|• WHITING PETROLEUM CORP FORM 10-Q, 3-31-2012 • CERTIFICATION OF THE CHAIRMAN AND CEO • CERTIFICATION OF THE VICE PRESIDENT AND CFO • WRITTEN STATEMENT OF THE CHAIRMAN AND CEO • WRITTEN STATEMENT OF THE VICE PRESIDENT AND CFO • XBRL INSTANCE DOCUMENT • XBRL TAXONOMY EXTENSION SCHEMA • XBRL TAXONOMY EXTENSION CALCULATION LINKBASE • XBRL TAXONOMY EXTENSION DEFINITION LINKBASE • XBRL TAXONOMY EXTENSION LABEL LINKBASE • XBRL TAXONOMY EXTENSION PRESENTATION LINKBASE|
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
For the quarterly period ended March 31, 2012
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 T 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 T 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 T
Number of shares of the registrant’s common stock outstanding at April 15, 2012: 117,617,777 shares.
GLOSSARY OF CERTAIN DEFINITIONS
Unless the context otherwise requires, the terms “we,” “us,” “our” or “ours” when used in this report 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 and other liquid hydrocarbons.
“Bcf” One billion cubic feet of natural gas.
“BOE” One stock tank barrel equivalent of oil, calculated by converting natural gas volumes to equivalent oil barrels at a ratio of six Mcf to one Bbl of oil.
“EBITDAX” Earnings before interest, income taxes, depreciation, depletion, amortization and exploration expense.
“FASB” Financial Accounting Standards Board.
“FASB ASC” The Financial Accounting Standards Board Accounting Standards Codification.
“GAAP” Generally accepted accounting principles in the United States of America.
“MBbl” One thousand barrels of oil or other liquid hydrocarbons.
“MBOE” One thousand BOE.
“MBOE/d” One MBOE per day.
“Mcf” One thousand cubic feet of natural gas.
“MMBbl” One million Bbl.
“MMBOE” One million BOE.
“MMBtu” One million British Thermal Units.
“MMcf” One million cubic feet of natural gas.
“MMcf/d” One MMcf per day.
“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 many states require plugging of abandoned wells.
“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:
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.
“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 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.
PART I – FINANCIAL INFORMATION
WHITING PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands, except share and per share data)
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(In thousands, except per share data)
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY (Unaudited)
WHITING PETROLEUM CORPORATION
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS (Unaudited)
Description of Operations—Whiting Petroleum Corporation, a Delaware corporation, is an independent oil and gas company that explores for, develops, acquires and produces crude oil, natural gas and natural gas liquids primarily in the Rocky Mountains, Permian Basin, Mid-Continent, Michigan and Gulf Coast 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.
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. 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 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. Whiting’s 2011 Annual Report on Form 10-K includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Form 10-Q. Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in Whiting’s 2011 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 and outstanding stock options using the treasury method, as well as convertible perpetual preferred stock using the if-converted 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 share method to the extent that such excess tax benefits are more likely than not to be realized. 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.
On March 22, 2012, the Company completed the acquisition of approximately 13,300 net undeveloped acres in the Missouri Breaks prospect in Richland County, Montana for $33.3 million.
On March 28, 2012, the Company completed an initial public offering of units of beneficial interest in Whiting USA Trust II (“Trust II”), selling 18,400,000 Trust II units at $20.00 per unit, providing net proceeds of $323.6 million after underwriters’ fees, offering expenses and post-close adjustments. The Company used the net offering proceeds to repay a portion of the debt outstanding under its credit agreement. The net proceeds from the sale of Trust II units to the public resulted in a deferred gain on sale of $129.5 million. Immediately prior to the closing of the offering, Whiting conveyed a term net profits interest in certain of its oil and gas properties to Trust II in exchange for 18,400,000 trust units.
The net profits interest entitles Trust II to receive 90% of the net proceeds from the sale of oil and natural gas production from the underlying properties. The net profits interest will terminate on the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold. This is the equivalent of 10.61 MMBOE in respect of Trust II’s right to receive 90% of the net proceeds from such reserves pursuant to the net profits interest. The conveyance of the net profits interest to Trust II consisted entirely of proved reserves of 10.61 MMBOE as of the January 1, 2012 effective date, representing 3% of Whiting’s proved reserves as of December 31, 2011 and 5% (or 4.5 MBOE/d) of its March 2012 average daily net production.
On July 28, 2011, the Company completed the acquisition of approximately 23,400 net acres and one well in the Missouri Breaks prospect in Richland County, Montana for an unadjusted purchase price of $46.9 million. Disclosures of pro forma revenues and net income for the acquisition of this one well are not material and have not been presented accordingly.
On March 18, 2011, Whiting and an unrelated third party formed Sustainable Water Resources, LLC (“SWR”) to develop a water project in the state of Colorado. The Company contributed $25.0 million for a 75% interest in SWR, and the 25% noncontrolling interest in SWR was ascribed a fair value of $8.3 million, which consisted of $2.5 million in cash contributions, as well as $5.8 million in intangible and fixed assets contributed to the joint venture.
On February 15, 2011, the Company completed the acquisition of 6,000 net undeveloped acres and additional working interests in the Pronghorn field in the Billings and Stark counties of North Dakota, for an aggregate purchase price of $40.0 million.
On September 29, 2011, Whiting sold its interest in several non-core oil and gas producing properties located in the Karnes, Live Oak and DeWitt counties of Texas for total cash proceeds of $64.8 million, resulting in a pre-tax gain on sale of $12.3 million. Whiting used the net proceeds from the property sale to repay a portion of the debt outstanding under its credit agreement.
Long-term debt consisted of the following at March 31, 2012 and December 31, 2011 (in thousands):
Credit Agreement—Whiting Oil and Gas Corporation (“Whiting Oil and Gas”), the Company’s wholly-owned subsidiary, has a credit agreement with a syndicate of banks. As of March 31, 2012, this credit facility had a borrowing base of $1.5 billion with $858.6 million of available borrowing capacity, which is net of $640.0 million in borrowings and $1.4 million in letters of credit outstanding. The credit agreement provides for interest only payments until April 2016, when the agreement expires and all outstanding borrowings are due.
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 its 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. A portion of the revolving credit facility in an aggregate amount not to exceed $50.0 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 March 31, 2012, $48.6 million was available for additional letters of credit under the agreement.
Interest 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 0.50% or an adjusted LIBOR rate plus 1.00%, 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 lesser of the aggregate commitments of the lenders or the borrowing base, and are included as a component of interest expense. At March 31, 2012, the weighted average interest rate on the outstanding principal balance under the credit agreement was 2.1%.
The credit agreement contains restrictive covenants that may limit the Company’s ability to, among other things, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, enter into hedging contracts, incur liens and engage in certain other transactions without the prior consent of its lenders. Except for limited exceptions, which include the payment of dividends on the Company’s 6.25% convertible perpetual preferred stock, the credit agreement also restricts our ability to make any dividend payments or distributions on its common stock. These restrictions apply to all of the net assets of Whiting Oil and Gas. As of March 31, 2012, total restricted net assets were $2,961.0 million, and the amount of retained earnings free from restrictions was $17.8 million. The credit agreement requires the Company, as of the last day of any quarter, (i) to not exceed a total debt to the last four quarters’ EBITDAX ratio (as defined in the credit agreement) of 4.25 to 1.0 for quarters ending prior to and on December 31, 2012 and 4.0 to 1.0 for quarters ending March 31, 2013 and thereafter and (ii) to have a consolidated current assets to consolidated current liabilities ratio (as defined in the credit agreement and which includes an add back of the available borrowing capacity under the credit agreement) of not less than 1.0 to 1.0. The Company was in compliance with its covenants under the credit agreement as of March 31, 2012.
The obligations of Whiting Oil and Gas under the amended credit agreement are secured by a first lien on substantially all of Whiting Oil and Gas’ 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 Whiting Oil and Gas as security for its guarantee.
Senior Subordinated Notes—In October 2005, the Company issued at par $250.0 million of 7% Senior Subordinated Notes due February 2014. The estimated fair value of these notes was $266.9 million as of March 31, 2012, based on quoted market prices for these same debt securities, and such fair value is therefore designated as Level 1 within the valuation hierarchy.
In September 2010, the Company issued at par $350.0 million of 6.5% Senior Subordinated Notes due October 2018. The estimated fair value of these notes was $372.3 million as of March 31, 2012, based on quoted market prices for these same debt securities, and such fair value is therefore designated as Level 1 within the valuation hierarchy.
The notes are unsecured obligations of Whiting Petroleum Corporation and are subordinated to all of the Company’s senior debt, which currently consists of Whiting Oil and Gas’ credit agreement. The Company’s obligations under the 2014 notes are fully, unconditionally, jointly and severally guaranteed by the Company’s 100%-owned subsidiaries, Whiting Oil and Gas and Whiting Programs, Inc. (the “2014 Guarantors”). Additionally, the Company’s obligations under the 2018 notes are fully, unconditionally, jointly and severally guaranteed by the Company’s 100%-owned subsidiary, Whiting Oil and Gas (collectively with the 2014 Guarantors, the “Guarantors”). Any subsidiaries other than the Guarantors are minor subsidiaries as defined by Rule 3-10(h)(6) of Regulation S-X of the Securities and Exchange Commission. Whiting Petroleum Corporation has no assets or operations independent of this debt and its investments in guarantor subsidiaries.
The Company’s asset retirement obligations represent the 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 March 31, 2012 and December 31, 2011 were $11.8 million and $7.7 million, respectively, and are included in accrued liabilities and other. Revisions to the liability could 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 three months ended March 31, 2012 (in thousands):
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.
Commodity Derivative Contracts—Historically, prices received for crude oil and natural gas production have been volatile because of seasonal weather patterns, supply and demand factors, worldwide political factors and general economic conditions. Whiting enters into derivative contracts, primarily costless collars, 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. Costless collars are designed to establish floor and ceiling prices on anticipated future oil and 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 Company does not enter into derivative contracts for speculative or trading purposes.
Whiting Derivatives. The table below details the Company’s costless collar derivatives, including its proportionate share of Trust I and Trust II derivatives, entered into to hedge forecasted crude oil and natural gas production revenues, as of April 1, 2012.
Derivatives Conveyed to Whiting USA Trust I. In connection with the Company’s conveyance in April 2008 of a term net profits interest to Trust I and related sale of 11,677,500 Trust I units to the public, the right to any future hedge payments made or received by Whiting on certain of its derivative contracts have been conveyed to Trust I, and therefore such payments will be included in Trust I’s calculation of net proceeds. Under the terms of the aforementioned conveyance, Whiting retains 10% of the net proceeds from the underlying properties. Whiting’s retention of 10% of these net proceeds, combined with its ownership of 2,186,389 Trust I units, results in third-party public holders of Trust I units receiving 75.8%, and Whiting retaining 24.2%, of the future economic results of commodity derivative contracts conveyed to Trust I. The relative ownership of the future economic results of such commodity derivatives is reflected in the tables below. No additional hedges are allowed to be placed on Trust I assets.
The 24.2% portion of Trust I derivatives that Whiting has retained the economic rights to (and which are also included in the table above) are as follows:
The 75.8% portion of Trust I derivative contracts of which Whiting has transferred the economic rights to third-party public holders of Trust I units (and which have not been reflected in the above tables) are as follows:
Derivatives Conveyed to Whiting USA Trust II. In connection with the Company’s conveyance in March 2012 of a term net profits interest to Trust II and related sale of 18,400,000 Trust II units to the public, the right to any future hedge payments made or received by Whiting on certain of its derivative contracts have been conveyed to Trust II, and therefore such payments will be included in Trust II’s calculation of net proceeds. Under the terms of the aforementioned conveyance, Whiting retains 10% of the net proceeds from the underlying properties, which results in third-party public holders of Trust II units receiving 90%, and Whiting retaining 10%, of the future economic results of commodity derivative contracts conveyed to Trust II. The relative ownership of the future economic results of such commodity derivatives is reflected in the tables below. No additional hedges are allowed to be placed on Trust II assets.
The 10% portion of Trust II derivatives that Whiting has retained the economic rights to (and which are also included in the first derivative table above) are as follows:
The 90% portion of Trust II derivative contracts of which Whiting has transferred the economic rights to third-party public holders of Trust II units (and which have not been reflected in the above tables) are as follows:
Embedded Commodity Derivative Contracts—As of March 31, 2012, Whiting had entered into certain contracts for oil field goods or services, whereby the price adjustment clauses for such goods or services are linked to changes in NYMEX crude oil prices. The Company has determined that the portions of these contracts linked to NYMEX oil prices are not clearly and closely related to the host contracts, and the Company has therefore bifurcated these embedded pricing features from their host contracts and reflected them at fair value in the consolidated financial statements.
Drilling Rig Contracts. As of March 31, 2012, Whiting had entered into two contracts with drilling rig companies, whereby the rig day rates included price adjustment clauses that are linked to changes in NYMEX crude oil prices. These drilling rig contracts have termination dates of March 2014 and September 2014. The price adjustment formulas in the rig contracts stipulate that with every $10 increase or decrease in the price of NYMEX crude, the cost of drilling rig day rates to the Company will likewise increase or decrease by specific dollar amounts as set forth in each of the individual contracts. As of March 31, 2012, the aggregate estimated fair value of the embedded derivatives in these drilling rig contracts was a liability of $0.8 million.
As global crude oil prices increase or decrease, the demand for drilling rigs in North America similarly increases and decreases. Because the supply of onshore drilling rigs in North America is fairly inelastic, these changes in rig demand cause drilling rig day rates to increase or decrease in tandem with crude oil price fluctuations. When the Company enters into a long-term drilling rig contract that has a fixed rig day rate, which does not increase or decrease with changes in oil prices, the Company is exposed to the risk of paying higher than the market day rate for drilling rigs in a climate of declining oil prices. This in turn could have a negative impact on the Company’s oil and gas well economics. As a result, the Company reduces its exposure to this risk by entering into certain drilling contracts which have day rates that fluctuate in tandem with changes in oil prices.
CO2 Purchase Contract. In May 2011, Whiting entered into a long-term contract to purchase CO2 from 2015 through 2029 for use in its enhanced oil recovery project that is being carried out at its North Ward Estes field in Texas. The price per Mcf of CO2 purchased under this agreement increases or decreases as the average price of NYMEX crude oil likewise increases or decreases. As of March 31, 2012, the estimated fair value of the embedded derivative in this CO2 purchase contract was an asset of $8.9 million.
Although CO2 is not a commodity that is actively traded on a public exchange, the market price for CO2 generally fluctuates in tandem with increases or decreases in crude oil prices. When Whiting enters into a long-term CO2 purchase contract where the price of CO2 is fixed and does not adjust with changes in oil prices, the Company is exposed to the risk of paying higher than the market rate for CO2 in a climate of declining oil and CO2 prices. This in turn could have a negative impact on the project economics of the Company’s CO2 flood at North Ward Estes. As a result, the Company reduces its exposure to this risk by entering into certain CO2 purchase contracts which have prices that fluctuate along with changes in crude oil prices.
Derivative Instrument Reporting—All derivative instruments are recorded on the consolidated balance sheet at fair value, other than derivative instruments that meet the “normal purchase normal sale” exclusion. The following tables summarize the location and fair value amounts of all derivative instruments in the consolidated balance sheets (in thousands):
The following tables summarize the effects of commodity derivatives instruments on the consolidated statements of income for the three months ended March 31, 2012 and 2011 (in thousands):
Contingent Features in Derivative Instruments. None of the Company’s derivative instruments contain credit-risk-related contingent features. Counterparties to the Company’s derivative contracts are high credit-quality financial institutions that are current or former lenders under Whiting’s credit agreement. At the time Whiting enters into derivative contracts, 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.
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 March 31, 2012 and December 31, 2011, 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 assets and liabilities in the tables above:
Commodity Derivatives. Commodity derivative instruments consist primarily of costless collars for crude oil and natural gas. The Company’s costless collars are valued based on an income approach. These option models consider various assumptions, including quoted forward prices for commodities, time value and volatility factors. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are therefore designated as Level 2 within the valuation hierarchy. The discount rates used in the fair values of these instruments include a measure of either the Company’s or the counterparty’s nonperformance risk, as appropriate. The Company utilizes counterparties’ valuations to assess the reasonableness of its own valuations.
Embedded Commodity Derivatives. Embedded commodity derivatives relate to long-term drilling rig contracts as well as a long-term CO2 purchase contract, which all have price adjustment clauses that are linked to changes in NYMEX crude oil prices. Whiting has determined that the portions of these contracts linked to NYMEX oil prices are not clearly and closely related to the host drilling contracts, and the Company has therefore bifurcated these embedded pricing features from their host contracts and reflected them at fair value in its consolidated financial statements. These embedded commodity derivatives are valued based on an income approach. These option models consider various assumptions, including quoted forward prices for commodities, LIBOR discount rates and either the Company’s or the counterparty’s nonperformance risk, as appropriate.
The assumptions used in the valuation of the drilling rig contracts are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and the fair value measurements of the drilling rig contracts are therefore designated as Level 2 within the valuation hierarchy.
The assumptions used in the CO2 contract valuation, however, include inputs that are both observable in the marketplace as well as unobservable during the term of the contract. With respect to forward prices for NYMEX crude oil where there is a lack of price transparency in certain future periods, such unobservable oil price inputs are significant to the CO2 contract valuation methodology, and the contract’s fair value is 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 embedded commodity derivative instrument 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.
The following table presents a reconciliation of changes in the fair value of financial assets (liabilities) designated as Level 3 in the valuation hierarchy for the three months ended March 31, 2012 (in thousands):
Quantitative Information About Level 3 Fair Value Measurements. The significant unobservable inputs used in the fair value measurement of the Company’s embedded commodity derivative contract designated as Level 3 are as follows:
Sensitivity To Changes In Significant Unobservable Inputs. As presented in the table above, the significant unobservable inputs used in the fair value measurement of Whiting’s embedded commodity derivative within its CO2 purchase contract are the future prices of NYMEX crude oil from 2018 to 2029. Significant increases (decreases) in these unobservable inputs in isolation would result in a significantly lower (higher) fair value asset measurement.
Nonrecurring Fair Value Measurements. The Company applies the provisions of the fair value measurement standard to its nonrecurring, non-financial measurements. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. The Company did not recognize any nonrecurring fair value adjustments during the 2012 or 2011 reporting periods presented.
Production Participation Plan—The Company has a Production Participation Plan (the “Plan”) in which all employees participate. On an annual basis, interests in oil and gas properties acquired, developed or sold during the year are allocated to the Plan as determined annually by the Compensation Committee of the Company’s Board of Directors. Once allocated, the interests (not legally conveyed) are fixed. Interest allocations prior to 1995 consisted of 2%-3% overriding royalty interests. Interest allocations since 1995 have been 2%-5% of oil and gas sales less lease operating expenses and production taxes.
Payments of 100% of the year’s Plan interests to employees and the vested percentages of former employees in the year’s Plan interests are made annually in cash after year-end. Accrued compensation expense under the Plan for the three months ended March 31, 2012 and 2011 amounted to $18.9 million and $8.0 million, respectively, charged to general and administrative expense and $2.0 million and $0.9 million, respectively, charged to exploration expense.
Employees vest in the Plan ratably at 20% per year over a five-year period. Pursuant to the terms of the Plan, (i) employees who terminate their employment with the Company are entitled to receive their vested allocation of future Plan year payments on an annual basis; (ii) employees will become fully vested at age 62, regardless of when their interests would otherwise vest; and (iii) any forfeitures inure to the benefit of the Company.
The Company uses average historical prices to estimate the vested long-term Production Participation Plan liability. At March 31, 2012, the Company used three-year average historical NYMEX prices of $82.50 for crude oil and $4.01 for natural gas to estimate this liability. If the Company were to terminate the Plan or upon a change in control of the Company (as defined in the Plan), all employees fully vest and the Company would 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 or within one month after a change in control event. Based on current strip prices at March 31, 2012, if the Company elected to terminate the Plan or if a change of control event occurred, it is estimated that the fully vested lump sum cash payment to employees would approximate $167.6 million. This amount includes $15.0 million attributable to proved undeveloped oil and gas properties and $20.9 million relating to the short-term portion of the Plan liability, which has been accrued as a current payable to be paid in February 2013. The ultimate sharing contribution for proved undeveloped oil and gas properties will be awarded in the year of Plan termination or change of control. However, the Company has no intention to terminate the Plan.
The following table presents changes in the Plan’s estimated long-term liability (in thousands):
Common Stock—In May 2011, Whiting’s stockholders approved an amendment to the Company’s Restated Certificate of Incorporation to increase the number of authorized shares of common stock from 175,000,000 shares to 300,000,000 shares.
Stock Split. On January 26, 2011, the Company’s Board of Directors approved a two-for-one split of the Company's shares of common stock to be effected in the form of a stock dividend. As a result of the stock split, stockholders of record on February 7, 2011 received one additional share of common stock for each share of common stock held. The additional shares of common stock were distributed on February 22, 2011. Concurrently with the payment of such stock dividend in February 2011, there was a transfer from additional paid-in capital to common stock of $0.1 million, which amount represents $0.001 per share (being the par value thereof) for each share of common stock so issued. The common stock dividend resulted in the conversion price for Whiting’s 6.25% Convertible Perpetual Preferred Stock being adjusted from $43.4163 to $21.70815.
6.25% Convertible Perpetual Preferred Stock—In June 2009, the Company completed a public offering of 6.25% convertible perpetual preferred stock (“preferred stock”), selling 3,450,000 shares at a price of $100.00 per share. As of March 31, 2012, however, only 172,391 shares of preferred stock remained outstanding.
Each holder of the preferred stock is entitled to an annual dividend of $6.25 per share to be paid quarterly in cash, common stock or a combination thereof on March 15, June 15, September 15 and December 15, when and if such dividend has been declared by Whiting’s board of directors. Each share of preferred stock has a liquidation preference of $100.00 per share plus accumulated and unpaid dividends and is convertible, at a holder’s option, into shares of Whiting’s common stock based on a conversion price of $21.70815, subject to adjustment upon the occurrence of certain events. The preferred stock is not redeemable by the Company. At any time on or after June 15, 2013, the Company may cause all outstanding shares of this preferred stock to be converted into shares of common stock if the closing price of our common stock equals or exceeds 120% of the then-prevailing conversion price for at least 20 trading days in a period of 30 consecutive trading days. The holders of preferred stock have no voting rights unless dividends payable on the preferred stock are in arrears for six or more quarterly periods.
Equity Incentive Plan—The Company maintains the Whiting Petroleum Corporation 2003 Equity Incentive Plan (the “Equity Plan”), pursuant to which 2,978,323 shares of the Company’s common stock have been reserved for issuance. 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. As of March 31, 2012, 1,066,089 shares of common stock remained available for grant under the Plan.
For the three months ended March 31, 2012 and 2011, total stock compensation expense recognized for restricted share awards and stock options was $4.2 million and $3.2 million, respectively.
Restricted Shares. Restricted stock awards for executive officers, directors and employees generally vest ratably over a three-year service period. The Company uses historical data and projections to estimate expected employee behaviors related to restricted stock forfeitures. The expected forfeitures are then included as part of the grant date estimate of compensation cost. For service-based restricted stock awards, the grant date fair value is determined based on the closing bid price of the Company’s common stock on the grant date.
In January 2012 and 2011, 444,501 shares and 201,420 shares, respectively, of restricted stock, subject to certain market-based vesting criteria in addition to the standard three-year service condition, were granted to executive officers under the Equity Plan. Vesting each year is subject to the condition that Whiting’s stock price increases by a greater percentage, or decreases by a lesser percentage, than the average percentage increase or decrease, respectively, of the stock prices of a peer group of companies. The market-based conditions must be met in order for the stock awards to vest, and it is therefore possible that no shares could vest in one or more of the three-year vesting periods. However, the Company recognizes compensation expense for awards subject to market conditions regardless of whether it becomes probable that these conditions will be achieved or not, and compensation expense is not reversed if vesting does not actually occur.
For these awards subject to market conditions, the grant date fair value was estimated using a Monte Carlo valuation model. The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility was calculated based on the historical volatility of Whiting’s common stock, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with the three-year vesting period. The key assumptions used in valuing the market-based restricted shares were as follows:
The grant date fair value of the market-based restricted stock as determined by the Monte Carlo valuation model was $29.45 per share in January 2012 and $42.20 per share in January 2011.
The following table shows a summary of the Company’s nonvested restricted stock as of March 31, 2012 as well as activity during the three months then ended:
As of March 31, 2012, there was $22.5 million of total unrecognized compensation cost related to unvested restricted stock granted under the stock incentive plans. That cost is expected to be recognized over a weighted average period of 2.6 years.
Stock Options. In January 2012 and 2011, 45,358 stock options and 80,820 stock options, respectively, were granted under the Equity Plan to certain executive officers of the Company with exercise prices equal to the closing market price of the Company’s common stock on the grant date. These stock options vest ratably over a three-year service period from the grant date and are exercisable immediately upon vesting through the tenth anniversary of the grant date.
The Company uses a Black-Scholes option-pricing model to estimate the fair value of stock option awards. Because the Company first granted stock options in 2009, it does not have historical exercise data upon which to estimate the expected term of the options. As such, the Company has elected to estimate the expected term of the stock options granted using the “simplified” method for “plain vanilla” options. The expected volatility at the grant date is based on the historical volatility of Whiting’s common stock, and the risk-free interest rate is determined based on the yield on U.S. Treasury strips with maturities similar to those of the expected term of the stock options. The following table summarizes the assumptions used to estimate the grant date fair value of stock options awarded in each respective period:
The grant date fair value of the stock options awarded, as determined by the Black-Scholes valuation model, was $28.88 per share in January 2012 and $34.15 per share in January 2011.
The following table shows a summary of the Company’s stock options outstanding as of March 31, 2012 as well as activity during the three months then ended (aggregate intrinsic value presented in thousands):
Unrecognized compensation cost as of March 31, 2012 related to unvested stock option awards was $2.2 million, which is expected to be recognized over a period of 2.3 years.
Noncontrolling Interest—The noncontrolling interest represents an unrelated third party’s 25% ownership interest in SWR. The table below summarizes the activity for the equity attributable to the noncontrolling interest (in thousands):
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 months ended March 31, 2012 and 2011 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.
The reconciliations between basic and diluted earnings per share are as follows (in thousands, except per share data):
For the three months ended March 31, 2012, the diluted earnings per share calculation excludes the effect of 7,006 common shares for stock options that were out-of-the-money. For the three months ended March 31, 2011, the diluted earnings per share calculation excludes the effect of 794,330 incremental common shares (which were issuable upon the conversion of perpetual preferred stock as of a January 1, 2011 assumed conversion date) because their effect was anti-dilutive.
In May 2011, the FASB issued Accounting Standards Update No. 2011-04, Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”), which provides amendments to FASB ASC Topic 820, Fair Value Measurement. The objective of ASU 2011-04 is to create common fair value measurement and disclosure requirements between GAAP and International Financial Reporting Standards (“IFRS”). The amendments clarify existing fair value measurement and disclosure requirements and make changes to particular principles or requirements for measuring or disclosing information about fair value measurements. These amendments are not having a significant impact on companies applying GAAP. ASU 2011-04 was effective for interim and annual periods beginning after December 15, 2011. The Company adopted this standard effective January 1, 2012, which did not have an impact on the Company’s consolidated financial statements other than additional disclosures.
In June 2011, the FASB issued Accounting Standards Update No. 2011-05, Comprehensive Income: Presentation of Comprehensive Income (“ASU 2011-05”), which provides amendments to FASB ASC Topic 220, Comprehensive Income. The objective of ASU 2011-05 is to require an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. ASU 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of equity. ASU 2011-05 is effective for interim and annual periods beginning after December 15, 2011 and is to be applied retrospectively. In December 2011, the FASB issued Accounting Standards Update No. 2011-12, Comprehensive Income: Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (“ASU 2011-12”), which defers the effective date of changes in ASU 2011-05 that relate to the presentation of reclassification adjustments out of accumulated other comprehensive income. The amendments in this update are effective at the same time as the amendments in ASU 2011-05. The Company adopted the provisions of ASU 2011-05 and 2011-12 effective January 1, 2012, which did not have an impact on its consolidated financial statements other than requiring the Company to present its statements of comprehensive income separately from its statements of equity, as these statements were previously presented on a combined basis.
In December 2011, the FASB issued Accounting Standards Update No. 2011-11, Balance Sheet: Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). The objective of ASU 2011-11 is to require an entity to provide enhanced disclosures that will enable users of its financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. ASU 2011-11 is effective for interim and annual reporting periods beginning on or after January 1, 2013 and should be applied retrospectively. The adoption of this standard will not have an impact on the Company’s consolidated financial statements.
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 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.
We are an independent oil and gas company engaged in exploration, development, acquisition and production activities primarily in the Rocky Mountains, Permian Basin, Mid-Continent, Michigan and Gulf Coast regions of the United States. Prior to 2006, we generally emphasized the acquisition of properties that increased our production levels and provided upside potential through further development. Since 2006, we have focused primarily 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. We believe the combination of acquisitions, subsequent development and organic drilling provides us a broad set of growth alternatives and allows us to direct our capital resources to what we believe to be the most advantageous investments.
As demonstrated by our recent capital expenditure programs, we are increasingly focused on a balanced exploration and development program, while continuing to selectively pursue acquisitions that complement our existing core properties. We believe that our significant drilling inventory, combined with our operating experience and cost structure, provides us with meaningful organic growth opportunities. Our growth plan is centered on the following activities:
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. We 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.
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. 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 2010:
Lower oil 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 or natural gas prices may result in impairments of our proved oil and gas properties 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 oil and gas prices may also reduce the amount of our borrowing base under our credit agreement, which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders. Alternatively, higher oil and natural gas prices may result in significant non-cash, mark-to-market losses being incurred on our commodity-based derivatives, which may in turn cause us to experience net losses.
First Quarter 2012 Highlights and Future Considerations
Lewis & Clark/Pronghorn. Our Lewis & Clark/Pronghorn prospects are located primarily in the Stark and Billings counties of North Dakota and run along the Bakken shale pinch-out in the southern Williston Basin. In this area, the Upper Bakken shale is thermally mature, moderately over-pressured, and we believe that it has charged reservoir zones within the immediately underlying Pronghorn Sand and Three Forks formations. Net production in the Lewis & Clark/Pronghorn prospects averaged 9.1 MBOE/d in the first quarter of 2012, representing a 54% increase from 5.9 MBOE/d in the fourth quarter of 2011. We currently have five drilling rigs operating in the Pronghorn prospect and one drilling rig operating in the Lewis & Clark prospect.
In December 2011, we completed and commissioned the gas processing plant located south of Belfield, North Dakota, which will have a processing capacity of 30 MMcf/d and which will primarily process production from the Pronghorn area. Currently there is inlet compression in place to process 24 MMcf/d, and as of March 31, 2012 the plant was processing 7.6 MMcf/d.
Hidden Bench/Tarpon. Our Hidden Bench and Tarpon prospects in McKenzie County, North Dakota target the Bakken and Three Forks formations. Net production from the Hidden Bench/Tarpon prospects averaged 2.2 MBOE/d in the first quarter of 2012, which represents a 27% increase from 1.8 MBOE/d in the fourth quarter of 2011.
Sanish. Our Sanish field in Mountrail County, North Dakota targets the Bakken and Three Forks formations. Net production in the Sanish field averaged 28.8 MBOE/d for the first quarter of 2012, representing a 26% increase from 22.9 MBOE/d in the fourth quarter of 2011. During the first quarter of 2012, we completed 15 operated wells, bringing the total number of producing wells in the field to 233.
North Ward Estes. The North Ward Estes field is located in the Ward and Winkler counties in Texas, and we continue to have significant development and related infrastructure activity in this field since we acquired it in 2005. Our activity at North Ward Estes to date has resulted in substantial reserve additions and production increases, and our expansion of the CO2 flood in this area continues to generate positive results.
North Ward Estes has been responding positively to the water and CO2 floods that we initiated in May 2007. In the first quarter of 2012, production from North Ward Estes averaged 8.8 MBOE/d, which was consistent with production rates in the fourth quarter of 2011. We are currently injecting approximately 325 MMcf/d of CO2 into the field, over half of which is recycled.
Postle. The Postle field is located in Texas County, Oklahoma and produces from the Morrow sandstone. Postle averaged 8.3 MBOE/d in the first quarter of 2012, which represents a 3% increase from 8.1 MBOE/d in the fourth quarter of 2011. We are currently injecting approximately 120 MMcf/d of CO2 into the field, over half of which is recycled.
Big Tex. Our Big Tex prospect in Pecos, Reeves and Ward counties, Texas targets the Brushy Canyon, Bone Spring and Wolfcamp horizons. We have increased our planned capital expenditures and drilling activity in the Big Tex prospect from a 13-well drilling program to a 17-well program. These wells will be a mixture of vertical Wolfcamp and Wolfbone wells, horizontal Wolfcamp wells and horizontal Bone Spring wells.
Redtail. Our Redtail prospect in Weld County, Colorado targets the Niobrara formation. In late 2010, we initiated a seven-well exploratory drilling program (five horizontal and two vertical monitor wells) in the Niobrara formation. Based on the results of our exploratory drilling program and recently acquired 3-D seismic data, we increased our previous eight-well drilling program for 2012 to a 17-well program, of which two were drilled in the first quarter of 2012. We plan to resume drilling operations at our Redtail prospect in June 2012.
Acquisition and Divestiture Highlights. On March 22, 2012, we completed the acquisition of approximately 13,300 net undeveloped acres in the Missouri Breaks prospect in Richland County, Montana for $33.3 million.
Whiting USA Trust II. On March 28, 2012, we completed an initial public offering of units of beneficial interest in Whiting USA Trust II (“Trust II”), selling 18,400,000 Trust II units at $20.00 per unit, providing net proceeds of $323.6 million after underwriters’ fees, offering expenses and post-close adjustments. We used the net offering proceeds to repay a portion of the debt outstanding under our credit agreement. The net proceeds from the sale of Trust II units to the public resulted in a deferred gain on sale of $129.5 million. Immediately prior to the closing of the offering, we conveyed a term net profits interest in certain of our oil and gas properties to Trust II in exchange for 18,400,000 trust units.
The net profits interest entitles Trust II to receive 90% of the net proceeds from the sale of oil and natural gas production from the underlying properties. The net profits interest will terminate on the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold. This is the equivalent of 10.61 MMBOE in respect of Trust II’s right to receive 90% of the net proceeds from such reserves pursuant to the net profits interest. The conveyance of the net profits interest to Trust II consisted entirely of proved reserves of 10.61 MMBOE as of the January 1, 2012 effective date, representing 3% of our proved reserves as of December 31, 2011 and 5% (or 4.5 MBOE/d) of our March 2012 average daily net production.
Results of Operations
Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011
Oil and Natural Gas Sales. Our oil and natural gas sales revenue increased $133.0 million to $558.7 million in the first quarter of 2012 compared to the same period in 2011. Sales are a function of oil and gas volumes sold and average commodity prices realized. Our oil sales volumes increased 31% between periods, while our natural gas sales volumes decreased 6%. The oil volume increase resulted primarily from drilling success at our Lewis & Clark field, Sanish and Parshall fields and Hidden Bench prospect. During the first quarter of 2012, oil production from our Lewis & Clark field increased 640 MBbl, while oil production from our Sanish and Parshall fields increased 490 MBbl, and oil production from our Hidden Bench prospect increased 180 MBbl over the same period in 2011. Gas production volumes decreased between periods primarily due to normal field production decline across many of our areas. During the first quarter of 2012, gas production at our Flat Rock field decreased 840 MMcf and gas production at our Canyon field decreased 210 MMcf compared to the first quarter of 2011. These gas volume decreases were partially offset by increased gas production of 370 MMcf at our Lewis and Clark field and 255 MMcf at our Sanish and Parshall fields due to new wells drilled and completed in these areas during the last twelve months.
Also contributing to the increase in oil and gas sales revenue in 2012 was an increase in the average sales price realized for oil. Our average price for oil before the effects of hedging increased 5% between periods. Our average price for natural gas before the effects of hedging, on the other hand, decreased 31% which was mainly due to lower average NYMEX prices during 2012.
Gain (Loss) on Hedging Activities. Our gain on hedging activities decreased $1.9 million in 2012 as compared to the first quarter of 2011, and it consisted of the following (in thousands):
Effective April 1, 2009, we elected to de-designate all of our commodity derivative contracts that had been previously designated as cash flow hedges, and we elected to discontinue all hedge accounting prospectively. Accordingly, each period we reclassify from accumulated other comprehensive income (“AOCI”) into earnings unrealized gains (which were frozen in AOCI on the April 1, 2009 de-designation date) upon the expiration of these de-designated crude oil hedges, and we report such non-cash unrealized gains as gain on hedging activities.
See Item 3, “Quantitative and Qualitative Disclosures about Market Risk,” for a list of our outstanding oil and natural gas derivatives as of April 1, 2012.
Lease Operating Expenses. Our lease operating expenses (“LOE”) during the first quarter of 2012 were $94.8 million, a $23.3 million increase over the same period in 2011. This rise in LOE in 2012 was related to a $19.0 million increase in the cost of oil field goods and services associated with net wells we added during the last twelve months, as well as a higher level of workover activity. Workovers increased to $26.3 million in the first quarter of 2012, as compared to $22.0 million in the first quarter of 2011, primarily due to a higher number of well workovers being conducted on our two main CO2 projects and at our Sanish and Parshall fields.
Our lease operating expenses on a BOE basis also increased to $12.90 during the first quarter of 2012 from $12.04 during the first quarter of 2011. This increase on a BOE basis was mainly due to higher costs of oil field goods and services and the higher amount of workover activity in 2012, as discussed above. These cost increases incurred during the first quarter of 2012 were partially offset by higher overall production volumes between periods.
Production Taxes. Our production taxes during the first quarter of 2012 were $44.6 million, a $13.0 million increase over the same period in 2011, which increase was primarily due to higher oil and natural gas sales between periods. However, our production taxes are generally calculated as a percentage of oil and natural gas sales revenue before the effects of hedging, and this percentage on a company-wide basis remained relatively consistent between periods at 8.0% and 7.4% for the first quarter of 2012 and 2011, respectively. In addition, we take advantage of credits and exemptions allowed in our various taxing jurisdictions.
Depreciation, Depletion and Amortization. Our depreciation, depletion and amortization (“DD&A”) expense increased $48.4 million in 2012 as compared to the first quarter of 2011. The components of our DD&A expense were as follows (in thousands):
DD&A increased in the first quarter of 2012 primarily due to $48.2 million in higher depletion expense between periods. This increase was the result of $29.4 million in higher depletion due to a rise in overall production volumes during the first quarter of 2012 and $18.8 million in higher depletion due to an increase in our depletion rate between periods. On a BOE basis, our DD&A rate of $21.25 for the first quarter of 2012 was 17% higher than the rate of $18.14 for the same period in 2011. The higher DD&A rate was mainly due to $1,760.1 million in drilling and development expenditures during the past twelve months, which was partially offset by reserve additions during this same time period.
Exploration and Impairment Costs. Our exploration and impairment costs increased $5.3 million in the first quarter of 2012 as compared to the first quarter of 2011. The components of our exploration and impairment costs were as follows (in thousands):
Exploration costs decreased $4.9 million during the first quarter of 2012 as compared to the same period in 2011 primarily due to a decrease in geological and geophysical (“G&G”) activity and lower exploratory dry hole costs. G&G costs, such as seismic studies, amounted to $3.0 million during the first quarter of 2012 as compared to $6.6 million during the same period in 2011. We did not drill any exploratory dry holes during the three months ended March 31, 2012, while we drilled three exploratory dry holes in the Rocky Mountain, Permian Basin and Gulf Coast regions totaling $2.9 million during the first three months of 2011. These decreases in exploration costs were partially offset by an increase of $1.5 million in geology related general and administrative expenses.
Impairment expense in the first quarter of 2012 and 2011 primarily related to the amortization of leasehold costs associated with individually insignificant unproved properties. Undeveloped leasehold costs of $12.8 million were amortized to impairment on a group basis f