.  Any of these outcomes could require the Company to make cash payments to settle those claims instead of or in addition to issuing shares of the Successor’s common stock, and such cash payments would result in losses in future periods.

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

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

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

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16.       SUBSEQUENT EVENTS

Williston Basin AcquisitionOn July 19, 2021, the Company entered into a purchase and sale agreement to acquire interests in approximately 8,750 net acres in the Williston Basin, including interests in 76 gross (50.2 net) producing wells, 5 gross (2.3 net) drilled and uncompleted oil and gas wells and undeveloped acreage located in Mountrail County, North Dakota for an aggregate purchase price of $271 million (before closing adjustments).  Upon executing the agreement, the company tendered a $23 million deposit which will be held in escrow until closing of the transaction.  The transaction is anticipated to close in September 2021 and the Company plans to account for the transaction using the acquisition method of accounting.

Denver-Julesburg Basin DivestitureOn July 21, 2021, the Company entered into a purchase and sale agreement for the divestiture of all of its interests in producing assets and undeveloped acreage, including the associated midstream assets, of its Redtail field located in the Denver-Julesburg Basin of Weld County, Colorado for aggregate sales proceeds of $187 million (before closing adjustments).  Additionally during July 2021, the Company executed derivative contracts that will be novated to the purchaser upon closing of the transaction.  As of July 28, 2021, these derivative contracts covered the sale of 321,000 Bbl and 844,500 Bbl of oil and 870,000 MMBtu and 3,125,000 MMBtu of natural gas for the remainder of 2021 and the full year 2022, respectively.  The transaction is anticipated to close in September 2021.  

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

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

Overview

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

Our revenue, profitability, future growth rate and cash flows depend on many factors which are beyond our control, such as oil and gas prices; economic, political and regulatory developments; the financial condition of our industry partners; competition from other sources of energy; and the other items discussed under the caption “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the period ended December 31, 2020.  Oil and gas prices historically have been volatile and may fluctuate widely in the future.  The following table highlights the quarterly average NYMEX price trends for crude oil and natural gas prices since the first quarter of 2019:

2019

2020

2021

Q1

Q2

Q3

Q4

Q1

Q2

Q3

Q4

Q1

Q2

Crude oil

$

54.90

$

59.83

$

56.45

$

56.96

$

46.08

$

27.85

$

40.94

$

42.67

$

57.80

$

66.06

Natural gas

$

3.00

$

2.58

$

2.29

$

2.44

$

1.88

$

1.66

$

1.89

$

2.51

$

2.56

$

2.74

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

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Recent Developments

Williston Basin Acquisition.  On July 19, 2021, we entered into a purchase and sale agreement for the acquisition of approximately 8,750 net acres and 4,200 BOE per day (80% oil) of net daily production in the Williston Basin, including interests in 76 gross (50.2 net) producing wells, 5 gross (2.3 net) drilled and uncompleted oil and gas wells and undeveloped acreage located in Mountrail County, North Dakota for an aggregate purchase price of $271 million (before closing adjustments).  We expect this transaction to close in September 2021.  We intend to finance this acquisition with proceeds from the Denver-Julesburg Basin divestiture discussed below and borrowings under our Credit Agreement.

Denver-Julesburg Basin Divestiture.  On July 21, 2021, we entered into a purchase and sale agreement to divest all of our interests in producing assets with net daily production of approximately 7,100 BOE per day (51% oil) and undeveloped acreage, including the associated midstream assets, of our Redtail field located in the Denver-Julesburg Basin of Weld County, Colorado for aggregate sales proceeds of $187 million (before closing adjustments).  We expect this transaction to close in September 2021.  These properties represent 4% of our estimated proved reserves as of June 30, 2021.  We intend to use the sales proceeds from this divestiture to fund the Williston Basin acquisition discussed above.

Chapter 11 Emergence and Fresh Start Accounting.  On April 1, 2020 (the “Petition Date”), Whiting and certain of its subsidiaries (the “Debtors”) commenced voluntary cases (the “Chapter 11 Cases”) under chapter 11 of the Bankruptcy Code.  On June 30, 2020, the Debtors filed the Joint Chapter 11 Plan of Reorganization of Whiting Petroleum Corporation and its Debtor affiliates (as amended, modified and supplemented, the “Plan”).  On August 14, 2020, the Bankruptcy Court confirmed the Plan.  On September 1, 2020, (the “Emergence Date”) the Debtors satisfied all conditions required for Plan effectiveness and emerged from the Chapter 11 Cases.  Beginning on the Emergence Date, we applied fresh start accounting, which resulted in a new basis of accounting and we became a new entity for financial reporting purposes.  As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the consolidated financial statements after September 1, 2020 are not comparable with the consolidated financial statements on or prior to that date and the historical financial statements on or before the Emergence Date are not a reliable indicator of our financial condition and results of operations for any period after the adoption of fresh start accounting.  References to “Successor” refer to Whiting and its financial position and results of operations after the Emergence Date.  References to “Predecessor” refer to Whiting and its financial position and results of operations on or before the Emergence Date.  References to “Successor YTD Period” relate to the six months ended June 30, 2021.  References to “Predecessor YTD Period” relate to the six months ended June 30, 2020.  

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

2021 Highlights and Future Considerations

Operational Highlights

North Dakota & Montana – Williston Basin

Our properties in the Williston Basin of North Dakota and Montana target the Bakken and Three Forks formations.  Net production from North Dakota and Montana averaged 85.2 MBOE/d for the second quarter of 2021, which represents a 4% increase from the first quarter of 2021 and is in line with our production exit rate for the fourth quarter of 2020.  Across our acreage in the Williston Basin, we have implemented custom, right-sized completion designs to increase well performance while reducing cost.  We continue to focus on reducing time-on-location and total well cost while maximizing our lateral footage through drilling best practices including utilizing top tier drilling rigs, advanced downhole motor and drill bit technology and our custom drilling fluid system.  

During portions of the second quarter of 2021, we had one active completion crew in this area, and we plan to continue with this crew intermittently for the remainder of 2021.  In addition, we resumed drilling in the Williston Basin in February with one rig, and we plan to add a second rig in September 2021.  During the second quarter of 2021, we drilled 9 gross (5.6 net) wells and TIL 9 gross (5.4 net) wells in this area, and as of June 30, 2021, we have 21 gross (15.3 net) drilled uncompleted wells.  Under our current 2021 capital program, we expect to TIL approximately 55 gross (35.4 net) wells in this area during the year.

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On July 19, 2021, we entered into a purchase and sale agreement to acquire additional oil and gas properties in the Williston Basin for an aggregate purchase price of $271 million (before closing adjustments).  Refer to “Recent Developments” above for additional details.

Colorado – Denver-Julesburg Basin

Our properties in the Denver-Julesburg Basin in Weld County, Colorado produce from the Niobrara “A,” “B” and “C” zones and the Codell/Fort Hays formations.  Net production from Colorado averaged 7.1 MBOE/d for the second quarter of 2021, representing a 5% decrease from the first quarter of 2021.  As detailed in “Recent Developments” above, on July 21, 2021, we entered into a purchase and sale agreement to divest all properties associated with our Redtail field, including the associated midstream assets, and we expect this transaction to close in September 2021.

Financing Highlights

On the Emergence Date, in connection with our emergence from the Chapter 11 Cases, we repaid all outstanding borrowings and accrued interest on the Predecessor’s credit agreement (the “Predecessor Credit Agreement”) and entered into a reserves-based credit agreement with a syndicate of banks (the “Credit Agreement”).  In April 2021, the borrowing base and aggregate commitments under the Credit Agreement of $750 million were reaffirmed in connection with our semi-annual borrowing base redetermination.  Refer to the “Long-Term Debt” footnote in the notes to the condensed consolidated financial statements for more information.

Dakota Access Pipeline

On March 25, 2020, the U.S. District Court for D.C. (“D.C. District Court”) found that the U.S. Army Corps of Engineers (“Army Corps”) had violated the National Environmental Policy Act when it granted an easement relating to a portion of the Dakota Access Pipeline (“DAPL”) because it had failed to prepare an environmental impact statement (“EIS”).  As a result, in an order issued July 6, 2020, the D.C. District Court vacated the easement and directed that the DAPL be shut down and emptied of oil by August 5, 2020.  After issuing a stay of the order to shut down the pipeline on August 5, 2020, the U.S. Court of Appeals for the D.C. Circuit (“D.C. Appellate Court”), on January 26, 2021, affirmed the D.C. District Court’s decision to vacate the easement and concluded that the D.C. District Court must further consider whether shut down of the DAPL is an appropriate remedy while the Army Corps develops an EIS.  On May 21, 2021, the D.C. District Court ruled that it would not issue an injunction requiring a shutdown of the DAPL and that the DAPL could continue to operate while the Army Corps prepares an EIS.  The D.C. District Court further ruled on June 22, 2021 that the litigation be dismissed and that the plaintiffs could renew their challenge to DAPL upon the Army Corps’ issuance of an EIS.  Barring an appeal by plaintiffs or different discretionary action by the Army Corps, these rulings allow the DAPL’s continued operation unless and until new challenges are made and succeed following issuance of the EIS, which the Army Corps anticipates issuing in the spring of 2022.  The potential disruption of transportation as a result of the DAPL being shut down or the anticipation of the DAPL being shut down could negatively impact our ability to achieve the most favorable prices for our crude oil production, which could have an adverse effect on our business, financial condition, results of operations or cash flows.  To help mitigate the potential impact of an unfavorable outcome, we have coordinated with our midstream partners and downstream markets to source transportation alternatives.

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Results of Operations

Successor YTD Period Compared to Predecessor YTD Period

Successor

Predecessor

   

Six Months Ended June 30, 2021

  

  

Six Months Ended June 30, 2020

Net production

Oil (MMBbl)

9.7

11.8

NGLs (MMBbl)

3.4

3.4

Natural gas (Bcf)

20.9

22.6

Total production (MMBOE)

16.5

19.0

Net sales (in millions) (1)

Oil

$

565.1

$

323.8

NGLs

55.3

11.3

Natural gas

34.3

1.3

Total oil, NGL and natural gas sales

$

654.7

$

336.4

Average sales prices

Oil (per Bbl) (1)

$

58.37

$

27.42

Effect of oil hedges on average price (per Bbl)

(10.91)

3.91

Oil after the effect of hedging (per Bbl)

$

47.46

$

31.33

Weighted average NYMEX price (per Bbl) (2)

$

61.95

$

37.25

NGLs (per Bbl) (1)

$

16.47

$

3.27

Effect of NGL hedges on average price (per Bbl)

(0.26)

-

NGLs after the effect of hedging (per Bbl)

$

16.21

$

3.27

Natural gas (per Mcf) (1)

$

1.64

$

0.06

Effect of natural gas hedges on average price (per Mcf)

(0.02)

-

Natural gas after the effect of hedging (per Mcf)

$

1.62

$

0.06

Weighted average NYMEX price (per MMBtu) (2)

$

2.65

$

1.77

Costs and expenses (per BOE)

Lease operating expenses

$

7.48

$

6.61

Transportation, gathering, compression and other

$

0.88

$

0.95

Production and ad valorem taxes

$

3.02

$

1.62

Depreciation, depletion and amortization

$

6.38

$

14.07

General and administrative

$

1.35

$

3.96

(1)Before consideration of hedging transactions.
(2)Average NYMEX pricing weighted for monthly production volumes.

Oil, NGL and Natural Gas Sales.  Our oil, NGL and natural gas sales revenue increased $318 million to $655 million when comparing the Successor YTD Period to the Predecessor YTD Period.  Changes in sales revenue between periods are due to changes in production sold and changes in average commodity prices realized (excluding the impacts of hedging).  When comparing the Successor YTD Period to the Predecessor YTD Period, increases in commodity prices realized between periods accounted for a $377 million increase in revenue, which was partially offset by a decrease in total production between periods that accounted for a $59 million decrease in revenue.

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Our oil, NGL and gas volumes decreased 18%, 3% and 7%, respectively, between periods.  The volume decreases between periods were primarily driven by normal field production decline as a result of operational decisions to curtail production, reduce drilling and workover activity, defer completions of certain wells and delay placing some of our completed wells online during the majority of 2020 as a result of sustained lower prices and our bankruptcy filing.  This decline was partially offset by production from new wells drilled and completed during the first half of 2021 in the Williston Basin.  

Our average price for oil, NGLs and natural gas (before the effects of hedging) increased 113%, 404% and 2,633%, respectively, between periods.  Our average realized price for oil, NGLs and natural gas primarily increased as a result of favorable movements in the NYMEX and Mont Belvieu market indices between periods.  During the first half of 2020, our average realized price for oil was impacted by deficiency payments we made under a physical delivery contract in Colorado due to our inability to meet the minimum volume commitments under this contract.  This contract was terminated in April 2020 and did not continue to negatively impact the price we receive for oil from our Redtail field after that time.  During the Predecessor YTD Period, our total average sales price was $2.05 per Bbl lower as a result of these deficiency payments.  Additionally, our oil average realized price differentials to NYMEX improved between periods as a result of decreased basin-wide utilization of pipeline capacity and lower firm transportation costs, and our natural gas average realized price differentials to NYMEX also improved significantly as a result of stronger regional pricing in the Williston Basin during the Successor YTD Period.

Lease Operating Expenses.  Our lease operating expenses (“LOE”) during the Successor YTD Period were $124 million, a $2 million decrease over the Predecessor YTD Period.  This decrease was primarily due to an $11 million decrease in saltwater disposal costs as well as other ongoing cost reduction initiatives which contributed to an additional $3 million decrease in LOE between periods, partially offset by an $8 million increase in well workover costs associated with increased activity during the Successor YTD Period.

Our lease operating expenses on a BOE basis increased when comparing the Successor YTD Period to the Predecessor YTD Period.  LOE per BOE amounted to $7.48 during the Successor YTD Period, which represents an increase of $0.87 per BOE (or 13%) from the Predecessor YTD Period.  This increase was mainly due to lower overall production volumes between periods, partially offset by the overall decrease in LOE discussed above.

Transportation, Gathering, Compression and Other.  Our transportation, gathering, compression and other (“TGC”) expenses during the Successor YTD Period were $14 million, a $4 million decrease over the Predecessor YTD Period.  This decrease mainly relates to lower production volumes between periods and decreased rates negotiated with midstream partners as a result of the Chapter 11 Cases.  

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

Production and Ad Valorem Taxes.  Our production and ad valorem taxes during the Successor YTD Period were $50 million, a $19 million increase over the Predecessor YTD Period, which was primarily due to higher sales revenue between periods.  Our production taxes, however, are generally calculated as a percentage of net oil, NGL and natural gas sales revenue before the effects of hedging, and this percentage on a company-wide basis was 7.2% and 8.7% for the Successor YTD Period and the Predecessor YTD Period, respectively.  Our production tax rate for the Successor YTD Period was lower than the rate for the Predecessor YTD Period as certain production taxes levied on natural gas are volume-based and did not increase with the increase in realized prices.  Additionally, we recognized Colorado severance tax refunds during the Successor YTD period.

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

Successor

Predecessor

    

Six Months Ended June 30, 2021

  

Six Months Ended June 30, 2020

Depletion

$

98,232

$

258,894

Accretion of asset retirement obligations

4,412

6,107

Depreciation

2,703

2,516

Total

$

105,347

$

267,517

DD&A decreased between the Successor YTD Period and the Predecessor YTD Period primarily due to $161 million in lower depletion expense, consisting of a $146 million decrease related to a lower depletion rate between periods and a $15 million decrease related to lower overall production volumes during the Successor YTD Period.  On a BOE basis, our overall DD&A rate of $6.38 per BOE for the Successor YTD Period was 55% lower than the rate of $14.07 per BOE for the Predecessor YTD Period.  The primary factors contributing to this lower DD&A rate were impairment write-downs on proved oil and gas properties in the Williston Basin recognized in the first and second quarters of 2020 and the application of fresh start accounting upon emergence from the Chapter 11 Cases, under which we adjusted the value of our oil and gas properties down to their fair values on the Emergence Date.  Refer to the “Fresh Start Accounting” footnote in the notes to the consolidated financial statements in Item 8 of our Annual Report on Form 10-K for the period ending December 31, 2020 for more information.  Also contributing to the lower DD&A rate in the Successor YTD Period were upward reserve revisions to proved reserves, which were largely driven by higher commodity prices during the first half of 2021.

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

Successor

Predecessor

    

Six Months Ended June 30, 2021

  

Six Months Ended June 30, 2020

Impairment

$

2,691

$

4,154,369

Exploration

1,978

20,244

Total

$

4,669

$

4,174,613

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

Exploration costs decreased $18 million during the Successor YTD Period compared to the Predecessor YTD Period primarily due to (i) $12 million of lower deficiency fees paid under our produced water disposal agreement at our Redtail field, which contract was rejected through the Chapter 11 Cases and (ii) $5 million of lower geology-related general and administrative expenses due to a company restructuring in September 2020.

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

Successor

Predecessor

    

Six Months Ended June 30, 2021

  

  

Six Months Ended June 30, 2020

General and administrative expenses, other (1)

$

54,098

$

108,371

Stock-based compensation, non-cash

4,764

3,401

Reimbursements and allocations

(36,576)

(36,469)

General and administrative expenses, net (GAAP)

22,286

75,303

Less: Significant cost drivers (2)

-

(26,884)

Non-GAAP general and administrative expenses less significant cost drivers (3)

$

22,286

$

48,419

(1)General and administrative expenses, other excludes non-cash stock-based compensation expense and reimbursements and allocations.  We believe general and administrative expenses, other provides useful information to compare our expenses between periods without the impact of the aforementioned items.
(2)Includes cash retention incentives for Predecessor executives and directors, third-party advisory and legal fees related to the Chapter 11 Cases and charges related to a litigation settlement discussed below.
(3)We believe non-GAAP general and administrative expenses less significant cost drivers is a useful measure for investors to understand our general and administrative expenses incurred on a recurring basis.  We further believe investors may utilize this non-GAAP measure to estimate future general and administrative expenses.  However, this non-GAAP measure is not a substitute for general and administrative expenses, net (GAAP), and there can be no assurance that any of the significant cost drivers excluded from such metric will not be incurred again in the future.

G&A expenses, other during the Successor YTD Period decreased $54 million compared to the Predecessor YTD Period primarily due to $27 million of significant cost drivers incurred during the Predecessor YTD Period, including (i) $16 million in cash retention incentives paid to executives and directors, (ii) $8 million of third party advisory and legal fees incurred to prepare for the Chapter 11 Cases and (iii) $3 million of additional costs related to a legal settlement.  In addition, compensation costs decreased by $18 million as a result of a company restructuring completed in the third quarter of 2020.

G&A expense per BOE amounted to $1.35 during the Successor YTD Period, which represents a decrease of $2.61 per BOE (or 66%) from the Predecessor YTD Period.  This decrease was mainly due to the overall decrease in G&A discussed above partially offset by lower overall production volumes between periods.  G&A expense per BOE excluding significant cost drivers was $2.55 per BOE during the Predecessor YTD Period.

Derivative (Gain) Loss, Net.  Our commodity derivative contracts are marked to market each quarter with fair value gains and losses recognized immediately in earnings as derivative (gain) loss, net.  Cash flow, however, is only impacted to the extent that settlements under these contracts result in us making or receiving a payment to or from the counterparty.  Derivative (gain) loss, net, amounted to a loss of $402 million and a gain of $225 million for the Successor YTD Period and the Predecessor YTD Period, respectively.  These gains and losses relate to our collar, swap, basis swap and differential swap commodity derivative contracts and resulted from the upward and downward shifts, respectively, in the futures curve of forecasted commodity prices for crude oil, natural gas and NGLs during those periods.

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

Gain on Sale of Properties.  During the Successor YTD period, a series of non-core producing oil and gas properties were divested for aggregate sales proceeds of $6.4 million (before closing adjustments).  As a result of one of these divestitures, our asset retirement obligation liability decreased by $10 million and we recognized a corresponding gain on sale of $10 million.

36

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

Successor

Predecessor

    

Six Months Ended June 30, 2021

  

Six Months Ended June 30, 2020

Credit agreements

$

6,911

$

16,496

Amortization of debt issue costs, discounts and premiums

1,773

9,786

Other

400

553

Notes

-

34,840

Total

$

9,084

$

61,675

The decrease in interest expense of $53 million during the Successor YTD Period compared to the Predecessor YTD Period was primarily attributable to lower interest costs incurred on our notes and our credit agreements and lower amortization of debt issue costs, discounts and premiums.  Upon the filing of the Chapter 11 Cases on April 1, 2020, we discontinued accruing interest on our notes, which resulted in a $35 million decrease in note interest expense between periods.  In addition, the remaining unamortized debt issuance costs and premiums associated with these notes were written off on the Petition Date, resulting in an $8 million decrease in amortization expense between periods.  Upon emergence from the Chapter 11 Cases, all outstanding obligations under our notes were cancelled in exchange for shares of Successor common stock.  Refer to the “Chapter 11 Emergence” and “Long-Term Debt” footnotes in the notes to the condensed consolidated financial statements for more information.

The decrease in interest expense incurred on our credit agreements of $10 million resulted from lower borrowings outstanding between periods.  Our weighted average borrowings outstanding under the Credit Agreement during the Successor YTD Period were $268 million compared to $710 million weighted average borrowings outstanding under the Predecessor Credit Agreement during the Predecessor YTD Period.

Our weighted average debt outstanding during the Successor YTD Period, consisting solely of borrowings under the Credit Agreement, was $268 million, with a weighted average cash interest rate of 5.2%.  Our weighted average debt outstanding during the Predecessor YTD Period, consisting of the notes and borrowings outstanding on the Predecessor Credit Agreement, was $3.1 billion, with a weighted average cash interest rate of 3.3%.  

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

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

Income Tax Expense (Benefit).  As a result of the full valuation allowance on our U.S. deferred tax assets (“DTAs”) as of June 30, 2021 (Successor) and June 30, 2020 (Predecessor), we did not recognize any U.S. income tax expense or benefit during the periods presented, outside of a $1 million alternative minimum tax refund received during the Predecessor YTD period.  This resulted in overall U.S. effective tax rates of 0% for both periods.  During the Predecessor YTD Period, we reclassified $4 million of Canadian deferred tax expense to current.  

37

Three Months Ended June 30, 2021 Compared to Three Months Ended March 31, 2021

Successor

Three Months Ended

June 30,

March 31,

    

2021

    

2021

Net production

Oil (MMBbl)

4.9

4.8

NGLs (MMBbl)

1.8

1.6

Natural gas (Bcf)

10.7

10.2

Total production (MMBOE)

8.4

8.1

Net sales (in millions) (1)

Oil

$

308.4

$

256.7

NGLs

28.3

27.0

Natural gas

13.3

21.0

Total oil, NGL and natural gas sales

$

350.0

$

304.7

Average sales prices

Oil (per Bbl) (1)

$

63.46

$

53.24

Effect of oil hedges on average price (per Bbl)

(13.64)

(8.16)

Oil after the effect of hedging (per Bbl)

$

49.82

$

45.08

Weighted average NYMEX price (per Bbl) (2)

$

66.03

$

57.83

NGLs (per Bbl) (1)

$

15.76

$

17.28

Effect of NGL hedges on average price (per Bbl)

(0.47)

-

NGLs after the effect of hedging (per Bbl)

$

15.29

$

17.28

Natural gas (per Mcf) (1)

$

1.25

$

2.05

Effect of natural gas hedges on average price (per Mcf)

(0.04)

0.01

Natural gas after the effects of hedging (per Mcf)

$

1.21

$

2.06

Weighted average NYMEX price (per MMBtu) (2)

$

2.74

$

2.56

Costs and expenses (per BOE)

Lease operating expenses

$

7.61

$

7.34

Transportation, gathering, compression and other

$

0.88

$

0.87

Production and ad valorem taxes

$

3.04

$

2.99

Depreciation, depletion and amortization

$

6.12

$

6.64

General and administrative

$

1.42

$

1.27

(1)Before consideration of hedging transactions.
(2)Average NYMEX pricing weighted for monthly production volumes.

38

Oil, NGL and Natural Gas Sales.  Our oil, NGL and natural gas sales revenue increased $45 million to $350 million when comparing the second quarter of 2021 to the first quarter of 2021.  Changes in sales revenue between periods are due to changes in production sold and changes in average commodity prices realized (excluding the impacts of hedging).  When comparing the second quarter of 2021 to the first quarter of 2021, increases in commodity prices realized between periods accounted for a $38 million increase in revenue and increases in total production between periods accounted for a $7 million increase in revenue.

Our oil, NGL and gas volumes increased 1%, 15% and 4%, respectively, between periods.  The overall volume increase between periods was primarily driven by production from new wells drilled and completed during the first half of 2021 in the Williston Basin and increased workover activity, partially offset by normal field production decline.

Our average price for oil (before the effects of hedging) increased 19% between periods, and our average price for natural gas and NGLs decreased 39% and 9%, respectively.  Our average sales price realized for oil primarily increased as a result of favorable movements in the NYMEX market index between periods.  Our average sales price realized for natural gas decreased as a result of unusually strong regional pricing in the Williston Basin during the first quarter of 2021 that was not repeated in the second quarter of 2021.  

Lease Operating Expenses.  Our LOE during the second quarter of 2021 were $64 million, a $5 million increase over the first quarter of 2021.  This increase between periods was primarily due to an increase in well workover costs and certain variable expenses associated with increased activity and production during the second quarter of 2021.

Our lease operating expenses on a BOE basis also increased when comparing the second quarter of 2021 to the first quarter of 2021.  LOE per BOE amounted to $7.61 during the second quarter of 2021, which represents an increase of $0.27 per BOE (or 4%) from the first quarter of 2021.  This increase was mainly due to the overall increase in LOE discussed above.

Transportation, Gathering, Compression and Other.  Our TGC expenses during the second quarter of 2021 were $7 million, which is consistent with TGC expenses incurred during the first quarter of 2021.

TGC per BOE increased slightly when comparing the second quarter of 2021 to the first quarter of 2021.  TGC per BOE amounted to $0.88 per BOE during the second quarter of 2021, which represents an increase of $0.01 per BOE (or 1%) from the first quarter of 2021.  

Production and Ad Valorem Taxes.  Our production and ad valorem taxes during the second quarter of 2021 totaled $26 million, a $2 million increase over the first quarter of 2021, which was primarily due to higher sales revenue between periods, partially offset by Colorado severance tax refunds recognized during the second quarter of 2021.  Our production taxes, however, are generally calculated as a percentage of net oil, NGL and natural gas sales revenue before the effects of hedging, and this percentage on a company-wide basis was 6.9% and 7.6% for the second quarter of 2021 and the first quarter of 2021, respectively.  Our production tax rate for the second quarter of 2021 was lower than the rate for the first quarter of 2021 primarily due to the Colorado severance tax refunds recognized during the period.

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

Successor

Three Months Ended

June 30,

March 31,

    

2021

    

2021

Depletion

$

48,081

$

50,150

Accretion of asset retirement obligations

2,190

2,222

Depreciation

1,347

1,357

Total

$

51,618

$

53,729

DD&A decreased between the second quarter of 2021 and the first quarter of 2021 primarily due to $2 million in lower depletion expense due to a lower depletion rate between periods.  On a BOE basis, our overall DD&A rate of $6.12 per BOE for the second quarter of 2021 was 8% lower than the rate of $6.64 per BOE for the first quarter of 2021.  The primary factor contributing to this lower DD&A rate was upward revisions to proved reserves during the second quarter of 2021, which were largely driven by higher commodity prices.

39

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

Successor

Three Months Ended

June 30,

March 31,

    

2021

    

2021

Impairment

$

1,250

$

1,441

Exploration

797

1,181

Total

$

2,047

$

2,622

Impairment expense for the first and second quarters of 2021 primarily related to the amortization of leasehold costs associated with individually insignificant unproved properties.  

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

Successor

Three Months Ended

June 30,

March 31,

    

2021

    

2021

General and administrative expenses, other (1)

$

27,197

$

26,901

Stock-based compensation, non-cash

2,455

2,309

Reimbursements and allocations

(17,657)

(18,919)

General and administrative expenses, net (GAAP)

$

11,995

$

10,291

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

G&A expenses, other were consistent between periods.  G&A expense per BOE amounted to $1.42 per BOE during the second quarter of 2021, which represents an increase of $0.15 per BOE (or 12%) from the first quarter of 2021.  This increase was mainly due to the decrease in reimbursements and allocations between periods resulting from lower employee benefit costs associated with field workers on Whiting-operated properties.

Derivative Loss, Net.  Our commodity derivative contracts are marked to market each quarter with fair value gains and losses recognized immediately in earnings as derivative (gain) loss, net.  Cash flow, however, is only impacted to the extent that settlements under these contracts result in us making or receiving a payment to or from the counterparty.  Derivative (gain) loss, net, amounted to losses of $255 million and $147 million for the three months ended June 30, 2021 and March 31, 2021, respectively.  These losses relate to our collar, swap, differential swap and basis swap commodity derivative contracts and resulted from the upward shift in the futures curve of forecasted commodity prices for crude oil, natural gas and NGLs during the respective periods.

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

(Gain) Loss on Sale of Properties.  During the second quarter of 2021, a series of non-core producing oil and gas properties were divested for aggregate sales proceeds of $6.4 million (before closing adjustments).  As a result of one of these divestitures, our asset retirement obligation liability decreased by $10 million and we recognized a corresponding gain on sale of $10 million.

40

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

Successor

Three Months Ended

June 30,

March 31,

    

2021

    

2021

Credit agreement

$

2,974

$

3,936

Amortization of debt issue costs

887

887

Other

120

280

Total

$

3,981

$

5,103

The decrease in interest expense between periods is primarily due to a decrease in interest incurred on the Credit Agreement as a result of lower average outstanding borrowings during the second quarter of 2021.  Our weighted average borrowings outstanding under the Credit Agreement during the second quarter of 2021 were $214 million, with a weighted average cash interest rate of 5.6%.  Our weighted average borrowings outstanding during the first quarter of 2021 were $324 million, with a weighted average cash interest rate of 4.9%.

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

41

Liquidity and Capital Resources

Overview.  At June 30, 2021, we had $17 million of unrestricted cash on hand, $115 million of long-term debt and $1.2 billion of shareholders’ equity, while at December 31, 2020, we had $26 million of unrestricted cash on hand, $360 million of long-term debt and $1.2 billion of equity.  We expect that our liquidity going forward will be primarily derived from cash flows from operating activities, cash on hand and availability under the Credit Agreement and that these sources of liquidity will be sufficient to provide us the ability to fund our material cash requirements, as described below, as well as our operating and development activities and planned capital programs.  We may need to fund acquisitions or pursuits of business opportunities that support our strategy through additional borrowings or the issuance of common stock or other forms of equity.

Cash Flows.  During the Successor YTD Period, we generated $336 million of cash from operating activities, an increase of $269 million from the Predecessor YTD Period.  Cash provided by operating activities increased between periods primarily due to higher realized sales prices, as well as lower cash G&A, cash interest expense and exploration expenses.  These positive factors were partially offset by an increase in cash settlements paid on our commodity derivative contracts and higher production taxes between periods.  Refer to “Results of Operations” for more information on the impact of volumes and prices on revenues and for more information on increases and decreases in certain expenses between periods.  During the Successor YTD Period, cash flows from operating activities and proceeds from the sale of properties were used for the net repayment of $245 million of outstanding borrowings under the Credit Agreement and $103 million of drilling and development expenditures.

One of the primary sources of variability in our cash flows from operating activities is commodity price volatility, which we partially mitigate through the use of commodity derivative contracts.  As of July 28, 2021, we had crude oil derivative contracts (consisting of collars, swaps and differential swaps) covering the sale of 37,000 Bbl, 28,000 Bbl and 18,000 Bbl of oil per day for the remainder of 2021, the full year 2022 and the first six months of 2023, respectively.  As of July 28, 2021, we had natural gas derivative contracts (consisting of collars, swaps and basis swaps) covering the sale of 99,000 MMBtu, 53,000 MMBtu and 54,000 MMBtu of natural gas per day through the remainder of 2021, the full year 2022 and the first six months of 2023, respectively.  As of July 28, 2021, we had NGL derivative contracts (consisting of swaps) covering the sale of 105,000 gallons and 42,000 gallons of NGLs per day for the remainder of 2021 and first quarter of 2022, respectively.  For more information on our outstanding derivatives refer to the “Derivative Financial Instruments” footnote in the notes to the condensed consolidated financial statements.

Material Cash Requirements.  Our material short-term cash requirements include payments under our short-term lease agreements, recurring payroll and benefits obligations for our employees, capital and operating expenditures and other working capital needs.  Working capital, defined as total current assets less total current liabilities, fluctuates depending on commodity pricing and effective management of payables to our vendors and receivables from our purchasers and working interest partners.  As commodity prices improve, our working capital requirements may increase as we spend additional capital, increase production and pay larger settlements on our outstanding commodity derivative contracts.  Additionally, as discussed in “Recent Developments” above, on July 19, 2021 we entered into a purchase and sale agreement that results in a material short-term cash commitment of $271 million, subject to normal closing adjustments.

Our long-term material cash requirements from currently known obligations include repayment of outstanding borrowings and interest payment obligations under our Credit Agreement, settlements on our outstanding commodity derivative contracts, future obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, operating and finance lease obligations and contracts to transport a minimum volume of crude oil and natural gas within specified time frames.  The following table summarizes our estimated material cash requirements for known obligations as of June 30, 2021.  This table does not include repayments of outstanding borrowings on our Credit Agreement, or the associated interest payments, as the timing and amount of borrowings and repayments cannot be forecasted with certainty and are based on working capital requirements, commodity prices and acquisition and divestiture activity, among other factors.  As of June 30, 2021, our outstanding borrowings under our Credit Agreement were $115 million, with a weighted average interest rate on the outstanding principal balance of 4.1%.  Refer to “Credit Agreement” below as well as the “Long-Term Debt” footnote in the notes to the condensed consolidated financial statements for more information.  This table also does not include amounts payable under obligations where we cannot forecast with certainty the amount and timing of such payments, including any amounts we may be obligated to pay under our derivative contracts, as such payments are dependent on commodity prices in effect at the time of settlement.  Refer to the “Derivative Financial Instruments” footnote in the notes to the condensed consolidated financial statements for further information on these contracts and their fair values as of June 30, 2021, which fair values represent the cash settlement amount required to terminate such instruments based on forward price curves for commodities as of that date.

42

Payments due by period

(in thousands)

Less than 1

More than 5

Material Cash Requirements

    

Total

    

year

    

1-3 years

    

3-5 years

    

years

Asset retirement obligations (1)

$

99,523

$

6,247

35,876

$

12,621

$

44,779

Operating leases (2)

22,526

3,215

6,601

4,325

8,385

Finance leases (2)

16,765

5,058

7,714

3,993

-

Pipeline transportation agreements (3)

8,523

4,693

3,830

-

-

Total

$

147,337

$

19,213

$

54,021

$

20,939

$

53,164

(1)Asset retirement obligations represent the present value of estimated amounts expected to be incurred in the future to plug and abandon oil and gas wells, remediate oil and gas properties and dismantle their related plants and facilities.
(2)We have operating and finance leases for corporate and field offices, pipeline and midstream facilities and automobiles.  The obligations reported above represent our minimum financial commitments pursuant to the terms of these contracts, however our actual expenditures under these contracts may exceed the minimum commitments presented above.  Refer to the “Leases” footnote in the notes to the consolidated financial statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2020 for more information on these leases.
(3)Our pipeline transportation agreements consist of contracts through 2024 with various third parties to facilitate the delivery of our produced oil, gas and NGLs to market.  These contracts require either fixed monthly reservation fees or commitments to deliver minimum volumes at fixed rates in exchange for dedicated pipeline capacity.  If minimum volume commitments are not met, we are required to pay any deficiencies at the prices stipulated in the contracts.  The obligations reported above represent our minimum financial commitments pursuant to the terms of these contracts, however, our actual expenditures under these contracts may exceed the minimum commitments presented above.

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

Successor

Predecessor

Six Months Ended June 30, 2021

Six Months Ended June 30, 2020

Capital expenditures, accrual basis

$

114,070

$

178,596

Decrease (increase) in accrued capital expenditures

(10,691)

45,309

Capital expenditures, cash basis

$

103,379

$

223,905

We continually evaluate our capital needs and compare them to our capital resources.  Our 2021 E&D budget is a range of $240 million to $252 million, which we expect to fund with net cash provided by operating activities and cash on hand, and represents a slight increase from the E&D expenditures incurred during 2020.  Our level of E&D expenditures is largely discretionary, although a portion of our E&D expenditures are for non-operated properties where we have limited control over the timing and amount of such expenditures, and the amount of funds we devote to any particular activity may increase or decrease depending on commodity prices, cash flows, available opportunities and development results, among other factors.  We believe that we have sufficient liquidity and capital resources to execute our development plan over the next 12 months.  With our expected cash flow streams, commodity price hedging strategies, current liquidity levels (primarily consisting of availability under the Credit Agreement) and flexibility to modify future capital expenditure programs, we expect to fund all planned capital programs, comply with our debt covenants and meet other obligations that may arise from our oil and gas operations.

43

Credit Agreement.  Whiting Petroleum Corporation, as parent guarantor, and Whiting Oil and Gas, as borrower, have a reserves-based credit facility, with a syndicate of banks that had a borrowing base and aggregate commitments of $750 million as of June 30, 2021.  As of June 30, 2021, we had $633 million of available borrowing capacity under the Credit Agreement, which was net of $115 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 our proved reserves that have been mortgaged to such lenders, and is subject to regular redeterminations on April 1 and October 1 of each year, as well as special redeterminations described in the Credit Agreement, in each case which may increase or decrease the amount of the borrowing base.  In April 2021, our borrowing base and aggregate commitments of $750 million were reaffirmed in connection with our regular borrowing base redetermination.  Asset sales that materially impact the value of our proved reserves may result in a reduction of our borrowing base.  

A portion of the borrowing base in an aggregate amount not to exceed $50 million may be used to issue letters of credit for the account of Whiting Oil and Gas or our other designated subsidiaries.  As of June 30, 2021, $48 million was available for additional letters of credit under the Credit Agreement.

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

The Credit Agreement contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, enter into hedging contracts, incur liens and engage in certain other transactions without the prior consent of our lenders.  Except for limited exceptions, the Credit Agreement also restricts our ability to make any dividend payments or distributions on our common stock prior to September 1, 2021, and thereafter only to the extent that we have distributable free cash flow and (i) have at least 20% of available borrowing capacity, (ii) have a consolidated net leverage ratio of less than or equal to 2.0 to 1.0, (iii) do not have a borrowing base deficiency and (iv) are not in default under the Credit Agreement.  These restrictions apply to all of our restricted subsidiaries and are calculated in accordance with definitions contained in the Credit Agreement.  The Credit Agreement requires us, as of the last day of any quarter, to maintain commodity hedges covering a minimum of 65% of our projected production for the succeeding twelve months, and 35% of our projected production for the next succeeding twelve months, both as reflected in our reserves report most recently provided to the lenders under the Credit Agreement.  We are also limited to hedging a maximum of 85% of our production from proved reserves.  The Credit Agreement requires us to maintain the following ratios: (i) a consolidated current assets to consolidated current liabilities ratio of not less than 1.0 to 1.0 and (ii) a total debt to last four quarters’ EBITDAX ratio of not greater than 3.5 to 1.0.  

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

44

Critical Accounting Policies and Estimates

Information regarding critical accounting policies and estimates is contained in Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2020.  No material updates were made to such critical accounting policies and estimates during the six months ended June 30, 2021.

Forward-Looking Statements

This report contains statements that we believe to be “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.  All statements other than historical facts, including, without limitation, statements regarding our future financial position, business strategy, cash flows, acquisitions and divestitures, returns, costs and capital expenditures, and plans and objectives of management for future operations, are forward-looking statements.  When used in this report, words such as 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: risks associated with our emergence from bankruptcy; declines in, or extended periods of low oil, NGL or natural gas prices; the occurrence of epidemic or pandemic diseases, including the coronavirus pandemic; actions of the Organization of Petroleum Exporting Countries and other oil exporting nations to set and maintain production levels; the potential shutdown of the Dakota Access Pipeline; our level of success in development and production activities; impacts resulting from the allocation of resources among our strategic opportunities; our ability to replace our oil and natural gas reserves; the geographic concentration of our operations; our inability to access oil and gas markets due to market conditions or operational impediments; market availability of, and risks associated with, transport of oil and gas; weakened differentials impacting the price we receive for oil and natural gas; our ability to successfully complete asset acquisitions and dispositions and the risks related thereto; the impacts of hedging on our results of operations; shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs and completion services; the timing of our development expenditures; properties that we acquire may not produce as projected and may have unidentified liabilities; adverse weather conditions that may negatively impact development or production activities; we may incur substantial losses and be subject to liability claims as a result of our oil and gas operations, including uninsured or underinsured losses resulting from our oil and gas operations; lack of control over non-operated properties; unforeseen underperformance of or liabilities associated with acquired properties or other strategic partnerships or investments; competition in the oil and gas industry; cybersecurity attacks or failures of our telecommunication and other information technology infrastructure; our ability to comply with debt covenants, periodic redeterminations of the borrowing base under our Credit Agreement and our ability to generate sufficient cash flows from operations to service our indebtedness; our ability to generate sufficient cash flows from operations to meet the internally funded portion of our capital expenditures budget; revisions to reserve estimates as a result of changes in commodity prices, regulation and other factors; inaccuracies of our reserve estimates or our assumptions underlying them; our ability to use net operating loss carryforwards in future periods; impacts to financial statements as a result of impairment write-downs and other cash and noncash charges; the impact of negative shifts in investor sentiment towards the oil and gas industry; federal and state initiatives relating to the regulation of hydraulic fracturing and air emissions; the Biden administration could enact regulations that impose more onerous permitting and other costly environmental, health and safety requirements; the impact and costs of compliance with laws and regulations governing our oil and gas operations; the potential impact of changes in laws that could have a negative effect on the oil and gas industry; impacts of local regulations, climate change issues, negative perception of our industry and corporate governance standards; negative impacts from litigation and legal proceedings; and other risks described under the caption “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the period ended December 31, 2020.  We assume no obligation, and disclaim any duty, to update the forward-looking statements in this Quarterly Report on Form 10-Q.

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Item 3.    Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

The price we receive for our oil, NGL and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth.  Crude oil, NGL and natural gas are commodities, and therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand.  Historically, the markets for oil, NGLs and natural gas have been volatile, and these markets will likely continue to be volatile in the future.  

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

Crude Oil, Natural Gas and NGL Collars, Swaps and Basis and Differential Swaps.  Our hedging portfolio currently consists of crude oil, natural gas and NGL collars and swaps, as well as crude oil differential swaps and natural gas basis swaps.  Refer to the “Derivative Financial Instruments” footnote in the notes to the condensed consolidated financial statements for a description and list of our outstanding derivative contracts at June 30, 2021.

Our collar contracts have the effect of providing a protective floor, while allowing us to share in upward pricing movements up to the ceiling price.  Our fixed-price swap contracts entitle us to receive settlement from the counterparty in amounts, if any, by which the settlement price for the applicable calculation period is less than the fixed price, or to pay the counterparty if the settlement price for the applicable calculation period is more than the fixed price.  Our basis and differential swap contracts guarantee us a fixed price differential to NYMEX and the referenced index price, with settlement terms based on the difference between the floating market price differential and the fixed price differential.

The fair value of our oil derivative positions at June 30, 2021 was a net liability of $325 million.  A hypothetical upward or downward shift of 10% per Bbl in the NYMEX forward curve for crude oil as of June 30, 2021 would cause an increase of $123 million or a decrease of $115 million, respectively, in this fair value liability.  The fair value of our natural gas derivative positions was a net liability of $23 million.  A hypothetical upward or downward shift of 10% per MMBtu in the NYMEX forward curve for natural gas as of June 30, 2021 would cause an increase of $8 million or a decrease of $12 million, respectively, in this fair value liability.  The fair value of our NGL contracts was a net liability of $7 million.  A hypothetical upward or downward shift of 10% per Bbl in the Mont Belvieu forward curve for propane as of June 30, 2021 would cause an increase or decrease, respectively, of $2 million in this fair value liability.

While these collars, fixed-price swaps, basis swaps and differential swaps are designed to decrease our exposure to downward price movements, they also have the effect of limiting the benefit of (i) price increases above the ceiling with respect to the collars, (ii) upward price movements generally with respect to the fixed-price swaps and (iii) decreasing floating market differentials relative to NYMEX with respect to the basis swaps and differential swaps.  

Interest Rate Risk

Market risk is estimated as the change in fair value resulting from a hypothetical 100 basis point change in the interest rate on the outstanding balance under the Credit Agreement.  The Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance for a period up to one month.  To the extent that the interest rate is fixed, interest rate changes affect the instrument’s fair market value but do not impact results of operations or cash flows.  Conversely, for the portion of the Credit Agreement that has a floating interest rate, interest rate changes will not affect the fair market value but will impact future results of operations and cash flows.  At June 30, 2021, our outstanding principal balance under the Credit Agreement was $115 million, and the weighted average interest rate on the outstanding principal balance was 4.1%.  At June 30, 2021, the carrying amount approximated fair market value.  Assuming a constant debt level of $115 million, the cash flow impact resulting from a 100 basis point change in interest rates during periods when the interest rate is not fixed would be $1 million over a 12-month time period.  

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Item 4.    Controls and Procedures

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

Changes in internal control over financial reporting.  There was no change in our internal control over financial reporting that occurred during the quarter ended June 30, 2021 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1.    Legal Proceedings

The information contained in the “Commitments and Contingencies” footnote in the notes to the condensed consolidated financial statements under the headings “Chapter 11 Cases” and “Litigation” are incorporated herein by reference.

Item 1A.  Risk Factors

Risk factors relating to us are contained in Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2020.  No material change to such risk factors has occurred during the six months ended June 30, 2021.

Item 6.    Exhibits

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

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EXHIBIT INDEX

Exhibit
Number

Exhibit Description

(2)

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

(3.1)

Amended and Restated Certificate of Incorporation of Whiting Petroleum Corporation [Incorporated by reference to Exhibit 3.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on September 1, 2020 (File No. 001-31899)].

(3.2)

Second Amended and Restated By-laws of Whiting Petroleum Corporation [Incorporated by reference to Exhibit 3.2 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on September 1, 2020 (File No. 001-31899)].

(10.1)

First Amendment to Credit Agreement, dated as of June 7, 2021, among Whiting Oil and Gas Corporation as Borrower, its Parent Guarantor Whiting Petroleum Corporation, JPMorgan Chase Bank, N.A. as Administrative Agent and the lenders signatory thereto.  

(31.1)

Certification by the President and Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.

(31.2)

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

(32.1)

Written Statement of the President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.

(32.2)

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

(99)

Order Confirming Joint Chapter 11 Plan of Reorganization of Whiting Petroleum Corporation [Incorporated by reference to Exhibit 99.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on August 17, 2020 (File No. 001-31899)].

(101)

The following materials from Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2021 are filed herewith, formatted in iXBRL (Inline Extensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Operations, (iii) the Condensed Consolidated Statements of Cash Flows, (iv) the Condensed Consolidated Statements of Equity and (v) Notes to Condensed Consolidated Financial Statements.  The instance document does not appear in the interactive data file because its XBRL tags are embedded within the iXBRL document.

(104)

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

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on this 4th day of August, 2021.

WHITING PETROLEUM CORPORATION

By

/s/ Lynn A. Peterson

Lynn A. Peterson

President and Chief Executive Officer

By

/s/ James P. Henderson

James P. Henderson

Executive Vice President Finance and Chief Financial Officer

By

/s/ Sirikka R. Lohoefener

Sirikka R. Lohoefener

Vice President, Accounting and Controller

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