Whiting Holdings LLC - Quarter Report: 2015 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

 

FORM 10‑Q

 

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

For the quarterly period ended September 30, 2015

or

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

For the transition period from _______________ to _______________

 

 

 

 

 

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).    Yes  ☒    No  ☐

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.  (Check one):

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

Number of shares of the Registrant’s common stock outstanding at October 15, 2015:  204,142,725 shares.

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Glossary of Certain Definitions

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

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

“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 or CO2.

“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.

“CO2”  Carbon dioxide.

“CO2 flood” A tertiary recovery method in which CO2 is injected into a reservoir to enhance hydrocarbon recovery.

“completion” The installation of permanent equipment for the production of crude oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“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, and the wellhead price received.

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

“EOR” Enhanced oil recovery.

“exploratory well” A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.  Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well.

“extension well” A well drilled to extend the limits of a known reservoir.

“FASB” Financial Accounting Standards Board.

“FASB ASC” The Financial Accounting Standards Board Accounting Standards Codification.

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

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

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

“ISDA”  International Swaps and Derivatives Association, Inc.

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

“LIBOR” London interbank offered rate.

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

“MBbl/d” One MBbl per day.

“MBOE” One thousand BOE.

“MBOE/d” One MBOE per day.

“Mcf” One thousand cubic feet, used in reference to natural gas or CO2.

“MMBbl” One million Bbl.

“MMBOE” One million BOE.

“MMBtu” One million British Thermal Units.

“MMcf” One million cubic feet, used in reference to natural gas or CO2.

“MMcf/d” One MMcf per day.

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

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

“NGL” Natural gas liquid.

“NYMEX” The New York Mercantile Exchange.

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

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

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

“proved 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:

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:

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

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

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

“recompletion” An operation whereby a completion in one zone is abandoned in order to attempt a completion in a different zone within the existing wellbore.

“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.

“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.

“royalty interest” An interest in an oil or natural gas property entitling the owner to shares of the crude oil or natural gas production free of costs of exploration, development and production operations.

“SEC” The United States Securities and Exchange Commission.

“service well” A service well is a well drilled or completed for the purpose of supporting production in an existing field.  Wells in this class are drilled for the following specific purposes: gas injection (natural gas, propane, butane, CO2 or flue gas), water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation or injection for in-situ combustion.

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

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

 

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PART I – FINANCIAL INFORMATION

 

Item 1.     Consolidated Financial Statements

 

WHITING PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS (unaudited)

(in thousands, except share and per share data)

 

See notes to consolidated financial statements.

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WHITING PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF INCOME (unaudited)

(in thousands, except per share data)

 

 

 

See notes to consolidated financial statements.

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WHITING PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(in thousands)

 

 

See notes to consolidated financial statements.

 

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WHITING PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY (unaudited)

(in thousands)

 

 

See notes to consolidated financial statements.

 

 

 

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WHITING PETROLEUM CORPORATION

NOTES TO 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 exploration, development, acquisition and production of crude oil, NGLs and natural gas primarily in the Rocky Mountains and Permian Basin regions of the United States.  Unless otherwise specified or the context otherwise requires, all references in these notes to “Whiting” or the “Company” are to Whiting Petroleum Corporation and its consolidated subsidiaries, Whiting Oil and Gas Corporation (“Whiting Oil and Gas”), Whiting US Holding Company, Whiting Canadian Holding Company ULC (formerly Kodiak Oil & Gas Corp., “Kodiak”), Whiting Resources Corporation (formerly Kodiak Oil & Gas (USA) Inc.) and Whiting Programs, Inc.

Consolidated Financial Statements—The unaudited consolidated financial statements include the accounts of Whiting Petroleum Corporation, its consolidated subsidiaries and Whiting’s pro rata share of the accounts of Whiting USA Trust I (“Trust I”) pursuant to Whiting’s 15.8% ownership interest in Trust I.  On January 28, 2015, the net profits interest that Whiting conveyed to Trust I terminated as a result of 9.11 MMBOE (which amount is equivalent to 8.20 MMBOE attributable to the 90% net profits interest) having been produced and sold from the underlying properties.  Upon termination, the net profits interest in the underlying properties reverted back to Whiting.  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 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 2014 Annual Report on Form 10-K.  Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in the Company’s 2014 Annual Report on Form 10‑K.

Earnings Per Share—Basic earnings per common share is calculated by dividing net income available to common shareholders by the weighted average number of common shares outstanding during each period.  Diluted earnings per common share is calculated by dividing adjusted net income available to common shareholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities.  Potentially dilutive securities for the diluted earnings per share calculations consist of unvested restricted stock awards, outstanding stock options and contingently issuable shares of convertible debt, all using the treasury stock method.  In the computation of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of unvested restricted shares or the assumed exercise of stock options (i.e. hypothetical excess tax benefits) are included in the assumed proceeds component of the treasury stock method to the extent that such excess tax benefits are more likely than not to be realized.  In addition, to the extent the conversion value of the convertible debt exceeds the aggregate principal amount of the notes, such conversion spread is included in the diluted earnings per share computation under the treasury stock method.  When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share.

2.           OIL AND GAS PROPERTIES

Net capitalized costs related to the Company’s oil and gas producing activities at September 30, 2015 and December 31, 2014 are as follows (in thousands):

 

 

 

 

 

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3.           ACQUISITIONS AND DIVESTITURES

2015 Acquisitions

There were no significant acquisitions during the nine months ended September 30, 2015.

2015 Divestitures

In June 2015, the Company completed the sale of its interests in certain non-core producing oil and gas wells, effective June 1, 2015, for a purchase price of $150 million (subject to post-closing adjustments) and resulting in a pre-tax loss on sale of $114 million.  The properties included over 2,000 gross wells in 132 fields across 10 states.

In April 2015, the Company completed the sale of its interests in certain non-core producing oil and gas wells, effective May 1, 2015, for a purchase price of $108 million (subject to post-closing adjustments) and resulting in a pre-tax gain on sale of $31 million.  The properties are located in 187 fields across 14 states, and predominately consist of assets that were previously included in the underlying properties of Whiting USA Trust I.

Also during the nine months ended September 30, 2015, the Company completed several immaterial divestiture transactions for the sale of its interests in certain non-core producing oil and gas wells and undeveloped acreage, for a total purchase price of $78 million (subject to post-closing adjustments) and resulting in a pre-tax gain on sale of $21 million.  In addition, subsequent to quarter-end,  the Company entered into an agreement to sell its interests in additional non-core producing oil and gas wells, effective October 1, 2015, for a purchase price of $52 million (subject to post-closing adjustments).

2014 Acquisitions

On December 8, 2014, the Company completed the acquisition of Kodiak Oil & Gas Corp. (now known as Whiting Canadian Holding Company ULC, “Kodiak”), whereby Whiting acquired all of the outstanding common stock of Kodiak (the “Kodiak Acquisition”).  Pursuant to the terms of the Kodiak Acquisition agreement, Kodiak shareholders received 0.177 of a share of Whiting common stock in exchange for each share of Kodiak common stock they owned.  Total consideration for the Kodiak Acquisition was $1.8 billion, consisting of 47,546,139 Whiting common shares issued at the market price of $37.25 per share on the date of issuance plus the fair value of Kodiak’s outstanding equity awards assumed by Whiting.  The aggregate purchase price of the transaction was $4.3 billion, which included the assumption of Kodiak’s outstanding debt of $2.5 billion as of December 8, 2014 and the net cash acquired of $19 million.

Kodiak was an independent energy company focused on exploration and production of crude oil and natural gas reserves, primarily in the Williston Basin region of the United States.  As a result of the Kodiak Acquisition, Whiting acquired approximately 327,000 gross (178,000 net) acres located primarily in North Dakota, including interests in 778 producing oil and gas wells and undeveloped acreage.  Approximately 10,000 of the net acres acquired were located in Wyoming and Colorado.

The Kodiak Acquisition was accounted for using the acquisition method of accounting for business combinations.  The allocation of the purchase price is based upon management’s estimates and assumptions related to the fair value of assets acquired and liabilities assumed on the acquisition date using currently available information.  Transaction costs relating to the Kodiak Acquisition were expensed as incurred.  The initial accounting for the Kodiak Acquisition is preliminary, and adjustments to provisional amounts (such as goodwill, certain accrued receivables and liabilities, and their related deferred taxes) or recognition of additional assets acquired or liabilities assumed, may occur as additional information is obtained about facts and circumstances that existed as of the acquisition date.  Since the acquisition date, the Company has recorded adjustments to provisional amounts, and a corresponding decrease to goodwill, totaling $6 million.  These adjustments did not have a material impact on the Company’s previously reported consolidated financial statements, and therefore the Company has not retrospectively adjusted those financial statements.

The consideration transferred, fair value of assets acquired and liabilities assumed, and the resulting goodwill as of the acquisition date are as follows (in thousands):

 

                                

Goodwill recognized as a result of the Kodiak Acquisition totaled $870 million, none of which is deductible for income tax purposes.  Goodwill was primarily attributable to the operational and financial synergies expected to be realized from the acquisition, including the employment of optimized completion techniques on Kodiak's undrilled acreage which improved hydrocarbon recovery, the realization of savings in drilling and well completion costs, the accelerated development of Kodiak’s asset base, and the acquisition of experienced oil and gas technical personnel.    During the third quarter of 2015, the Company determined that the goodwill recognized as a result of the Kodiak Acquisition had become fully impaired and wrote its carrying value down to zero.  Refer to the “Fair Value Measurements” footnote for further information regarding goodwill impairment.

2014 Divestitures

In March 2014, the Company completed the sale of approximately 49,900 gross (41,000 net) acres in its Big Tex prospect, which consisted mainly of undeveloped acreage as well as its interests in certain producing oil and gas wells, located in the Delaware Basin of Texas for a cash purchase price of $76 million resulting in a pre-tax gain on sale of $12 million.

 

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4.           LONG-TERM DEBT

Long-term debt consisted of the following at September 30, 2015 and December 31, 2014 (in thousands):

Credit Agreement—Whiting Oil and Gas, the Company’s wholly-owned subsidiary, has a credit agreement with a syndicate of banks that as of September 30, 2015 had a borrowing base of $4.5 billion, with aggregate commitments of $3.5 billion.  In October 2015, the Company entered into an amendment to its credit agreement in connection with the November 1, 2015 regular borrowing base redetermination that (i) decreased the borrowing base under the facility to $4.0 billion,  (ii) extended the Interim Covenant Period (as defined in the credit agreement and below), and (iii) included an additional financial covenant requirement during the Interim Covenant Period.  The aggregate commitments under the amended credit agreement remain unchanged at $3.5 billion.  The Company may increase the maximum aggregate amount of commitments under the credit agreement up to the $4.0 billion borrowing base if certain conditions are satisfied, including the consent of lenders participating in the increase.    As of September 30, 2015, the Company had $3.5 billion of available borrowing capacity, which was net of $4 million in letters of credit with no borrowings outstanding.

The borrowing base under the credit agreement is determined at the discretion of the lenders, based on the collateral value of the Company’s proved reserves that have been mortgaged to such lenders, and is subject to regular redeterminations on May 1 and November 1 of each year, as well as special redeterminations described in the credit agreement, in each case which may reduce the amount of the borrowing base.  Upon a redetermination of the borrowing base, either on a periodic or special redetermination date, if borrowings in excess of the revised borrowing capacity were outstanding, the Company could be forced to immediately repay a portion of its debt outstanding under the credit agreement.

A portion of the revolving credit facility in an aggregate amount not to exceed $100 million may be used to issue letters of credit for the account of Whiting Oil and Gas or other designated subsidiaries of the Company.  As of September 30, 2015,  $96 million was available for additional letters of credit under the agreement.

The credit agreement provides for interest only payments until December 2019, when the credit agreement expires and all outstanding borrowings are due.  Interest under the revolving credit facility accrues at the Company’s option at either (i) a base rate for a base rate loan plus the margin in the table below, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.5% per annum, or an adjusted LIBOR rate plus 1.0% per annum, or (ii) an adjusted LIBOR rate for a Eurodollar loan plus the margin in the table below.  Additionally, the Company also incurs commitment fees as set forth in the table below on the unused portion of the aggregate commitments of the lenders under the revolving credit facility, which are included as a component of interest expense.

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

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engage in certain other transactions without the prior consent of its lenders.  Except for limited exceptions, the credit agreement also restricts the Company’s ability to make any dividend payments or distributions on its common stock.  These restrictions apply to all of the net assets of the subsidiaries.  As of September 30, 2015, total restricted net assets were $4.1 billion, and there were no retained earnings free from restrictions.  The amended credit agreement requires the Company, as of the last day of any quarter, to maintain the following ratios (as defined in the credit agreement): (i) a  consolidated current assets to consolidated current liabilities ratio (which includes an add back of the available borrowing capacity under the credit agreement) of not less than 1.0 to 1.0, (ii) a total senior secured debt to the last four quarters’ EBITDAX ratio of less than 2.5 to 1.0 during the Interim Covenant Period (defined below), and thereafter a total debt to EBITDAX ratio of less than 4.0 to 1.0 and (iii) a ratio of the last four quarters’ EBITDAX to consolidated interest charges of not less than 2.25 to 1.0 during the Interim Covenant Period.  Under the amended credit agreement, the “Interim Covenant Period” is defined as the period from June 30, 2015 until the earlier of (a) April 1, 2018 or (b) the commencement of an investment-grade debt rating period as described below.  The Company was in compliance with its covenants under the credit agreement as of September 30, 2015.

Under the terms of the credit agreement, at any time during which Whiting has an investment-grade debt rating from Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Group and Whiting has elected, at its discretion, to effect an investment-grade rating period, (i) certain security requirements, including the borrowing base requirement, and restrictive covenants will cease to apply, (ii) certain other restrictive covenants will become less restrictive, (iii) an additional financial covenant will be imposed, and (iv) the interest rate margin applicable to all revolving borrowings as well as the commitment fee with respect to the revolving facility will be based upon the Company’s debt rating rather than the ratio of outstanding borrowings to the borrowing base.

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

Senior Notes and Senior Subordinated Notes—In September 2010, the Company issued at par $350 million of 6.5% Senior Subordinated Notes due October 2018 (the “2018 Senior Subordinated Notes”).  The estimated fair value of these notes was $319 million and $345 million as of September 30, 2015 and December 31, 2014, respectively, based on quoted market prices for this debt security, and such fair value is therefore designated as Level 1 within the valuation hierarchy.

In September 2013, the Company issued at par $1.1 billion of 5% Senior Notes due March 2019 (the “2019 Senior Notes”) and $800 million of 5.75% Senior Notes due March 2021, and issued at 101% of par an additional $400 million of 5.75% Senior Notes due March 2021 (collectively, the “2021 Senior Notes”).  The estimated fair value of the 2019 Senior Notes was $946 million and $1.0 billion as of September 30, 2015 and December 31, 2014, respectively.  The estimated fair value of the 2021 Senior Notes was $1.0 billion and $1.1 billion as of September 30, 2015 and December 31, 2014, respectively.  These fair values are based on quoted market prices for these debt securities, and such fair values are therefore designated as Level 1 within the valuation hierarchy.

Kodiak Senior Notes.  In conjunction with the Kodiak Acquisition, Whiting US Holding Company, a wholly-owned subsidiary of the Company, became a co-issuer of Kodiak’s $800 million of 8.125% Senior Notes due December 2019 (the “2019 Kodiak Notes”), $350 million of 5.5% Senior Notes due January 2021 (the “2021 Kodiak Notes”), and $400 million of 5.5% Senior Notes due February 2022 (the “2022 Kodiak Notes” and together with the 2019 Kodiak Notes and the 2021 Kodiak Notes, the “Kodiak Notes”).  The Kodiak Notes were recorded at their fair values of $824 million, $351 million and $401 million, respectively, on December 8, 2014, the closing date of the acquisition.

Upon closing of the Kodiak Acquisition, the indentures under which the Kodiak Notes were issued (the “Kodiak Indentures”) were amended to (i) modify certain covenants and restrictions, (ii) provide for unconditional and irrevocable guarantees by Whiting Petroleum Corporation and Whiting Oil and Gas of the prompt payment, when due, of any amounts owed under the Kodiak Notes and the Kodiak Indentures, and (iii) allow Whiting US Holding Company to become a co-issuer of the Kodiak Notes.  Also in conjunction with the Kodiak Acquisition, in December 2014, each of the indentures governing the Company’s 2019 Senior Notes, 2021 Senior Notes and 2018 Senior Subordinated Notes were amended to include Whiting US Holding Company, Kodiak and Whiting Resources Corporation as guarantors.  Shortly after closing, the Kodiak Notes were deregistered in accordance with the Securities Exchange Act of 1934, and accordingly, the Company is exempt from the reporting requirements under Rule 3-10 of Regulation S-X of the SEC with respect to the Kodiak Notes.

Repurchase of Kodiak Notes.  On January 7, 2015, as required under the Kodiak Indentures upon a change in control of Kodiak, Whiting offered to repurchase at 101% of par all $1,550 million principal amount of Kodiak Notes then outstanding.  On March 6, 2015, Whiting paid $760 million to repurchase $2 million aggregate principal amount of the 2019 Kodiak Notes, $346 million aggregate principal amount of the 2021 Kodiak Notes and $399 million aggregate principal amount of the 2022 Kodiak Notes, which payment consisted of the 101% redemption price and all accrued and unpaid interest on such notes.  On May 1, 2015, Whiting paid $5 million to repurchase the remaining $4 million aggregate principal amount of the 2021 Kodiak Notes and $1 million aggregate

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principal amount of the 2022 Kodiak Notes, which payment consisted of the 101% redemption price and all accrued and unpaid interest on such notes.  The Company financed the note repurchases with borrowings under its revolving credit facility.  As a result of the repurchases, Whiting recognized a $6 million loss on early extinguishment of debt, which consisted of an $8 million cash charge related to the redemption premium on the Kodiak Notes, partially offset by a $2 million non-cash credit related to the acceleration of unamortized debt premiums on such notes.

The remaining debt premium on the 2019 Kodiak Notes is being amortized as a reduction to interest expense over the life of the notes.  The estimated fair value of the 2019 Kodiak Notes was $758 million and $812 million as of September 30, 2015 and December 31, 2014, respectively, based on quoted market prices for this debt security, and such fair value is therefore designated as Level 1 within the valuation hierarchy.

Issuance of Senior Notes.  In March 2015, the Company issued at par $750 million of 6.25% Senior Notes due April 2023 (the “2023 Senior Notes” and together with the 2019 Senior Notes and 2021 Senior Notes, the “Whiting Senior Notes”).  The Company used the net proceeds from this issuance to repay a portion of the debt outstanding under its credit agreement.  The estimated fair value of the 2023 Senior Notes was $660 million as of September 30, 2015.  The fair value is based on quoted market prices for this debt security, and such fair value is therefore designated as Level 1 within the valuation hierarchy.

Convertible Senior Notes—In March 2015, the Company issued at par $1,250 million of 1.25% Convertible Senior Notes due April 2020 (the “Convertible Senior Notes”) for net proceeds of $1.2 billion, net of initial purchasers’ fees of $25 million.  The Company used the net proceeds from this issuance to repay a portion of the debt outstanding under its credit agreement.  The notes will mature on April 1, 2020 unless earlier converted in accordance with their terms.

The Company has the option to settle conversions of these notes with cash, shares of common stock or a combination of cash and common stock at its election.  The Company’s intent is to settle the principal amount of the Convertible Senior Notes in cash upon conversion.  Prior to January 1, 2020, the Convertible Senior Notes will be convertible only under the following circumstances: (i) during any calendar quarter commencing after the calendar quarter ending on June 30, 2015 (and only during such calendar quarter), if the last reported sale price of the Company’s common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day; (ii) during the five business day period after any five consecutive trading day period (the “measurement period”) in which the trading price per $1,000 principal amount of the Convertible Senior Notes for each trading day of the measurement period is less than 98% of the product of the last reported sale price of the Company’s common stock and the conversion rate on each such trading day; or (iii) upon the occurrence of specified corporate events.  On or after January 1, 2020, the Convertible Senior Notes will be convertible at any time until the second scheduled trading day immediately preceding the April 1, 2020 maturity date of the notes.  The notes will be convertible at an initial conversion rate of 25.6410 shares of Whiting’s common stock per $1,000 principal amount of the notes, which is equivalent to an initial conversion price of approximately $39.00.  The conversion rate will be subject to adjustment in some events.  In addition, following certain corporate events that occur prior to the maturity date, the Company will increase, in certain circumstances, the conversion rate for a holder who elects to convert its Convertible Senior Notes in connection with such corporate event.  As of September 30, 2015, none of the contingent conditions allowing holders of the Convertible Senior Notes to convert these notes had been met.

Upon issuance, the Company separately accounted for the liability and equity components of the Convertible Senior Notes.  The liability component was recorded at the estimated fair value of a similar debt instrument without the conversion feature.  The difference between the principal amount of the Convertible Senior Notes and the estimated fair value of the liability component was recorded as a debt discount and will be amortized to interest expense over the term of the notes using the effective interest method, with an effective interest rate of 5.61% per annum.  The fair value of the Convertible Senior Notes as of the issuance date was estimated at $1.0 billion, resulting in a debt discount at inception of $238 million.  The equity component, representing the value of the conversion option, was computed by deducting the fair value of the liability component from the initial proceeds of the Convertible Senior Notes issuance.  This equity component was recorded, net of deferred taxes and issuance costs, in additional paid-in capital within shareholders’ equity, and will not be remeasured as long as it continues to meet the conditions for equity classification. 

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

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The Convertible Senior Notes consist of the following at September 30, 2015 (in thousands):

 

                                

The estimated fair value of the Convertible Senior Notes was $1.0 billion as of September 30, 2015.  The fair value is based on quoted market prices for this debt security, and such fair value is therefore designated as Level 1 within the valuation hierarchy.

Interest expense recognized on the Convertible Senior Notes related to the stated interest rate and amortization of the debt discount totaled $14 million and $29 million for the three and nine months ended September 30, 2015, respectively.

The Whiting Senior Notes and the Convertible Senior Notes are unsecured obligations of Whiting Petroleum Corporation and the 2019 Kodiak Notes are unsecured obligations of Whiting US Holding Company, and these unsecured obligations are subordinated to all of the Company’s secured indebtedness, which consists of Whiting Oil and Gas’ credit agreement.  The 2018 Senior Subordinated Notes are also unsecured obligations of Whiting Petroleum Corporation and are subordinated to all of the Company’s senior debt, which currently consists of the Whiting Senior Notes, the Convertible Senior Notes, the 2019 Kodiak Notes and Whiting Oil and Gas’ credit agreement.

The Company’s obligations under the 2018 Senior Subordinated Notes, the Whiting Senior Notes and the Convertible Senior Notes are guaranteed by the Company’s wholly-owned subsidiaries, Whiting Oil and Gas, Whiting US Holding Company, Whiting Canadian Holding Company ULC and Whiting Resources Corporation (the “Guarantors”).  These guarantees are full and unconditional and joint and several among the Guarantors.  Any subsidiaries other than these Guarantors are minor subsidiaries as defined by Rule 3-10(h)(6) of Regulation S‑X of the SEC.  Whiting Petroleum Corporation has no assets or operations independent of this debt and its investments in its consolidated subsidiaries.

5.           ASSET RETIREMENT OBLIGATIONS

The Company’s asset retirement obligations represent the present value of estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage, and land restoration (including removal of certain onshore and offshore facilities in California) in accordance with applicable local, state and federal laws.  The Company follows FASB ASC Topic 410, Asset Retirement and Environmental Obligations, to determine its asset retirement obligation amounts by calculating the present value of the estimated future cash outflows associated with its plug and abandonment obligations.  The current portions at September 30, 2015 and December 31, 2014 were $8 million and $12 million, respectively, and have been included in accrued liabilities and other.  Revisions to the liability typically occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells.  The following table provides a reconciliation of the Company’s asset retirement obligations for the nine months ended September 30, 2015 (in thousands):

 

 

 

 

 

 

 

6.           DERIVATIVE FINANCIAL INSTRUMENTS

The Company is exposed to certain risks relating to its ongoing business operations, and Whiting uses derivative instruments to manage its commodity price risk.  Whiting follows FASB ASC Topic 815, Derivatives and Hedging, to account for its derivative financial instruments.

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Commodity Derivative Contracts—Historically, prices received for crude oil and natural gas production have been volatile because of supply and demand factors, worldwide political factors,  general economic conditions and seasonal weather patterns.  Whiting enters into derivative contracts such as costless collars, swaps and crude oil sales and delivery contracts to achieve a more predictable cash flow by reducing its exposure to commodity price volatility.  Commodity derivative contracts are thereby used to ensure adequate cash flow to fund the Company’s capital programs and to manage returns on acquisitions and drilling programs.  The Company does not enter into derivative contracts for speculative or trading purposes.

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

The table below details the Company’s costless collar and swap derivatives entered into to hedge forecasted crude oil production revenues as of October 1, 2015.

 

                                

Crude Oil Sales and Delivery Contract.  The Company has a long-term crude oil sales and delivery contract for oil volumes produced from its Redtail field in Colorado.  Under the terms of the agreement, Whiting has committed to deliver certain fixed volumes of crude oil through 2020.  The Company determined that it was not probable that future oil production from its Redtail field would be sufficient to meet the minimum volume requirement specified in this contract, and accordingly, that the Company would not settle this contract through physical delivery of crude oil volumes.  As a result, Whiting determined that this contract would not qualify for the “normal purchase normal sale” exclusion and has therefore reflected the contract at fair value in the consolidated financial statements.  As of September 30, 2015, the estimated fair value of this derivative contract was a liability of $11 million.

Embedded Commodity Derivative Contract—In May 2011, Whiting entered into a long-term contract to purchase CO2 for use in its EOR project that is being carried out at its North Ward Estes field in Texas.  This contract contained a price adjustment clause that was linked to changes in NYMEX crude oil prices.  The Company had determined that the portion of this contract linked to NYMEX oil prices was not clearly and closely related to the host contract, and the Company therefore bifurcated this embedded pricing feature from its host contract and reflected it at fair value in the consolidated financial statements.  This contract has been terminated.

Derivative Instrument Reporting—All derivative instruments are recorded in the consolidated financial statements at fair value, other than derivative instruments that meet the “normal purchase normal sale” exclusion.  The following table summarizes the effects of commodity derivative instruments on the consolidated statements of income for the three and nine months ended September 30, 2015 and 2014 (in thousands):

 

 

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Offsetting of Derivative Assets and Liabilities.  The Company typically has numerous hedge positions with each individual financial derivative counterparty that span a several-month time period and that typically result in both fair value asset and liability positions held with that counterparty.  These positions are all offset to a single fair value asset or liability amount at the end of each reporting period.  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 derivative instruments in the consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheets (in thousands):

 

 

 

                                

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

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7.           FAIR VALUE MEASUREMENTS

Cash and cash equivalents, accounts receivable and accounts payable are carried at cost, which approximates their fair value because of the short-term maturity of these instruments.  The Company’s credit agreement has a recorded value that approximates its fair value since its variable interest rate is tied to current market rates.  The Company’s Senior Notes (including the Kodiak Notes), Convertible Senior Notes and Senior Subordinated Notes are recorded at cost, and the fair values of these instruments are included in the “Long-Term Debt” footnote.  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 counterparties, as appropriate.

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

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement.  The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability.  The Company reflects transfers between the three levels at the beginning of the reporting period in which the availability of observable inputs no longer justifies classification in the original level.

The following tables present information about the Company’s financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2015 and December 31, 2014, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values (in thousands):

 

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

Commodity Derivatives.  Commodity derivative instruments consist mainly of costless collars and swap contracts for crude oil.  The Company’s costless collars and 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

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the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are therefore designated as Level 2 within the valuation hierarchy.  The discount rates used in the fair values of these instruments include a measure of either the Company’s or the counterparty’s nonperformance risk, as appropriate.  The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations.

In addition, the Company has a long-term crude oil sales and delivery contract, whereby it has committed to deliver certain fixed volumes of crude oil through 2020.    Whiting has determined that the contract did not meet the “normal purchase normal sale” exclusion, and has therefore reflected this contract at fair value in its consolidated financial statements.  This commodity derivative was valued based on an income approach, which considers various assumptions, including quoted forward prices for commodities, market differentials for crude oil, U.S. Treasury rates and either the Company’s or the counterparty’s nonperformance risk, as appropriate.

The assumptions used in the valuation of the crude oil sales and delivery contract include certain market differential metrics that were unobservable during the term of the contract.  Such unobservable inputs were significant to the contract valuation methodology, and the contract’s fair value was therefore designated as Level 3 within the valuation hierarchy.

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

The following table presents a reconciliation of changes in the fair value of financial assets or liabilities designated as Level 3 in the valuation hierarchy for the three and nine months ended September 30, 2015 and 2014 (in thousands):

                                

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

 

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

Non-recurring Fair Value Measurements.  The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including proved property and goodwill.  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 following table presents information about the Company’s non-financial assets measured at fair value on a non-recurring basis as of September 30,

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2015, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value (in thousands):

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The following methods and assumptions were used to estimate the fair values of the non-financial assets in the tables above:

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 from June 30, 2015 to September 30, 2015 and the associated decline in oil and gas reserves over that same period, the Company performed a proved property impairment test as of September 30, 2015.  The fair value was ascribed using income approach analyses based on the net discounted future cash flows from the producing property and a market approach analysis, which approaches have been probability-weighted.  The discounted cash flows are based on management’s expectations for the future.  Unobservable inputs include estimates of future oil and gas or CO2 production, as the case may be, from the Company’s reserve reports, commodity prices based on sales contract terms or NYMEX forward price curves as of the date of the estimate (adjusted for basis differentials), operating and development costs, and a discount rate based on the Company’s weighted-average cost of capital (all of which are designated as Level 3 inputs within the fair value hierarchy).  The impairment test indicated that a proved property impairment had occurred, and the Company therefore recorded a non-cash impairment charge to reduce the carrying value of the impaired property to its fair value.

Goodwill Impairment.  The Company tests goodwill for impairment annually in the second quarter or whenever events or changes in circumstances indicate that the fair value of its reporting unit may have been reduced below its carrying value.  The Company performed its annual goodwill impairment test as of June 30, 2015, and determined that no impairment had occurred.  However, as a result of a sustained decrease in the price of Whiting’s common stock during the third quarter of 2015 caused by a significant decline in crude oil and natural gas prices over that same period, the Company performed another goodwill impairment test as of September 30, 2015.  The fair value of the Company’s reporting unit was ascribed using an income approach analysis based on the Company’s net discounted future cash flows and a market approach analysis.  The discounted cash flows are based on management’s expectations for the future.  Unobservable inputs include estimates of future oil and gas production from the Company’s reserve reports, commodity prices based on sales contract terms or NYMEX forward price curves as of the date of the estimate (adjusted for basis differentials), operating and development costs, and a  discount rate based on the Company’s weighted-average cost of capital (all of which are designated as Level 3 inputs within the fair value hierarchy).  The impairment test performed by the Company indicated that the fair value of its reporting unit was less than its carrying amount, and further that there was no remaining implied fair value attributable to goodwill.  Based on these results, the Company recorded a non-cash impairment charge to reduce the carrying value of goodwill to zero.

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8.           DEFERRED COMPENSATION

Production Participation Plan—The Company had a Production Participation Plan (the “Plan”) in which all employees participated.  On June 11, 2014, the Board of Directors of the Company terminated the Plan effective December 31, 2013.  Prior to Plan termination, interests in oil and gas properties acquired, developed or sold during the year were allocated to the Plan on an annual basis as determined by the Compensation Committee of the Company’s Board of Directors.  Once allocated, the interests (not legally conveyed) were fixed.  Interest allocations prior to 1995 consisted of 2%‑3% overriding royalty interests.  Interest allocations after 1995 were 1.75%‑5% of oil and gas sales less lease operating expenses and production taxes.

Employees vested in the Plan ratably at 20% per year over a five-year period.  However, pursuant to the terms of the Plan, upon Plan termination all employees fully vested, and the Company was required to distribute to each Plan participant an amount, based upon the valuation method set forth in the Plan, in a lump sum payment twelve months after the date of termination.  This distribution included the value of proved undeveloped oil and gas properties awarded upon Plan termination and was based on forecasted commodity prices for crude oil, NGLs and natural gas as of December 31, 2013.  In January 2015, a portion of the amount due to Plan participants representing a regular distribution under the Plan was paid totaling $41 million, and in June 2015, the remaining fully vested amount due to Plan participants was paid totaling  $72 million.

Accrued compensation expense under the Plan for the nine months ended September 30, 2014 primarily related to the change in liability for employee vestings and PUDs assigned upon Plan termination and amounted to $24 million charged to general and administrative expense and $2 million charged to exploration expense.

Prior to Plan termination, the Company recorded non-cash changes in the present value of estimated future payments under the Plan as a separate line item in the consolidated statements of income.

 

9.           SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTEREST

Common Stock Offering—In March 2015, the Company completed a public offering of its common stock, selling 35,000,000 shares of common stock at a price of $30.00 per share and providing net proceeds of approximately $1.0 billion after underwriter’s fees.  In addition, the Company granted the underwriter a 30-day option to purchase up to an additional 5,250,000 shares of common stock.  On April 1, 2015, the underwriter exercised its right to purchase an additional 2,000,000 shares of common stock, providing additional net proceeds of $61 million.  The Company used the net proceeds from these offerings to repay a portion of the debt outstanding under its credit agreement, as well as for general corporate purposes.

Equity Incentive Plan—At the Company’s 2013 Annual Meeting held on May 7, 2013, shareholders approved the Whiting Petroleum Corporation 2013 Equity Incentive Plan (the “2013 Equity Plan”), which replaced the Whiting Petroleum Corporation 2003 Equity Incentive Plan (the “2003 Equity Plan”) and includes the authority to issue 5,300,000 shares of the Company’s common stock.  Upon shareholder approval of the 2013 Equity Plan, the 2003 Equity Plan was terminated.  The 2003 Equity Plan continues to govern awards that were outstanding as of the date of its termination, which remain in effect pursuant to their terms. Any shares netted or forfeited after May 7, 2013 under the 2003 Equity Plan will be available for future issuance under the 2013 Equity Plan. Under the 2013 Equity Plan, no employee or officer participant may be granted options for more than 600,000 shares of common stock, stock appreciation rights relating to more than 600,000 shares of common stock, or more than 300,000 shares of restricted stock during any calendar year.  On December 8, 2014, the Company increased the number of shares issuable under the 2013 Equity Plan by 978,161 shares to accommodate for the conversion of Kodiak’s outstanding equity awards to Whiting equity awards upon closing of the Kodiak Acquisition.  Any shares netted or forfeited under this increased availability will be cancelled and will not be available for future issuance under the 2013 Equity Plan.  As of September 30, 2015,  4,095,721 shares of common stock remained available for grant under the 2013 Equity Plan.

Noncontrolling Interest—The Company’s noncontrolling interest represents an unrelated third party’s 25% ownership interest in Sustainable Water Resources, LLC.  The table below summarizes the activity for the equity attributable to the noncontrolling interest (in thousands):

 

 

 

 

 

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10.         INCOME TAXES

Income tax expense during interim periods is based on applying an estimated annual effective income tax rate to year-to-date income, plus any significant unusual or infrequently occurring items which are recorded in the interim period.  The provision for income taxes for the three and nine months ended September 30, 2015 and 2014 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 35% to pre-tax income primarily because of state income taxes and estimated permanent differences.

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

11.        EARNINGS PER SHARE

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

 

 

During the three months ended September 30, 2015,  the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes the anti-dilutive effect of 94,513 shares of restricted stock and 59,320 stock options.  In addition, the diluted earnings per share calculation for the three months ended September 30, 2015 excludes (i) the anti-dilutive effect of 359,270 incremental shares of restricted stock that did not meet its market-based vesting criteria as of September 30, 2015 and (ii) the dilutive effect of 712,778 common shares for stock options that were out-of-the-money.

During the nine months ended September 30, 2015, the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes the anti-dilutive effect of 442,713 shares of restricted stock and 94,434 stock options.  In addition, the diluted earnings per share calculation for the nine months ended September 30, 2015 excludes (i) the anti-dilutive effect of 644,233 incremental shares of restricted stock that did not meet its market-based vesting criteria as of September 30, 2015 and (ii) the dilutive effect of 405,065 common shares for stock options that were out-of-the-money.

As discussed in the “Long-Term Debt” footnote, the Company has Convertible Senior Notes whereby it has the option to settle the conversion of such notes with cash, shares of common stock or any combination thereof.  The Company’s intent is to settle the principal amount of the Convertible Senior Notes in cash upon conversion.  As a result, only the amount by which the conversion value exceeds the aggregate principal amount of the notes (the “conversion spread”) is considered in the diluted earnings per share computation under the treasury stock method.  As of September 30, 2015,  the conversion value did not exceed the principal amount of the notes, and accordingly, there was no impact to diluted earnings per share or the related disclosures for that period.

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12.        COMMITMENTS AND CONTINGENCIES

Delivery Commitments—In the second quarter of 2015, the Company entered into a physical delivery contract requiring the Company to deliver fixed volumes of crude oil from its Sanish field in Mountrail County, North Dakota.  Under the terms of the contract, the Company is committed to deliver 5.5 MMBbl of crude oil per year for a term of seven years beginning when the related pipeline is placed in service, which is expected to occur in the second half of 2016. If the Company fails to deliver the committed volumes, it will be required to pay a deficiency payment of $7.00 per undelivered Bbl (or up to $38 million per year), subject to upward adjustment, over the duration of the contract.  However, the Company expects to fully deliver the contracted volumes and therefore avoid any payments for deficiencies.

Drilling Rig Contracts—As of September 30, 2015, the Company had 10 drilling rigs under long-term contract, including two that were on standby.  Four of these agreements expire in 2016 and six expire in 2017.  As of September 30, 2015, the Company’s minimum future payments under these contracts totaled $25 million for the remainder of 2015, $84 million in 2016 and $33 million in 2017.  As of September 30, 2015, early termination of these contracts would require penalties of $119 million, which would be in lieu of paying the remaining drilling commitments under these contracts. 

13.        ADOPTED AND RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In September 2015, the FASB issued Accounting Standards Update No. 2015-16, Simplifying the Accounting for Measurement-Period Adjustments (“ASU 2015-16”).  This ASU eliminates the requirement to retrospectively apply measurement-period adjustments made to provisional amounts recognized in a business combination.  Under ASU 2015-16, the cumulative impact of a measurement-period adjustment (including the impact on prior periods) should instead be recognized in the reporting period in which the adjustment is identified.  ASU 2015-16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015.  This standard should be applied prospectively, and early adoption is permitted.  The adoption of this standard is not expected to have a significant impact on the Company’s consolidated financial statements.

In July 2015, the FASB issued Accounting Standards Update No. 2015-11, Simplifying the Measurement of Inventory (“ASU 2015-11”).  This ASU requires entities to measure most inventory at the lower of cost and net realizable value, thereby simplifying the current guidance under which an entity must measure inventory at the lower of cost or market.  ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years and should be applied prospectively.  Early adoption is permitted.  The adoption of this standard will not have a material impact on the Company’s consolidated financial statements.

In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”).  The objective of ASU 2015-03 is to simplify the presentation of debt issuance costs in financial statements by presenting such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset.  In August 2015, the FASB issued Accounting Standards Update No. 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements (“ASU 2015-15”).  This ASU amends ASU 2015-03 which had not addressed the balance sheet presentation of debt issuance costs incurred in connection with line-of-credit arrangements.  Under ASU 2015-15, a Company may defer debt issuance costs associated with line-of-credit arrangements and present such costs as an asset, subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings.  ASU 2015-03 and ASU 2015-15 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015 and should be applied retrospectively.  Early adoption is permitted.  The adoption of these standards will not have an impact on the Company’s consolidated financial statements, other than balance sheet reclassifications.

In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Presentation of Financial Statements – Going Concern (“ASU 2014-15”).  The objective of ASU 2014-15 is to provide guidance on management’s responsibility to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures.  ASU 2014-15 is effective for fiscal years ending after December 15, 2016 and annual and interim periods thereafter.  This standard is not expected to have an impact on the Company’s consolidated financial statements.

In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014‑09”).  The objective of ASU 2014-09 is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards.  ASU 2014-09 was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, however, in August 2015, the FASB issued Accounting Standards Update No. 2015-14, Revenue from Contracts with Customers: Deferral of the Effective Date (“ASU 2015-14”), which deferred the effective date of ASU 2014‑09 for one year.  ASU 2015-14 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017.  The standards permit retrospective application using either of the following methodologies: (i) restatement of each prior reporting period presented or (ii) recognition of a cumulative-effect adjustment as of the date of initial

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application.  The Company is currently evaluating the impact of adopting ASU 2014‑09 and ASU 2015-14, including the transition method to be applied,  however the standards are not expected to have a significant effect on its consolidated financial statements.

14.        SUBSEQUENT EVENT

In October 2015, Whiting Oil and Gas entered into an amendment to its existing credit agreement in connection with the November 1, 2015 regular redetermination that (i) decreased the borrowing base under the facility from $4.5 billion to $4.0 billion, with no change to the aggregate commitments of $3.5 billion, (ii) extended the interim covenant period (as defined in the credit agreement) until April 1, 2018 and (iii) added a requirement that the Company maintain a ratio of the last four quarters’ EBITDAX to consolidated interest charges (as defined in the credit agreement) of not less than 2.25 to 1.0 during the interim covenant period.  Refer to the “Long-Term Debt” footnote for more information.

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

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

Overview

We are an independent oil and gas company engaged in development, production, acquisition and exploration activities primarily in the Rocky Mountains and Permian Basin regions of the United States.  Since 2006, we have increased our focus on organic drilling activity and on the development of previously acquired properties, specifically on projects that we believe provide the opportunity for repeatable successes and production growth, while selectively pursuing acquisitions that complement our existing core properties, such as the acquisition of Kodiak (the “Kodiak Acquisition”).  As a result of the sustained decline in commodity prices during 2015, we have significantly reduced our level of capital spending to more closely align with our cash flows from operating activities, and have focused our organic drilling operations on projects in our drilling inventory that provide the highest rate of return.  In addition, we continually evaluate our current property portfolio and sell properties when we believe that the sales price realized will provide an above average rate of return for the property or when the property no longer matches the profile of properties we desire to own, such as the asset sales discussed below under “Acquisition and Divestiture Highlights.”  We are currently exploring additional asset sales of non-core properties and anticipate further sales during the fourth quarter of 2015 and early 2016.

We have historically acquired operated and non-operated properties that exceed our rate of return criteria.  For acquisitions of properties with additional development and exploration potential, our focus has been on acquiring operated properties so that we can better control the timing and implementation of capital spending.  In some instances, we have been able to acquire non-operated property interests at attractive rates of return that established a presence in a new area of interest or that have complemented our existing operations.  We intend to continue to acquire both operated and non-operated interests to the extent we believe they meet our return criteria.  In addition, our willingness to acquire non-operated properties in new geographic regions provides us with geophysical and geologic data in some cases that leads to further acquisitions in the same region, whether on an operated or non-operated basis.

Our revenue, profitability and future growth rate depend on many factors which are beyond our control, such as economic, political and regulatory developments and competition from other sources of energy, as well as other items discussed under the caption “Risk Factors” in this Quarterly Report on Form 10-Q and our Annual Report on Form 10-K for the period ended December 31, 2014.  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 2013:

 

Oil prices have fallen significantly since reaching highs of over $105.00 per Bbl in June 2014, dropping below $40.00 per Bbl in August 2015.  Natural gas prices have also declined from over $4.80 per Mcf in April 2014 to below $2.10 per Mcf in October 2015.  In addition, forecasted prices for both oil and gas for the remainder of 2015 have also declined.  Lower oil, NGL and natural gas prices may not only decrease our revenues, but may also reduce the amount of oil and natural gas that we can produce economically and therefore potentially lower our oil and gas reserves.  A substantial or extended decline in oil, NGL or natural gas prices may result in impairments of our proved oil and gas properties, undeveloped acreage or goodwill (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 finance planned capital expenditures.  Lower commodity prices may also reduce the amount of our borrowing base under our credit agreement (such as the reduction discussed below under “Financing Highlights”), which is determined at the discretion of the lenders and which 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.  In addition, higher oil prices may result in significant mark-to-market losses being incurred on our commodity-based derivatives, which may in turn cause us to experience net losses.

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2015 Highlights and Future Considerations

Operational Highlights.

Williston Basin

Our properties in the Williston Basin of North Dakota and Montana target the Bakken and Three Forks formations.  Net production from the Williston Basin averaged 130.9 MBOE/d for the third quarter of 2015, which represents a 4% decrease from 135.8 MBOE/d in the second quarter of 2015.  As of September 30, 2015, we had five rigs active in the Williston Basin.  We have implemented our new completion design across our acreage in the Williston Basin, utilizing cemented liners, plug-and-perf technology and higher sand volumes with both hybrid and slickwater fracture stimulation methods, resulting in improved initial production rates.

In order to process the produced gas stream from our wells in the Sanish field, we constructed the Robinson Lake gas plant.  The plant has a current processing capacity of 130 MMcf/d and fractionation equipment that allows us to convert NGLs into propane and butane, which end products can then be sold locally for higher realized prices.

We also hold a 50% ownership interest in a gas processing plant, gathering systems and related facilities located south of Belfield, North Dakota, which primarily processes production from our Pronghorn field.  There is currently inlet compression in place to process 35 MMcf/d, and as of September 30, 2015, the plant was processing over 19 MMcf/d.

Denver Julesburg Basin

Our Redtail field in the Denver Julesburg Basin (“DJ Basin”) in Weld County, Colorado targets the Niobrara and Codell/Fort Hays formations.  In the third quarter of 2015, net production from the Redtail field averaged 16.6 MBOE/d, representing a 3%  decrease from 17.1 MBOE/d in the second quarter of 2015.  We have established production in the Niobrara “A”, “B” and “C” zones and the Codell/Fort Hays formations, and we began testing our new slickwater fracture stimulation method in this field in 2015.  Our development plan at Redtail currently includes drilling up to eight wells per spacing unit in the Niobrara “A”, “B” and “C” zones and up to four wells per spacing unit in the Codell/Fort Hays formations.    We are currently testing a 32-well per spacing unit pattern in the Niobrara “A”, “B” and “C” zones.  Additionally, the Codell/Fort Hays formation is prospective throughout our acreage in the Redtail field, and we are currently expanding our drilling program in that formation.  The next significant round of completions at Redtail is planned for the first quarter of 2016.  As of September 30, 2015, we had two drilling rigs operating in this area.  

In April 2014, we brought online the Redtail gas plant to process the associated gas produced from our wells in this area.  During the third quarter of 2015, the plant’s inlet capacity was expanded to 50 MMcf/d from 20 MMcf/d.

Permian Basin

Our North Ward Estes field in the Ward and Winkler counties in Texas has responded positively to the water and CO2 floods that we initiated in May 2007.  We are currently injecting CO2 into one of the largest phases of our eight-phase project at this field.  As of September 30, 2015, we were injecting approximately 395 MMcf/d of CO2 into the field, over half of which is recycled.  Net production from North Ward Estes averaged 9.4 MBOE/d for the third quarter of 2015,  which was consistent with production rates in the second quarter of 2015.

Other Non-Core Properties

Whiting USA Trust I.  On January 28, 2015, the net profits interest that Whiting conveyed to Whiting USA Trust I (“Trust I”) terminated as a result of 9.11 MMBOE (which amount is equivalent to 8.20 MMBOE attributable to the 90% net profits interest) having been produced and sold from the underlying properties.  Upon termination, the net profits interest in the underlying properties reverted back to Whiting, resulting in an increase in our production volumes of approximately 2.3 MBOE/d as of the termination of the net profits interest.  However, these properties were sold effective May 1, 2015, as discussed below under “Acquisition and Divestiture Highlights.”

Acquisition and Divestiture Highlights.

 

In June 2015, we completed the sale of our interests in certain non-core producing oil and gas wells, effective June 1, 2015, for a purchase price of $150 million (subject to post-closing adjustments) and resulting in a pre-tax loss on sale of $114 million.  The properties included over 2,000 gross wells in 132 fields across 10 states.  The properties had estimated proved reserves of 20.9 MMBOE as of December 31, 2014, representing 3% of our proved reserves as of that date, and generated 5.3 MBOE/d (or 3%) of our May 2015 average daily production.

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In April 2015, we completed the sale of our interests in certain non-core producing oil and gas wells, effective May 1, 2015, for a cash purchase price of $108 million (subject to post-closing adjustments) and resulting in a pre-tax gain on sale of $31 million.  The properties are located in 187 fields across 14 states, and predominately consisted of assets that were previously included in the underlying properties of Whiting USA Trust I.  The properties had estimated proved reserves of 8.9 MMBOE as of December 31, 2014, representing 1% of our total proved reserves as of that date, and generated 2.7 MBOE/d (or 2%) of our March 2015 average daily net production.

Also during the nine months ended September 30, 2015, we completed several immaterial divestiture transactions for the sale of our interests in certain non-core producing oil and gas wells and undeveloped acreage, for a total purchase price of $78 million (subject to post-closing adjustments) and resulting in a pre-tax gain on sale of $21 million.  In addition, subsequent to quarter-end, we entered into an agreement to sell our interests in additional non-core producing oil and gas wells, effective October 1, 2015, for a purchase price of $52 million (subject to post-closing adjustments).

Financing Highlights.

In October 2015, we entered into an amendment to our existing credit agreement in connection with the November 1, 2015 regular borrowing base redetermination that (i) decreased our borrowing base under the facility from $4.5 billion to $4.0 billion, with no change to our aggregate commitments of $3.5 billion, (ii) extended the interim covenant period (as defined in the credit agreement) until April 1, 2018 and (iii) added a requirement that we maintain a ratio of the last four quarters’ EBITDAX to consolidated interest charges (as defined in the credit agreement) of not less than 2.25 to 1.0 during the interim covenant period.

In March 2015, we completed a public offering of our common stock, selling 35,000,000 shares of common stock at a price of $30.00 per share and providing net proceeds of approximately $1.0 billion after underwriter’s fees.  In addition, we granted the underwriter a 30-day option to purchase up to an additional 5,250,000 shares of common stock.  On April 1, 2015, the underwriter exercised its right to purchase an additional 2,000,000 shares of common stock, providing additional net proceeds of $61 million.  Concurrent with the common stock offering in March, we issued at par $1,250 million of 1.25% Convertible Senior Notes due April 2020 (the “Convertible Senior Notes”).  The notes will mature on April 1, 2020 unless earlier converted in accordance with their terms. In addition, we issued at par $750 million of 6.25% Senior Notes due April 2023.  We used the net proceeds from these offerings to repay all of the debt outstanding under our credit agreement, as well as for general corporate purposes.

On January 7, 2015, as required under the terms of the indentures governing the Kodiak Notes (the “Kodiak Indentures”) upon a change in control of Kodiak, we offered to repurchase at 101% of par all $800 million principal amount of the 8.125% Senior Notes due December 2019 (the “2019 Kodiak Notes”), $350 million principal amount of the 5.5% Senior Notes due 2021 (the “2021 Kodiak Notes”) and $400 million principal amount of the 5.5% Senior Notes due 2022 (the “2022 Kodiak Notes” and together with the 2019 Kodiak Notes and the 2021 Kodiak Notes, the “Kodiak Notes”).  On March 6, 2015, we paid $760 million to repurchase $2 million aggregate principal amount of the 2019 Kodiak Notes, $346 million aggregate principal amount of the 2021 Kodiak Notes and $399 million aggregate principal amount of the 2022 Kodiak Notes, which payment consisted of the 101% redemption price and all accrued and unpaid interest on such notes.  On May 1, 2015, we paid $5 million to repurchase the remaining $4 million aggregate principal amount of the 2021 Kodiak Notes and $1 million aggregate principal amount of the 2022 Kodiak Notes, which payment consisted of the 101% redemption price and all accrued and unpaid interest on such notes.  We financed the repurchases with borrowings under our revolving credit facility, which were subsequently repaid with proceeds from the equity and debt offerings discussed above, and with cash on hand.  As a result of the repurchases, we recognized a $6 million loss on early extinguishment of debt, which consisted of an $8 million cash charge related to the redemption premium on the Kodiak Notes, partially offset by a $2 million non-cash credit related to the acceleration of unamortized debt premiums on such notes.

 

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Results of Operations

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014

 

                                

Oil, NGL and Natural Gas Sales.  Our oil, NGL and natural gas sales revenue decreased $678 million to $1.7 billion when comparing the first nine months of 2015 to the same period in 2014.  Sales revenue is a function of oil, NGL and gas volumes sold and average commodity prices realized.  Our oil sales volumes increased 53%, our NGL sales volumes increased 66% and our natural gas sales volumes increased 41% between periods.  The oil volume increase between periods resulted primarily from producing properties acquired in the Kodiak Acquisition, as well as drilling success across our two core development areas.  The Kodiak Acquisition, which closed on December 8, 2014, added 8,335 MBbl of oil production during the first nine months of 2015 across several of our Northern Rockies areas.  In addition, oil production from our Williston Basin and DJ Basin properties increased 4,130 MBbl and 1,770 MBbl, respectively, over the same period in 2014 as a result of drilling.  These production increases were partially offset by normal field production decline across several of our areas, as well as decreases in production volumes resulting from the property divestitures discussed above under “Acquisition and Divestiture Highlights”, which negatively impacted oil production by 370 MBbl during the first nine months of 2015.  Our NGLs are generally produced concurrently with our crude oil volumes, resulting in a high correlation between fluctuations in our oil quantities sold and our NGL quantities sold.  As a result, our NGL sales volume increases generally related to the same areas as our oil volume increases,  in addition to NGL production added from the Kodiak Acquisition.  Similar to the trends in crude oil production noted above, the gas volume increase between periods was also primarily the result of producing properties acquired in the Kodiak Acquisition, as well as drilling success across our two core development areas.  The Kodiak Acquisition added 5,940 MMcf of gas production during the first nine months of 2015.  In addition, gas production increased 4,535 MMcf at our Williston Basin properties and 2,320 MMcf at our DJ Basin properties over the same period in 2014 as a result of drilling.  These gas volume increases were partially offset by decreases in production volumes resulting from the property divestitures discussed above under “Acquisition and Divestiture Highlights”, which negatively impacted gas production by 3,215 MMcf during the first nine months of 2015, as well as normal field production decline across several of our areas.

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These crude oil, NGL and natural gas production-related increases in net revenue were offset by significant decreases in the average sales price realized for oil, NGLs and natural gas in the first nine months of 2015 compared to 2014.  Our average price for oil before the effects of hedging decreased 52%, our average sales price for NGLs decreased 68% and our average sales price for natural gas decreased 58% between periods.

Gain (Loss) on Sale of Properties.  During the first nine months of 2015, we sold our interests in certain non-core producing oil and gas wells and undeveloped acreage for aggregate net proceeds of $339 million, which resulted in a pre-tax loss on sale of $62 million.  During the first nine months of 2014, we sold undeveloped acreage as well as our interests in certain producing oil and gas wells in the Big Tex prospect for net proceeds of $76 million in cash, which resulted in a pre-tax gain on sale of $12 million.  There were no other property divestitures resulting in a significant gain or loss on sale during the first nine months of 2014.

Lease Operating Expenses.  Our lease operating expenses (“LOE”) during the first nine months of 2015 were $435 million, a $78 million increase over the same period in 2014.  Higher LOE in 2015 were primarily related to an  $82 million increase in oil field goods and services associated with net wells we added during the last twelve months as a result of the Kodiak Acquisition and through drilling, partially offset by the impact of our property divestitures in the first nine months of 2015 as well as a decrease in well workover activity between periods.  Workovers decreased from $46 million in the first nine months of 2014 to $42 million in the first nine months of 2015, primarily due to a reduction in well workover activity at our EOR project at North Ward Estes. 

Our lease operating expenses on a BOE basis, however, decreased when comparing the first nine months of 2015 to the same 2014 period.  LOE per BOE amounted to $9.61 during the first nine months of 2015, which represents a decrease of $2.41 per BOE (or 20%) from the first nine months of 2014.  This decrease was mainly due to declining costs of goods and services in the industry combined with higher overall production volumes between periods, lower well workover costs and the impact of property divestitures discussed above.  The properties sold during the first nine months of 2015 consisted mainly of mature oil and gas producing properties with LOE per BOE rates that were higher than our overall rate.

Production Taxes.  Our production taxes during the first nine months of 2015 were $145 million, a $53 million decrease over the same period in 2014, which decrease was primarily due to lower oil, NGL and natural gas sales between periods.  Our production taxes, however, are generally calculated as a percentage of net sales revenue before the effects of hedging, and this percentage on a company-wide basis was 8.7% and 8.4% for the first nine months of 2015 and 2014, respectively.

Depreciation, Depletion and Amortization.  Our depreciation, depletion and amortization (“DD&A”) expense increased $133 million in 2015 as compared to the first nine months of 2014.  The components of our DD&A expense were as follows (in thousands):

 

DD&A for the first nine months of 2015 increased over the same period in 2014 primarily due to $123 million in higher depletion expense between periods.  Of this increase, $309 million related to an increase in our overall production volumes during the first nine months of 2015, which was partially offset by a  $186 million decrease related to a lower depletion rate between periods.  On a BOE basis, our overall DD&A rate of $20.36 for the first nine months of 2015 was 23% lower than the rate of $26.56 for the same period in 2014.  The primary factors contributing to this lower DD&A rate were additions to proved and proved developed reserves over the last twelve months, including reserves that were added as a result of the Kodiak Acquisition, as well as impairment write-downs on proved oil and gas properties recognized in the fourth quarter of 2014.  These positive factors that lowered our DD&A rate were partially offset by $2.9 billion in drilling and development expenditures during the past twelve months.

Exploration and Impairment.  Our exploration and impairment costs increased $1.7 billion for the first nine months of 2015 as compared to the same period in 2014.  The components of our exploration and impairment expense  were as follows (in thousands):

 

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Exploration costs increased $58 million during the first nine months of 2015 as compared to the same period in 2014 primarily due to rig termination fees incurred in 2015 totaling $76 million, which were partially offset by decreases in geological and geophysical (“G&G”) activity and lower exploratory dry hole costs between periods.  G&G costs, such as seismic studies, amounted to $6 million during the first nine months of 2015 as compared to $21 million during the first nine months of 2014.  We did not drill any exploratory dry holes during the first nine months of 2015, while we drilled one exploratory dry hole in the Rocky Mountains region totaling $4 million during the first nine months of 2014.

Impairment expense for the first nine months of 2015 primarily related to (i) $1.5  billion in non-cash impairment charges for the partial write-down of our North Ward Estes field in Texas and other non-core proved oil and gas properties primarily in Texas, Wyoming, North Dakota and Colorado that are not currently being developed due to depressed oil and gas prices, (ii) $70 million of leasehold amortization associated with individually insignificant unproved properties, (iii) $62 million of impairment write-downs on our CO2 development properties whose net book values exceeded their undiscounted future net cash flows, and (iv) $49 million in impairment write-downs of undeveloped acreage costs for leases where we have no current or future plans to drill.  Impairment expense for the first nine months of 2014 primarily related to $54 million of leasehold amortization associated with individually insignificant unproved properties.  The increase in unproved property leasehold amortization in 2015 is due to $1.0 billion in unproved property costs added as a result of the Kodiak Acquisition.

Goodwill Impairment.  As a result of a sustained decrease in the price of our common stock during the third quarter of 2015 caused by a significant decline in crude oil and natural gas prices over that same period, we performed a goodwill impairment test as of September 30, 2015.  The impairment test indicated that the fair value of our reporting unit was less than its carrying amount, and further that there was no remaining implied fair value attributable to goodwill.  Based on these results, we recorded a non-cash impairment charge of $870 million in the third quarter of 2015 to reduce the carrying value of goodwill to zero.

General and Administrative.  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):

 

G&A expenses before reimbursements and allocations increased $45 million during the first nine months of 2015 as compared to the same period in 2014 primarily due to higher employee compensation between periods, partially offset by lower transaction-related costs incurred on the Kodiak Acquisition as well as savings realized as a result of our cost reduction measures.  Employee compensation increased $44 million for the first nine months of 2015 as compared to the same period in 2014 due to personnel hired during the past twelve months, primarily related to the Kodiak Acquisition,  as well as general pay increases.  Transaction costs incurred for the Kodiak Acquisition totaled $12 million during the nine months ended September 30, 2014, while only $1 million of transaction-related costs were incurred in 2015.    The increase in reimbursements and allocations for the first nine months of 2015 was the result of higher salary costs and a greater number of field workers on Whiting-operated properties, primarily related to the Kodiak Acquisition.

Our general and administrative expenses on a BOE basis, however, decreased when comparing the first nine months of 2015 to the same 2014 period.  G&A expense per BOE amounted to $2.95 during the first nine months of 2015, which represents a decrease of $0.58 per BOE (or 16%) from the first nine months of 2014.  This decrease was mainly due to higher overall production volumes between periods, as well as savings realized as a result of our cost reduction measures.

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

 

The increase in interest expense of $127 million between periods was mainly attributable to $88 million in higher interest costs incurred on our notes during 2015, a $24 million increase in amortization of debt issue costs, discounts and premiums, and a $16 million increase in the amount of interest incurred on our credit agreement during the first nine months of 2015 as compared to the first nine months of 2014.  The increase in note interest is due to interest costs incurred on the $1.6 billion of Kodiak Notes we assumed on December 8, 2014 as part of the Kodiak Acquisition, as well as our March 2015 issuance of $1,250 million of 1.25% Convertible Senior Notes due 2020.  The increase in amortization of debt issue costs, discounts and premiums is primarily due to the amortization of the discount on the Convertible Senior Notes.  Our credit agreement interest was higher in 2015 due to a greater amount of average borrowings outstanding under this facility.

Our weighted average debt outstanding during the first nine months of 2015 was $5.7 billion versus $2.7 billion for the first nine months of 2014.  Our weighted average effective cash interest rate was 5.1% during the first nine months of 2015 compared to 5.7% for the first nine months of 2014.

Commodity Derivative (Gain) Loss, Net.  All of our commodity derivative contracts as well as our embedded derivatives are marked-to-market each quarter with fair value gains and losses recognized immediately in earnings as commodity derivative (gain) loss, net.  Cash flow, however, is only impacted to the extent that settlements under these contracts result in making or receiving a payment to or from the counterparty.  Commodity derivative (gain) loss, net amounted to a gain of $115 million for the nine months ended September 30, 2015 mainly due to the downward shift in the futures curve of forecasted commodity prices (“forward price curve”) for crude oil from January 1, 2015 (or the 2015 date on which new contracts were entered into) to September 30, 2015.  Commodity derivative (gain) loss, net for the nine months ended September 30, 2014 resulted in a loss of $27 million due to the upward shift in the same forward price curve from January 1, 2014 (or the 2014 date on which prior year contracts were entered into) to September 30, 2014.

See Item 3, “Quantitative and Qualitative Disclosures about Market Risk,” for a list of our outstanding derivatives as of October 1, 2015.

Income Tax Expense (Benefit).  Income tax benefit for the first nine months of 2015 totaled $726 million as compared to $270 million of income tax expense for the first nine months of 2014, a decrease of $996 million that was mainly related to $3.5 billion in lower pre-tax income between periods.

Our effective tax rates for the periods ending September 30, 2015 and 2014 differ from the U.S. statutory income tax rate primarily due to the effects of state income taxes and permanent taxable differences.  Our overall effective tax rate decreased from 39.2% for the first nine months of 2014 to 25.5% for the first nine months of 2015.  This decrease is mainly the result of $870 million in goodwill impairment recognized during the third quarter of 2015, which is not tax deductible, as well as the impact of pre-tax earnings shifting from net income in the first nine months of 2014 to a net loss in the first nine months of 2015.

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Three Months Ended September 30, 2015 Compared to Three Months Ended September 30, 2014

 

                                

Oil, NGL and Natural Gas Sales.  Our oil, NGL and natural gas sales revenue decreased $301 million to $504 million when comparing the third quarter of 2015 to the same period in 2014.  Sales revenue is a function of oil, NGL and gas volumes sold and average commodity prices realized.  Our oil sales volumes increased 37%, our NGL sales volumes increased 63%, and our natural gas sales volumes increased 23% between periods.  The oil volume increase between periods resulted primarily from producing properties acquired in the Kodiak Acquisition, as well as drilling success across our two core development areas.  The Kodiak Acquisition, which closed on December 8, 2014, added 2,520 MBbl of oil production across several of our Northern Rockies areas during the third quarter of 2015.  In addition, oil production from our Williston Basin and DJ Basin properties increased 1,420 MBbl and 575 MBbl, respectively, over the same period in 2014 as a result of drilling.  These production increases were partially offset by normal field production decline across several of our areas, as well as decreases in production volumes resulting from the property divestitures discussed above under “Acquisitions and Divestiture Highlights”, which negatively impacted oil production by 275 MBbl during the third quarter of 2015.  Our NGLs are generally produced concurrently with our crude oil volumes, resulting in a high correlation between fluctuations in our oil quantities sold and our NGL quantities sold.  As a result, our NGL sales volume increases generally related to the same areas as our oil volume increases, in addition to NGL production added from the Kodiak Acquisition.  Similar to the trends in crude oil production noted above, the gas volume increase between periods was also primarily the result of producing properties acquired in the Kodiak Acquisition, as well as drilling success across our two core development areas.  The Kodiak Acquisition added 2,015 MMcf of gas production during the third quarter of 2015.  In addition, new wells drilled and completed during the past twelve months caused increases in associated gas production of 1,680 MMcf at our Williston Basin properties and 625 MMcf at our DJ Basin properties over the same period in 2014.  These gas volume increases were partially offset by decreases in production volumes resulting from the property divestitures discussed above under “Acquisition and Divestiture Highlights”, which negatively impacted gas production by 2,350 MMcf during the third quarter of 2015, as well as normal field production decline across several of our areas.

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These crude oil, NGL and natural gas production-related increases in net revenue were offset by significant decreases in the average sales price realized for oil, NGLs and natural gas in the third quarter of 2015 compared to 2014.  Our average price for oil before the effects of hedging decreased 55%, our average price for NGLs decreased 71%, and our average price for natural gas decreased 31% between periods.

Lease Operating Expenses.  Our lease operating expenses during the third quarter of 2015 were $126 million, a $2 million increase over the same period in 2014, which increase was primarily related to a higher level of well workover activity between periods in North Dakota.  Workovers increased from $11 million in the third quarter of 2014 to $13 million in the third quarter of 2015.

Our lease operating expenses on a BOE basis, however, decreased between periods.  LOE per BOE amounted to $8.50 during the third quarter of 2015, which represents a decrease of $3.06 per BOE (or 26%) from the third quarter of 2014.  This decrease was mainly due to declining costs of goods and services in the industry combined with higher overall production volumes between periods, partially offset by the increase in well workover costs discussed above.

Production Taxes.  Our production taxes during the third quarter of 2015 were $44 million, a $25 million decrease over the same period in 2014, which decrease was primarily due to lower oil, NGL and natural gas sales between periods.  Our production taxes, however, are generally calculated as a percentage of net sales revenue before the effects of hedging, and this percentage on a company-wide basis was 8.8% and 8.6% for the third quarter of 2015 and 2014, respectively.

Depreciation, Depletion and Amortization.  Our depreciation, depletion and amortization expense increased $30 million in 2015 as compared to the third quarter of 2014.  The components of our DD&A expense were as follows (in thousands):

 

DD&A increased in the third quarter of 2015 primarily due to $29 million in higher depletion expense between periods.  Of this increase, $85 million related to an increase in our overall production volumes during the third quarter of 2015, which was partially offset by a $56 million decrease related to a lower depletion rate between periods.  On a BOE basis, our overall DD&A rate of $21.40 for the third quarter of 2015 was 20% lower than the rate of $26.61 for the same period in 2014.  The primary factors contributing to this lower DD&A rate were additions to proved and proved developed reserves over the last twelve months, including reserves that were added as a result of the Kodiak Acquisition, as well as impairment write-downs on proved oil and gas properties recognized in the fourth quarter of 2014.  These positive factors that lowered our DD&A rate were partially offset by $2.9 billion in drilling and development expenditures during the last twelve months. 

Exploration and Impairment.  Our exploration and impairment costs increased $1.7 billion for the third quarter of 2015 as compared to the same period in 2014.  The components of our exploration and impairment expense were as follows (in thousands):

 

Exploration costs increased $9 million during the third quarter of 2015 as compared to the same period in 2014 primarily due to rig termination fees incurred in 2015 totaling $11 million.

Impairment expense for the third quarter of 2015 primarily related to (i) $1.5  billion in non-cash impairment charges for the partial write-down of our North Ward Estes field in Texas and other non-core proved oil and gas properties primarily in Texas, Wyoming, North Dakota and Colorado that are not currently being developed due to depressed oil and gas prices, (ii) $62 million of impairment write-downs on our CO2 development properties whose net book values exceeded their undiscounted future net cash flows, (iii) $48 million in impairment write-downs of undeveloped acreage costs for leases where we have no current or future plans to drill, and (iv) $20 million of leasehold amortization associated with individually insignificant unproved properties.  Impairment expense for the third

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quarter of 2014 primarily related to $18 million of leasehold amortization associated with individually insignificant unproved properties.

Goodwill Impairment.  As a result of a sustained decrease in the price of our common stock during the third quarter of 2015 caused by a significant decline in crude oil and natural gas prices over that same period, we performed a goodwill impairment test as of September 30, 2015.  The impairment test indicated that the fair value of our reporting unit was less than its carrying amount, and further that there was no remaining implied fair value attributable to goodwill.  Based on these results, we recorded a non-cash impairment charge of $870 million in the third quarter of 2015 to reduce the carrying value of goodwill to zero.

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

 

G&A expenses before reimbursements and allocations increased $9 million during the third quarter of 2015 as compared to the same period in 2014 primarily due to higher employee compensation between periods.  Employee compensation increased $19 million for the third quarter of 2015 as compared to the same period in 2014 due to personnel hired during the past twelve months, primarily related to the Kodiak Acquisition, as well as general pay increases.  This increase was partially offset by $12 million of transaction-related costs incurred in the third quarter of 2014 on the Kodiak Acquisition, while no such costs were incurred in the same period in 2015.    The increase in reimbursements and allocations for the third quarter of 2015 was the result of higher salary costs and a greater number of field workers on Whiting-operated properties, primarily related to the Kodiak Acquisition.

Our general and administrative expenses on a BOE basis, however, decreased during the third quarter of 2015.  G&A expense per BOE amounted to $3.03 during the third quarter of 2015, which represents a decrease of $0.42 per BOE (or 12%) from the third quarter of 2014.  This decrease was mainly due to higher overall production volumes between periods, as well as savings realized as a result of our cost reduction measures.

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

 

The increase in interest expense of $45 million between periods was mainly attributable to $32 million in higher interest costs incurred on our notes during 2015 and an $11 million increase in amortization of debt issue costs, discounts and premiums during the third quarter of 2015 as compared to the third quarter of 2014.  This increase in note interest is primarily due to interest costs incurred on the $1.6 billion of Kodiak Notes we assumed on December 8, 2014 as part of the Kodiak Acquisition, as well as our March 2015 issuance of $1,250 million of 1.25% Convertible Senior Notes due 2020.  The increase in amortization of debt issue costs, discounts and premiums is primarily due to the amortization of the discount on the Convertible Senior Notes.

Our weighted average debt outstanding during the third quarter of 2015 was $5.5 billion versus $2.8 billion for the third quarter of 2014.  Our weighted average effective cash interest rate was 5.3% during the third quarter of 2015 compared to 5.6% for the third quarter of 2014.

Commodity Derivative (Gain) Loss, Net.  All of our commodity derivative contracts as well as our embedded derivatives are marked-to-market each quarter with fair value gains and losses recognized immediately in earnings, as commodity derivative (gain) loss, net.  Cash flow, however, is only impacted to the extent that settlements under these contracts result in making or receiving a payment to or from the counterparty.  Commodity derivative (gain) loss, net amounted to a gain of $208 million for the three months ended

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September 30, 2015 mainly due to the downward shift in the forward price curve for crude oil from July 1, 2015 (or the 2015 date on which new contracts were entered into) to September 30, 2015.  Commodity derivative (gain) loss, net for the three months ended September 30, 2014, resulted in a gain of $24 million mainly due to the less significant downward shift in the same forward price curve for crude oil from July 1, 2014 (or the 2014 date on which prior year contracts were entered into) to September 30, 2014.

See Item 3, “Quantitative and Qualitative Disclosures about Market Risk,” for a list of our outstanding derivatives as of October 1, 2015.

Income Tax Expense (Benefit).  Income tax benefit for the third quarter of 2015 totaled $595 million as compared to $93 million of income tax expense for the third quarter of 2014, a decrease of $688 million that was mainly related to $2.7 billion in lower pre-tax income between periods.

Our effective tax rates for the periods ending September 30, 2015 and 2014 differ from the U.S. statutory income tax rate primarily due to the effects of state income taxes and permanent taxable differences.  Our overall effective tax rate decreased from 37.2% for the third quarter of 2014 to 24.2% for the third quarter of 2015.  This decrease is mainly a result of $870 million in goodwill impairment recognized during the third quarter of 2015, which is not tax deductible, as well as the impact of pre-tax earnings shifting from net income in the third quarter of 2014 to a net loss in the third quarter of 2015.

Liquidity and Capital Resources

Overview.  At September 30, 2015, we had $38 million of cash on hand and $4.9 billion of equity, while at December 31, 2014, we had $78 million of cash on hand and $5.7 billion of equity.

One of the primary sources of variability in our cash flows from operating activities is commodity price volatility, which we partially mitigate through the use of commodity hedge contracts.  Oil accounted for 80% of our total production in the first nine months of 2015 and 2014.  As a result, our operating cash flows are more sensitive to fluctuations in oil prices than they are to fluctuations in NGL or natural gas prices.  As of October 1, 2015, we had derivative contracts covering the sale of approximately 52% of our forecasted oil production volumes for the remainder of 2015.  For a list of all of our outstanding derivatives as of October 1, 2015, see Item 3, “Quantitative and Qualitative Disclosures about Market Risk.”

During the first nine months of 2015, we generated $901 million of cash provided by operating activities, a decrease of $448 million over the same period in 2014.  Cash provided by operating activities decreased primarily due to lower realized sales prices for oil, NGLs and natural gas, as well as increased lease operating expenses, exploration costs, general and administrative expenses and cash interest expense in the first nine months of 2015.  These negative factors were partially offset by higher crude oil, NGL and natural gas production volumes, as well as lower production taxes during the first nine months of 2015  as compared to the same period in 2014.  Refer to “Results of Operations” for more information on the impact of volumes and prices on revenues and for more information on increases and decreases in certain expenses between periods.

During the first nine months of 2015, cash flows from operating activities plus $2.0 billion in proceeds from the issuance of our Convertible Senior Notes and 2023 Senior Notes, $1.1 billion in proceeds from the issuance of our common stock and $339 million in proceeds from the sale of oil and gas properties were used to finance $2.1 billion of drilling and development expenditures, $1.4 billion of net repayments under our credit agreement, $758 million for the redemption of the 2021 and 2022 Kodiak Notes and  $54 million of debt and equity issuance costs.

Exploration, Development and Undeveloped Acreage Expenditures.  The following chart details our exploration, development and undeveloped acreage expenditures incurred by region (in thousands):

 

                                

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We continually evaluate our capital needs and compare them to our capital resources.  Our current 2015 exploration and development budget is  $2.15 billion, which we expect to fund substantially with net cash provided by our operating activities, cash on hand, proceeds from property divestitures and borrowings under our credit facility.  The overall budget represents a substantial decrease from the $3.2 billion incurred on exploration, development and acreage expenditures during 2014.  This reduced capital budget is in response to the significantly lower crude oil prices experienced during the fourth quarter of 2014 and continuing into 2015.  We expect to allocate $1,953 million of our 2015 budget to exploration and development activity, $59 million to undeveloped acreage purchases and $138 million to facilities.  Although we have only budgeted $59 million for undeveloped leasehold purchases in 2015, we will continue to selectively pursue property acquisitions that complement our existing core property base.  We believe that should additional attractive acquisition opportunities arise or exploration and development expenditures exceed $2.15 billion, we will be able to finance additional capital expenditures with borrowings under our credit agreement, agreements with industry partners or divestitures of certain oil and gas property interests.  Our level of exploration, development and acreage expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows and development results, among other factors.  Based on anticipated production and commodity price levels for 2016, we plan to continue to reduce our level of capital spending to more closely align with our cash flows from operating activities.  We believe that we have sufficient liquidity and capital resources to execute our business plans over the next 12 months and for the foreseeable future.  With our expected cash flow streams, commodity price hedging strategies, current liquidity levels, access to debt and equity markets and flexibility to modify future capital expenditure programs, we expect to be able to fund all planned capital programs and debt repayments, comply with our debt covenants, and meet other obligations that may arise from our oil and gas operations.

Credit Agreement.  Whiting Oil and Gas, our wholly-owned subsidiary, has a credit agreement with a syndicate of banks that as of September 30, 2015 had a borrowing base of $4.5 billion, with aggregate commitments of $3.5 billion.  In October 2015, we entered into an amendment to our credit agreement in connection with the November 1, 2015 regular redetermination that (i) decreased our borrowing base under the facility to $4.0 billion, (ii) extended the Interim Covenant Period (as defined in the credit agreement and below), and (iii) included an additional financial covenant requirement during the Interim Covenant Period.  The aggregate commitments under the amended credit agreement remain unchanged at $3.5 billion.  We may increase the maximum aggregate amount of commitments under the credit agreement up to the $4.0 billion borrowing base if certain conditions are satisfied, including the consent of lenders participating in the increase.  As of September 30, 2015, we had $3.5 billion of available borrowing capacity, which was net of $4 million in letters of credit with no borrowings 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 May 1 and November 1 of each year, as well as special redeterminations described in the credit agreement, in each case which may reduce the amount of the borrowing base.  Upon a redetermination of our borrowing base, if borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of our debt outstanding under the credit agreement.

A portion of the revolving credit facility in an aggregate amount not to exceed $100 million may be used to issue letters of credit for the account of Whiting Oil and Gas or other designated subsidiaries of ours.  As of September 30, 2015,  $96 million was available for additional letters of credit under the agreement.

The credit agreement provides for interest only payments until December 2019, when the credit agreement expires and all outstanding borrowings are due.  Interest under the revolving credit facility accrues at our option at either (i) a base rate for a base rate loan plus the margin in the table below, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.5% per annum, or an adjusted LIBOR rate plus 1.0% per annum, or (ii) an adjusted LIBOR rate for a Eurodollar loan plus the margin in the table below.  Additionally, we also incur commitment fees as set forth in the table below on the unused portion of the aggregate commitments of the lenders under the revolving credit facility.

 

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

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ability to make any dividend payments or distributions on our common stock.  These restrictions apply to all of the net assets of the subsidiaries.  The amended credit agreement requires us, as of the last day of any quarter, to maintain the following ratios (as defined in the credit agreement): (i) a consolidated current assets to consolidated current liabilities ratio (which includes an add back of the available borrowing capacity under the credit agreement) of not less than 1.0 to 1.0, (ii) a total senior secured debt to the last four quarters’ EBITDAX ratio of less than 2.5 to 1.0 during the Interim Covenant Period (defined below), and thereafter a total debt to EBITDAX ratio of less than 4.0 to 1.0 and (iii) a ratio of the last four quarters’ EBITDAX to consolidated interest charges of not less than 2.25 to 1.0 during the Interim Covenant Period.  Under the amended credit agreement, the “Interim Covenant Period” is defined as the period from June 30, 2015 until the earlier of (a) April 1, 2018 or (b) the commencement of an investment-grade debt rating period as described below.  We were in compliance with our covenants under the credit agreement as of September 30, 2015.  However, a substantial or extended decline in oil, NGL or natural gas prices may adversely affect our ability to comply with these covenants in the future.

Under the terms of the credit agreement, at any time during which we have an investment-grade debt rating from Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Group and we have elected, at our discretion, to effect an investment-grade rating period, (i) certain security requirements, including the borrowing base requirement, and restrictive covenants will cease to apply, (ii) certain other restrictive covenants will become less restrictive, (iii) an asset coverage covenant will be imposed, and (iv) the interest rate margin applicable to all revolving borrowings as well as the commitment fee with respect to the revolving facility will be based upon our debt rating rather than the ratio of outstanding borrowings to the borrowing base.

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

Senior Notes and Senior Subordinated Notes.  In March 2015, we issued at par $750 million of 6.25% Senior Notes due April 2023 (the “2023 Senior Notes”).  In September 2013, we issued at par $1.1 billion of 5% Senior Notes due March 2019 (the “2019 Senior Notes”) and $800 million of 5.75% Senior Notes due March 2021, and also in September 2013, we issued at 101% of par an additional $400 million of 5.75% Senior Notes due March 2021 (collectively the “2021 Senior Notes”).  In September 2010, we issued at par $350 million of 6.5% Senior Subordinated Notes due October 2018 (the “2018 Senior Subordinated Notes” and together with the 2023 Senior Notes, the 2021 Senior Notes and the 2019 Senior Notes the “Nonconvertible Whiting Notes”).

Convertible Senior Notes. In March 2015, we issued at par $1,250 million of 1.25% Convertible Senior Notes due April 2020 (the “Convertible Senior Notes”).

We have the option to settle conversions of the Convertible Senior Notes with cash, shares of common stock or a combination of cash and common stock at our election.  Our intent is to settle the principal amount of the Convertible Senior Notes in cash upon conversion.  Prior to January 1, 2020, the Convertible Senior Notes will be convertible only under the following circumstances: (i) during any calendar quarter commencing after the calendar quarter ending on June 30, 2015 (and only during such calendar quarter), if the last reported sale price of our common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day; (ii) during the five business day period after any five consecutive trading day period (the “measurement period”) in which the trading price per $1,000 principal amount of the Convertible Senior Notes for each trading day of the measurement period is less than 98% of the product of the last reported sale price of our common stock and the conversion rate on each such trading day; or (iii) upon the occurrence of specified corporate events.  On or after January 1, 2020, the Convertible Senior Notes will be convertible at any time until the second scheduled trading day immediately preceding the April 1, 2020 maturity date of the notes.  The notes will be convertible at an initial conversion rate of 25.6410 shares of our common stock per $1,000 principal amount of the notes, which is equivalent to an initial conversion price of approximately $39.00.  The conversion rate will be subject to adjustment in some events.  In addition, following certain corporate events that occur prior to the maturity date, we will increase, in certain circumstances, the conversion rate for a holder who elects to convert its Convertible Senior Notes in connection with such corporate event.  As of September 30, 2015, none of the contingent conditions allowing holders of the Convertible Senior Notes to convert these notes had been met.

Kodiak Senior Notes.  In conjunction with the Kodiak Acquisition, Whiting US Holding Company, our wholly-owned subsidiary, became a co-issuer of the Kodiak Notes.  Upon closing of the Kodiak Acquisition, the Kodiak Indentures were amended to (i) modify certain covenants and restrictions, (ii) provide for unconditional and irrevocable guarantees by Whiting Petroleum Corporation and Whiting Oil and Gas of the prompt payment, when due, of any amounts owed under the Kodiak Notes and the Kodiak Indentures, and (iii) allow Whiting US Holding Company to become a co-issuer of the Kodiak Notes.  In May 2015, we repurchased the remaining 2021 Kodiak Notes and 2022 Kodiak Notes and the indentures pursuant to which such notes were issued were terminated.

Also in conjunction with the Kodiak Acquisition, in December 2014, each of the indentures governing our 2019 Senior Notes, 2021 Senior Notes and 2018 Senior Subordinated Notes were amended to include Whiting US Holding Company, Kodiak and Whiting

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Resources Corporation as guarantors.  The indentures governing our 2023 Senior Notes and Convertible Senior Notes issued in March 2015 also include Whiting Oil and Gas, Whiting US Holding Company, Kodiak and Whiting Resources Corporation as guarantors.

The indentures governing the Nonconvertible Whiting Notes restrict us from incurring additional indebtedness, subject to certain exceptions, unless our fixed charge coverage ratio (as defined in the indentures) is at least 2.0 to 1.  The indenture governing the 2019 Kodiak Notes restrict us from incurring additional indebtedness, subject to certain exceptions, unless our fixed charge coverage ratio (as defined in the indenture) is at least 2.25 to 1.  If we were in violation of these covenants, then we may not be able to incur additional indebtedness, including under Whiting Oil and Gas’ credit agreement.  Additionally, the indentures governing the Nonconvertible Whiting Notes and the 2019 Kodiak Notes contain restrictive covenants that may limit our ability to, among other things, pay cash dividends, make certain other restricted payments, redeem or repurchase our capital stock or our subordinated debt, make investments or issue preferred stock, sell assets, consolidate, merge or transfer all or substantially all of the assets of ours and our restricted subsidiaries taken as a whole, and enter into hedging contracts.  These covenants may potentially limit the discretion of our management in certain respects.  We were in compliance with these covenants as of  September 30, 2015.  However, a substantial or extended decline in oil, NGL or natural gas prices may adversely affect our ability to comply with these covenants in the future.

Contractual Obligations and Commitments

Schedule of Contractual Obligations.  The table below does not include any penalties that may be incurred under our physical delivery contracts, since we cannot predict with accuracy the amount and timing of any such penalties if incurred.  For further information on our physical delivery contracts, refer to the “Commitments and Contingencies” footnote in the notes to consolidated financial statements in this Quarterly Report on Form 10-Q and our Annual Report on Form 10-K for the period ended December 31, 2014.    The following table summarizes our obligations and commitments as of September 30, 2015 to make future payments under certain contracts, aggregated by category of contractual obligation, for the time periods specified below (in thousands):

                                

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

New Accounting Pronouncements

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

Critical Accounting Policies and Estimates

Information regarding critical accounting policies and estimates is contained in Item 7 of our Annual Report on Form 10‑K for the fiscal year ended December 31, 2014.  The following is a material update to such critical accounting policies and estimates:

Goodwill Impairment. We test goodwill for impairment annually in the second quarter or whenever events or changes in circumstances indicate that the fair value of our reporting unit may have been reduced below its carrying value.  When testing goodwill for impairment, if our qualitative analysis indicates that it is more likely than not that the fair value of the reporting unit is less than its carrying value, we then perform a quantitative impairment test.  If the carrying value of the reporting unit exceeds its fair value, goodwill is written down to its implied fair value with an offsetting charge to earnings.

The fair value of our reporting unit is ascribed using an income approach analysis based on net discounted future cash flows and a market approach analysis.  The income approach analysis is dependent on a number of factors including estimates of future oil and gas production from our reserve reports, future commodity prices based on sales contract terms or NYMEX forward price curves as of the date of the estimate (adjusted for basis differentials), operating and development costs, the successful development of proved and unproved reserves, an inflation rate and a discount rate based on our weighted-average cost of capital.  The market approach is dependent on our market capitalization as of the date of the estimate, an estimate of the control premium that a market participant would apply to value our reporting unit as a whole and the fair value of our outstanding debt.

There is considerable judgment involved in estimating fair values, particularly in determining the valuation methodologies to utilize and the weighting applied to such methodologies.  Although we base the fair value estimate of our reporting unit on assumptions we believe to be reasonable, those assumptions are inherently uncertain, and actual results could differ from our estimates.  A sustained decrease in crude oil or natural gas prices, negative revisions to estimated reserve quantities, increases in future cost estimates, significant declines in the trading price of our common stock or a substantial decrease in the fair value of our debt could lead to a reduction in the estimated fair value of our reporting unit, which could result in a goodwill impairment.

Based on the results of our goodwill impairment test performed as of September 30, 2015, we recorded a non-cash impairment charge of $870 million in the third quarter of 2015 to reduce the carrying value of goodwill to zero.

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Effects of Inflation and Pricing

We experienced increased costs during 2014 due to increased demand for oil field products and services, however, costs have begun to decline in 2015 following a decrease in demand for these same products and services.  The oil and gas industry is very cyclical, and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts extreme pressure on the economic stability and pricing structure within the industry.  Typically, as prices for oil and natural gas increase, so do all associated costs.  Conversely, in a period of declining prices, associated cost declines are likely to lag and not adjust downward in proportion to prices.  Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, depletion expense, impairment assessments of oil and gas properties and goodwill, and values of properties in purchase and sale transactions.  Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrow money and retain personnel.  While we do not currently expect business costs to materially increase, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.

Forward-Looking Statements

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

These risks and uncertainties include, but are not limited to: declines in oil, NGL or natural gas prices; our level of success in exploration, development and production activities; risks related to our level of indebtedness and periodic redeterminations of the borrowing base under our credit agreement; impacts to financial statements as a result of impairment write-downs; our ability to successfully complete asset dispositions and the risks related thereto; revisions to reserve estimates as a result of changes in commodity prices, regulation and other factors; adverse weather conditions that may negatively impact development or production activities; the timing of our exploration and development expenditures; inaccuracies of our reserve estimates or our assumptions underlying them; risks relating to any unforeseen liabilities of ours; our ability to generate sufficient cash flows from operations to meet the internally funded portion of our capital expenditures budget; our ability to obtain external capital to finance exploration and development operations and acquisitions; federal and state initiatives relating to the regulation of hydraulic fracturing; the potential impact of federal debt reduction initiatives and tax reform legislation being considered by the U.S. Federal Government that could have a negative effect on the oil and gas industry; our ability to obtain sufficient quantities of CO2 necessary to carry out our EOR projects; our ability to identify and complete acquisitions and to successfully integrate acquired businesses; unforeseen underperformance of or liabilities associated with acquired properties; the impacts of hedging on our results of operations; failure of our properties to yield oil or gas in commercially viable quantities; availability of, and risks associated with, transport of oil and gas; our ability to drill producing wells on undeveloped acreage prior to its lease expiration; shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs and completion services; uninsured or underinsured losses resulting from our oil and gas operations; our inability to access oil and gas markets due to market conditions or operational impediments; the impact and costs of compliance with laws and regulations governing our oil and gas operations; our ability to replace our oil and natural gas reserves; any loss of our senior management or technical personnel; competition in the oil and gas industry; cyber security attacks or failures of our telecommunication systems; and other risks described under the caption “Risk Factors” in this Quarterly Report on Form 10-Q and in our Annual Report on Form 10‑K for the period ended December 31, 2014.  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

Our quantitative and qualitative disclosures about market risk for changes in interest rates are included in Item 7A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2014 and have not materially changed since that report was filed.

Commodity Price Risk

The price we receive for our oil and gas production heavily influences our revenue, profitability, access to capital and future rate of growth.  Crude oil and natural gas are commodities, and therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand.  Historically, the markets for oil and gas have been volatile, and these markets will likely continue to be volatile in the future.  Based on production for the first nine months of 2015, our income (loss) before income taxes for the nine months ended September 30, 2015 would have moved up or down $155 million for each 10% change in oil prices per Bbl,  $5 million for each 10% change in NGL prices per Bbl and $7 million for each 10% change in natural gas prices per Mcf.

We periodically enter into derivative contracts to achieve a more predictable cash flow by reducing our exposure to oil and natural gas price volatility.  Our derivative contracts have traditionally been costless collars and swap contracts, 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.

Commodity Derivative Contracts

Crude Oil Costless Collars and Swaps.    The collared hedges shown in the tables below have the effect of providing a protective floor while allowing us to share in upward pricing movements.  The three-way collars, however, do not provide complete protection against declines in crude oil prices due to the fact that when the market price falls below the sub-floor, the minimum price we would receive would be NYMEX plus the difference between the floor and the sub-floor.  While these hedges are designed to reduce our exposure to price decreases, they also have the effect of limiting the benefit of price increases above the ceiling.  For the crude oil collars outstanding as of September 30, 2015, a hypothetical upward or downward shift of 10% per Bbl in the NYMEX forward curve as of September 30, 2015 would cause a decrease or increase, respectively, of $63 million in our commodity derivative loss.

The swap contracts shown in the tables below entitle us to receive settlement from the counterparty in amounts, if any, by which the settlement price for the applicable calculation period is less than the fixed price, or to pay the counterparty if the settlement price for the applicable calculation period is more than the fixed price.  While the fixed-price swaps are designed to decrease our exposure to downward price movements, they also have the effect of limiting the benefit of upward price movements.  For the swaps outstanding as of September 30, 2015, a hypothetical upward or downward shift of 10% per Bbl in the NYMEX forward curve as of September 30, 2015 would cause a decrease or increase, respectively, of $3 million in our commodity derivative loss.

Our outstanding hedges as of October 1, 2015 are summarized below:

 

 

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Item 4.     Controls and Procedures

Evaluation of disclosure controls and procedures.  In accordance with Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), our management evaluated, with the participation of our Chairman, President and Chief Executive Officer and our Senior Vice President and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of September 30, 2015.  Based upon their evaluation of these disclosures controls and procedures, the Chairman, President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer concluded that the disclosure controls and procedures were effective as of September 30, 2015 to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure.

Changes in internal control over financial reporting.  There was no change in our internal control over financial reporting that occurred during the quarter ended September 30, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1.     Legal Proceedings

Whiting is subject to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business.  It is management’s opinion that all claims and litigation we are involved in are not likely to have a material adverse effect on our consolidated financial position, cash flows or results of operations.

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, 2014.  The following is a material update to such risk factors:

The Convertible Senior Notes may adversely affect the market price of our common stock.

The market price of our common stock is likely to be influenced by the Convertible Senior Notes. For example, the market price of our common stock could become more volatile and could be depressed by:

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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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 29th day of October, 2015.

 

 

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EXHIBIT INDEX

 

 

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