XNYS:KOG Kodiak Oil & Gas Corp. Quarterly Report 10-Q Filing - 6/30/2012
Effective Date 6/30/2012
| • 10-Q • EX-23.1 • EX-31.1 • EX-31.2 • EX-32.1 • EX-32.2 • EX-99.1 • XBRL INSTANCE DOCUMENT • XBRL TAXONOMY EXTENSION SCHEMA DOCUMENT • XBRL TAXONOMY EXTENSION CALCULATION LINKBASE DOCUMENT • XBRL TAXONOMY EXTENSION DEFINITION LINKBASE DOCUMENT • XBRL TAXONOMY EXTENSION LABELS LINKBASE DOCUMENT • XBRL TAXONOMY EXTENSION PRESENTATION LINKBASE DOCUMENT | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
UNITED STATES Washington, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2012
Commission File No. 001-32920
(Exact name of registrant as specified in its charter)
1625 Broadway, Suite 250 Denver, Colorado 80202 (Address of principal executive offices, including zip code)
(303) 592-8075 (Registrant’s telephone number, including area code)
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 x No o
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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o
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 definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
263,689,108 shares, no par value, of the Registrant’s common stock were issued and outstanding as of August 1, 2012.
KODIAK OIL & GAS CORP.
KODIAK OIL & GAS CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (In thousands, except share data) (Unaudited)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
KODIAK OIL & GAS CORP. CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except share data) (Unaudited)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
KODIAK OIL & GAS CORP. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) (Unaudited)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
KODIAK OIL & GAS CORP. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 1—Organization
Description of Operations
Kodiak Oil & Gas Corp. and its subsidiary (“Kodiak” or the “Company”) is a public company listed for trading on the New York Stock Exchange under the symbol: “KOG”. The Company’s corporate headquarters are located in Denver, Colorado, USA. The Company is an independent energy company engaged in the exploration, exploitation, development, acquisition and production of crude oil and natural gas in the Rocky Mountain region of the United States.
The Company was incorporated (continued) in the Yukon Territory on September 28, 2001.
Note 2—Basis of Presentation and Significant Accounting Policies
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements include the accounts of the Company and its wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc. All significant inter-company balances and transactions have been eliminated in consolidation. The Company’s business is transacted in US dollars and, accordingly, the financial statements are expressed in US dollars. The financial statements included herein were prepared from the records of the Company in accordance with generally accepted accounting principles in the United States (“GAAP”) for interim financial information and the instructions to Form 10-Q and Regulation S-X and S-K. In the opinion of management, all adjustments, consisting of normal recurring accruals that are considered necessary for a fair presentation of the interim financial information, have been included. However, operating results for the periods presented are not necessarily indicative of the results that may be expected for a full year. Kodiak’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 Kodiak’s 2011 Annual Report on Form 10-K.
The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant areas requiring the use of assumptions, judgments and estimates include (1) oil and gas reserves; (2) cash flow estimates used in ceiling test of oil and natural gas properties; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) accrued revenue and related receivables; (7) valuation of commodity derivative instruments; (8) accrued liabilities; (9) valuation of share-based payments and (10) income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company evaluates our estimates on an on-going basis and bases our estimates on historical experience and on various other assumptions the Company believes to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, the Company believes that our estimates are reasonable.
Impairment of Oil and Gas Properties
Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are subject to amortization. Should capitalized costs exceed this ceiling, an impairment is recognized.
Wells in Progress
Wells in progress represent the costs associated with wells that have not reached total depth or been completed as of period end. These costs are related to wells that are classified as both proved and unproved. Costs related to wells that are classified as proved are included in the depletion base. Costs associated with wells that are classified as unproved are excluded from the depletion base. The costs for unproved wells are then transferred to proved property when proved reserves are determined. The costs then become subject to depletion.
Reclassifications
The Company has condensed certain line items within the current period financial statements, and certain prior period balances were reclassified to conform to the current year presentation accordingly. Such reclassifications had no impact on net income, statements of cash flows, working capital or equity previously reported.
Recently Issued Accounting Standards
In May 2011, the FASB issued Accounting Standards Update 2011-04 (“ASU 2011-04”), Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. ASU 2011-04 changes the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements to ensure consistency between U.S. GAAP and International Financial Reporting Standards (“IFRS”). ASU 2011-04 also expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. This new guidance is applied prospectively. ASU 2011-04 was made effective for interim and annual periods beginning after December 15, 2011, with early adoption permitted. The Company believes that the adoption of this standard did not materially expand the condensed consolidated financial statement footnote disclosures.
Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date, are not expected to have a material impact on the financial statements upon adoption.
Note 3—Acquisitions
January 2012 Acquisition
On January 10, 2012, the Company acquired two separate private, unaffiliated oil and gas company’s interests in approximately 50,000 net acres of Williston Basin leaseholds, and related producing properties located primarily in McKenzie and Williams Counties, North Dakota, along with various other related rights, permits, contracts, equipment and other assets, including the assignment and assumption of a drilling rig contract for a combination of cash and stock. The sellers received an aggregate of 5.1 million shares of Kodiak’s common stock valued at approximately $49.8 million and cash consideration of approximately $588.4 million. The effective date for the acquisition was September 1, 2011, with purchase price adjustments calculated as of the closing date on January 10, 2012. The acquisition provided strategic additions adjacent to the Company’s core project area and the acquired producing wells contributed revenue of $8.8 million and $20.3 million to Kodiak for the three and six months ended June 30, 2012, respectively. Total transaction costs related to the acquisition were approximately $295,000, of which $0 and $85,000 were recorded in the statement of operations within the general and administrative expenses line item for the three and six months ended June 30, 2012, respectively. There were no transaction costs related to the acquisition recorded in the statement of operations within the general and administrative expenses line item for the three and six months ended June 30, 2011. No material costs were incurred for the issuance of the 5.1 million shares of common stock.
The acquisition is accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of January 10, 2012. In July 2012, the Company completed the transaction’s post-closing settlement. The following table summarizes the preliminary purchase price and the preliminary estimated values of assets acquired and liabilities assumed and is subject to revision as the Company continues to evaluate the fair value of the acquisition (in thousands):
* The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company’s closing stock price of $9.85 on the measurement date of January 10, 2012.
October 2011 Acquisition
On October 28, 2011, the Company acquired a private, unaffiliated oil and gas company’s interests in approximately 13,400 net acres of Williston Basin leaseholds, and related producing properties located primarily in Williams County, North Dakota along with various other related rights, permits, contracts, equipment and other assets. The seller received cash consideration of approximately $248.2 million and the effective date was August 1, 2011, with purchase price adjustments calculated as of the closing date on October 28, 2011. The total purchase included approximately $239.9 million related to the acquisition of the properties and approximately $8.6 million related to the assumption of certain working capital items. The acquisition provided strategic additions adjacent to the Company’s core project area and the acquired producing wells contributed revenue of $7.1 million and $15.6 million to Kodiak for the three and six months ended June 30, 2012, respectively. Total transaction costs related to the acquisition incurred were approximately $200,000. Transaction costs are recorded in the statement of operations within the general and administrative expenses line item. No transaction costs for this acquisition were recorded within the three and six months ended June 30, 2012 and 2011.
The acquisition is accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of October 28, 2011. In February 2012, the Company completed the transaction’s post-closing settlement. The following table summarizes the preliminary purchase price and the preliminary estimated values of assets acquired and liabilities assumed and is subject to revision as the Company continues to evaluate the fair value of the acquisition (in thousands):
June 2011 Acquisition
On June 30, 2011,the Company acquired a private, unaffiliated oil and gas company’s interests in approximately 25,000 net acres of Williston Basin leaseholds and related producing properties located in McKenzie County, North Dakota along with various other related rights, permits, contracts, equipment and other assets for a combination of cash and stock. The seller received 2.5 million shares of Kodiak’s common stock valued at approximately $14.4 million and cash consideration of approximately $71.5 million. The effective date for the acquisition was April 1, 2011, with purchase price adjustments calculated as of the closing date on June 30, 2011. The acquisition provided strategic additions to the Company’s core positions in Koala, Smokey and Grizzly Project areas and the acquired producing wells contributed revenue of $400,000 and $836,000 to Kodiak for the three and six months ended June 30, 2012, respectively. Total transaction costs related to the acquisition were approximately $265,000. There were no transaction costs related to the acquisition recorded in the statement of operations, within the general and administrative expenses line item, for the three and six months ended June 30, 2012. Transaction costs of $245,000 were recorded within the general and administrative expenses line item for the three and six months ended June 30, 2011, respectively. Costs of $85,000 for issuing and registering with the SEC for the resale of 2.5 million shares of common stock were charged to common stock.
The acquisition is accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of June 30, 2011. The transaction’s final settlement was completed in September 2011 resulting in no material changes. Of the $85.9 million purchase price, $8.0 million was allocated to proved oil and gas properties, $77.8 million was allocated to unproved oil and gas properties and the remaining $100,000 was working capital and asset retirement obligation adjustments.
Pro Forma Financial Information
The following unaudited pro forma financial information represents the combined results for the Company and the properties acquired in January 2012, October 2011 and June 2011 for the three and six months ended June 30, 2012 and 2011 as if the acquisitions had occurred on January 1, 2011 (in thousands, except per share data). For purposes of the pro forma it was assumed that the $650.0 million 8.125% Senior Notes were issued on January 1, 2011 and that the stand-by bridge was not utilized. The pro forma information includes the effects of adjustments for depletion, depreciation, amortization and accretion expense of $0 and $600,000 for the three and six months ended June 30, 2012, respectively, as compared to $6.5 million and $10.9 million for the three and six months ended June 30, 2011, respectively. The pro forma information includes the effects of adjustments for amortization of financing costs of $400,000 and $800,000 for the three and six months ended June 30, 2011, respectively. For the three and six months ended June 30, 2012, there was no pro forma adjustments for the amortization of deferred financing costs. For the three and six months ended June 30, 2012, there was a pro forma adjustment reducing interest expense of $0 and $400,000, respectively. For the three and six months ended June 30, 2011, there was no pro forma adjustment for interest expense. The pro forma financial information includes total capitalization of interest expense of $12.9 million and $24.9 million for the three and six months ended June 30, 2012, respectively, as compared to $14.3 million and $28.6 million for the three and six months ended June 30, 2011, respectively. The pro forma results do not include any cost savings or other synergies that may result from the acquisitions or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisitions had been completed as of the beginning of the period, nor are they necessarily indicative of future results.
Note 4—Long-Term Debt
As of the dates indicated, the Company’s long-term debt consisted of the following (in thousands):
Credit Facility
Kodiak Oil & Gas (USA) Inc. (the “Borrower”), a wholly-owned subsidiary of Kodiak Oil & Gas Corp., has in place a credit agreement (“credit facility”) with a syndicate of banks. The maximum credit available under the credit facility is $750.0 million with a borrowing base of $225.0 million at June 30, 2012. Redetermination of the borrowing base occurs semi-annually, on April 1 and October 1. Additionally, the Company may elect a redetermination of the borrowing base one time during any six month period. In July 2012, the Company elected an unscheduled interim redetermination of its borrowing base. As a result, the borrowing base was increased to $375.0 million effective August 2, 2012. The credit facility matures on October 28, 2016.
Interest on the credit facility is payable at one of the following two variable rates: the alternate base rate for ABR loans or the adjusted LIBO rate for Eurodollar loans, as selected by the Company, plus an additional percentage that can vary on a daily basis and is based on the daily unused portion of the facility. This additional percentage is referred to as the “Applicable Margin” and varies depending on the type of loan. The Applicable Margin for the ABR loans is a sliding scale of 0.75% to 1.75%, depending on borrowing base usage. The Applicable Margin on the adjusted LIBO rate is a sliding scale of 1.75% to 2.75%, depending on borrowing base usage. Additionally, the credit facility provides for a borrowing base fee of 0.5% and a commitment fee of 0.375% to 0.50%, depending on borrowing base usage. The grid below shows the Applicable Margin options depending on the applicable Borrowing Base Utilization Percentage (as defined in the Credit Agreement) as of June 30, 2012 and the date of this filing:
Borrowing Base Utilization Grid
The credit facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on dividends, distributions, redemptions and restricted payments covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on the sale of property, mergers, consolidations and other similar transactions covenants. Additionally, the credit facility requires the Borrower to enter hedging agreements necessary to support the borrowing base.
The credit facility also contains financial covenants requiring the Borrower to comply with a current ratio of consolidated current assets (including unused borrowing capacity) to consolidated current liabilities of not less than 1.0:1.0 and to maintain, on the last day of each quarter, a ratio of total debt to EBITDAX of not greater than (i) 4.75 to 1.0 at the end of each of the two fiscal quarters ending December 31, 2011 and March 31, 2012, (ii) 4.50 to 1.0 at the end of the fiscal quarter ending June 30, 2012, (iii) 4.25 to 1.0 at the end of the fiscal quarter ending September 30, 2012, and (iv) 4.0 to 1.0 at the end of each fiscal quarter thereafter. As of June 30, 2012, the Company was in compliance with all financial covenants under the credit facility.
As of June 30, 2012, the Company had no outstanding borrowings under the credit facility and as such, the available credit under the credit facility at that date was $225.0 million. Subsequent to June 30, 2012, the Company borrowed $20 million which is currently outstanding. Any borrowings under the credit facility are collateralized by the Borrower’s oil and gas producing properties, the Borrower’s personal property and the equity interests of the Borrower held by the Company. The Company has entered into crude oil hedging transactions with Wells Fargo. The Company’s obligations under the hedging contracts with Wells Fargo are secured by the credit facility.
Second Lien Credit Agreement
On January 10, 2012, the Company terminated the second lien credit agreement and repaid the $100.0 million of outstanding debt, and incurred a $3.0 million prepayment penalty in connection therewith. The Company recorded the $3.0 million prepayment penalty in the first quarter of 2012 within the interest income (expense), net line item of the statement of operations.
Senior Notes
In November 2011, the Company issued at par $650.0 million of 8.125% Senior Notes due December 1, 2019 (the “Senior Notes”). On May 17, 2012, the Company issued an additional $150.0 million aggregate principal amount of our existing 8.125% Senior Notes at a price of 104.0% of par, resulting in net proceeds of $151.8 million, after deducting discounts and fees. The net proceeds from the May 2012 offering were used to repay all borrowings on the credit facility and to fund the Company’s ongoing capital expenditure program and general corporate purposes. The interest on the Senior Notes is payable on June and December 1 of each year, beginning June 1, 2012. The Senior Notes were issued under an Indenture, dated as of November 23, 2011 (the “Indenture”) among the Company, Kodiak Oil & Gas (USA) Inc. (the “Guarantor”), U.S. Bank National Association, as the trustee (the “Trustee”) and Computershare Trust Company of Canada, as the Canadian trustee. The Indenture contains affirmative and negative covenants that, among other things, limit the Company’s and the Guarantor’s ability to make investments; incur additional indebtedness or issue preferred stock; create liens; sell assets; enter into agreements that restrict dividends or other payments by restricted subsidiaries; consolidate, merge or transfer all or substantially all of the assets of the Company; engage in transactions with the Company’s affiliates; pay dividends or make other distributions on capital stock or prepay subordinated indebtedness; and create unrestricted subsidiaries. The Indenture also contains customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the Senior Notes shall become due and payable immediately without any declaration or other act of the Trustee or the holders of the Senior Notes. Upon the occurrence of certain other events of default, the Trustee or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately. The Company was in compliance with all financial covenants under its Senior Notes as of June 30, 2012, and through the filing of this report.
The Senior Notes are redeemable by the Company at any time on or after December 1, 2015, at the redemption prices set forth in the Indenture. The Senior Notes are redeemable by the Company prior to December 1, 2015, at the redemption prices plus a “make-whole” premium set forth in the Indenture. The Company is also entitled to redeem up to 35% of the aggregate principal amount of the Senior Notes before December 1, 2014 with net proceeds that the Company raises in equity offerings at a redemption price equal to 108.125% of the principal amount of the Senior Notes being redeemed, plus accrued and unpaid interest. If the Company undergoes a change of control on or prior to January 1, 2013, it may redeem all, but not less than all, of the Senior Notes at a redemption price equal to 110% of the principal amount of the Senior Notes redeemed plus accrued and unpaid interest. The Company estimates that the fair value of this option is immaterial at June 30, 2012.
The Senior Notes are jointly and severally guaranteed on a senior basis by the Guarantor and by certain of the Company’s future subsidiaries. The Senior Notes and the guarantees thereof will be the Company and the Guarantor’s general senior obligations and will, prior to the release of the amounts held in escrow, be secured by the net proceeds of the Company’s offer and sale of the Senior Notes and certain other funds held in the escrow account pursuant to an escrow agreement (upon release of such escrow property, the Senior Notes will not be secured), rank senior in right of payment to any of the Company’s and the Guarantor’s future subordinated indebtedness, rank equal in right of payment with any of the Company’s and the Guarantor’s existing and future senior indebtedness, rank effectively junior in right of payment to the Company’s and the Guarantor’s existing and future secured indebtedness (including indebtedness under the Company’s credit facility), to the extent of the value of the Company’s and the Guarantor’s assets constituting collateral securing such indebtedness, and rank effectively junior in right of payment to any indebtedness or liabilities of any the Company’s future subsidiaries of any subsidiary that does not guarantee the Senior Notes.
In connection with the sale of the Senior Notes, the Company entered into a registration rights agreement that provides the holders of the Senior Notes certain rights relating to the registration of the Senior Notes under the Securities Act. Pursuant to the registration rights agreement, the Company agreed to conduct a registered exchange offer for the Senior Notes or cause to become effective a shelf registration statement providing for the resale of the Senior Notes, each in accordance with the terms of the agreement. If the Company fails to comply with certain obligations under the agreement, it will be required to pay liquidated damages by way of additional interest on the Senior Notes. On July 20, 2012, the Company filed a registration statement on Form S-4 (No. 333-182783) with the SEC in accordance with such registration rights agreement, although the registration statement is not yet effective.
Deferred Financing Costs
As of June 30, 2012, the Company had deferred financing costs of $25.1 million related to its credit facility and Senior Notes. Deferred financing costs include origination, legal, engineering, and other fees incurred in connection with the Company’s credit facilities and Senior Notes. The Company recorded amortization expense for the three and six months ended June 30, 2012 of $690,000 and $1.3 million, respectively, as compared to $200,000 and $387,000 for the three and six months ended June 30, 2011, respectively.
Interest Incurred On Long-Term Debt
Total interest expense incurred during the three and six months ended June 30, 2012 was approximately $15.0 million and $28.5 million, respectively, as compared to $1.1 million and $2.2 million for the three and six months ended June 30, 2011, respectively. The Company capitalized interest costs of $12.0 million and $24.5 million for the three and six months ended June 30, 2012, respectively, as compared to $1.1 million and $2.2 million for the three and six months ended June 30, 2011, respectively.
Note 5— Income Taxes
The Company computes its quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to its year-to-date income or loss. As of March 31, 2012, the Company had not generated taxable income to-date and had incurred a cumulative book loss over the previous three fiscal years, which led the Company to provide a valuation allowance against both U.S. and Canadian net deferred tax assets, since it could not conclude that it is more likely than not that the net deferred tax assets would be fully realized.
During the second quarter of 2012, the Company concluded that it is more likely than not that it would be able to realize the benefits of its U.S. deferred tax assets, and that it was appropriate to release the U.S. valuation allowance against it. This decision was based on the fact that for the three-year period ended June 30, 2012, the Company has reported positive cumulative net income. Additionally, for the three months ended June 30, 2012, the Company recognized income before taxes of $119.0 million. As a result of the second quarter 2012 income before income taxes, the Company is in a net deferred tax liability position as of June 30, 2012.
The Company continues to provide a full valuation allowance on the Canadian net deferred tax assets as ultimate realization of these deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income and tax planning strategies in making this assessment. As the Company does not have revenue generating assets in Canada, the Company does not expect to utilize the Canadian net deferred tax assets. The Company will continue to evaluate whether a valuation allowance on a separate country basis is needed in future reporting periods.
The effective tax rate for the six months ended June 30, 2012, was 22.33%, which differs from the statutory federal income tax rate as shown in the below table. Our actual effective tax rate for 2012 could vary significantly from this rate based on our actual results. For the three and six months ended June 30, 2011, no income tax expense was recognized.
The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of June 30, 2012, the Company had no provision for interest or penalties related to uncertain tax positions. The Company files income tax returns in Canada and U.S. federal jurisdiction and various states. There are currently no Canadian or U.S. federal or state income tax examinations underway for these jurisdictions. Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue Service, state or local tax authorities for tax years ended on or before December 31, 2007 or Canadian tax examinations by the Canadian Revenue Agency for tax years ended on or before December 31, 2001. Although certain tax years are closed under the statute of limitations, tax authorities can still adjust tax losses being carried forward to open tax years.
Note 6— Commodity Derivative Instruments
Through its wholly-owned subsidiary Kodiak Oil & Gas (USA) Inc., the Company has entered into commodity derivative instruments, as described below. The Company has utilized swaps or “no premium” collars to reduce the effect of price changes on a portion of our future oil production. A swap requires us to pay the counterparty if the settlement price exceeds the strike price and the same counterparty is required to pay us if the settlement price is less than the strike price. A collar requires us to pay the counterparty if the settlement price is above the ceiling price and requires the counterparty to pay us if the settlement price is below the floor price. The objective of the Company’s use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.
The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with three counterparties. The Company has netting arrangements with the counterparty that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.
The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity price risk management assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity price risk management activities line on the consolidated statement of income. The Company’s valuation estimate takes into consideration the counterparties’ credit worthiness, the Company’s credit worthiness, and the time value of money. The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments.
The Company’s commodity derivative contracts as of June 30, 2012 are summarized below:
(1) NYMEX refers to quoted prices on the New York Mercantile Exchange
The following table details the fair value of the derivatives recorded in the applicable consolidated balance sheet, by category (in thousands):
The amount of gain (loss) recognized in the statements of operations related to our derivative financial instruments was as follows (in thousands):
Unrealized gains and losses resulting from derivatives are recorded at fair value on the consolidated balance sheet and changes in fair value are recognized on the consolidated statement of operations. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity price risk management activities line on the consolidated statement of income.
Note 7—Asset Retirement Obligations
The Company follows accounting for asset retirement obligations in accordance with ASC 410, Asset Retirement and Environmental Obligations, which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The Company’s asset retirement obligations primarily represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing and shut-in wells at the end of their productive lives in accordance with applicable state and federal laws. The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred; the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement costsare depleted as a component of the full cost pool using the unit of production method.
Note 8—Fair Value Measurements
ASC Topic 820, Fair Value Measurement and Disclosure, establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:
· Level 1: Quoted prices are available in active markets for identical assets or liabilities;
· Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability;
· Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.
The financial assets and liabilities are classified based on 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 requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. There were no significant assets or liabilities that were measured at fair value on a non-recurring basis in periods after initial recognition.
The Company’s non-recurring fair value measurements include asset retirement obligations, please refer to Note 7—Asset Retirement Obligations, and the purchase price allocations for the fair value of assets and liabilities acquired through business combinations, please refer to Note 3—Acquisitions.
The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities using level 3 inputs. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method.
The fair value of assets and liabilities acquired through business combinations is calculated using a discounted-cash flow approach using level 3 inputs. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including risk-adjusted oil and gas reserves, commodity prices and operating costs.
The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2012 by level within the fair value hierarchy (in thousands):
The following methods and assumptions were used to estimate the fair value of the assets and liabilities in the table above:
Commodity Derivative Instruments
The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit rating. In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At June 30, 2012 and December 31, 2011, derivative instruments utilized by the Company consist of both “no premium” collars and swaps. The crude oil derivative markets are highly active. Although the Company’s derivative instruments are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.
Fair Value of Financial Instruments
The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and long-term debt. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short-term maturities. The carrying amount of the Company’s credit facility approximated fair value as it bears interest at variable rates over the term of the loan. The fair value of the second lien credit agreement at December 31, 2011 was based on the amount paid on January 10, 2012 to extinguish the debt. The fair value of the Senior Notes was derived from available market data (Level 2 inputs). This disclosure (in thousands) does not impact our financial position, results of operations or cash flows.
Note 9—Share-Based Payments
The Company has granted options to directors, officers, and employees of the Company under the 2007 Stock Incentive Plan, amended on June 3, 2010 and further amended on June 15, 2011 (the “Plan”). The Plan authorizes the Company to issue stock options, stock appreciation rights, restricted stock and restricted stock units, performance awards, other stock grants and other stock-based awards to any employee, consultant, independent contractor, director or officer providing services to the Company or to an affiliate of the Company. The maximum number of shares of common stock available for issuance under the Plan is equal to 14% of the Company’s issued and outstanding shares of common stock, as calculated on January 1 of each respective year, subject to adjustment as provided in the Plan. As of January 1, 2012, the maximum number of shares issuable under the Plan, including those previously issued thereunder, was approximately 36.1 million shares.
Stock Options
Total compensation expense related to the stock options of $1.6 million and $3.0 million was recognized during the three and six months ended June 30, 2012, respectively, as compared to $652,000 and $2.0 million for the three and six months ended June 30, 2011, respectively. As of June 30, 2012, there was $9.7 million of total unrecognized compensation cost related to stock options, which is expected to be amortized over a weighted-average period of 2.0 years.
Compensation expense related to stock options is calculated using the Black-Scholes-Merton valuation model. Expected volatilities are based on the historical volatility of Kodiak’s common stock over a period consistent with that of the expected terms of the options. The expected terms of the options are estimated based on factors such as vesting periods, contractual expiration dates, historical trends in the Company’s common stock price and historical exercise behavior. The risk-free rates for periods within the contractual life of the options are based on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms. The following assumptions were used for the Black-Scholes-Merton model to calculate the share-based compensation expense for the periods presented:
A summary of the stock options outstanding as of January 1, 2012 and June 30, 2012 is as follows:
At June 30, 2012, stock options outstanding were as follows:
The aggregate intrinsic value of both outstanding and vested options as of June 30, 2012 was $25.8 million based on the Company’s June 29, 2012 closing common stock price of $8.21 per share. The total grant date fair value of the shares vested during the first half of 2012 was $2.3 million.
Restricted Stock Units and Restricted Stock
Total compensation expense related to restricted stock units (“RSUs”) and restricted stock of $1.1 million and $2.1 million was recognized during the three and six months ended June 30, 2012, respectively, as compared to $295,000 and $532,000 for the three and six months ended June 30, 2011, respectively. As of June 30, 2012, there was $5.5 million of total unrecognized compensation cost related to the RSUs and restricted stock, which is expected to be amortized over a weighted-average period of 2.1 years.
In the fourth quarter 2011, the Company awarded 775,611 performance based RSUs to officers pursuant to the Plan. Subject to the satisfaction of certain 2012 performance-based conditions, the RSUs vest one-quarter per year over a four year service period and the Company began recognizing compensation expense related to these grants beginning in the fourth quarter 2011 over the vesting period. The Company recognizes compensation cost for performance based grants on a tranche level basis over the requisite service period for the entire award. The fair value of RSU’s granted is based on the stock price on the grant date and the Company assumed no annual forfeiture rate.
During 2012, the Company awarded 30,000 shares of restricted stock to its Board of Directors pursuant to the Plan. These restricted stock shares vest over a four year period and the Company began recognizing compensation expense related to these grants in the first six months of 2012. The Company recognizes compensation cost for these grants on a straight-line basis over the requisite service period for the entire award. The fair value of restricted stock is based on the stock price on the grant date and the Company assumes a 3% annual forfeiture rate.
As of June 30, 2012, there were 985,611 unvested RSUs and 30,000 unvested restricted stock shares with a combined weighted average grant date fair value of $8.55 per share. The total fair value vested during the first half of 2012 was $166,000. A summary of the RSUs and restricted stock shares outstanding is as follows:
Note 10—Earnings Per Share
Basic net income (loss) per share is computed by dividing net income (loss) attributable to the common stockholders by the weighted average number of common shares outstanding during the reporting period. Diluted net income per common share includes shares of restricted stock units, and the potential dilution that could occur upon exercise of options to acquire common stock computed using the treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company with the proceeds from the exercise of the options (which were assumed to have been made at the average market price of the common shares during the reporting period).
In accordance with ASC 260-10-45, Share-Based Payment Arrangements and Participating Securities and the Two-Class Method, the Company’s unvested restricted stock shares are deemed participating securities, since these shares would be entitled to participate in dividends declared on common shares. During periods of net income, the calculation of earnings per share for common stock exclude income attributable to the restricted stock shares from the numerator and exclude the dilutive impact of those shares from the denominator. During periods of net loss, no effect is given to the participating securities because they do not share in the losses of the Company.
The performance based restricted stock units and unexercised stock options are not participating securities, since these shares are not entitled to participate in dividends declared on common shares. The number of potentially dilutive shares attributable to the performance based restricted stock units is based on the number of shares, if any, which would be issuable at the end of the respective reporting period, assuming that date was the end of the performance measurement period. Please refer to Note 9—Share-Based Payments under the heading Restricted Stock Units and Restricted Stock for additional discussion.
The table below sets forth the computations of basic and diluted net income per share for the three and six months ended June 30, 2012 and 2011 (in thousands, except per share data):
The following options and unvested restricted shares, which could be potentially dilutive in future periods, were not included in the computation of diluted net income per share because the effect would have been anti-dilutive for the periods indicated:
Note 11—Commitments and Contingencies
Lease Obligations
The Company leases office space in Denver, Colorado and Dickinson and Williston, North Dakota under separate operating lease agreements. The Denver, Colorado lease expires on April 30, 2016. The Dickinson and Williston, North Dakota leases expire on December 31, 2013 and May 31, 2013, respectively. Total rental commitments under non-cancelable leases for office space were $3.1 million at June 30, 2012. The future minimum lease payments under these non-cancelable leases are as follows: $360,000 in 2012, $740,000 in 2013, $690,000 in 2014, $720,000 in 2015, and $630,000 in 2016.
Drilling Rigs
As of June 30, 2012, the Company was subject to commitments on six drilling rig contracts. One of the contracts expires in late 2012, four expire in 2013 and one expires in 2015. In the event of early termination under all of these contracts, the Company would be obligated to pay an aggregate amount of approximately $50.8 million as of June 30, 2012 as required under the varying terms of such contracts.
Pressure Pumping Services
As of June 30, 2012, the Company was subject to a commitment with a pressure-pumping service company providing 24-hour per day crew availability for 30 days per month, to be reconciled on a quarterly basis. In the event of early contract termination, the Company would be obligated to pay approximately $36.0 million as of June 30, 2012 as required under the terms of the contract.
Guarantees of the Senior Notes
In November 2011 and May 2012, the Company issued Senior Notes due in 2019 in the amounts of $650.0 million and $156.0 million (including a $6.0 million premium on the issuance), respectively, which notes are guaranteed on a senior unsecured basis by our wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc. Kodiak Oil & Gas Corp., as the parent company, has no independent assets or operations. Such guarantee is full and unconditional, and the parent company has no other subsidiaries. In addition, there are no restrictions under the Senior Notes or the associated guarantees on the ability of the parent company to obtain funds from its subsidiary by dividend or loan. Finally, the parent company’s wholly-owned subsidiary does not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the parent company in the form of loans, advances or cash dividends by the subsidiary without the consent of a third-party.
The Company may issue additional debt securities in the future that the Company’s wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc., may guarantee. Any such guarantee is expected to be full, unconditional and joint and several. As stated above, the Company has no independent assets or operations nor does it have any other subsidiaries, and there are no significant restrictions on the ability of the Company to receive funds from the Company’s subsidiary through dividends, loans, and advances or otherwise.
Other
As is customary in the oil and gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells. If the Company does not meet such commitments, the acreage positions or wells may be lost.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Statements
The information discussed in this quarterly report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). All statements, other than statements of historical facts, included herein concerning, among other things, planned capital expenditures, changes in oil and gas production, the number of anticipated wells to be drilled after the date hereof, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could,” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:
· unsuccessful drilling and completion activities and the possibility of resulting write-downs;
· capital requirements and uncertainty of obtaining additional funding on terms acceptable to us;
· price volatility of oil and natural gas prices, and the effect that lower prices may have on our net income and stockholders’ equity;
· a decline in oil production or oil prices, and the impact of general economic conditions on the demand for oil and the availability of capital;
· geographical concentration of our operations;
· constraints imposed on our business and operations by our credit agreements and our ability to generate sufficient cash flows to repay our debt obligations;
· availability of borrowings under our credit agreements;
· termination fees related to drilling rig contracts and pressure pumping service contract;
· increases in the cost of drilling, completion and gas gathering or other costs of production and operations;
· our ability to successfully drill wells that produce oil in commercially viable quantities;
· failure to meet our proposed drilling schedule;
· financial losses and reduced earnings related to our commodity derivative agreements, and failure to produce enough oil to satisfy our commodity derivative agreements;
· adverse variations from estimates of reserves, production, production prices and expenditure requirements, and our inability to replace our reserves through exploration and development activities;
· our current level of indebtedness and the effect of any increase in our level of indebtedness;
· hazardous, risky drilling operations and adverse weather and environmental conditions;
· limited control over non-operated properties;
· reliance on limited number of customers;
· title defects to our properties and inability to retain our leases;
· incorrect estimates of proved reserves, the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs of properties that we acquire;
· our ability to successfully develop our large inventory of undeveloped operated and non-operated acreage;
· our ability to retain key members of our senior management and key technical employees;
· constraints in the Williston Basin with respect to gathering, transportation and processing facilities and marketing;
· federal, state and tribal regulations and laws;
· risks in connection with potential acquisitions and the integration of significant acquisitions;
· impact of environmental, health and safety, and other governmental regulations, and of current or pending legislation;
· federal and state legislation and regulatory initiatives relating to hydraulic fracturing;
· integration of significant acquisitions, and difficulty managing our growth and the related demands on our resources;
· developments in the global economy;
· constraints imposed on our business and operations by our credit agreements and our Senior Notes and our ability to generate sufficient cash flows to repay our debt obligations;
· financing and interest rate exposure;
· effects of competition;
· effect of seasonal factors;
· lack of availability of drilling rigs, equipment, supplies, insurance, personnel and oil field services; and
· further sales or issuances of common stock and the volatility of the market for our shares.
Finally, our future results will depend upon various other risks and uncertainties, including, but not limited to, those detailed in the section entitled “Risk Factors” included in our Annual Report on Form 10-K. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this report. Other than as required under securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.
Overview
Kodiak is an independent energy company focused on the exploration, exploitation, acquisition and production of crude oil and associated natural gas in the Rocky Mountain region of the United States. We have developed an asset base of proved reserves, as well as a portfolio of development and exploratory opportunities on high-potential prospects with an emphasis on oil resource plays. Our reserves and operations are primarily concentrated in the Williston Basin of North Dakota. As of June 30, 2012, we owned an interest in approximately 234,000 gross (155,000 net) acres in the Williston Basin where our primary target is the middle Bakken and Three Forks formations. As of June 30, 2012, we have an interest in 188 gross (81.6 net) producing wells in the Williston Basin.
Since late 2010, we have added significantly to our asset base in the Williston Basin through targeted acquisitions of properties within our core operating area. We intend to expand our asset base by drilling and completing wells on our current lands, and we will continue to evaluate and invest in acquisitions, if and to the extent opportunities arise.
As of the date of this filing, we operate seven drilling rigs on our acreage. The Company has a full-time, 24-hour-per-day completion crew. We have utilized and will continue to engage a second completion crew to accelerate completion activity when required.
Recent Developments
Operational Update
During the second quarter of 2012, we focused on drilling and completing wells within our core acreage in the Williston Basin. Wells within such core acreage generally have high working interests, are served by oil and gas gathering systems and can be drilled from multi-well pads.
During the first half of 2012, we drilled 28 gross (22.9 net) operated wells and completed 26 gross (20.7 net) operated wells. We participated as non-operator in the drilling of 5 gross (1.8 net) wells and completed 8 gross (3.3 net) wells within the areas of mutual interest (“AMI”) area in Dunn County, North Dakota, and also participated in 25 gross (3.4 net) wells and completed 25 gross (3.1 net) non-operated excluding the AMI area.
During the second quarter of 2012, we drilled 14 gross (10.8 net) operated wells and completed 14 gross (12.7 net) operated wells. Included in our wells completed during the second quarter are 4 gross (3.3 net) wells that were located in our recently acquired southern Williams county acreage. These wells were the first wells to be both drilled and completed in this area by Kodiak using our drilling and completion techniques. We are pleased with the performance of these wells and believe they demonstrate that this area is comparable to our core McKenzie county acreage, with similar high reservoir pressures, bottom-hole temperatures and depths.
During the second quarter of 2012, we continued our repair and remediation work on wells that encountered mechanical issues and successfully completed 4 gross (3.5 net) of these wells. Two of the remediated wells were drilled by the Company in the fourth quarter of 2011 and two wells were assumed through previously announced acquisitions. Ultimately, we expect all other wells with mechanical issues to be remediated and to undergo completion operations. We believe we have mitigated these mechanical issues predominantly through the use of cemented liners in new wells being drilled. We are pleased with the success to date and intend to continue to use cemented liners in our completions. Additionally, in the second quarter of 2012, we began employing a zipper fracturing technique on multi —well pad locations, which allow us to more rapidly complete the wells and establish cash flows. Utilization of the zipper fracturing technique allows the simultaneous completion of two wells at one time by alternating perforation and pressure pumping operations.
During the second quarter of 2012, we drilled four water disposal wells. With the addition of these wells and future water gathering systems, we anticipate that our operating costs, on a per unit basis, will improve.
We finished completion operations on 5 gross (3.4 net) operated wells in July 2012, and we expect to complete an additional 9 gross (7.5 net) operated wells during the remainder of the third quarter of 2012.
Generally, in the Williston Basin, oil and gas infrastructure continues to improve. The majority of our wells in Dunn County are connected to pipeline infrastructure to transport oil, gas and water. However, the ability to sell and process gas from these wells continues to be constrained due to gathering system pressure restrictions. Some of these restrictions are being eliminated as additional capacity has been brought on-line and due to the addition of planned natural gas compression. In McKenzie and Williams counties, the majority of our wells have been connected to gas pipelines and, in some cases, oil pipelines. Pipeline construction continues at a steady pace, and we expect most of our wells to have pipeline access for oil by year-end 2012. Sales of natural gas will continue to be dependent on processing plant capacity and the timing of connecting gas pipelines to newly completed wells.
The following summary provides a tabular presentation of our completion activities during the second quarter of 2012:
(1) Indicates remediated well with successful liner patch
Regulatory Matters
On April 17, 2012, the Environmental Protection Agency issued final rules that subject oil and natural gas production, processing, transmission and storage operations within federal regulatory jurisdiction to regulation under the New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants programs. The Environmental Protection Agency rules include standards under the New Source Performance Standards for completions of hydraulically fractured wells.
The final rules establish a phase-in period that will ensure that manufacturers have time to make and broadly distribute the required emissions reduction technology. During the first phase, until January 1, 2015, owners and operators must either flare their emissions or use emissions reduction technology called “green completions”. The finalized rules also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations, including the installation of new equipment to control emissions. We are currently evaluating the effect these rules will have on ourbusiness and financial condition.
On May 11, 2012, the Bureau of Land Management published proposed rules to regulate hydraulic fracturing on federal public lands and Indian lands. The proposed rules would address well stimulation operations, including requiring agency approval for certain activities, and would require the disclosure of well stimulation fluids, as well as address issues relating to flowback water. If adopted, these rules may require changes to our operations, lead to operational delays and/or increased operating costs, and result in greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. The rules are expected to be finalized by the end of 2012. We are currently evaluating the effect these proposed rules would have on our business and financial condition.
Capital Resources and Liquidity
2012 Capital Expenditures Budget
Our 2012 capital expenditure budget of $585.0 million (exclusive of $642.9 million used to fund our January 2012 acquisition) is subject to various factors, including market conditions, oilfield services and equipment availability, commodity prices and drilling results. During the first half of 2012, we incurred capital expenditures of approximately $335.5 million related to drilling and completion operations, and related infrastructure and leasehold acquisition (exclusive of our January 2012 acquisition and capitalized interest of $24.5 million).
During the six months ended June 30, 2012, we spent $253.9 million on our operated properties, $30.3 million on non-operated properties in our Dunn County AMI, $7.4 million on leasehold expenditures and $5.1 million for water disposal facilities. We anticipate spending approximately $300.0 million in the second half of the year on these properties.
We have incurred capital expenditures of $38.8 million for the six months ended June 30, 2012, related to non-operated interests outside our Dunn County AMI. The costs related to such non-operated properties are difficult to project because the timing of the operations is not under our control. Most of this activity in the first half of 2012 was associated with the properties acquired in January 2012. A significant portion of the non-operated acreage in this area is now held by production and we expect reduced drilling activity. Further, we participated in one well in which we incurred significant expenditures to technically evaluate the producing intervals. As a result, we expect our net expenditures on these activities to be lower in the second half of 2012 as compared to costs incurred to date. We estimate that total capital expenditures for this non-operated activity could be as much as $50.0 million for the entire year of 2012.
Our rig count will be in a direct relationship to oil prices and the economics derived from our wells. Recently, we have decreased our total drilling days and with this increased efficiency, we believe we can reduce our expected rig count without affecting our well count. While we continue to evaluate our capital expenditure program for the second half of 2012, we currently expect to maintain our operated rig count at seven rather than the eight as originally budgeted. This decrease will partially offset the increase in our capital expenditures from unbudgeted, non-operated activities.
Senior Notes
In November 2011, we issued at par $650.0 million principal amount of 8.125% Senior Notes due December 1, 2019. In May 2012, we issued an additional $150.0 million aggregate principal amount of our Senior Notes at 104.0% of par, resulting in a $6.0 million premium on the issuance. The interest on our Senior Notes is payable on June 1 and December 1 of each year. For further discussion regarding the Senior Notes, please refer to Note 4—Long-Term Debt under Item 1 in this Quarterly Report.
Derivative Instruments
We utilize various derivative instruments in connection with anticipated crude oil sales to minimize the impact of product price fluctuations and ensure cash flow fo | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
