UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
For the quarterly period ended June 30, 2011
OR
For the transition period from to
Commission File Number: 001-33784
SANDRIDGE ENERGY, INC.
(Exact name of registrant as specified in its charter)
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
123 Robert S. Kerr Avenue
Oklahoma City, Oklahoma
Registrant’s telephone number, including area code:
(405) 429-5500
Former name, former address and former fiscal year, if changed since last report: Not applicable
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 þ No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, 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 þ 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.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ
The number of shares outstanding of the registrant’s common stock, par value $0.001 per share, as of the close of business on July 29, 2011, was 412,428,752.
FORM 10-Q
Quarter Ended June 30, 2011
INDEX
ITEM 1.
Financial Statements (Unaudited)
Condensed Consolidated Balance Sheets
Condensed Consolidated Statements of Operations
Condensed Consolidated Statement of Changes in Equity
Condensed Consolidated Statements of Cash Flows
Notes to Condensed Consolidated Financial Statements
ITEM 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
ITEM 3.
Quantitative and Qualitative Disclosures About Market Risk
ITEM 4.
Controls and Procedures
Legal Proceedings
ITEM 1A.
Risk Factors
Unregistered Sales of Equity Securities and Use of Proceeds
ITEM 6.
Exhibits
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DISCLOSURES REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q (“Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements express a belief, expectation or intention and generally are accompanied by words that convey projected future events or outcomes. These forward-looking statements may include projections and estimates concerning capital expenditures, our liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, elements of our business strategy and other statements concerning our operations, economic performance and financial condition. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal,” “should,” “intend” or other words that convey the uncertainty of future events or outcomes. We have based these forward-looking statements on our current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including the risk factors discussed in Item 1A of Part II of this Quarterly Report and in Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2010 (the “2010 Form 10-K”). The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on our company, business or operations. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in such forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statements.
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PART I. Financial Information
ITEM 1. Financial Statements
SANDRIDGE ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except per share data)
Current assets
Cash and cash equivalents
Accounts receivable, net
Derivative contracts
Inventories
Other current assets
Total current assets
Oil and natural gas properties, using full cost method of accounting
Proved
Unproved
Less: accumulated depreciation, depletion and impairment
Other property, plant and equipment, net
Restricted deposits
Goodwill
Other assets
Total assets
Current liabilities
Current maturities of long-term debt
Accounts payable and accrued expenses
Billings and estimated contract loss in excess of costs incurred
Asset retirement obligation
Total current liabilities
Long-term debt
Other long-term obligations
Total liabilities
Commitments and contingencies (Note 15)
Equity
SandRidge Energy, Inc. stockholders’ equity
Preferred stock, $0.001 par value, 50,000 shares authorized
8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at June 30, 2011 and December 31, 2010; aggregate liquidation preference of $265,000
6.0% Convertible perpetual preferred stock; 2,000 shares issued and outstanding at June 30, 2011 and December 31, 2010; aggregate liquidation preference of $200,000
7.0% Convertible perpetual preferred stock; 3,000 shares issued and outstanding at June 30, 2011 and December 31, 2010; aggregate liquidation preference of $300,000
Common stock, $0.001 par value, 800,000 shares authorized; 410,498 issued and 409,918 outstanding at June 30, 2011 and 406,830 issued and 406,360 outstanding at December 31, 2010
Additional paid-in capital
Treasury stock, at cost
Accumulated deficit
Total SandRidge Energy, Inc. stockholders’ equity
Noncontrolling interest
Total equity
Total liabilities and equity
The accompanying notes are an integral part of these condensed consolidated financial statements.
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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Revenues
Oil and natural gas
Drilling and services
Midstream and marketing
Other
Total revenues
Expenses
Production
Production taxes
Depreciation and depletion — oil and natural gas
Depreciation and amortization — other
General and administrative
(Gain) loss on derivative contracts
(Gain) loss on sale of assets
Total expenses
Income from operations
Other income (expense)
Interest income
Interest expense
Loss on extinguishment of debt
Other income (expense), net
Total other expense
Income (loss) before income taxes
Income tax (benefit) expense
Net income (loss)
Less: net income attributable to noncontrolling interest
Net income (loss) attributable to SandRidge Energy, Inc.
Preferred stock dividends
Income available (loss applicable) to SandRidge Energy, Inc. common stockholders
Earnings (loss) per share
Basic
Diluted
Weighted average number of common shares outstanding
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CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(In thousands)
Six months ended June 30, 2011
Balance, December 31, 2010
Issuance of units by SandRidge Mississippian Trust I
Distributions to noncontrolling interest owners
Stock issuance expense
Purchase of treasury stock
Retirement of treasury stock
Stock purchases — retirement plans, net of distributions
Stock-based compensation
Stock-based compensation excess tax benefit
Issuance of restricted stock awards, net of cancellations
Net (loss) income
Convertible perpetual preferred stock dividends
Balance, June 30, 2011
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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
CASH FLOWS FROM OPERATING ACTIVITIES
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Provision for doubtful accounts
Inventory obsolescence
Depreciation, depletion and amortization
Debt issuance costs amortization
Discount amortization on long-term debt
Deferred income taxes
Unrealized loss (gain) on derivative contracts
Investment (income) loss
Changes in operating assets and liabilities
Net cash provided by operating activities
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment
Proceeds from sale of assets
Refunds of restricted deposits
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings
Repayments of borrowings
Premium on debt redemption
Debt issuance costs
Proceeds from issuance of units by SandRidge Mississippian Trust I
Noncontrolling interest distributions
Noncontrolling interest contributions
Dividends paid — preferred
Derivative settlements
Net cash provided by financing activities
NET DECREASE IN CASH AND CASH EQUIVALENTS
CASH AND CASH EQUIVALENTS, beginning of year
CASH AND CASH EQUIVALENTS, end of period
Supplemental Disclosure of Noncash Investing and Financing Activities
Change in accrued capital expenditures
Convertible perpetual preferred stock dividends payable
Adjustment to oil and natural gas properties for estimated contract loss
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Basis of Presentation
Nature of Business. SandRidge Energy, Inc. (including its subsidiaries, the “Company” or “SandRidge”) is an independent oil and natural gas company concentrating on development and production activities related to the exploitation of its significant holdings in West Texas and the Mid-Continent area of Oklahoma and Kansas. The Company’s primary areas of focus are the Permian Basin in West Texas, the Mississippian formation in the Mid-Continent and the West Texas Overthrust (“WTO”). The Company owns and operates other interests in the Mid-Continent, Cotton Valley Trend in East Texas, Gulf Coast and Gulf of Mexico. The Company also operates businesses that are complementary to its primary development and production activities, including gas gathering and treating facilities, a gas marketing business, an oil field services business, including a drilling rig business, and tertiary oil recovery operations.
Interim Financial Statements. The accompanying condensed consolidated financial statements as of December 31, 2010 have been derived from the audited financial statements contained in the Company’s 2010 Form 10-K. The unaudited interim condensed consolidated financial statements have been prepared by the Company in accordance with the accounting policies stated in the audited consolidated financial statements contained in the 2010 Form 10-K. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted, although the Company believes that the disclosures contained herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments, which consist only of normal recurring adjustments, necessary to state fairly the information in the Company’s unaudited condensed consolidated financial statements have been included. These condensed consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in the 2010 Form 10-K.
Risks and Uncertainties. The Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, each of which depends on numerous factors beyond the Company’s control such as economic conditions, regulatory developments and competition from other energy sources. Oil and natural gas prices historically have been volatile, and may be subject to significant fluctuations in the future. The Company’s derivative arrangements serve to mitigate a portion of the effect of this price volatility on the Company’s cash flows, and while derivative contracts are in place for the majority of expected oil production for 2011 through 2013, fixed price swap contracts are in place for only a portion of expected natural gas production in 2011 and 2012 and oil production for 2014 and 2015. No fixed price swap contracts are in place for the Company’s natural gas production beyond 2012 or oil production beyond 2015. The Company has natural gas collars in place for a portion of expected natural gas production through 2015. See Note 12 for the Company’s open oil and natural gas commodity derivative contracts.
The Company has incurred, and will have to continue to incur, capital expenditures to achieve production targets contained in certain gathering and treating arrangements. The Company depends on the availability of borrowings under its senior secured revolving credit facility (the “senior credit facility”), along with cash flows from operating activities and the proceeds from planned asset sales or other asset monetizations, to fund those capital expenditures. Based on anticipated oil and natural gas prices, availability under the senior credit facility, potential access to the capital markets and anticipated proceeds from sales or other monetizations of assets, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs for 2011. However, a substantial or extended decline in oil or natural gas prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced, which could adversely impact the Company’s ability to comply with the financial covenants under its senior credit facility, which in turn would limit further borrowings to fund capital expenditures. See Note 11 for discussion of the financial covenants in the senior credit facility.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
2. Recent Accounting Pronouncements
For a description of the Company’s significant accounting policies, refer to Note 1 of the consolidated financial statements included in the 2010 Form 10-K.
Recently Adopted Accounting Pronouncements. In January 2010, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update 2010-06, “Fair Value Measurements and Disclosures: Improving Disclosures about Fair Value Measurements” (“ASU 2010-06”). ASU 2010-06 requires additional disclosures and clarifies existing disclosure requirements about fair value measurement as set forth in Accounting Standards Codification (“ASC”) Topic 820, Fair Value Measurements and Disclosures. The new disclosure requirements regarding activity in Level 3 fair value measurements, which are effective for fiscal years beginning after December 15, 2010, were implemented in the first quarter of 2011 by the Company. The implementation of ASU 2010-06 had no impact on the Company’s financial position or results of operations. See Note 4.
Recent Accounting Pronouncement Not Yet Adopted. In May 2011, the FASB issued Accounting Standards Update 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS” (“ASU 2011-04”). ASU 2011-04 clarifies the FASB’s intent about the application of existing fair value measurements as set forth in ASC Topic 820 and requires additional disclosure information regarding valuation processes and inputs used. The new disclosure requirements are effective for interim and annual reporting periods beginning after December 15, 2011. As the additional requirements under ASU 2011-04, which will be implemented January 1, 2012, pertain to fair value measurement disclosures, no effect to the Company’s financial position or results of operations is expected.
3. Acquisitions and Divestitures
Arena Acquisition. On July 16, 2010, the Company acquired all of the outstanding common stock of Arena Resources, Inc. (“Arena”). In connection with the acquisition (the “Arena Acquisition”), the Company issued 4.7771 shares of its common stock and paid $4.50 in cash to Arena stockholders for each outstanding share of Arena unrestricted common stock. This resulted in the issuance of approximately 190.3 million shares of Company common stock and payment of approximately $177.9 million in cash for an aggregate estimated purchase price to stockholders of Arena equal to approximately $1.4 billion. The Company incurred approximately $0.2 million and $3.8 million in fees related to the acquisition during the three-month periods ended June 30, 2011 and 2010, respectively, and $0.6 million and $4.8 million in fees during the six-month periods ended June 30, 2011 and 2010, respectively, which have been included in general and administrative expenses in the accompanying condensed consolidated statements of operations.
In the second quarter of 2011, the Company completed its valuation of assets acquired and liabilities assumed related to the Arena Acquisition. Upon receipt of final confirmatory information for certain accruals in the second quarter of 2011 and completion of the 2010 Arena federal income tax return, the Company increased current assets, the net deferred tax liability and the value assigned to goodwill and reduced current liabilities. The accompanying condensed consolidated balance sheet at December 31, 2010 included certain preliminary allocations of the purchase price for the Arena Acquisition. During the first quarter of 2011, the Company updated certain estimates used in the purchase price allocation, primarily with respect to accruals, resulting in adjustments of $0.8 million to goodwill. Additional adjustments in the second quarter of 2011, primarily with respect to deferred taxes and other accruals, resulted in adjustments of $0.2 million to goodwill.
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The following table summarizes the final valuation of assets acquired and liabilities assumed in connection with the Arena Acquisition (in thousands):
Oil and natural gas properties(1)
Other property, plant and equipment
Deferred tax assets
Other long-term assets
Goodwill(2)
Total assets acquired
Long-term deferred tax liability(2)
Other long-term liabilities
Total liabilities assumed
Net assets acquired
The following unaudited pro forma results of operations are provided for the three and six-month periods ended June 30, 2010 as though the Arena Acquisition had been completed as of the beginning of each respective period. The pro forma information is based on the Company’s consolidated results of operations for the three and six-month periods ended June 30, 2010, Arena’s historical results of operations and estimates of the effect of the transaction on the combined results. The pro forma combined results of operations for the three and six-month periods ended June 30, 2010 have been prepared by adjusting the historical results of the Company to include the historical results of Arena, certain reclassifications to conform Arena’s presentation to the Company’s accounting policies and the impact of the purchase price allocation. These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted from the acquisition or any estimated costs that have been incurred by the Company to integrate Arena. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors.
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Income available to SandRidge Energy, Inc. common stockholders(1)
Earnings per common share
Sale of Wolfberry Assets. In January 2011, the Company sold its Wolfberry assets in the Permian Basin for $153.8 million, net of fees and subject to post-closing adjustments. This asset sale was accounted for as an adjustment to the full cost pool with no gain or loss recognized.
Sale of New Mexico Assets. In April 2011, the Company sold certain oil and natural gas properties in Lea County and Eddy County, New Mexico, for approximately $198.5 million, net of fees and subject to post-closing adjustments. This asset sale was accounted for as an adjustment to the full cost pool with no gain or loss recognized.
4. Fair Value Measurements
The Company applies the guidance provided under ASC Topic 820 to its financial assets and liabilities and nonfinancial liabilities that are measured and reported on a fair value basis. Pursuant to this guidance, the Company has classified and disclosed its fair value measurements using the following levels of the fair value hierarchy:
Assets and liabilities that are measured at fair value 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, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels as described in ASC Topic 820. The determination of the fair values, stated below, takes into account the market for the Company’s financial assets and liabilities, the associated credit risk and other factors as required by ASC Topic 820. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company has assets and liabilities it has classified as Level 1 and Level 3, as described below. The Company did not have any assets or liabilities classified as Level 2 at June 30, 2011 or December 31, 2010.
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Level 1 Fair Value Measurements
Restricted deposits. The fair value of restricted deposits invested in mutual funds or municipal bonds is based on quoted market prices. For restricted deposits held in savings accounts, carrying value is deemed to approximate fair value.
Other long-term assets. The fair value of other long-term assets, consisting of assets attributable to the Company’s deferred compensation plan, is based on quoted market prices.
Level 3 Fair Value Measurements
Derivative Contracts. The fair values of the Company’s oil and natural gas fixed price swaps, natural gas basis swaps, natural gas collars and interest rate swap are based upon quotes obtained from counterparties to the derivative contracts. The Company reviews other readily available market prices for its derivative contracts as there is an active market for these contracts. However, the Company does not have access to the specific valuation models used by its counterparties or other market participants. Included in these models are discount factors that the Company must estimate in its calculation. Additionally, the Company applies a weighted average credit default risk rating factor for its counterparties or gives effect to its credit risk, as applicable, in determining the fair value of its derivative contracts. Based on the inputs for the fair value measurement, the Company has classified its derivative contract assets and liabilities as Level 3.
The following tables summarize the Company’s financial assets and liabilities measured at fair value on a recurring basis by the fair value hierarchy (in thousands):
June 30, 2011
Assets
Commodity derivative contracts
Liabilities
Interest rate swap
December 31, 2010
Interest rate swaps
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The tables below set forth a reconciliation of the Company’s financial assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three and six-month periods ended June 30, 2011 and 2010 (in thousands):
Balance of Level 3, March 31
Total realized and unrealized gains (losses)
Purchases
Settlements
Balance of Level 3, June 30
Balance of Level 3, December 31
Total realized and unrealized (losses) gains
During the three and six-month periods ended June 30, 2011 and 2010, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements.
See Note 12 for further discussion of the Company’s derivative contracts.
Fair Value of Debt
The Company measures the fair value of its long-term debt based on quoted market prices and also considers the effect of the Company’s credit risk. The estimated fair values of the Company’s senior notes and the carrying value at June 30, 2011 and December 31, 2010 were as follows (in thousands):
Senior Floating Rate Notes due 2014
8.625% Senior Notes due 2015
9.875% Senior Notes due 2016(1)
8.0% Senior Notes due 2018
8.75% Senior Notes due 2020(2)
7.5% Senior Notes due 2021
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The carrying values of the Company’s senior credit facility and remaining fixed rate debt instruments approximate fair value based on current rates applicable to similar instruments. See Note 11 for discussion of the Company’s long-term debt, including the purchase and redemption of all outstanding 8.625% Senior Notes due 2015 and the issuance of the 7.5% Senior Notes due 2021, which both occurred during 2011.
5. Property, Plant and Equipment
Property, plant and equipment consists of the following (in thousands):
Oil and natural gas properties
Total oil and natural gas properties
Net oil and natural gas properties capitalized costs
Land
Non oil and natural gas equipment(1)
Buildings and structures
Total
Less: accumulated depreciation and amortization
Net capitalized costs
Total property, plant and equipment, net
There were no full cost ceiling impairments during the three or six-month periods ended June 30, 2011 or 2010. Cumulative full cost ceiling limitation impairment charges of $3,548.3 million at both June 30, 2011 and December 31, 2010 were included in accumulated depreciation, depletion and impairment for oil and natural gas properties in the table above.
6. Goodwill
At June 30, 2011, the Company had $235.4 million of goodwill, including the effects of the $0.8 million and $0.2 million purchase price adjustments recorded in the first and second quarters of 2011, respectively, as a result of the excess consideration over the fair value of net assets acquired in the Arena Acquisition. Goodwill recorded in the Arena Acquisition is primarily attributable to operational and cost synergies expected to be realized from the acquisition by using the Company’s current presence in the Permian Basin, its Fort Stockton, Texas service base and its existing rig ownership to efficiently increase its drilling and oil production from Arena assets
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acquired in the Central Basin Platform, as these assets have a proven production history. See Note 3 for additional discussion of the Arena Acquisition. The Company assigned all of the goodwill related to the Arena Acquisition to its exploration and production segment, which will be the reporting unit for impairment testing purposes. The Company will test goodwill for impairment annually on July 1, beginning in 2011. The Company monitors the existence of potential impairment indicators throughout the year. As of June 30, 2011, no such indicators were noted. Goodwill recognized is not deductible for tax purposes.
7. Other Assets
Other assets consist of the following (in thousands):
Debt issuance costs, net of amortization
Investments
Total other assets
8. Variable Interest Entities
In accordance with the guidance in ASC Topic 810, Consolidation, including the guidance in Accounting Standards Update 2009-17, “Consolidations—Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities” (“ASU 2009-17”), the Company consolidates the activities of variable interest entities (“VIEs”) of which it is the primary beneficiary. The primary beneficiary of a VIE is that variable interest holder possessing a controlling financial interest through (i) its power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether the Company owns a variable interest in a VIE, the Company performs a qualitative analysis of the entity’s design, organizational structure, primary decision makers and related financial agreements.
The Company’s significant associated VIEs, including those for which the Company has determined it is the primary beneficiary and those for which it has determined it is not, are described below.
SandRidge Mississippian Trust I. On April 12, 2011, SandRidge Mississippian Trust I (the “Mississippian Trust”), a newly formed Delaware statutory trust, completed its initial public offering of 17,250,000 common units representing beneficial interests in the Mississippian Trust. Net proceeds to the Mississippian Trust, after certain offering expenses, were approximately $336.9 million. In conjunction with the closing, the Company conveyed certain royalty interests to the Mississippian Trust in exchange for the net proceeds of the Mississippian Trust’s initial public offering and 10,750,000 units (3,750,000 common units and 7,000,000 subordinated units) representing approximately 38.4% of the beneficial interest in the Mississippian Trust. The royalty interests conveyed to the Mississippian Trust are in certain oil and natural gas properties leased by the Company in the Mississippian formation in five counties in Northern Oklahoma. The conveyance of the royalty interests to the Mississippian Trust was recorded in April 2011 at the historical cost to the Company, or $309.0 million, and was determined by allocating the historical net book value of the Company’s full cost pool based on the fair value of the conveyed royalty interests relative to the fair value of the Company’s total full cost pool.
In order to provide support for cash distributions on the Mississippian Trust’s common units, SandRidge agreed to subordinate a portion of the Mississippian Trust units it owns (the “subordinated units”), which
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constitute 25% of the total outstanding Mississippian Trust units. The subordinated units are entitled to receive pro rata distributions from the Mississippian Trust each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is no less than the applicable quarterly subordination threshold. If there is not sufficient cash to fund such a distribution on all common units, the distribution to be made with respect to the subordinated units will be reduced or eliminated for such quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on all common units, including common units held by the Company.
SandRidge and one of its wholly owned subsidiaries entered into a development agreement with the Mississippian Trust that obligates the Company to drill, or cause to be drilled, a specified number of wells, which are also subject to the royalty interest, by December 31, 2014. In the event of delays, the Company will have until December 31, 2015 to fulfill its drilling obligation. At the end of the fourth full calendar quarter following satisfaction of the Company’s drilling obligation (the “subordination period”), the Company’s subordinated units will automatically convert into common units on a one-for-one basis and the Company’s right to receive incentive distributions will terminate. Incentive distributions are equal to 50% of the amount by which the cash available for distribution on all of the Mississippian Trust units for any quarter is 20% or greater than the target distribution for such quarter. One of the Company’s wholly owned subsidiaries also granted to the Mississippian Trust a lien in the Company’s interests in the properties where the development wells will be drilled, in order to secure the estimated amount of the drilling costs for the wells. As the Company fulfills its drilling obligation, the total amount that may be recovered by the Mississippian Trust will be proportionately reduced and completed development wells will be released from the lien. As of June 30, 2011, the maximum amount recoverable by the Mississippian Trust under the lien was $136.4 million. Additionally, the Company and the Mississippian Trust entered into an administrative services agreement, pursuant to which the Company provides certain administrative services to the Mississippian Trust, and a derivatives agreement, pursuant to which the Company passes to the Mississippian Trust the benefits and obligations of certain of the Company’s derivative contracts. The tables below present open oil and natural gas commodity derivative contracts at June 30, 2011, the benefits and obligations of which will be passed to the Mississippian Trust under the derivatives agreement. See Note 12 for further discussion of the derivatives agreement between the Company and the Mississippian Trust and a complete listing of the Company’s open commodity derivative contracts at June 30, 2011, including the derivative contracts the effects of which have been conveyed to the Mississippian Trust.
Oil
Period and Type of Contract
July 2011 — December 2011
Price swap contracts
January 2012 — December 2012
January 2013 — December 2013
January 2014 — December 2014
January 2015 — December 2015
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Natural Gas
January 2012 — June 2012
July 2012 — December 2012
Collars
The Mississippian Trust is considered a VIE due to the lack of voting or similar decision-making rights by its equity holders regarding activities that have a significant effect on the success of the Mississippian Trust. The Company’s ownership in the Mississippian Trust constitutes a variable interest. The Company has determined it is the primary beneficiary of the Mississippian Trust as it has (a) the power to direct the activities that most significantly impact the economic performance of the Mississippian Trust through (i) its participation in the creation and structure of the Mississippian Trust, (ii) the manner in which it fulfills its drilling obligation to the Mississippian Trust, and (iii) the manner in which it operates the Underlying Properties, and (b) through the end of the subordination period, the obligation to absorb losses and right to receive residual returns, through its ownership of the subordinated units, that could potentially be significant to the Mississippian Trust. As a result, the Company began consolidating the activities of the Mississippian Trust into its results of operations in April 2011. In consolidation, the common units of the Mississippian Trust owned by third parties are reflected as noncontrolling interest. As discussed above, the Company’s subordinated Mississippian Trust units will automatically convert to common Mississippian Trust units at the end of the subordination period.
The Mississippian Trust’s assets can be used to settle its own obligations and not other obligations of the Company. The Mississippian Trust’s creditors have no contractual recourse to the general credit of the Company. Although the Mississippian Trust is included in the Company’s consolidated financial statements, the Company’s legal interest in the Mississippian Trust’s assets is limited to its ownership of the Mississippian Trust units. At June 30, 2011, $350.2 million of noncontrolling interest in the accompanying condensed consolidated balance sheets was attributable to the Mississippian Trust. The Mississippian Trust’s assets and liabilities included in the accompanying condensed consolidated balance sheet at June 30, 2011 consisted of the following (in thousands):
Investment in royalty interests, net(1)
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Grey Ranch, L.P. Primarily engaged in treating and transportation of natural gas, Grey Ranch Plant, L.P. (“GRLP”) is a limited partnership that operates the Company’s Grey Ranch plant (the “Plant”) located in Pecos County, Texas. The Company has long-term operating and gathering agreements with GRLP and also owns a 50% interest in GRLP. Income or losses of GRLP are allocated to the partners based on ownership percentage and any operating or cash shortfalls require contributions from the partners. The Company has determined that GRLP qualifies as a VIE under the provisions of ASC Topic 810. Agreements related to the ownership and operation of GRLP provide for GRLP to pay management fees to the Company to operate the Plant and lease payments for the Plant. Under the operating agreements, lease payments are reduced if throughput volumes are below those expected. The Company has determined that it is the primary beneficiary of GRLP as it has both (i) the power to direct the activities of GRLP that most significantly impact its economic performance as operator of the Plant and (ii) the obligation to absorb losses, as a result of the operating and gathering agreements, that could potentially be significant to GRLP.
GRLP’s assets can be used to settle its own obligations and not other obligations of the Company. GRLP’s creditors have no recourse to the general credit of the Company. Although GRLP is included in the Company’s consolidated financial statements, the Company’s legal interest in GRLP’s assets is limited to its 50% ownership. At June 30, 2011 and December 31, 2010, $9.6 million and $11.3 million, respectively, of noncontrolling interest in the accompanying condensed consolidated balance sheets were related to GRLP. GRLP’s assets and liabilities included in the accompanying condensed consolidated balance sheets at June 30, 2011 and December 31, 2010 consisted of the following (in thousands):
Grey Ranch Plant Genpar, LLC. The Company owns a 50% interest in Grey Ranch Plant Genpar, LLC (“Genpar”), the managing partner and 1% owner of GRLP. Additionally, the Company serves as Genpar’s administrative manager. Genpar’s ownership interest in GRLP is its only asset.
As managing partner of GRLP, Genpar has the sole right to manage, control and conduct the business of GRLP. However, Genpar is restricted from making certain major decisions, including the decision to remove the Company as operator of the Plant. The rights afforded the Company under the Plant operating agreement and the restrictions on Genpar serve to limit Genpar’s ability to make decisions on behalf of GRLP. Therefore, Genpar is considered a VIE. Although both the Company and Genpar’s other equity owner share equally in Genpar’s economic losses and benefits and also have agreements that may be considered variable interests, the Company determined it was the primary beneficiary due to (i) its ability, as administrative manager, to direct the activities of Genpar that most significantly impact its performance and (ii) its obligation or right, as operator of the Plant, to absorb the losses of or receive benefits from Genpar that could potentially be significant to Genpar. As the primary beneficiary, the Company consolidates Genpar’s activity. However, its sole asset, the investment in GRLP, is eliminated in consolidation. Genpar has no liabilities.
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Piñon Gathering Company, LLC. The Company has 20-year gas gathering and operations and maintenance agreements with Piñon Gathering Company, LLC (“PGC”). Under the gas gathering agreement, the Company is required to compensate PGC for any throughput shortfalls below a required minimum volume. By guaranteeing a minimum throughput, the Company absorbs the risk that lower than projected volumes will be gathered by the gathering system. Therefore, PGC is a VIE. While the Company operates the assets of PGC as directed under the operations and management agreement, the member and managers of PGC have the authority to directly control PGC and make substantive decisions regarding PGC’s activities including terminating the Company as operator without cause. As the Company does not have the ability to control the activities of PGC that most significantly impact PGC’s economic performance, the Company is not the primary beneficiary of PGC. Therefore, the results of PGC’s activities are not consolidated into the Company’s financial statements.
9. Century Plant Contract
The Company is constructing the Century Plant, a CO2 treatment plant in Pecos County, Texas (the “Century Plant”), and associated compression and pipeline facilities pursuant to an agreement with Occidental Petroleum Corporation (“Occidental”). Under the terms of the agreement, the Company will construct the Century Plant and Occidental will pay the Company a minimum of 100% of the contract price, or $800.0 million, plus any subsequently agreed-upon revisions, through periodic cost reimbursements based upon the percentage of the project completed by the Company. The Company expects to complete the Century Plant in two phases. Upon completion of each phase of the Century Plant, Occidental will take ownership of the related assets and will operate the Century Plant for the purpose of separating and removing CO2 from delivered natural gas. Phase I is in the commissioning process with completion and transfer of title to Occidental expected in the third quarter of 2011, and Phase II is under construction and expected to be completed in mid 2012. Pursuant to a 30-year treating agreement executed simultaneously with the construction agreement, Occidental will remove CO2 from the Company’s delivered production volumes. The Company will retain all methane gas from the natural gas it delivers to the Century Plant.
The Company accounts for construction of the Century Plant using the completed-contract method, under which contract revenues and costs are recognized when work under both phases of the contract is completed and assets have been transferred to Occidental. In the interim, costs incurred on and billings related to contracts in process are accumulated on the balance sheet. Contract gains or losses will be recorded, as development costs within the Company’s oil and natural gas properties as part of the full cost pool, when it is determined that a gain or loss will be incurred. The Company recorded an addition of $124.0 million ($105.0 million in 2010 and $19.0 million in the first quarter of 2011) to its oil and natural gas properties for the estimated loss identified based on projections of the costs to be incurred in excess of contract amounts. Billings and estimated contract loss in excess of costs incurred of $41.2 million and $31.5 million at June 30, 2011 and December 31, 2010, respectively, are reported as current liabilities in the accompanying condensed consolidated balance sheets.
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10. Asset Retirement Obligation
A reconciliation of the beginning and ending aggregate carrying amounts of the asset retirement obligation for the period from December 31, 2010 to June 30, 2011 is as follows (in thousands):
Asset retirement obligation, December 31, 2010
Liability incurred upon acquiring and drilling wells
Sales of reserves in place
Liability settled in current period
Accretion of discount expense
Asset retirement obligation, June 30, 2011
Less: current portion
Asset retirement obligation, net of current
11. Long-Term Debt
Long-term debt consists of the following (in thousands):
Senior credit facility
Other notes payable
Drilling rig fleet and related oil field services equipment
Mortgage
9.875% Senior Notes due 2016, net of $11,881 and $12,793 discount, respectively
8.75% Senior Notes due 2020, net of $6,693 and $6,943 discount, respectively
Total debt
Less: current maturities of long-term debt
For the three-month periods ended June 30, 2011 and 2010, interest payments were approximately $56.9 million and $83.3 million, respectively. For the six-month periods ended June 30, 2011 and 2010, interest payments were approximately $110.3 million and $92.3 million, respectively. Interest paid for the three and six-month periods ended June 30, 2011 included $1.5 million and $25.7 million, respectively, of accrued interest paid in connection with the purchase and redemption of the 8.625% Senior Notes due 2015. See discussion of redemption below.
Senior Credit Facility. The senior credit facility is available to be drawn on subject to limitations based on its terms and certain financial covenants, as described below. The senior credit facility matures on April 15, 2014.
On February 23, 2011, the senior credit facility was amended to, among other things, (a) exclude from the calculation of Consolidated Net Income the net income (or loss) of a Royalty Trust, except to the extent of cash
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distributions received by the Company, (b) establish that an investment in a Royalty Trust and dispositions to, and of interests in, Royalty Trusts are permitted, (c) clarify that a Royalty Trust is not a Subsidiary, (d) allow the Company to net against its calculation of Consolidated Funded Indebtedness cash balances exceeding $10.0 million in the event no loans are outstanding under the senior credit facility at that time, and (e) establish that, for any fiscal quarter ending prior to March 31, 2012, if the ratio of the Company’s secured indebtedness to EBITDA is less than 1.5:1.0 then compliance with the Company’s Consolidated Leverage Ratio covenant is not required. Terms capitalized in the preceding sentence have the meaning given to them in the senior credit facility, as amended.
On April 20, 2011, the senior credit facility was amended. The amendment permits the Company to pay cash dividends on its 7.0% convertible perpetual preferred stock and reaffirms the borrowing base at $790.0 million.
As of June 30, 2011, the senior credit facility contained financial covenants, including maintaining agreed levels for the (i) ratio of total funded debt to EBITDA, which may not exceed 4.5:1.0 at each quarter end, calculated using the last four completed fiscal quarters, unless, for any quarter ending prior to March 31, 2012, the ratio of the Company’s secured indebtedness to EBITDA is less than 1.5:1.0, calculated using the last four completed fiscal quarters (in each case through the second quarter of 2011, adjusted for annualized amounts of the post-acquisition results of operations of Arena), (ii) ratio of current assets to current liabilities, which must be at least 1.0:1.0 at each quarter end (in the current ratio calculation (as defined in the senior credit facility), any amounts available to be drawn under the senior credit facility are included in current assets, and unrealized assets and liabilities resulting from mark-to-market adjustments on the Company’s derivative contracts are disregarded) and (iii) ratio of the Company’s secured indebtedness to EBITDA, which may not exceed 2.0:1.0 at each quarter end, calculated using the last four completed fiscal quarters (in each case through the second quarter of 2011, adjusted for annualized amounts of the post-acquisition results of operations of Arena). As of and during the three and six-month periods ended June 30, 2011, the Company was in compliance with all of the financial covenants under the senior credit facility.
Additionally, the senior credit facility contains various covenants that limit the ability of the Company and certain of its subsidiaries to grant certain liens; make certain loans and investments; make distributions; redeem stock; redeem or prepay debt; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets. Additionally, the senior credit facility limits the ability of the Company and certain of its subsidiaries to incur additional indebtedness with certain exceptions.
The obligations under the senior credit facility are guaranteed by certain Company subsidiaries and are secured by first priority liens on all shares of capital stock of each of the Company’s material present and future subsidiaries; all intercompany debt of the Company; and substantially all of the Company’s assets, including proved oil and natural gas reserves representing at least 80% of the discounted present value (as defined in the senior credit facility) of proved oil and natural gas reserves considered by the lenders in determining the borrowing base for the senior credit facility.
At the Company’s election, interest under the senior credit facility is determined by reference to (a) the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 2.00% and 3.00% per annum or (b) the “base rate,” which is the highest of (i) the federal funds rate plus 0.5%, (ii) the prime rate published by Bank of America or (iii) the Eurodollar rate (as defined in the senior credit facility) plus 1.00% per annum, plus, in each case under scenario (b), an applicable margin between 1.00% and 2.00% per annum. Interest is payable quarterly for base rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period
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for a LIBOR loan is six months, interest is paid at the end of each three-month period. The average annual interest rate paid on amounts outstanding under the senior credit facility was 2.51% and 2.65% for the three-month periods ended June 30, 2011 and 2010, respectively, and 2.70% and 2.52% for the six-month periods ended June 30, 2011 and 2010, respectively.
Borrowings under the senior credit facility may not exceed the lower of the borrowing base or the committed amount. On March 15, 2011, the borrowing base was reduced from $850.0 million to $790.0 million as a result of the issuance of the 7.5% Senior Notes due 2021, discussed below. The Company’s borrowing base is redetermined in April and October of each year. With respect to each redetermination, the administrative agent and the lenders under the senior credit facility consider several factors, including the Company’s proved reserves and projected cash requirements, and make assumptions regarding, among other things, oil and natural gas prices and production. Because the value of the Company’s proved reserves is a key factor in determining the amount of the borrowing base, changing commodity prices and the Company’s success in developing reserves may affect the borrowing base. At the April 2011 redetermination, the borrowing base remained $790.0 million. The Company at times incurs additional costs related to the senior credit facility as a result of amendments to the credit agreement and changes to the borrowing base. During the first six months of 2011, additional costs of approximately $0.3 million were incurred. These costs have been deferred and are included in other assets in the accompanying condensed consolidated balance sheets.
At June 30, 2011, the Company had $80.0 million outstanding under the senior credit facility and $24.5 million in outstanding letters of credit, which affect the availability under the senior credit facility on a dollar-for-dollar basis.
Other Notes Payable. The Company financed a portion of its drilling rig fleet and related oil field services equipment through the issuance of notes secured by such equipment. In March 2011, the Company paid the outstanding $4.3 million principal balance on these notes.
The debt incurred to purchase the downtown Oklahoma City property that serves as the Company’s corporate headquarters is fully secured by a mortgage on one of the buildings located on the property. The note underlying the mortgage bears interest at 6.08% annually and matures on November 15, 2022. Payments of principal and interest in the amount of approximately $0.5 million are due on a quarterly basis through the maturity date.
Senior Floating Rate Notes Due 2014 and 8.625% Senior Notes Due 2015. The Company’s Senior Floating Rate Notes due 2014 (the “Senior Floating Rate Notes”) and 8.625% Senior Notes due 2015 (the “8.625% Senior Notes”) were issued in May 2008. The Senior Floating Rate Notes are jointly and severally guaranteed unconditionally on an unsecured basis by certain of the Company’s wholly owned subsidiaries and are freely tradable. See Note 20 for condensed financial information of the subsidiary guarantors. As discussed below, on April 1, 2011, the Company redeemed the 8.625% Senior Notes that remained outstanding following the completion of its tender offer in respect of such notes.
The Senior Floating Rate Notes bear interest at LIBOR plus 3.625% (3.93% at June 30, 2011). Interest is payable quarterly with the principal due on April 1, 2014. The average interest rate paid on the outstanding Senior Floating Rate Notes was 3.93% and 3.92% for the three-month periods ended June 30, 2011 and 2010, respectively, and 3.93% and 3.90% for the six-month periods ended June 30, 2011 and 2010, respectively, without consideration of the interest rate swap discussed below. The Company may redeem, at specified redemption prices, some or all of the Senior Floating Rate Notes at any time.
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As of June 30, 2011, the Company had a $350.0 million notional interest rate swap agreement to fix the variable interest rate on the Senior Floating Rate Notes through April 1, 2013. The swap agreement effectively serves to fix the rate on the Senior Floating Rate Notes at an annual rate of 6.69% for the period from April 1, 2011 to April 1, 2013. This swap has not been designated as a hedge.
On March 1, 2011, the Company announced a cash tender offer to purchase any and all of the outstanding $650.0 million aggregate principal amount of its 8.625% Senior Notes for total consideration of $1,046.88 per $1,000 principal amount of such notes tendered by March 14, 2011. Holders tendering after March 14, 2011 were eligible to receive $1,016.88 per $1,000 principal amount of notes tendered. All holders whose notes were purchased received accrued and unpaid interest from the last interest payment date. As of March 31, 2011, the Company had purchased approximately 94.5%, or $614.2 million, of the aggregate principal amount of its 8.625% Senior Notes pursuant to the tender offer, which expired on March 28, 2011. On April 1, 2011, the Company redeemed the remaining outstanding $35.8 million aggregate principal amount of its 8.625% Senior Notes for $1,043.13 per $1,000 principal amount outstanding, plus accrued interest. All holders whose notes were redeemed received accrued and unpaid interest from October 1, 2010. The premium paid to purchase these notes and the unamortized debt issuance costs associated with the notes, totaling $2.0 million and $38.2 million for the three and six-month periods ended June 30, 2011, respectively, were recorded as a loss on extinguishment of debt and are included in the accompanying condensed consolidated statements of operations.
The $9.4 million of debt issuance costs associated with the Senior Floating Rate Notes is included in other assets in the accompanying condensed consolidated balance sheets and is being amortized over the term of the notes.
9.875% Senior Notes Due 2016. The Company’s unsecured 9.875% Senior Notes due 2016 (the “9.875% Senior Notes”) were issued in May 2009 and bear interest at a fixed rate of 9.875% per annum, payable semi-annually, with the principal due on May 15, 2016. The 9.875% Senior Notes were issued at a discount, which is amortized into interest expense over the term of the notes. The 9.875% Senior Notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally guaranteed unconditionally on an unsecured basis by certain of the Company’s wholly owned subsidiaries and are freely tradable.
Debt issuance costs of $7.9 million incurred in connection with the offering of the 9.875% Senior Notes are included in other assets in the accompanying condensed consolidated balance sheets and are being amortized over the term of the notes.
8.0% Senior Notes Due 2018. The Company’s unsecured 8.0% Senior Notes due 2018 (the “8.0% Senior Notes”) were issued in May 2008 and bear interest at a fixed rate of 8.0% per annum, payable semi-annually, with the principal due on June 1, 2018. The notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally guaranteed unconditionally on an unsecured basis, by certain of the Company’s wholly owned subsidiaries and are freely tradable.
The Company incurred $16.0 million of debt issuance costs in connection with the offering of the 8.0% Senior Notes. These costs are included in other assets in the accompanying condensed consolidated balance sheets and are being amortized over the term of the notes.
8.75% Senior Notes Due 2020. The Company’s unsecured 8.75% Senior Notes due 2020 (the “8.75% Senior Notes”) were issued in December 2009 and bear interest at a fixed rate of 8.75% per annum, payable semi-annually, with the principal due on January 15, 2020. The 8.75% Senior Notes were issued at a discount which is
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amortized into interest expense over the term of the notes. The 8.75% Senior Notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally, guaranteed unconditionally on an unsecured basis by certain of the Company’s wholly owned subsidiaries and are freely tradable. See Note 20 for condensed financial information of the subsidiary guarantors.
Debt issuance costs of $9.7 million incurred in connection with the offering of and subsequent registered exchange of the 8.75% Senior Notes are included in other assets in the accompanying condensed consolidated balance sheets and are being amortized over the term of the notes.
7.5% Senior Notes Due 2021. In March 2011, the Company issued $900.0 million of unsecured 7.5% Senior Notes due 2021 (the “7.5% Senior Notes”) to qualified institutional buyers eligible under Rule 144A of the Securities Act and to persons outside the United States under Regulation S under the Securities Act. Net proceeds from the offering were approximately $880.7 million after deducting offering expenses, and were used to fund the tender offer for the 8.625% Senior Notes, including any accrued and unpaid interest, the redemption of the 8.625% Senior Notes that remained outstanding following the conclusion of the tender offer, including accrued and unpaid interest (each as described above) and to repay borrowings under the Company’s senior credit facility. The 7.5% Senior Notes bear interest at a fixed rate of 7.5% per annum, payable semi-annually, with the principal due on March 15, 2021. Prior to March 15, 2016, the 7.5% Senior Notes are redeemable, in whole or in part, at a specified redemption price plus accrued and unpaid interest. On or after March 15, 2016, the 7.5% Senior Notes are redeemable, in whole or in part, prior to their maturity at other various specified redemption prices. The notes are jointly and severally guaranteed unconditionally on an unsecured basis by certain of the Company’s wholly owned subsidiaries.
In conjunction with the issuance of the 7.5% Senior Notes, the Company entered into a Registration Rights Agreement requiring the Company to conduct a registered exchange offer for or register the resale of these notes before March 14, 2012. The Company is required to pay additional interest if it fails to fulfill its obligations under the agreement within the specified time periods.
Debt issuance costs of $19.3 million incurred in connection with the offering of the 7.5% Senior Notes are included in other assets in the accompanying condensed consolidated balance sheets and are being amortized over the term of the notes.
Indentures. The indentures governing the Company’s senior notes contain limitations on the incurrence of indebtedness, payment of dividends, investments, asset sales, certain asset purchases, transactions with related parties and consolidations or mergers. As of and for the three and six-month periods ended June 30, 2011, the Company was in compliance with all of the covenants contained in the indentures governing the senior notes.
12. Derivatives
None of the Company’s derivative contracts have been designated as hedges. The Company records all derivative contracts, which include commodity derivatives and an interest rate swap, at fair value. Changes in derivative contract fair values are recognized in earnings. Cash settlements and valuation gains and losses are included in (gain) loss on derivative contracts for the commodity derivative contracts and in interest expense for interest rate swaps in the consolidated statement of operations. Commodity derivative contracts are settled on a monthly basis. Settlements on interest rate swaps occur quarterly. Derivative assets and liabilities arising from the Company’s derivative contracts with the same counterparty that provide for net settlement are reported on a net basis in the consolidated balance sheet.
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Commodity Derivatives. The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil and natural gas. The Company seeks to manage this risk through the use of commodity derivative contracts. These derivative contracts allow the Company to limit its exposure to a portion of its projected oil and natural gas sales. None of the Company’s derivative contracts may be terminated early as a result of a party to the contract having its credit rating downgraded. At June 30, 2011, the Company’s commodity derivative contracts consisted of fixed price swaps, collars and basis swaps, which are described below:
On April 12, 2011, the Company entered into a derivatives agreement with the Mississippian Trust, effective April 1, 2011, that provides the Mississippian Trust with the benefit of certain oil and natural gas derivative contracts previously entered into by the Company with third parties. The underlying commodity derivative contracts cover volumes of oil and natural gas production through December 31, 2015. Under this arrangement, the Company will pay the Mississippian Trust amounts it receives from its counterparties in accordance with the underlying contracts, and the Mississippian Trust will pay the Company any amounts that it is required to pay its counterparties under such contracts. These commodity derivative contracts are included in the open oil and natural gas derivative contracts tables below. See Note 8 for additional discussion of the Mississippian Trust and a listing of the derivative contracts, the benefits and obligations of which will be passed to the Mississippian Trust.
Interest Rate Swaps. The Company is exposed to interest rate risk on its long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes the Company to (i) changes in market interest rates reflected in the fair value of the debt and (ii) the risk that the Company may need to refinance maturing debt with new debt at a higher rate. Variable rate debt, where the interest rate fluctuates, exposes the Company to short-term changes in market interest rates as the Company’s interest obligations on these instruments are periodically redetermined based on prevailing market interest rates, primarily LIBOR and the federal funds rate.
The Company has an interest rate swap agreement to manage the interest rate risk on a portion of its floating rate debt by effectively fixing the variable interest rate on its Senior Floating Rate Notes through April 1, 2013. See Note 11 for further discussion of the Company’s interest rate swap.
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Fair Value of Derivatives. In accordance with ASC Topic 815, Derivatives and Hedging, the following table presents the fair value of the Company’s derivative contracts at June 30, 2011 and December 31, 2010 on a gross basis without regard to same-counterparty netting (in thousands):
Type of Contract
Balance Sheet Classification
Derivative assets
Oil price swaps
Derivative contracts-current
Natural gas price swaps
Derivative contracts-noncurrent
Derivative liabilities
Natural gas basis swaps
Natural gas collars
Total derivative contracts, net
Refer to Note 4 for additional discussion on the fair value measurement of the Company’s derivative contracts.
The following table summarizes the effects of the Company’s derivative contracts on the accompanying condensed consolidated statements of operations for the three and six-month periods ended June 30, 2011 and 2010 (in thousands):
Location of (Gain) Loss
Recognized in Income
Oil and natural gas derivatives
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The following tables summarize the cash settlements and valuation gains and losses on our commodity derivative contracts and interest rate swaps for the three and six-month periods ended June 30, 2011 and 2010 (in thousands):
Oil and Natural Gas Derivatives
Realized loss (gain)(1)
Unrealized (gain) loss
(Gain) loss on commodity derivative contracts
Interest Rate Swaps
Realized loss
Unrealized loss (gain)
Loss on interest rate swaps
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On June 30, 2011, the Company’s open oil and natural gas commodity derivative contracts consisted of the following:
Oil Swaps
Period and Type of Contract(1)
July 2011 — September 2011
October 2011 — December 2011
January 2012 — March 2012
April 2012 — June 2012
July 2012 — September 2012
October 2012 — December 2012
January 2013 — March 2013
April 2013 — June 2013
July 2013 — September 2013
October 2013 — December 2013
January 2014 — March 2014
April 2014 — June 2014
July 2014 — September 2014
October 2014 — December 2014
January 2015 — March 2015
April 2015 — June 2015
July 2015 — September 2015
October 2015 — December 2015
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Natural Gas Swaps
Price swap contracts(3)
Basis swap contracts
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Natural Gas Collars
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13. Income Taxes
The Company estimates for each interim reporting period the effective tax rate expected for the full fiscal year and uses that estimated rate in providing for income taxes on a current year-to-date basis. The (benefit) provision for income taxes consisted of the following components for the three and six-month periods ended June 30, 2011 and 2010 (in thousands).
Current
Federal
State
Deferred
Total (benefit) provision
Less: income tax provision attributable to noncontrolling interest
Total (benefit) provision attributable to SandRidge Energy, Inc.
Deferred income taxes are provided to reflect the future tax consequences of temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. Deferred tax assets are reduced by a valuation allowance as necessary when a determination is made that it is more likely than not that some or all of the deferred tax assets will not be realized based on the weight of all available evidence. As of December 31, 2008, the Company determined it was appropriate to record a full valuation allowance against its net deferred tax asset. In the second quarter of 2011, the Company completed its valuation of assets acquired and liabilities assumed related to the Arena Acquisition in order to finalize the purchase price allocation. In connection therewith, the Company adjusted the previously recorded net deferred tax liability associated with the Arena Acquisition by recording an additional net deferred tax liability of $7.0 million. The adjustment resulted in the Company releasing a corresponding portion of its previously recorded valuation allowance. This release of valuation allowance is in addition to the $447.5 million released in 2010. The 2010 and 2011 partial releases of the valuation allowance were based on management’s assessment that it is more likely than not that the Company will realize a benefit from more of its existing deferred tax assets as the Arena deferred tax liabilities are available to offset the reversal of the Company’s deferred tax assets. Although the Company continued to have a full valuation allowance against its net deferred tax asset at June 30, 2011, the additional release of the valuation allowance resulted in an income tax benefit of $7.0 million for the three and six-month periods ended June 30, 2011.
IRC Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. The Company experienced an ownership change within the meaning of IRC Section 382 on December 31, 2008. The ownership change subjected certain of the Company’s tax attributes, including $302.8 million of federal net operating loss carryforwards, to the IRC Section 382 limitation. The Company experienced a subsequent ownership change within the meaning of IRC Section 382 on July 16, 2010 as a result of the Arena Acquisition. The Company expects a more restrictive limitation on certain of its tax attributes as a result of the July 16, 2010 ownership change than with the December 31, 2008 ownership change. The more restrictive limitation would apply not only
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to the $302.8 million of federal net operating loss carryforwards and certain other tax attributes existing at December 31, 2008 but also to the net operating losses of approximately $491.4 million and certain other attributes generated during the period from January 1, 2009 through July 16, 2010. The subsequent limitation could result in a material amount of the loss carryforwards existing at July 16, 2010 expiring unused. Arena also experienced an ownership change on July 16, 2010 as a result of its acquisition by the Company. This ownership change is expected to result in a limitation on Arena’s net operating loss carryforwards and certain other carryforwards available to the Company on an annual basis. None of the limitations discussed above resulted in a current federal tax liability at June 30, 2011 or December 31, 2010.
As of June 30, 2011, the Company had a liability of approximately $1.52 million for unrecognized tax benefits. If recognized, approximately $1.0 million, net of federal tax expense, would be recorded as a reduction of income tax expense and would affect the effective tax rate. The liability for unrecognized tax benefits as of December 31, 2010 was $1.45 million.
Consistent with the Company’s policy to record interest and penalties on income taxes as a component of the income tax provision, the Company has included $0.02 million and $0.07 million of accrued gross interest with respect to unrecognized tax benefits in its condensed consolidated statements of operations for the three and six-month periods ended June 30, 2011, respectively. The Company did not recognize any interest and penalties related to unrecognized tax benefits during the three and six-month periods ended June 30, 2010.
The Company’s only taxing jurisdiction is the United States (federal and state). The Company’s tax years 2007 to present remain open for federal examination. Additionally, various tax years remain open for certain acquired entities beginning with tax year 2003 due to federal net operating loss carryforwards. The number of years open for state tax audits varies, depending on the state, but are generally from three to five years. Currently, several examinations are in progress. The Company does not anticipate that any federal or state audits will have a significant impact on the Company’s results of operations or financial position. In addition, the Company does not expect resolution of any uncertain tax positions that would result in a significant increase or decrease to the amount of unrecognized tax benefits during the next twelve months.
For the three-month period ended June 30, 2011, income tax refunds, net of payments, were $0.04 million. For the six-month period ended June 30, 2011, income tax payments, net of refunds, were $0.94 million. For the three and six-month periods ended June 30, 2010, income tax refunds, net of payments, were $0.1 million and $3.5 million, respectively.
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14. Earnings Per Share
Basic earnings per share are computed using the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average shares outstanding during the period, but also include the dilutive effect of awards of restricted stock and outstanding convertible preferred stock. The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings per share for the three and six-month periods ended June 30, 2011 and 2010 (in thousands):
Weighted average basic common shares outstanding
Effect of dilutive securities
Restricted stock
Convertible preferred stock outstanding
Weighted average diluted common and potential common shares outstanding
For the six-month period ended June 30, 2011, restricted stock awards covering 7.3 million shares were excluded from the computation of net loss per share because their effect would have been antidilutive.
In computing diluted earnings per share, the Company evaluated the if-converted method with respect to its outstanding 8.5% convertible perpetual preferred stock, 6.0% convertible perpetual preferred stock and 7.0% convertible perpetual preferred stock for the three and six-month periods ended June 30, 2011 and its outstanding 8.5% convertible perpetual preferred stock and 6.0% convertible perpetual preferred stock for the three and six-month periods ended June 30, 2010. See Note 16 for discussion of the Company’s convertible preferred stock. Under the if-converted method, the Company assumes the conversion of the preferred stock to common stock and determines if this is more dilutive than including the preferred stock dividends (paid and unpaid) in the computation of income available to common stockholders. For the three-month period ended June 30, 2011, the Company determined the if-converted method was more dilutive and did not include the 6.0%, 8.5% or 7.0% preferred stock dividends in the determination of income available to common stockholders. For the six-month period ended June 30, 2011, the Company determined the if-converted method was not more dilutive and included preferred stock dividends in the determination of loss applicable to common stockholders. For the three-month period ended June 30, 2010, the Company determined the if-converted method was more dilutive and did not include the 6.0% and 8.5% preferred stock dividends in the determination of income available to common stockholders. For the six-month period ended June 30, 2010, the Company determined the if-converted method was more dilutive with respect to its 6.0% convertible perpetual preferred stock, but not more dilutive with respect to its 8.5% convertible perpetual preferred stock. As a result, the Company did not include the 6.0% preferred stock dividends, but did include the 8.5% preferred stock dividends in the determination of income available to common stockholders for the six-month period ended June 30, 2010.
15. Commitments and Contingencies
The Company is a defendant in lawsuits from time to time in the normal course of business. In management’s opinion, the Company is not currently involved in any legal proceedings that, individually or in the aggregate, could have a material effect on the financial condition, operations or cash flows of the Company.
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On or about June 27, 2008 and November 6, 2008, there were fires at the Company’s Grey Ranch Plant and a nearby compressor station. The Company, as owner of the plant and compressor station, recovered approximately $24.5 million from its insurance carriers for damages caused by the fires. At the time of the plant fire, the plant was operated by Southern Union Gas Services, Ltd. (“Southern Union Gas”). On June 4, 2010, November 10, 2010, and March 15, 2011, the Company’s insurance carriers filed lawsuits against Southern Union Gas and its parent, Southern Union Company (together with Southern Union Gas, “Southern Union”) seeking recovery for amounts paid under the Company’s insurance policies. Southern Union, in turn, has tendered indemnity requests to GRLP, of which the Company is a 50% owner. GRLP has not accepted or acknowledged any responsibility to indemnify Southern Union. To the extent the Company, as a 50% owner of GRLP, is required to fund any indemnification of Southern Union, it will pursue coverage for such liability under its general liability insurance policy. An estimate of reasonably possible losses associated with these claims cannot be made at this time. The Company has not established any reserves relating to these claims.
On February 14, 2011, Aspen Pipeline, II, L.P. (“Aspen”) filed a complaint in the District Court of Harris County, Texas, against Arena Resources, Inc. and SandRidge Energy, Inc. claiming damages based upon alleged representations by Arena in connection with the construction by Aspen of a natural gas pipeline in West Texas. The plaintiff seeks damages that include the construction cost of the pipeline, which it claims approach $90.0 million. The Company intends to defend this lawsuit vigorously and, believes the plaintiff’s claims are without merit. This case is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this claim cannot be made at this time. The Company has not established any reserves relating to this claim.
On April 5, 2011, Wesley West Minerals, Ltd. and Longfellow Ranch Partners, LP (collectively, the “plaintiffs”) filed suit against SandRidge Energy, Inc. and SandRidge Exploration and Production, LLC (collectively, the “SandRidge Entities”) in the 83rd District Court of Pecos County, Texas. The plaintiffs, who have leased mineral rights to the SandRidge Entities in Pecos County, allege that the SandRidge Entities have not properly paid royalties on all volumes of natural gas (including carbon dioxide, or “CO2”) produced from the acreage leased from the plaintiffs. The plaintiffs also allege that the SandRidge Entities have inappropriately failed to pay royalties on CO2 produced from the plaintiffs’ acreage that results from the treatment of natural gas at the Century Plant. The plaintiffs seek unspecified actual damages, punitive damages and a declaration that the SandRidge Entities must pay royalties on CO2 produced from plaintiffs’ acreage that results from treatment of natural gas at the Century Plant. The Company intends to defend this lawsuit vigorously. This case is in the early stages and, accordingly, an estimate of reasonably possible losses, if any, associated with these claims cannot be made at this time. The Company has not established any reserves relating to these claims.
SandRidge acquired certain oil and natural gas leases in Loving County, Texas, from mineral owners in April 2010, which it subsequently sold to Energen Resources Corporation (“Energen”) in December 2010 for an allocated value of approximately $4.0 million. Subsequent to the acquisition by SandRidge of the leases and prior to their disposition to Energen, the mineral owners executed oil and natural gas leases conveying the same mineral estates to Cimarex Energy Co. (“Cimarex”). SandRidge has requested a declaratory judgment resolving all disputes between it and Cimarex regarding the validity of the leases insofar as they purport to cover the same mineral interests. In connection with that action, Cimarex has filed a third-party petition naming Energen as a third-party defendant, and is asserting quiet title and trespass to try title claims against Energen. Energen has tendered to SandRidge a demand for indemnity, and SandRidge has assumed Energen’s defense and any potential loss suffered by it. An estimate of reasonably possible losses, if any, associated with the demand for indemnity cannot be made at this time. Accordingly, the Company has not established any reserves relating to the demand.
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16. Equity
Preferred Stock. The following table presents information regarding the Company’s preferred stock (in thousands):
Shares authorized
Shares outstanding at end of period
8.5% Convertible perpetual preferred stock
6.0% Convertible perpetual preferred stock
7.0% Convertible perpetual preferred stock
The Company is authorized to issue 50,000,000 shares of preferred stock, $0.001 par value, of which 7,650,000 shares were designated as convertible perpetual preferred stock at June 30, 2011 and December 31, 2010. All of the outstanding shares of the Company’s convertible perpetual preferred stock were issued in private transactions and none of these shares are listed on a stock exchange.
8.5% Convertible perpetual preferred stock. The Company’s 8.5% convertible perpetual preferred stock was issued in January 2009. Each share of 8.5% convertible perpetual preferred stock has a liquidation preference of $100.00 and is convertible at the holder’s option at any time initially into approximately 12.4805 shares of the Company’s common stock based on an initial conversion price of $8.01, subject to adjustments upon the occurrence of certain events. Each holder of the convertible perpetual preferred stock is entitled to an annual dividend of $8.50 per share to be paid semi-annually in cash, common stock or a combination thereof, at the Company’s election. All dividend payments to date have been paid in cash. Approximately $5.6 million in dividends (all unpaid) and $11.3 million in dividends ($2.8 million paid and $8.5 million unpaid) on the 8.5% convertible perpetual preferred stock have been included in the Company’s earnings per share calculations for the three and six-month periods ended June 30, 2011, respectively, as presented in the accompanying condensed consolidated statements of operations. Approximately $5.6 million in dividends (all unpaid) and $11.3 million in dividends ($2.8 million paid and $8.5 million unpaid) on the 8.5% convertible perpetual preferred stock have been included in the Company’s earnings per share calculations for the three and six-month periods ended June 30, 2010, respectively, as presented in the accompanying condensed consolidated statements of operations. The 8.5% convertible perpetual preferred stock is not redeemable by the Company at any time. After February 20, 2014, the Company may cause all outstanding shares of the convertible perpetual preferred stock to convert automatically into common stock at the then-prevailing conversion rate if certain conditions are met.
6.0% Convertible perpetual preferred stock. The Company’s 6.0% convertible perpetual preferred stock was issued in December 2009. Each share of the 6.0% convertible perpetual preferred stock has a liquidation preference of $100.00 and is entitled to an annual dividend of $6.00 payable semi-annually in cash, common stock or any combination thereof, at the Company’s election. All dividend payments to date have been paid in cash. Approximately $3.0 million (all unpaid) and $6.0 million in dividends ($0.5 million paid and $5.5 million unpaid) on the 6.0% convertible perpetual preferred stock have been included in the Company’s earnings per share calculations for the three and six-month periods ended June 30, 2011, respectively, as presented in the accompanying condensed consolidated statements of operations. Approximately $3.0 million and $6.0 million in unpaid dividends on the 6.0% convertible perpetual preferred stock have been included in the Company’s earnings per share calculations for the three and six-month periods ended June 30, 2010, respectively, as presented in the accompanying condensed consolidated statements of operations. The 6.0% convertible perpetual preferred stock is not redeemable by the Company at any time. Each share is initially convertible into approximately 9.2115 shares of the Company’s common stock, at the holder’s option based on an initial
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conversion price of $10.86 and subject to customary adjustments in certain circumstances. Five years after their issuance, all outstanding shares of the convertible preferred stock will be converted automatically into shares of the Company’s common stock at the then-prevailing conversion price as long as all dividends accrued at that time have been paid.
7.0% Convertible perpetual preferred stock. The Company’s 7.0% convertible perpetual preferred stock was issued in November 2010. Each share of the 7.0% convertible preferred stock has a liquidation preference of $100.00 per share and became convertible at the holder’s option on February 15, 2011, initially into approximately 12.8791 shares of the Company’s common stock based on an initial conversion price of $7.76 per share. The annual dividend on each share of the 7.0% convertible preferred stock is $7.00 payable semi-annually, in cash, common stock or a combination thereof, at the Company’s election beginning on May 15, 2011. All dividend payments to date have been paid in cash. Approximately $5.3 million ($2.7 million paid and $2.6 million unpaid) and $10.6 million in dividends ($8.0 million paid and $2.6 million unpaid) on the 7.0% convertible perpetual preferred stock have been included in the Company’s earnings per share calculations for the three and six-month periods ended June 30, 2011 as presented in the accompanying condensed consolidated statements of operations. The 7.0% convertible perpetual preferred stock is not redeemable by the Company at any time. After November 20, 2015, the Company may cause all outstanding shares of the 7.0% convertible perpetual preferred stock to convert automatically into common stock at the then-prevailing conversion rate if certain conditions are met.
Common Stock. The following table presents information regarding the Company’s common stock (in thousands):
Shares held in treasury
Treasury Stock. The Company makes required tax payments on behalf of employees when their restricted stock awards vest and then withholds a number of vested shares of common stock having a value on the date of vesting equal to the tax obligation. As a result of such transactions, the Company withheld approximately 617,000 shares with a total value of $5.0 million and approximately 274,000 shares with a total value of $2.9 million during the six-month periods ended June 30, 2011 and 2010, respectively. These shares were accounted for as treasury stock when withheld, and subsequently retired.
Any shares of Company common stock held as assets in a trust for the Company’s non-qualified deferred compensation plan are accounted for as treasury shares. These shares are not included as outstanding shares of common stock in this Quarterly Report. For corporate purposes and for purposes of voting at Company stockholder meetings, these shares are considered outstanding and have voting rights, which are exercised by the Company.
Equity Compensation. The Company awards restricted common stock under incentive compensation plans that vest over specified periods, subject to certain conditions. All awards issued during and after 2006 have four-year vesting periods. Shares of restricted common stock are subject to restriction on transfer. Unvested restricted stock awards are included in the Company’s outstanding shares of common stock.
For the three and six-month periods ended June 30, 2011, the Company recognized stock-based compensation expense of $8.9 million and $17.1 million, net of $1.9 million and $3.7 million capitalized,
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respectively, related to restricted common stock awards. For the three and six-month periods ended June 30, 2010, the Company recognized stock-based compensation expense of $7.3 million and $14.2 million, net of $1.3 million and $2.6 million capitalized, respectively, related to restricted common stock awards.
Noncontrolling Interest. Noncontrolling interests in one of the Company’s subsidiaries and three variable interest entities of which the Company is the primary beneficiary (see Note 8) represent third-party ownership interests in the consolidated entity and are included as a component of equity in the consolidated balance sheet and consolidated statement of changes in equity.
17. Related Party Transactions
The Company enters into transactions in the ordinary course of business with certain related parties. These transactions primarily consist of purchases related to drilling and completion activities, gas treating services and drilling equipment and sales of oil field services, equipment and natural gas. Following is a summary of significant transactions with such related parties (in thousands):
Sales to and reimbursements from related parties
Accounts receivable due from related parties
Oklahoma City Thunder Agreements. The Company’s Chairman and Chief Executive Officer owns a minority interest in a limited liability company that owns and operates the Oklahoma City Thunder, a National Basketball Association team playing in Oklahoma City, where the Company is headquartered. The Company is party to a sponsorship agreement, through the 2013 season, whereby it pays approximately $3.3 million per year for advertising and promotional activities related to the Oklahoma City Thunder. Additionally, the Company entered into an agreement to license a suite at the arena where the Oklahoma City Thunder plays its home games. Under this four-year agreement, the Company pays an annual license fee of $0.2 million through 2013. Amounts related to these agreements are not included in the tables above. At June 30, 2011 the Company had no amounts due under these agreements. At December 31, 2010, the amount due under these agreements was $0.8 million.
18. Subsequent Events
Events occurring after June 30, 2011 were evaluated to ensure that any subsequent events that met the criteria for recognition and/or disclosure in this Quarterly Report have been included.
SandRidge Permian Trust. On May 25, 2011, the Company and SandRidge Permian Trust (the “Permian Trust”), a newly formed Delaware trust, filed a joint registration statement with the Securities and Exchange Commission (the “SEC”) relating to a proposed public offering of up to approximately $760.7 million (before underwriting discounts and offering expenses) in common units representing beneficial interests in the Permian Trust (including common units issuable upon exercise of the underwriters’ over-allotment option). Prior to the closing of this offering, the Company intends to convey certain royalty interests to the Permian Trust in exchange for units representing approximately 40% of the beneficial interest in the Permian Trust and the net proceeds of the Permian Trust’s public offering. The royalty interests will entitle the Permian Trust to a percentage of the
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proceeds received by the Company from the production of hydrocarbons from currently producing wells and development wells to be drilled by the Company on approximately 15,900 net acres in the Permian Basin’s Central Basin Platform in Andrews County, Texas. There can be no assurance that this transaction will be completed, as it is subject to market conditions and other uncertainties, as well as completion of the SEC’s review process. If the transaction is completed, the Company intends to use the proceeds it receives to repay borrowings under its senior credit facility and for general corporate purposes.
Sale of Working Interest in Mississippian Properties. On August 3, 2011, the Company entered into an agreement with Atinum Partners Co., Ltd. (“Atinum”) pursuant to which the Company agreed to sell to Atinum a 13.2% undivided working interest in approximately 860,000 acres that the Company has leased in Oklahoma and Kansas for development of the Mississippian Lime horizontal play. In exchange for the working interest, Atinum will pay the Company $250.0 million in cash at closing and will pay $250.0 million of the Company’s costs to develop the acreage over the next three years. The agreement is subject to customary closing conditions and is expected to close during the fourth quarter of 2011.
19. Business Segment Information
The Company has three business segments: exploration and production, drilling and oil field services and midstream gas services. These segments represent the Company’s three main business units, each offering different products and services. The exploration and production segment is engaged in the acquisition, development and production of oil and natural gas properties. The drilling and oil field services segment is engaged in the contract drilling of oil and natural gas wells. The midstream gas services segment is engaged in the purchasing, gathering, treating and selling of natural gas. The All Other column in the tables below includes items not related to the Company’s reportable segments, including the Company’s CO2 gathering and sales operations and corporate operations.
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Management evaluates the performance of the Company’s business segments based on operating income (loss), which is defined as segment operating revenues less operating expenses and depreciation, depletion and amortization. Summarized financial information concerning the Company’s segments is shown in the following tables (in thousands):
Three Months Ended June 30, 2011
Inter-segment revenue
Operating income (loss)
Interest income (expense), net
Capital expenditures(1)
Three Months Ended June 30, 2010
Six Months Ended June 30, 2011
At June 30, 2011
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Six Months Ended June 30, 2010
Interest expense (expense), net
At December 31, 2010
20. Condensed Consolidating Financial Information
The Company provides condensed consolidating financial information for its subsidiaries that are guarantors of its registered debt. The subsidiary guarantors are wholly owned and have jointly and severally guaranteed unconditionally on an unsecured basis the Company’s Senior Floating Rate Notes and 8.75% Senior Notes as of June 30, 2011. Prior to their purchase and redemption, the 8.625% Senior Notes were also jointly and severally guaranteed unconditionally on an unsecured basis by the wholly owned subsidiary guarantors. The subsidiary guarantees (i) rank equally in right of payment with all of the existing and future senior debt of the subsidiary guarantors; (ii) rank senior to all of the existing and future subordinated debt of the subsidiary guarantors; (iii) are effectively subordinated in right of payment to any existing or future secured obligations of the subsidiary guarantors to the extent of the value of the assets securing such obligations; and (iv) are structurally subordinated to all debt and other obligations of the subsidiaries of the guarantors who are not themselves guarantors. The Company’s subsidiary guarantors guarantee payments of principal and interest under the Company’s registered notes. The Company has not presented separate financial and narrative information for each of the subsidiary guarantors because it believes that such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the guarantees.
The following condensed consolidating financial information represents the financial information of SandRidge Energy, Inc., its wholly owned subsidiary guarantors and its non-guarantor subsidiaries, prepared on the equity basis of accounting. The non-guarantor subsidiaries and three variable interest entities are included in the non-guarantor column in the tables below. The financial information may not necessarily be indicative of the financial position, results of operations or cash flows had the subsidiary guarantors operated as independent entities.
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Condensed Consolidating Balance Sheets
Accounts and notes receivable, net
Property, plant and equipment, net
Investment in subsidiaries
Other current liabilities
Other liabilities
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Condensed Consolidating Statements of Operations
Direct operating expenses
Depreciation, depletion, amortization and impairment
Gain on derivative contracts
(Loss) income from operations
Equity earnings from subsidiaries
Interest expense, net
Other income, net
Income before income taxes
Income tax benefit
Net income
Net income attributable to SandRidge Energy, Inc.
Other expense (income), net
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(Loss) gain on derivative contracts
(Loss) income before income taxes
Net (loss) income attributable to SandRidge Energy, Inc.
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Condensed Consolidating Statements of Cash Flows
Net cash provided by (used in) operating activities
Net cash (used in) provided by financing activities
Net (decrease) increase in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of period
Net cash (used in) provided by operating activities
Net cash provided by (used in) financing activities
Net decrease in cash and cash equivalents
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ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Introduction
The following discussion and analysis is intended to help the reader understand the Company’s business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with the Company’s condensed consolidated financial statements and the accompanying notes included in this Quarterly Report, as well as the Company’s audited consolidated financial statements and the accompanying notes included in the 2010 Form 10-K. The Company’s discussion and analysis includes the following subjects:
Overview of the Company
Recent Developments
Recent Accounting Pronouncements
Results by Segment
Consolidated Results of Operations
Liquidity and Capital Resources
The financial information with respect to the three and six-month periods ended June 30, 2011 and June 30, 2010, discussed below, is unaudited. In the opinion of management, this information contains all adjustments, which consist only of normal recurring adjustments, necessary to state fairly the unaudited condensed consolidated financial statements. The results of operations for the interim periods are not necessarily indicative of the results of operations for the full fiscal year.
SandRidge is an independent oil and natural gas company concentrating on development and production activities related to the exploitation of the Company’s significant holdings in West Texas and the Mid-Continent area of Oklahoma and Kansas. The Company’s primary areas of focus are the Permian Basin in West Texas, the Mississippian formation in the Mid-Continent and the WTO. The Company also owns and operates other interests in the Mid-Continent, Cotton Valley Trend in East Texas, Gulf Coast and Gulf of Mexico. In 2009, the Company began expanding the oil component of its property base. This expansion included the purchase of properties from Forest Oil Corporation and one of its subsidiaries in December 2009 and the Arena Acquisition in July 2010, both of which added significantly to the Company’s holdings in the Permian Basin area. Concurrent with these acquisitions, the Company focused on increasing oil production in the Mid-Continent by significantly growing and developing its property base in that area.
The Company operates businesses that are complementary to its development and production activities. The Company owns related gas gathering and treating facilities, a gas marketing business and an oil field services business. The extent to which each of these supplemental businesses contributes to the Company’s consolidated results of operations largely is determined by the amount of work each performs for third parties. Revenues and costs related to work performed by these businesses for the Company’s own account are eliminated in consolidation and, therefore, do not directly contribute to the Company’s consolidated results of operations.
The Company currently generates the majority of its consolidated revenues and cash flow from the production and sale of oil and natural gas. The Company’s revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas and on the Company’s ability to find and economically develop and produce oil and natural gas reserves. Prices for oil and natural gas fluctuate widely. In order to reduce the Company’s exposure to these fluctuations, the Company enters into commodity derivative contracts for a portion of its anticipated future oil and natural gas production. Reducing the Company’s exposure to price volatility helps ensure that it has adequate funds available for its capital expenditure programs.
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SandRidge Mississippian Trust I. On April 12, 2011, the Mississippian Trust completed its initial public offering of 17,250,000 common units representing beneficial interests in the Mississippian Trust. Net proceeds to the Mississippian Trust, after certain offering expenses, were approximately $336.9 million. Concurrent with the closing, the Company conveyed certain royalty interests to the Mississippian Trust in exchange for the net proceeds of the Mississippian Trust’s initial public offering and 10,750,000 units (3,750,000 common units and 7,000,000 subordinated units) representing approximately 38.4% of the beneficial interest in the Mississippian Trust. The Company used the net proceeds it received from the Mississippian Trust’s offering to repay borrowings under the Company’s senior credit facility and for general corporate purposes.
In order to provide support for cash distributions on the Mississippian Trust’s common units, SandRidge agreed to subordinate a portion of the Mississippian Trust units it owns, which constitute 25% of the total outstanding Mississippian Trust units. The subordinated units are entitled to receive pro rata distributions from the Mississippian Trust each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is no less than the applicable quarterly subordination threshold. If there is not sufficient cash to fund such a distribution on all common units, the distribution to be made with respect to the subordinated units will be reduced or eliminated for such quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on all common units, including common units held by the Company.
SandRidge and one of its wholly owned subsidiaries entered into a development agreement with the Mississippian Trust that obligates the Company to drill, or cause to be drilled, a specified number of wells, which are also subject to a royalty interest, by December 31, 2014. In the event of delays, the Company will have until December 31, 2015 to fulfill its drilling obligation. One of the Company’s wholly owned subsidiaries also granted to the Mississippian Trust a lien in the Company’s interests in the properties where the development wells will be drilled, in order to secure the estimated amount of the drilling costs for the wells. Additionally, the Company and the Mississippian Trust entered into an administrative services agreement and a derivatives agreement. As the Mississippian Trust is a variable interest entity of which SandRidge is the primary beneficiary, its activities were consolidated with those of SandRidge, beginning in April 2011.
SandRidge Permian Trust. On May 25, 2011, the Company and the Permian Trust, a newly formed Delaware trust, filed a joint registration statement with the SEC relating to a proposed public offering of up to approximately $760.7 million (before underwriting discounts and offering expenses) in common units representing beneficial interests in the Permian Trust (including common units issuable upon exercise of the underwriters’ over-allotment option). Prior to the closing of this offering, the Company intends to convey certain royalty interests to the Permian Trust in exchange for units representing approximately 40% of the beneficial interest in the Permian Trust and the net proceeds of the Permian Trust’s public offering. The royalty interests will entitle the Permian Trust to a percentage of the proceeds received by the Company from the production of hydrocarbons from currently producing wells and development wells to be drilled by the Company on approximately 15,900 net acres in the Permian Basin’s Central Basin Platform in Andrews County, Texas. There can be no assurance that this transaction will be completed, as it is subject to market conditions and other uncertainties, as well as completion of the SEC’s review process. If the transaction is completed, the Company intends to use the proceeds it receives to repay borrowings under its senior credit facility and for general corporate purposes.
Sale of Working Interest in Mississippian Properties. On August 3, 2011, the Company entered into an agreement with Atinum pursuant to which the Company agreed to sell to Atinum a 13.2% undivided working interest in approximately 860,000 acres that the Company has leased in Oklahoma and Kansas for development of the Mississippian Lime horizontal play. In exchange for the working interest, Atinum will pay the Company $250.0 million in cash at closing and will pay $250.0 million of the Company’s costs to develop the acreage over the next three years. The agreement is subject to customary closing conditions and is expected to close during the fourth quarter of 2011.
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For a discussion of recent accounting pronouncements, see Note 2 to the Company’s condensed consolidated financial statements included in Item 1 of this Quarterly Report.
SandRidge operates in three business segments: exploration and production, drilling and oil field services and midstream gas services. The All Other column in the tables below includes items not related to the Company’s reportable segments, including its CO2 gathering and sales operations and corporate operations. Management evaluates the performance of the Company’s business segments based on operating income (loss), which is defined as segment operating revenues less operating expenses and depreciation, depletion and amortization. Results of these measurements provide important information to the Company about the activity and profitability of our lines of business. Set forth in the tables below is financial information regarding the Company’s business segments for the three and six-month periods ended June 30, 2011 and 2010 (in thousands).
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Exploration and Production Segment
The primary factors affecting the financial results of the Company’s exploration and production segment are the prices the Company receives for its oil and natural gas production, the quantity of oil and natural gas it produces and changes in the fair value of commodity derivative contracts used to reduce the volatility of the prices received for its oil and natural gas production. Quarterly comparisons of production and price data are presented in the tables below. Changes in the Company’s results for these periods reflect, in part, the acquisition of oil and natural gas properties in the Arena Acquisition in July 2010, which increased production volumes and revenues attributable to the Company’s exploration and production segment.
Production data
Oil (MBbl)(1)
Natural gas (MMcf)
Combined equivalent volumes (MBoe)
Average daily combined equivalent volumes (MBoe/d)
Average prices — as reported(2)
Oil (per Bbl)(1)
Natural gas (per Mcf)
Combined equivalent (per Boe)
Average prices — including impact of derivative contract settlements
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Exploration and Production Segment — Three months ended June 30, 2011 compared to the three months ended June 30, 2010
Exploration and production segment revenues increased $167.2 million, or 111.1%, to $317.7 million in the three months ended June 30, 2011 from $150.5 million in the three months ended June 30, 2010, as a result of a 105.9% increase in oil production and a 42.4% increase in the average price the Company received for its oil production. These increases were slightly offset by the 10.8% decrease in natural gas production. The increase in oil production was due to the addition of Permian Basin properties acquired from Arena, and a focus on increased oil drilling throughout 2010 and 2011. Properties acquired from Arena produced 985 MBbls of oil for the three-month period ended June 30, 2011. The decrease in natural gas production was a result of the decline in the number of rigs drilling for natural gas during 2010 and 2011 due to depressed natural gas prices.
The average price received for the Company’s oil production increased 42.4%, or $26.53 per barrel, to $89.09 per barrel during the three months ended June 30, 2011 from $62.56 per barrel during the same period in 2010. The average price received for the Company’s natural gas production for the three-month period ended June 30, 2011 increased 11.7%, or $0.40 per Mcf, to $3.81 per Mcf from $3.41 per Mcf in the comparable period in 2010. Including the impact of derivative contract settlements, the effective price received for oil for the three-month period ended June 30, 2011 was $76.26 per Bbl compared to $65.86 per Bbl during the same period in 2010. Including the impact of derivative contract settlements, the effective price received for natural gas for the three-month period ended June 30, 2011 was $3.31 per Mcf compared to $6.06 per Mcf during the same period in 2010. The Company’s derivative contracts are not designated as hedges and, as a result, gains or losses on commodity derivative contracts are recorded as a component of operating expenses. Internally, management views the settlement of such derivative contracts as adjustments to the price received for oil and natural gas production to determine “effective prices.” Realized gains or losses from the settlement of derivative contracts with contractual maturities outside of the reporting period are not considered in the calculation of “effective prices.”
During the three-month period ended June 30, 2011, the exploration and production segment reported a $170.0 million net gain on its commodity derivative positions ($18.3 million realized loss and $188.3 million unrealized gain) compared to a $119.6 million net gain on its commodity derivative positions ($117.9 million realized gain and $1.7 million unrealized gain) in the same period in 2010. The realized loss for the three months
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ended June 30, 2011 was primarily due to higher oil prices at the time of settlement compared to the contract price. Realized gains totaling $25.8 million resulting from settlements of commodity derivative contracts with original contractual maturities after June 30, 2011 were included in the net realized loss for the three months ended June 30, 2011. The realized gain of $117.9 million for the three months ended June 30, 2010 was primarily due to lower natural gas prices at the time of settlement compared to the contract price. Realized gains totaling $62.4 million resulting from settlements of commodity derivative contracts with original contractual maturities after June 30, 2010 were included in the net realized gain for the three-month period ended June 30, 2010. Unrealized gains or losses on derivative contracts represent the change in fair value of open derivative contracts during the period. The unrealized gain on the Company’s commodity contracts recorded during the three months ended June 30, 2011 was primarily attributable to a decrease in average oil prices at June 30, 2011 compared to the average oil prices at March 31, 2011 or the contract price for contracts entered into during the second quarter of 2011. The unrealized gain on the Company’s commodity contracts recorded during the three months ended June 30, 2010 was attributable to a decrease in average oil prices and increases in the price differentials on the Company’s basis swaps at June 30, 2010 compared to the average oil prices and price differentials at March 31, 2010. This amount was partially offset by increases in the average natural gas price at June 30, 2010 compared to the average natural gas price at March 31, 2010.
For the three months ended June 30, 2011, the Company had operating income of $301.2 million in its exploration and production segment compared to operating income of $136.5 million for the same period in 2010. The increases of $162.1 million in oil and natural gas revenues and $50.4 million in gain on derivative contracts were partially offset by increases of $25.8 million in production expense and $21.9 million in depreciation and depletion on oil and natural gas properties during the three months ended June 30, 2011. See discussion of production expense and depreciation and depletion under “Consolidated Results of Operations.”
Exploration and Production Segment — Six months ended June 30, 2011 compared to the six months ended June 30, 2010
Exploration and production segment revenues increased $264.3 million, or 82.4%, to $584.9 million in the six months ended June 30, 2011 from $320.6 million in the six months ended June 30, 2010, as a result of a 109.3% increase in oil production and a 31.3% increase in the average price the Company received for its oil production. These increases were slightly offset by the 10.1% decrease in natural gas production and a 9.2% decrease in the average price received for the Company’s natural gas production. The increase in oil production was due to the addition of Permian Basin properties acquired from Arena, and a focus on increased oil drilling throughout 2010 and 2011. Properties acquired from Arena produced 1,870 MBbls of oil for the six-month period ended June 30, 2011. The decrease in natural gas production was a result of the decline in the number of rigs drilling for natural gas during 2010 and 2011 due to depressed natural gas prices.
The average price received for the Company’s oil production increased 31.3%, or $20.16 per barrel, to $84.59 per barrel during the six months ended June 30, 2011 from $64.43 per barrel during the same period in 2010. The average price received for the Company’s natural gas production for the six-month period ended June 30, 2011 decreased 9.2%, or $0.37 per Mcf, to $3.67 per Mcf from $4.04 per Mcf in the comparable period in 2010. Including the impact of derivative contract settlements, the effective price received for oil for the six-month period ended June 30, 2011 was $74.33 per Bbl compared to $67.39 per Bbl during the same period in 2010. Including the impact of derivative contract settlements, the effective price received for natural gas for the six-month period ended June 30, 2011 was $3.46 per Mcf compared to $6.40 per Mcf during the same period in 2010.
During the six-month period ended June 30, 2011, the exploration and production segment reported a $107.6 million net loss on its commodity derivative positions ($26.9 million realized loss and $80.7 million unrealized loss) compared to a $181.6 million net gain on its commodity derivative positions ($160.6 million realized gain and $21.0 million unrealized gain) in the same period in 2010. The realized loss for the six months ended June 30, 2011 was primarily due to higher oil prices at the time of settlement compared to the contract price. Realized gains totaling $38.2 million resulting from settlements of commodity derivative contracts with
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original contractual maturities after the quarterly period in which they were settled were included in the net realized loss for the six months ended June 30, 2011. The realized gain of $160.6 million for the six months ended June 30, 2010 was primarily due to lower natural gas prices at the time of settlement compared to the contract price. Realized gains totaling $62.4 million resulting from settlements of commodity derivative contracts with original contractual maturities after the quarterly period in which they were settled were included in the net realized gain for the six months ended June 30, 2010. The unrealized loss on the Company’s commodity contracts recorded during the six months ended June 30, 2011 was primarily attributable to an increase in average oil prices at June 30, 2011 compared to the average oil prices at December 31, 2010 or the contract price for contracts entered into during first six months of 2011. The unrealized gain for the six-month period ended June 30, 2010 was attributable to a decrease in average oil prices and increases in the price differentials on the Company’s basis swaps at June 30, 2010 compared to the average oil prices and price differentials at December 31, 2009 or the contract price for contracts entered into during the first six months of 2010. This amount was partially offset by increases in the average price of natural gas at June 30, 2010 compared to the average price of natural gas at December 31, 2009, or as stated in the contract for contracts entered into during the first six months of 2010.
For the six months ended June 30, 2011, the Company had operating income of $117.0 million in its exploration and production segment compared to operating income of $246.5 million for the same period in 2010. Offsetting the $259.5 million increase in oil and natural gas revenues were the increases of $49.5 million in production expense and $43.5 million in depreciation and depletion on oil and natural gas properties during the six months ended June 30, 2011. Additionally, the Company recorded a $107.6 million net loss on the Company’s commodity derivative contracts for the six months ended June 30, 2011 compared to a $181.6 million net gain for the same period in 2010. See discussion of production expense and depreciation and depletion under “Consolidated Results of Operations.”
Drilling and Oil Field Services Segment
The financial results of the Company’s drilling and oil field services segment depend primarily on demand and prices that can be charged for its services. In addition to providing drilling services, the Company’s oil field services business also conducts operations that complement its exploration and production segment such as providing pulling units, trucking, rental tools, location and road construction and roustabout services. On a consolidated basis, drilling and oil field service revenues earned and expenses incurred in performing services for third parties, including third party working interests in wells the Company operates, are included in drilling and services revenues and expenses while drilling and oil field service revenues earned and expenses incurred in performing services for the Company’s own account are eliminated in consolidation.
As of June 30, 2011, the Company owned 31 drilling rigs. The table below presents a summary of the Company’s rigs as of June 30, 2011 and 2010:
Rigs working for SandRidge
Rigs working for third parties
Idle rigs
Total operational
Non-operational rigs(1)
Total rigs owned
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Drilling and Oil Field Services Segment — Three months ended June 30, 2011 compared to the three months ended June 30, 2010
Drilling and oil field services segment revenues increased to $28.5 million in the three-month period ended June 30, 2011 from $3.9 million in the three-month period ended June 30, 2010 and drilling and oil field services segment expenses increased $20.2 million to $24.4 million during the same period. The increase in revenue resulted in operating income of $4.1 million in the three-month period ended June 30, 2011 compared to an operating loss of $0.3 million for the same period in 2010. The increase in revenues and expenses was primarily attributable to an increase in the number of rigs working for third parties and an increase in oil field services performed for third parties during the 2011 period. The increase in the number of rigs working for third parties was a result of increased demand for the Company’s rigs and the result of additional rigs becoming available in West Texas as the Company decreased its drilling activity in the WTO beginning in 2010 and transitioned to drilling more oil wells in the Permian Basin and Mid-Continent areas.
Drilling and Oil Field Services Segment — Six months ended June 30, 2011 compared to the six months ended June 30, 2010
Drilling and oil field services segment revenues increased to $49.6 million in the six-month period ended June 30, 2011 from $9.7 million in the six-month period ended June 30, 2010 and drilling and oil field services segment expenses increased $31.3 million during the same period to $45.6 million. The increase in revenue resulted in operating income of $4.0 million in the six-month period ended June 30, 2011 compared to an operating loss of $4.6 million for the same period in 2010. The increase in revenues and expenses was primarily attributable to an increase in the number of rigs working for third parties and an increase in oil field services performed for third parties during the 2011 period.
Midstream Gas Services Segment
Midstream gas services segment revenues consist mostly of revenue from gas marketing, which is a very low-margin business. Midstream gas services are primarily undertaken to realize incremental margins on natural gas purchased at the wellhead, and provide value-added services to customers. On a consolidated basis, midstream and marketing revenues represent natural gas sold on behalf of third parties and the fees the Company charges to gather, compress and treat this natural gas. Gas marketing operating costs represent payments made to third parties for the proceeds from the sale of natural gas owned by such parties, net of any applicable margin and actual costs the Company charges to gather, compress and treat the natural gas. In general, natural gas purchased and sold by the Company’s midstream gas business is priced at a published daily or monthly index price. The primary factors affecting the results of the Company’s midstream gas services segment are the quantity of natural gas the Company gathers, treats and markets and the prices it pays and receives for natural gas.
The Company owns and operates two gas treating plants in West Texas, which remove CO2 from natural gas production and deliver residue gas to nearby pipelines. During the first six months of 2011, the Company continued with the operational assessment phase of the Century Plant, in Pecos County, Texas, including diverting some of the Company’s natural gas from the Company’s gas treating plants and processing it at the Century Plant during this time. As a result of this assessment, in April 2011, the Century Plant was taken off line to resolve certain operational issues. The Company is currently in the process of diverting its high CO2 natural gas production back through the Century Plant and anticipates commencing performance testing for Train 1 of the Century Plant during the third quarter of 2011. Upon successful completion of the performance testing, the use of the Company’s two gas treating plants in West Texas may be limited, the extent of which will depend on certain variables, including natural gas prices and the expected need for such plants to back up the Century Plant going forward. During the second quarter of 2011, the Company evaluated its gas treating plants for impairment in connection with completion of the operational assessment phase of Train I of the Century Plant and concluded there was no impairment necessary.
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Midstream Gas Services Segment — Three months ended June 30, 2011 compared to the three months ended June 30, 2010
Midstream gas services segment revenues for the three months ended June 30, 2011 were $15.8 million compared to $22.2 million in the same period in 2010. The decrease in revenue along with the continued impact of fixed charges resulted in an operating loss of $2.6 million for the three months ended June 30, 2011 compared to operating income of $0.9 million for the comparable period in 2010. The decrease in revenue was due to a decrease in third party volumes the Company marketed and a decrease in natural gas volumes processed in the Company’s gas treating plants in the three-month period ended June 30, 2011 compared to the same period in 2010.
Midstream Gas Services Segment — Six months ended June 30, 2011 compared to the six months ended June 30, 2010
Midstream gas services segment revenues for the six months ended June 30, 2011 were $37.7 million compared to $49.7 million in the same period in 2010. The decrease in revenue along with the continued impact of fixed charges resulted in an operating loss of $5.1 million for the six months ended June 30, 2011 compared to operating income of $2.2 million for the comparable period in 2010. The decrease in revenue was due to a decrease in third party volumes the Company marketed, a decrease in natural gas prices and a decrease in natural gas volumes processed in the Company’s gas treating plants in the six-month period ended June 30, 2011 compared to the same period in 2010.
Three months ended June 30, 2011 compared to the three months ended June 30, 2010
Revenues. Total revenues increased 99.9% for the three months ended June 30, 2011 from the same period in 2010. This increase was primarily due to the increase in oil and natural gas sales.
Total oil and natural gas revenues increased $162.1 million for the three months ended June 30, 2011 compared to the same period in 2010, primarily as a result of an increase in the amount of oil the Company produced and the price received for the Company’s oil production, offset slightly by a decrease in the amount of natural gas the Company produced. The 1,423 MBbl increase in oil production was primarily due to the properties acquired from Arena and the Company’s focus on increased oil drilling throughout 2010 and into 2011. The average price received for the Company’s oil production, excluding the impact of derivative contracts, increased 42.4% in the 2011 period to $89.09 per Bbl compared to $62.56 per Bbl in 2010.
Drilling and services revenues increased $24.6 million for the three months ended June 30, 2011 compared to the same period in 2010 due to an increase in the number of rigs working for third parties and an increase in oil field services work performed for third parties.
Midstream and marketing revenues decreased $6.3 million, or 27.8%, in the three-month period ended June 30, 2011 compared to the three-month period ended June 30, 2010. The decrease in midstream and
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marketing revenues was attributable to a decrease in third party volumes the Company marketed due to decreased natural gas production and a decrease in natural gas volumes processed at the Company’s gas treating plants in the three-month period ended June 30, 2011 compared to the same period in 2010.
Operating Costs and Expenses. Total operating costs and expenses increased to $85.1 million for the three months ended June 30, 2011 compared to $63.0 million for the same period in 2010. The increase was primarily due to increases in production expenses, production taxes, drilling and services expense and depreciation and depletion on oil and natural gas properties.
Operating costs and expenses
Total operating costs and expenses
Production expenses include the costs associated with the Company’s exploration and production activities, including, but not limited to, lease operating expenses and treating costs. Production expenses increased $25.8 million primarily due to the addition of operating expenses associated with properties acquired from Arena and newly completed oil wells brought on production during late 2010 and the first six months of 2011. Additionally, higher production costs were incurred on oil production compared to production costs on natural gas volumes as oil volumes continued to comprise a larger portion of the Company’s total production. Oil production increased 1,423 MBbls in the three-month period ended June 30, 2011 compared to the same period in 2010.
Production taxes increased $7.3 million, or 134.4%, due to taxes on increased oil production, including taxes for production from properties acquired from Arena and newly producing wells, in the three-month period ended June 30, 2011 compared to the same period in 2010.
Drilling and services expenses, which include operating expenses attributable to the drilling and oil field services segment and the Company’s CO2 services company, increased $17.0 million for the three months ended June 30, 2011 compared to the same period in 2010 primarily due to an increase in the number of rigs working for third parties and an increase in oil field services work performed for third parties during the three-month period ended June 30, 2011 compared to the same period in 2010.
Midstream and marketing expenses decreased $3.9 million, or 19.7%, to $15.9 million due to decreased volumes of natural gas purchased from third parties as a result of decreased natural gas production during the three-month period ended June 30, 2011.
Depreciation and depletion for the Company’s oil and natural gas properties increased $21.9 million for the three-month period ended June 30, 2011 from the same period in 2010. The increase was primarily due to an increase in depreciation and depletion per Boe to $13.51 in the second quarter of 2011 from $11.90 per Boe in
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the comparable period in 2010 as a result of an increase to the Company’s depreciable oil and natural gas properties, primarily due to the acquisition of properties from Arena and an increase in the Company’s combined production volume.
The Company recorded a net gain of $170.0 million ($18.3 million realized loss and $188.3 million unrealized gain) on its commodity derivative contracts for the three-month period ended June 30, 2011 compared to a net gain of $119.6 million ($117.9 million realized gain and $1.7 million unrealized gain) in the same period of 2010. See further discussion of gains and losses on commodity derivative contracts under “Results by Segment — Exploration and Production Segment.”
Other Income (Expense). Total other expense decreased to $63.6 million in the three-month period ended June 30, 2011 from $64.7 million in the three-month period ended June 30, 2010. The decrease is reflected in the table below.
Interest expense decreased to $61.7 million for the three months ended June 30, 2011 from $64.3 million for the same period in 2010. This decrease was primarily attributable to a $3.7 million decrease in the net loss on the Company’s interest rate swap for the three-month period ending June 30, 2011 compared to the same period in 2010, slightly offset by an increase in interest expense due to higher average debt balances outstanding for the three months ending June 30, 2011.
In connection with the redemption of the remaining 8.625% Senior Notes, the Company recognized a loss on extinguishment of debt of $2.0 million in the second quarter of 2011. The loss represents the premium paid to redeem these notes and the unamortized debt issuance costs associated with the remaining notes.
In the second quarter of 2011, the Company completed its valuation of assets acquired and liabilities assumed related to the Arena Acquisition in order to finalize the purchase price allocation. In connection therewith, the Company recorded an additional net deferred tax liability of $7.0 million associated with the Arena Acquisition. Management determined that it is more likely than not that the Company will now realize a benefit from more of its existing deferred tax assets as the additional Arena deferred tax liabilities are available to offset the reversal of the Company’s deferred tax assets. Accordingly, the tax benefit of $7.1 million for the three-month period ended June 30, 2011 is primarily comprised of the partial release of the Company’s previously recorded valuation allowance against its net deferred tax asset.
Net income attributable to noncontrolling interest increased to $13.2 million for the three months ended June 30, 2011 from $1.1 million for the same period in 2010 due to completion of the Mississippian Trust’s
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initial public offering in April 2011. As a result of the offering, 17,250,000 common units, or approximately 61.6% of the Mississippian Trust’s beneficial interests, are held by third parties. The portion of the Mississippian Trust’s net income or loss attributable to beneficial interests held by third parties is reflected as net income or loss attributable to noncontrolling interest.
Six months ended June 30, 2011 compared to the six months ended June 30, 2010
Revenues. Total revenues increased 72.2% for the six months ended June 30, 2011 from the same period in 2010. This increase was primarily due to the increase in oil and natural gas sales.
Total oil and natural gas revenues increased $259.5 million for the six months ended June 30, 2011 compared to the same period in 2010, primarily as a result of an increase in the amount of oil the Company produced and the price received for the Company’s oil production, offset slightly by a decrease in the amount of natural gas the Company produced as well as decreased prices received for the Company’s natural gas production. The 2,793 MBbl increase in oil production was primarily due to the properties acquired from Arena and the Company’s focus on increased oil drilling throughout 2010 and in 2011. The average price received for the Company’s oil production, excluding the impact of derivative contracts, increased 31.3% in the 2011 period to $84.59 per Bbl compared to $64.43 per Bbl in 2010.
Drilling and services revenues increased $39.9 million for the six months ended June 30, 2011 compared to the same period in 2010 due to an increase in the number of rigs working for third parties and an increase in oil field services work performed for third parties.
Midstream and marketing revenues decreased $12.0 million, or 23.8%, in the six-month period ended June 30, 2011 compared to the six-month period ended June 30, 2010. The decrease in midstream and marketing revenues was attributable to a decrease in third party volumes the Company marketed due to decreased natural gas production, a decrease in natural gas prices and a decrease in natural gas volumes processed at the Company’s gas treating plants in the six-month period ended June 30, 2011 compared to the same period in 2010.
Other revenues decreased $3.2 million for the six months ended June 30, 2011 from the same period in 2010. The decrease was due to lower CO2 volumes sold to third parties from the Company’s gas treating plants during the six-month period ended June 30, 2011 compared to the same period in 2010 as a result of less natural gas treated at these plants.
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Operating Costs and Expenses. Total operating costs and expenses increased to $605.7 million for the six months ended June 30, 2011 compared to $184.8 million for the same period in 2010. The increase was primarily due to increases in production expenses, production taxes, drilling and services expense and depreciation and depletion on oil and natural gas properties and the loss on derivative contracts.
Loss (gain) on derivative contracts
Production expenses increased $49.5 million primarily due to the addition of operating expenses associated with properties acquired from Arena and additional oil wells brought on production during late 2010 and the first six months of 2011. Additionally, higher production costs were incurred on oil production compared to production costs on natural gas volumes. Oil production increased 2,793 MBbls in the six-month period ended June 30, 2011 compared to the same period in 2010.
Production taxes increased $13.0 million, or 126.9%, due to taxes on increased oil production, including taxes for production from properties acquired from Arena and additional oil wells brought on production during late 2010 and the first six months of 2011, in the six-month period ended June 30, 2011 compared to the same period in 2010.
Drilling and services expenses increased $24.9 million, or 302.0%, for the six months ended June 30, 2011 compared to the same period in 2010 primarily due to an increase in the number of rigs working for third parties and an increase in oil field services work performed for third parties during the six-month period ended June 30, 2011 compared to the same period in 2010.
Midstream and marketing expenses decreased $7.1 million, or 15.7%, to $38.2 million due to decreased volumes of natural gas purchased from third parties as a result of decreased natural gas production during the six-month period ended June 30, 2011.
Depreciation and depletion for the Company’s oil and natural gas properties increased $43.5 million for the six-month period ended June 30, 2011 from the same period in 2010. The increase was primarily due to an increase in the depreciation and depletion per Boe to $13.52 in the first six months of 2011 from $11.91 per Boe in the comparable period in 2010 as a result of an increase to the Company’s depreciable oil and natural gas properties, primarily due to the acquisition of properties from Arena, and an increase in the Company’s combined production volume.
The Company recorded a net loss of $107.6 million ($26.9 million realized loss and $80.7 million unrealized loss) on its commodity derivative contracts for the six-month period ended June 30, 2011 compared to a net gain of $181.6 million ($160.6 million realized gain and $21.0 million unrealized gain) in the same period of 2010. See further discussion of gains and losses on commodity derivative contracts under “Results by Segment — Exploration and Production Segment.”
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Other Income (Expense). Total other expense increased to $158.0 million in the six-month period ended June 30, 2011 from $125.5 million in the six-month period ended June 30, 2010. The increase is reflected in the table below.
Interest expense decreased to $121.2 million for the six months ended June 30, 2011 from $126.3 million for the same period in 2010. This decrease was primarily attributable to a $9.3 million decrease in the net loss on the Company’s interest rate swaps for the six-month period ending June 30, 2011 compared to the same period in 2010, partially offset by an increase in interest expense due to higher average debt balances outstanding for the six months ending June 30, 2011.
In connection with the tender offer to repurchase and the redemption of the 8.625% Senior Notes, the Company recognized a loss on extinguishment of debt of $38.2 million for the six-month period ended June 30, 2011. The loss represents the premium paid to purchase these notes and the unamortized debt issuance costs associated with the notes.
In the second quarter of 2011, the Company completed its valuation of assets acquired and liabilities assumed related to the Arena Acquisition in order to finalize the purchase price allocation. In connection therewith, the Company recorded an additional net deferred tax liability of $7.0 million associated with the Arena Acquisition. Management determined that it is more likely than not that the Company will now realize a benefit from more of its existing deferred tax assets as the additional Arena deferred tax liabilities are available to offset the reversal of the Company’s deferred tax assets. Accordingly, the tax benefit of $7.0 million for the six-month period ended June 30, 2011 is primarily comprised of the partial release of the Company’s previously recorded valuation allowance against its net deferred tax asset.
Net income attributable to noncontrolling interest increased to $13.2 million for the six months ended June 30, 2011 compared to $2.2 million for the same period in 2010 due to completion of the Mississippian Trust’s initial public offering in April 2011, which resulted in approximately 61.6% of the Mississippian Trust units being held by third parties.
The Company’s primary sources of liquidity and capital resources are cash flow generated from operations, borrowings under the Company’s senior credit facility, the issuance of equity and debt securities and proceeds from sales or other monetization of assets. As described in “Recent Developments,” the Company received proceeds of $336.9 million in April 2011 as partial consideration for conveyance of royalty interests in certain of the Company’s oil and natural gas properties to the Mississippian Trust. The Company’s primary uses of capital
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are expenditures related to its oil and natural gas properties and other fixed assets, the acquisition of oil and natural gas properties, the repayment of amounts outstanding on its senior credit facility, the payment of dividends on its outstanding convertible perpetual preferred stock and interest payments on its outstanding debt. The Company maintains access to funds that may be needed to meet capital funding requirements through its senior credit facility.
Working Capital
The Company’s working capital balance fluctuates as a result of the timing and amount of borrowings or repayments under its credit arrangements and changes in the fair value of its outstanding commodity derivative instruments. Absent any significant effects from its commodity derivative instruments, the Company typically has a working capital deficit or a relatively small amount of positive working capital because the Company’s capital spending generally has exceeded the Company’s cash flows from operations and it generally uses excess cash to pay down borrowings outstanding under its credit arrangements.
At June 30, 2011, the Company had a working capital deficit of $450.4 million compared to a deficit of $368.9 million at December 31, 2010. Current assets increased $15.0 million at June 30, 2011, compared to current assets at December 31, 2010, primarily due to an increase in accounts receivable balances as a result of increased oil production and prices received on the Company’s oil production. Current liabilities increased $96.5 million, primarily due to a $47.0 million increase in accounts payable and accrued expenses due to increased drilling activity and a $46.0 million increase in the liability positions on the Company’s current derivative contracts, resulting primarily from an increase in average oil prices at June 30, 2011 compared to applicable contract prices.
The Company expects to fund its planned capital expenditures budget, debt service requirements and working capital needs for 2011 based on cash flow from operating activities, availability under its senior credit facility, potential access to the capital markets and anticipated proceeds from sales or other monetizations of assets.
Cash Flows
The Company’s cash flows for the six months ended June 30, 2011 and 2010 were as follows:
Cash flows provided by operating activities
Cash flows used in investing activities
Cash flows provided by financing activities
Cash Flows from Operating Activities
The Company’s operating cash flow is mainly influenced by the prices the Company receives for its oil and natural gas production; the quantity of oil and natural gas it produces; third-party demand for its drilling rigs and oil field services and the rates it is able to charge for these services; and the margins it obtains from its natural gas and CO2 gathering and treating contracts.
Net cash provided by operating activities for the six months ended June 30, 2011 and 2010 was $261.0 million and $258.5 million, respectively. Cash provided by operating activities increased slightly due to an increase in oil production and prices, which was partially offset by a decrease in realized gains on our commodity derivative contracts.
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Cash Flows from Investing Activities
The Company dedicates and expects to continue to dedicate a substantial portion of its capital expenditure program toward the development, production and acquisition of oil and natural gas reserves. These capital expenditures are necessary to offset inherent declines in production and proven reserves, which is typical in the capital-intensive oil and natural gas industry.
Cash flows used in investing activities increased to $502.7 million in the six-month period ended June 30, 2011 from $416.2 million in the comparable 2010 period primarily due to increased capital expenditures as a result of increased oil drilling activity in the Mid-Continent and Permian Basin areas, offset somewhat by proceeds from asset sales.
Capital Expenditures. The Company’s capital expenditures, on an accrual basis, by segment for the six-month periods ended June 30, 2011 and 2010 are summarized below:
Capital Expenditures
Exploration and production
Drilling and oil field services
Midstream gas services
Cash Flows from Financing Activities
The Company’s financing activities provided $240.4 million in cash for the six-month period ended June 30, 2011 compared to $152.0 million in the comparable period in 2010. Cash provided by financing activities during the six months ended June 30, 2011 was primarily comprised of $880.7 million of net proceeds from the issuance of the 7.5% Senior Notes and $336.9 million of net proceeds from the issuance of units by the Mississippian Trust, offset by the purchase and redemption of $650.0 million aggregate principal amount of the 8.625% Senior Notes, the premium of $30.3 million paid in connection with the purchase and redemption of the 8.625% Senior Notes, $260.0 million of net repayments under the senior credit facility and $29.0 million of dividends paid on the 8.5%, 6.0% and 7.0% convertible perpetual preferred stock.
Indebtedness
Senior Credit Facility. The amount the Company may borrow under its senior credit facility is limited to a borrowing base, and is subject to periodic redeterminations. Effective March 15, 2011, the borrowing base was reduced to $790.0 million due to the issuance of the Company’s 7.5% Senior Notes. The borrowing base is determined based upon the discounted present value of future cash flows attributable to the Company’s proved reserves. Because the value of the Company’s proved reserves is a key factor in determining the amount of the borrowing base, changing commodity prices and the Company’s success in developing reserves may affect the borrowing base. Outstanding letters of credit affect the availability under the senior credit facility on a dollar-for-dollar basis.
On February 23, 2011, the Company’s senior credit facility was amended to, among other things, (a) exclude from the calculation of Consolidated Net Income the net income (or loss) of a Royalty Trust, except to the extent of cash distributions received by the Company, (b) establish that an investment in a Royalty Trust and dispositions to, and of interests in, Royalty Trusts are permitted, (c) clarify that a Royalty Trust is not a Subsidiary, (d) allow the Company to net against its calculation of Consolidated Funded Indebtedness cash
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balances exceeding $10.0 million in the event no loans are outstanding under the senior credit facility at that time, and (e) establish that, for any fiscal quarter ending prior to March 31, 2012, if the ratio of the Company’s secured indebtedness to EBITDA is less than 1.5:1.0 then compliance with the Company’s Consolidated Leverage Ratio covenant is not required. Terms capitalized in the preceding sentence have the meaning given to them in the senior credit facility, as amended.
On April 20, 2011, the senior credit facility was amended. The amendment permits the Company to pay cash dividends on its 7.0% convertible perpetual preferred stock and reaffirmed the borrowing base at $790.0 million.
As of June 30, 2011, the senior credit facility contained financial covenants, including maintaining agreed levels for the (i) ratio of total funded debt to EBITDA, which may not exceed 4.5:1.0 at each quarter end calculated using the last four completed fiscal quarters, unless, for any quarter ending prior to March 31, 2012, the ratio of the Company’s secured indebtedness to EBITDA is less than 1.5:1.0, calculated using the last four completed fiscal quarters (in each case through the second quarter of 2011, adjusted for annualized amounts of the post-acquisition results of operations of Arena), (ii) ratio of current assets to current liabilities, which must be at least 1.0:1.0 at each quarter end (in the current ratio calculation (as defined in the senior credit facility), any amounts available to be drawn under the senior credit facility are included in current assets, and unrealized assets and liabilities resulting from mark-to-market adjustments on the Company’s derivative contracts are disregarded) and (iii) ratio of the Company’s secured indebtedness to EBITDA, which may not exceed 2.0:1.0 at each quarter end calculated using the last four completed fiscal quarters (in each case through the second quarter of 2011, adjusted for annualized amounts of the post-acquisition results of operations of Arena). The Company remains in compliance with all financial covenants under the senior credit facility.
Senior Notes. On March 1, 2011 the Company announced a cash tender offer to purchase any and all of the outstanding $650.0 million aggregate principal amount of its 8.625% Senior Notes. As of March 31, 2011, the Company had purchased approximately 94.5%, or $614.2 million of these notes. On April 1, 2011, the Company redeemed the remaining outstanding $35.8 million aggregate principal amount of its 8.625% Senior Notes. Additionally in March 2011, the Company issued $900.0 million of its 7.5% Senior Notes. Net proceeds were used to fund the tender offer for the 8.625% Senior Notes and to repay amounts outstanding under the Company’s senior credit facility. See Note 11 to the Company’s condensed consolidated financial statements included in this Quarterly Report for further information.
Long-term obligations under the senior credit facility and other long-term debt consist of the following at June 30, 2011 (in thousands):
9.875% Senior Notes due 2016, net of $11,881 discount
8.75% Senior Notes due 2020, net of $6,693 discount
The indentures governing the senior notes referred to above contain limitations on the incurrence of indebtedness, payment of dividends, investments, asset sales, certain asset purchases, transactions with related parties and consolidations or mergers.
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Maturities of Long-Term Debt. Aggregate maturities of long-term debt, excluding discounts, for the next five fiscal years are as follows (in thousands):
2011
2012
2013
2014
2015
Thereafter
For more information about the senior credit facility, the senior notes and the Company’s other long-term debt obligations, see Note 11 to the condensed consolidated financial statements included in this Quarterly Report.
Outlook
On August 4, 2011, the Company increased its budget for capital expenditures, including expenditures related to its drilling obligation under the development agreement with the Mississippian Trust and excluding acquisitions to $1.8 billion. The majority of the Company’s capital expenditures are discretionary and could be curtailed if the Company’s cash flows decline from expected levels or if the Company is unable to obtain capital on attractive terms. The Company may increase or decrease planned capital expenditures depending on oil and natural gas prices, the availability of capital through asset sales and the issuance of additional equity or long-term debt.
The Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, each of which depend on numerous factors beyond the Company’s control such as economic conditions, regulatory developments and competition from other energy sources. Oil and natural gas prices historically have been volatile and may be subject to significant fluctuations in the future. The Company’s derivative arrangements serve to mitigate a portion of the effect of this price volatility on its cash flows, and while derivative contracts are in place for the majority of expected oil production for 2011 through 2013, fixed price swap contracts are in place for only a portion of expected natural gas production in 2011 and 2012 and oil production for 2014 and 2015. No fixed price swap contracts are in place for the Company’s natural gas production beyond 2012 or oil production beyond 2015. The Company has natural gas collars in place for a portion of expected natural gas production through 2015. See Item 3 “Quantitative and Qualitative Disclosures About Market Risk” for additional information regarding the Company’s derivative contracts.
The Company has incurred, and will have to continue to incur, capital expenditures to achieve production targets contained in certain gathering and treating arrangements. The Company is dependent on the availability of borrowings under its senior credit facility, along with cash flows from operating activities and proceeds from planned asset sales and other asset monetizations, to fund those capital expenditures. Based on anticipated oil and natural gas prices, availability under the Company’s senior credit facility, potential access to the capital markets and anticipated proceeds from the sales or other monetizations of assets, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs for 2011. However, a substantial or extended decline in oil or natural gas prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced, which could adversely impact the Company’s ability to comply with the financial covenants under its senior credit facility, which in turn would limit further borrowings to fund capital expenditures. The Company has the ability to reduce its capital expenditures budget if cash flows are not available.
The Company may choose to refinance borrowings outstanding under its senior credit facility by issuing long-term debt or equity in the public or private markets, or both. In addition, the Company may from time to time seek to retire or purchase its outstanding securities through cash purchases and/or exchanges in open market
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purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, the Company’s liquidity requirements, contractual restrictions and other factors.
As of June 30, 2011, the Company’s cash and cash equivalents were $4.6 million and the Company had approximately $2.9 billion in total debt outstanding with $80.0 million outstanding under its senior credit facility. As of and for the three and six-month periods ended June 30, 2011, the Company was in compliance with all of the covenants under all of its senior notes and its senior credit facility. As of August 1, 2011, the Company’s cash and cash equivalents were approximately $2.2 million and the Company had $195.0 million outstanding under its senior credit facility with $24.5 million outstanding in letters of credit.
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk
General
The discussion in this section provides information about the financial instruments the Company uses to manage commodity prices and interest rate volatility. All contracts are settled in cash and do not require the actual delivery of a commodity at settlement.
Commodity Price Risk. The Company’s most significant market risk relates to the prices it receives for its oil and natural gas production. Due to the historical volatility of these commodities, the Company periodically has entered into, and expects in the future to enter into, derivative arrangements for the purpose of reducing the variability of oil and natural gas prices the Company receives for its production. From time to time, the Company enters into commodity pricing derivative contracts for a portion of its anticipated production volumes depending upon management’s view of opportunities under the then prevailing current market conditions. The Company’s senior credit facility limits its ability to enter into derivative transactions to 85% of expected production volumes from estimated proved reserves. The Company does not intend to enter into derivative contracts that would exceed its expected production volumes for the period covered by the derivative arrangement. Future credit facilities could require a minimum level of commodity price hedging.
The Company uses, and may continue to use, a variety of commodity-based derivative contracts, including fixed price swaps, collars and basis protection swaps. The Company’s oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period. The Company’s natural gas fixed price swap transactions are settled based upon New York Mercantile Exchange prices, and the Company’s natural gas basis protection swap transactions are settled based upon the index price of natural gas at the Waha hub, a West Texas gas marketing and delivery center, and the Houston Ship Channel. Settlement for oil derivative contracts occurs in the succeeding month and natural gas derivative contracts are settled in the production month. The Company’s natural gas collars are settled based upon the New York Mercantile Exchange prices on the penultimate commodity business day for the relevant contract. Natural gas collars only result in a cash settlement when the settlement price exceeds the fixed-price ceiling or falls below the fixed-price floor.
The Company has not designated any of its derivative contracts as hedges for accounting purposes. The Company records all derivative contracts on the balance sheet at fair value, which reflects changes in oil and natural gas prices. The Company establishes fair value of its derivative contracts by price quotations obtained from counterparties to the derivative contracts. Changes in fair values of the Company’s derivative contracts are recognized as unrealized gains and losses in current period earnings. As a result, the Company’s current period earnings may be significantly affected by changes in the fair value of its commodity derivative contracts. Changes in fair value are principally measured based on period-end prices compared to the contract price.
See Note 12 to the Company’s condensed consolidated financial statements included in this Quarterly Report for a summary of open oil and natural gas derivative contracts.
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The following table summarizes the cash settlements and valuation gains and losses on the Company’s commodity derivative contracts for the three and six-month periods ended June 30, 2011 and 2010 (in thousands):
Credit Risk. The use of derivative contracts involves the risk that the counterparties will be unable to meet their obligations under the contracts. The Company’s derivative contracts are with multiple counterparties to minimize its exposure to any individual counterparty. As of June 30, 2011, the Company had 19 approved derivative counterparties, all of which are lenders under its senior credit facility. The Company currently has derivative contracts outstanding with 15 of these counterparties. The Company periodically reviews the credit quality of each counterparty to its derivative contracts and the level of overall financial exposure the Company has to each counterparty to limit its credit risk exposure with respect to these contracts. Additionally, the Company applies a credit default risk rating factor for its counterparties or gives effect to its credit risk, as applicable, in determining the fair value of its derivative contracts. The counterparties for all of the Company’s derivative transactions have an “investment grade” credit rating.
The Company’s ability to fund its capital expenditure budget is partially dependent upon the availability of funds under its senior credit facility. In order to mitigate the credit risk associated with individual financial institutions committed to participate in the senior credit facility, the Company’s bank group currently consists of 26 financial institutions with commitments ranging from 0.57% to 5.41%.
Interest Rate Risk. The Company is subject to interest rate risk on its long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes the Company to (i) changes in market interest rates reflected in the fair value of the debt and (ii) the risk that the Company may need to refinance maturing debt with new debt at a higher rate. Variable rate debt, where the interest rate fluctuates, exposes the Company to short-term changes in market interest rates as its interest obligations on these instruments are periodically redetermined based on prevailing market interest rates, primarily LIBOR and the federal funds rate.
In addition to commodity price derivative arrangements, the Company may enter into derivative transactions to fix the interest the Company pays on a portion of the amount outstanding on its variable rate debt. At June 30, 2011, the Company had a $350.0 million notional interest rate swap agreement. The interest rate swap agreement effectively serves to fix the rate on the Senior Floating Rate Notes at an annual rate of 6.69% for the period from April 1, 2011 to April 1, 2013. This swap has not been designated as a hedge.
The Company’s interest rate swap reduces its market risk on its Senior Floating Rate Notes. The Company uses sensitivity analyses to determine the impact that market risk exposures could have on the Company’s variable interest rate borrowings if not for its interest rate swap. Based on the $350.0 million outstanding balance of the Company’s Senior Floating Rate Notes at June 30, 2011, a one percent change in the applicable rates, with
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all other variables held constant, would have resulted in a change in the Company’s interest expense of approximately $0.9 million and $1.8 million for the three and six-month periods ended June 30, 2011, respectively.
The following table summarizes the cash settlements and valuation gains and losses on the Company’s interest rate swaps for the three and six-month periods ended June 30, 2011 and 2010 (in thousands):
ITEM 4. Controls and Procedures
Under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, the Company performed an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures pursuant to Exchange Act Rules 13a-15 and 15d-15 as of the end of the period covered by this Quarterly Report. Based on that evaluation, the Company’s Chief Executive Officer and the Company’s Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2011 to provide reasonable assurance that the information required to be disclosed by the Company in its reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and such information is accumulated and communicated to management, as appropriate to allow timely decisions regarding required disclosure.
There was no change in the Company’s internal control over financial reporting during the quarter ended June 30, 2011 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
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PART II. Other Information
ITEM 1. Legal Proceedings
On February 14, 2011, Aspen Pipeline, II, L.P. (“Aspen”) filed a complaint in the District Court of Harris County, Texas, against Arena Resources, Inc. and SandRidge Energy, Inc. claiming damages based upon alleged representations by Arena in connection with the construction by Aspen of a natural gas pipeline in West Texas. The plaintiff seeks damages that include the construction cost of the pipeline, which it claims approach $90.0 million. The Company intends to defend this lawsuit vigorously and believes the plaintiff’s claims are without merit. This case is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this claim cannot be made at this time. The Company has not established any reserves relating to this claim.
On April 5, 2011, Wesley West Minerals, Ltd. and Longfellow Ranch Partners, LP (collectively, the “plaintiffs”), filed suit against SandRidge Energy, Inc. and SandRidge Exploration and Production, LLC (collectively, the “SandRidge Entities”), in the 83rd District Court of Pecos County, Texas. The plaintiffs, who have leased mineral rights to the SandRidge Entities in Pecos County, allege that the SandRidge Entities have not properly paid royalties on all volumes of natural gas (including carbon dioxide, or “CO2“) produced from the acreage leased from the plaintiffs. The plaintiffs also allege that the SandRidge Entities have inappropriately failed to pay royalties on CO2 produced from plaintiffs’ acreage that results from the treatment of natural gas at the Century Plant. The plaintiffs seek unspecified actual damages, punitive damages and a declaration that the SandRidge Entities must pay royalties on CO2 produced from plaintiffs’ acreage that results from treatment of natural gas at the Century Plant. The Company intends to defend this lawsuit vigorously. An estimate of reasonably possible losses, if any, associated with these claims cannot be made at this time. Accordingly, the Company has not established any reserves relating to these claims.
In addition, SandRidge is a defendant in lawsuits from time to time in the normal course of business. In management’s opinion, the Company is not currently involved in any legal proceedings that, individually or in the aggregate, could have a material effect on the Company’s financial condition, operations or cash flows.
ITEM 1A. Risk Factors
We describe one of our business risk factors below. This description includes a material change to the risk factors previously disclosed in Part I, Item 1A of the 2010 Form 10-K.
Production of oil, natural gas and natural gas liquids could be materially and adversely affected by severe or unseasonable weather.
Production of oil, natural gas and natural gas liquids could be materially and adversely affected by severe weather. Repercussions of severe weather conditions may include:
evacuation of personnel and curtailment of operations;
weather-related damage to drilling rigs or other facilities, resulting in suspension of operations;
inability to deliver materials to worksites; and
weather-related damage to pipelines and other transportation facilities.
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ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds
As part of the Company’s restricted stock program, the Company makes required tax payments on behalf of employees when their stock awards vest and then withholds a number of vested shares of common stock having a value on the date of vesting equal to the tax obligation. The shares withheld are initially recorded as treasury shares, then immediately retired. During the quarter ended June 30, 2011, the following shares were withheld in satisfaction of tax withholding obligations arising from the vesting of restricted stock:
Period
April 1, 2011 — April 30, 2011
May 1, 2011 — May 31, 2011
June 1, 2011 — June 30, 2011
ITEM 6. Exhibits
See the Exhibit Index accompanying this Quarterly Report.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
James D. Bennett
Executive Vice President and
Chief Financial Officer
Date: August 8, 2011
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EXHIBIT INDEX
Exhibit
No.
Exhibit Description
Form
SEC
File No.
Filing Date
Filed
Herewith
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