Summary of Significant Accounting Policies	12 Months Ended
Dec. 31, 2012
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Nature of Business. SandRidge Energy, Inc. (the “Company” or “SandRidge”) is an independent oil and natural gas company concentrating on development and production activities in the Mid-Continent, Gulf of Mexico and Permian Basin in west Texas. The Company’s primary area of focus is the Mississippian formation in the Mid-Continent area of Oklahoma and Kansas. The Company owns and operates additional interests in the Mid-Continent, Gulf of Mexico, Permian Basin, West Texas Overthrust (“WTO”) and Gulf Coast. The Company also operates businesses that are complementary to its primary development and production activities, including gas gathering and processing facilities, an oil and natural gas marketing business and an oil field services business, including a drilling rig business. Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its wholly owned or majority owned subsidiaries and variable interest entities (“VIEs”) for which the Company is the primary beneficiary. All significant intercompany accounts and transactions have been eliminated in consolidation. Reclassifications. Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Company’s previously reported results of operations. Use of Estimates. The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The more significant areas requiring the use of assumptions, judgments and estimates include: oil and natural gas reserves; cash flow estimates used in impairment tests of goodwill and other long-lived assets; depreciation, depletion and amortization; asset retirement obligations; assigning fair value and allocating purchase price in connection with business combinations; income taxes; valuation of derivative instruments; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could significantly differ from these estimates. 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 overall oil and natural gas production and inventories in relevant markets, economic conditions, the global political environment, 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. See Note 14 for the Company’s open oil and natural gas commodity derivative contracts. Production targets contained in certain gathering and treating agreements require the Company to incur capital expenditures or make associated shortfall payments. Additionally, the Company has a drilling obligation to each of SandRidge Mississippian Trust I (the “Mississippian Trust I”), SandRidge Permian Trust (the “Permian Trust”) and SandRidge Mississippian Trust II (the “Mississippian Trust II”). See Note 4 for discussion of these drilling obligations. The Company depends on cash flows from operating activities, funding commitments from third parties for drilling carries and the availability of borrowings under its senior secured revolving credit facility (the “senior credit facility”) to fund its capital expenditures. Additionally, the Company may use proceeds from the issuance of equity and debt securities in the capital markets and from sales or other monetizations of assets to fund its capital expenditures. Based on existing cash balances (including proceeds from the sale of the Permian Properties), cash flows from operating activities and funding commitments from third parties for drilling carries, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs for 2013. 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 13 for discussion of the financial covenants in the senior credit facility. Cash and Cash Equivalents. The Company considers all highly-liquid instruments with an original maturity of three months or less to be cash equivalents as these instruments are readily convertible to known amounts of cash and bear insignificant risk of changes in value due to their short maturity period. Accounts Receivable, Net. The Company has receivables for sales of oil and natural gas, as well as receivables related to the exploration and treating services for oil and natural gas. An allowance for doubtful accounts has been established based on management’s review of the collectability of the receivables in light of historical experience, the nature and volume of the receivables and other subjective factors. Accounts receivable are charged against the allowance, upon approval by management, when they are deemed uncollectible. Refer to Note 6 for further information on the Company’s accounts receivable and allowance for doubtful accounts. Inventories. Inventories consist of oil field services supplies and are stated at the lower of cost or market with cost determined on an average cost basis. Inventories are shown net of a provision for obsolescence, commensurate with known or estimated exposure, of $0.3 million and $0.2 million at December 31, 2012 and 2011, respectively. Fair Value of Financial Instruments. Certain of the Company’s financial assets and liabilities are measured at fair value. Fair value represents the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The Company’s financial instruments, not otherwise recorded at fair value, consist primarily of cash, trade receivables, trade payables and long-term debt. The carrying value of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short-term maturity of these instruments. See Note 5 for further discussion of the Company’s fair value measurements. Fair Value of Non-financial Assets and Liabilities. The Company also applies fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as business acquisitions, property, plant and equipment and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production or other applicable sales estimates, operational costs and a risk-adjusted discount rate. The Company primarily uses the present value of estimated future cash inflows and/or outflows to value its non-financial assets and liabilities when circumstances dictate determining fair value is necessary. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy discussed in Note 5. See Note 3 for additional discussion of the Company’s acquisitions. Additionally, the Company prepared fair value analyses of its gas treating plants and CO₂ compression facilities in 2012 as discussed further in Note 8. Derivative Financial Instruments. To manage risks related to price fluctuations in oil and natural gas prices and changes in interest rates, the Company enters into oil, natural gas and interest rate derivative contracts. The Company recognizes its derivative instruments as either assets or liabilities at fair value with changes in the derivative’s fair value being recognized in earnings unless designated as a hedging instrument with specific hedge accounting criteria being met. The commodity derivative instruments that the Company utilizes are to manage the price risk attributable to its expected oil and natural gas production. The Company has elected not to designate price risk management activities as accounting hedges under applicable accounting guidance, and, accordingly, accounts for its commodity derivative contracts at fair value with changes in fair value reported currently in earnings. The Company also utilizes derivatives to manage its exposure to variable interest rates and has not designated its interest rate swap as a hedging instrument. As such, the interest rate swap is recorded at fair value with the change in fair value reported currently in earnings. The Company nets derivative assets and liabilities whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. The related cash flow impact of the Company’s derivative activities are reflected as cash flows from operating activities unless the derivative contract contains a significant financing element; in this case, the cash settlements for these derivatives are classified as cash flows from financing activities in the consolidated statement of cash flows. See Note 14 for further discussion of the Company’s derivatives. Oil and Natural Gas Operations. The Company uses the full cost method to account for its oil and natural gas properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of oil and natural gas reserves are capitalized into a full cost pool. These capitalized costs include costs of all unproved properties and internal costs directly related to the Company’s acquisition, exploration and development activities and capitalized interest. The Company capitalized internal costs of $61.3 million, $37.1 million and $28.6 million to the full cost pool in 2012, 2011 and 2010, respectively. Capitalized costs are amortized using a unit-of-production method. Under this method, depreciation and depletion is computed at the end of each quarter by multiplying total production for the quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter. Costs associated with unproved properties are excluded from the amortizable cost base until a determination has been made as to the existence of proved reserves. Unproved properties are reviewed at the end of each quarter to determine whether the costs incurred should be reclassified to the full cost pool and, thereby, subjected to amortization. The costs associated with unproved properties relate primarily to costs to acquire unproved acreage. Unproved leasehold costs are transferred to the amortization base with the costs of drilling the related well upon determination of the existence of proved reserves or upon impairment of a lease. Costs of seismic data are allocated to various unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis. All items classified as unproved property are assessed on a quarterly basis for possible impairment or reduction in value. Properties are assessed on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and impairment, less related deferred income taxes may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties, plus estimated salvage value, less the related tax effects (the “ceiling limitation”). A ceiling limitation calculation is performed at the end of each quarter. If total capitalized costs, net of accumulated depreciation, depletion and impairment, less related deferred taxes are greater than the ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation and depletion expense in future periods. Once incurred, a write-down is not reversible at a later date. The ceiling limitation calculation is prepared using a 12-month oil and natural gas average price, as adjusted for basis or location differentials using a 12-month average, held constant over the life of the reserves (“net wellhead prices”). If applicable, these net wellhead prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil and natural gas. The Company may, from time-to-time, use derivative financial instruments to hedge against the volatility of oil and natural gas prices. Derivative contracts that qualify and are designated as cash flow hedges are included in estimated future cash flows. Historically, the Company has not designated any of its derivative contracts as cash flow hedges and has therefore not included its derivative contracts in estimating future cash flows. The future cash outflows associated with future development or abandonment of wells are included in the computation of the discounted present value of future net revenues for purposes of the ceiling limitation calculation. See Note 7 for further discussion of the full cost ceiling limitation. Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved oil and natural gas reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the proved reserve quantities of the cost center. Property, Plant and Equipment, Net. Other capitalized costs, including drilling equipment, natural gas gathering and treating equipment, transportation equipment and other property and equipment are carried at cost. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 10 to 39 years for buildings and 3 to 30 years for equipment. When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed and any resulting gain or loss is reflected in the consolidated statement of operations. Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying value of such asset may not be recoverable. Assets are considered to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset or asset group including disposal value, if any, is less than the carrying amount of the asset or asset group. If any asset or asset group is considered to be impaired, the impairment loss is measured as the amount by which the carrying amount of the asset or asset group exceeds its fair value. See Note 8 for further discussion of impairments. Capitalized Interest. Interest is capitalized on assets being made ready for use using a weighted average interest rate based on the Company’s outstanding borrowings. During 2012, 2011 and 2010, interest of approximately $10.1 million, $1.0 million and $0.3 million, respectively, was capitalized on unproved properties that were not currently being depreciated or depleted and on which exploration activities were in progress. Additionally, $4.7 million, $2.0 million and $1.0 million were capitalized in 2012, 2011 and 2010, respectively, on midstream and corporate assets which were under construction. Restricted Deposits. Restricted deposits represent bank trust and escrow accounts required by the Bureau of Ocean Energy Management, Bureau of Safety and Environmental Enforcement, surety bond underwriters, purchase agreements or other settlement agreements to satisfy the Company’s eventual responsibility to plug and abandon wells and remove structures when certain offshore fields are no longer in use. During 2010, $5.1 million was liquidated from the escrow accounts upon compliance with certain plugging and abandonment obligations. At December 31, 2012 and 2011, the Company had $27.9 million of such restricted deposits included as a long-term asset in the accompanying consolidated balance sheets. Restricted deposits may also include escrow deposits received on pending sales of oil and natural gas properties. Amounts are considered restricted until the transaction closes. In December 2012, the Company entered into an agreement to sell certain of its oil and natural gas properties in the Permian Basin and received a $255.0 million deposit. At December 31, 2012, this deposit was included in current assets and current liabilities in the accompanying consolidated balance sheets. See Note 22 for further discussion of the sale of the oil and natural gas properties in the Permian Basin. Goodwill. Goodwill represents the excess of the consideration paid over the fair value of identifiable net assets acquired as part of the acquisition of Arena Resources, Inc. (“Arena”). See Note 3 for discussion of this acquisition. Goodwill was assigned to the Company’s exploration and production segment and is not deductible for income tax purposes. Goodwill is not amortized, but rather tested annually for impairment. The Company performs its annual goodwill impairment test as of July 1st and between annual evaluations if events occur or circumstances exist that would more-likely-than-not reduce the fair value of the reporting unit below its carrying amount. Such circumstances could include, but are not limited to (1) a significant or sustained decrease in oil and natural gas prices, (2) a significant adverse change in the economic or business climate, (3) an adverse action or assessment by a regulator and (4) the likelihood that a reporting unit or a significant portion of a reporting unit will be sold or otherwise disposed. When a portion of a reporting unit that constitutes a business is disposed, goodwill is allocated to that business based on the relationship of the fair value of the portion sold to the total reporting unit’s fair value. When evaluating whether goodwill is impaired, the Company may elect to perform a qualitative assessment to determine whether it is necessary to perform the current two-step annual impairment test. If the Company determines, on the basis of qualitative factors, that the fair value of the reporting unit more-likely-than-not exceeds the carrying amount, the two-step impairment test is not required. However, if the Company determines it is necessary or elects to perform the two-step impairment test, the Company compares the fair value of the reporting unit to which the goodwill is assigned to the reporting unit’s carrying amount, including goodwill. The fair value of the reporting unit is estimated using the income, or discounted cash flow, approach. If the carrying amount of the reporting unit exceeds its fair value, then the amount of the impairment loss must be measured. The impairment loss would be calculated by comparing the implied fair value of reporting unit goodwill to the carrying amount of goodwill. In calculating the implied fair value of reporting unit goodwill, the fair value of the reporting unit is allocated to all of its other assets and liabilities based on their fair values. The excess of the fair value of a reporting unit over the amount assigned to its other assets and liabilities is the implied fair value of goodwill. An impairment loss would be recognized when the carrying amount of goodwill exceeds its implied fair value. Entry by the Company in December 2012 into an agreement to sell the Permian Properties was determined to be a triggering event. As such, an impairment test was performed as of December 31, 2012. See Note 9 for further discussion of goodwill and the impairment test performed. Investments. Investments in marketable equity securities have been designated as available for sale and measured at fair value pursuant to the fair value option which requires unrealized gains and losses be reported in earnings. Debt Issuance Costs. The Company amortizes debt issuance costs related to its long-term debt as interest expense over the scheduled maturity period of the related debt. The Company includes unamortized debt issuance costs in other assets in the consolidated balance sheet. Asset Retirement Obligations. The Company owns oil and natural gas properties that require expenditures to plug, abandon and remediate wells at the end of their productive lives, in accordance with applicable federal and state laws. Liabilities for these asset retirement obligations are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired) at the estimated present value at the asset’s inception, with the offsetting increase to property cost. These property costs are depreciated on a unit-of-production basis within the full cost pool. The liability accretes each period until the liability is settled or the well is sold, at which time the liability is removed. Both the accretion and the depreciation are included in the consolidated statement of operations. The Company determines its asset retirement obligations by calculating the present value of estimated expenses related to the liability. Estimating the future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability and what constitutes adequate restoration. Inherent in the present value calculation rates are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. See Note 15 for further discussion of the Company’s asset retirement obligations. In certain instances, the Company is required to make deposits to escrow accounts for future plugging and abandonment obligations. See Restricted Deposits discussed above. Revenue Recognition and Natural Gas Balancing. Oil and natural gas revenues are recorded when title of sold oil and natural gas production passes to the customer, net of royalties, discounts and allowances, as applicable. Taxes assessed by governmental authorities on oil and natural gas sales are presented separately from such revenues and included in production tax expense in the consolidated statement of operations. The Company accounts for natural gas production imbalances using the sales method, whereby it recognizes revenue on all natural gas sold to its customers notwithstanding the fact that its ownership may be less than 100% of the natural gas sold. Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves. The Company has recorded a liability for natural gas imbalance positions related to natural gas properties with insufficient proved reserves of $3.6 million and $1.7 million at December 31, 2012 and 2011, respectively. The Company includes the gas imbalance positions in other long-term obligations in the consolidated balance sheet. The Company accounts for its two construction contracts, discussed in Note 12, using the completed-contract method, under which contract revenues and costs are recognized when work under the contract is completed or substantially completed and assets have been transferred. In the interim, costs incurred on and billings related to contracts in process are accumulated on the balance sheet. Contract gains or losses are recorded as development costs within the Company’s oil and natural gas properties as part of the full cost pool. Contract losses are recorded at the time it is determined that a loss will be incurred. Contract gains, if any, are recorded at the end of the project. The Company recognizes revenues and expenses generated from daywork and footage drilling contracts as the services are performed as the Company does not bear the risk of completion of the well. The Company may receive lump-sum fees for the mobilization of equipment and personnel. Mobilization fees received and costs incurred to mobilize a rig from one market to another are recognized over the term of the related drilling contract. The contract terms can range from one month to two years. Midstream services revenues are recognized upon delivery of natural gas to customers and/or when services are rendered, pricing is determined and collectability is reasonably assured. Revenues from third-party midstream services are presented on a gross basis, as the Company acts as a principal by taking ownership of the natural gas purchased and taking responsibility of fulfillment for natural gas volumes sold. Revenue from sales of CO₂ is recognized when the product is delivered to the customer. Stock-Based Compensation. The Company grants restricted stock awards to members of its Board of Directors and its employees. Such awards and the related stock-based compensation cost are measured based on the calculated fair value of the award on the grant date. The expense is recognized on a straight-line basis over the employee’s requisite service period, generally the vesting period of the award. To the extent stock-based compensation cost relates to employees directly involved in oil and natural gas exploration and development activities, such amounts are capitalized to oil and natural gas properties. Amounts not capitalized are recognized as general and administrative expense, production expense, midstream and marketing expense and drilling and services expense in the consolidated statement of operations. The related excess tax benefit received upon vesting of restricted stock, if any, is reflected in the consolidated statement of cash flows as a financing activity. The related excess tax expense due upon vesting of restricted stock, if any, is reflected in the consolidated statement of cash flows as an operating activity. Advertising Costs. The Company expenses advertising costs as incurred. Advertising and promotional costs were $11.8 million, $4.8 million, and $5.4 million, respectively, during the years ended December 31, 2012, 2011 and 2010. Income Taxes. Deferred income taxes reflect the net tax effects 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 assets will not be realized based on all available evidence. The Company has elected an accounting policy in which interest and penalties on income taxes are presented as a component of the income tax provision, rather than as a component of interest expense. Interest and penalties resulting from the underpayment or the late payment of income taxes due to a taxing authority and interest and penalties accrued relating to income tax contingencies, if any, are presented, on a net of tax basis, as a component of the income tax provision. Variable Interest Entities. An entity is referred to as a VIE if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity’s residual economics, or (v) the entity was established with non-substantive voting interests. The Company consolidates a VIE when it has determined it is the primary beneficiary, which requires significant judgment. The primary beneficiary of a VIE has both the power to direct the activities that most significantly impact the activities of the VIE and the right to receive benefits or the obligation to absorb losses of the entity that could be potentially significant to the VIE. In addition to the VIEs that the Company consolidates, the Company also holds a variable interest in another VIE that is not consolidated as it was determined that the Company is not the primary beneficiary. The Company continually monitors both consolidated and unconsolidated VIEs to determine if any events have occurred that could cause the primary beneficiary to change. Noncontrolling Interest. Noncontrolling interest represents third-party ownership interests in the Company’s subsidiaries and consolidated VIEs and is included as a component of equity in the consolidated balance sheet and consolidated statement of changes in equity. The Company’s subsidiary Cholla Pipeline, L.P. had a 1.29% noncontrolling interest for the years ended December 31, 2012, 2011 and 2010. Other noncontrolling interest is third-party ownership in the Company’s VIEs. See Note 4 for discussion of the Company’s VIEs. Earnings per Share. Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted earnings per share calculation consist of unvested restricted stock awards, using the treasury method, and convertible preferred stock. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. See Note 20 for additional information on the Company’s earnings per share calculation. Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Environmental expenditures are expensed or capitalized, as appropriate, depending on future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and costs can be reasonably estimated. See Note 16 for discussion of the Company’s commitments and contingencies. Concentration of Risk. All of the Company’s hedging transactions have been carried out in the over-the-counter market. The use of hedging transactions in the over-the-counter market involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties for all of the Company’s hedging transactions have an “investment grade” credit rating. The Company monitors on an ongoing basis the credit ratings of its hedging counterparties and considers its counterparties’ credit default risk ratings in determining the fair value of its derivative contracts. The Company’s derivative contracts are with multiple counterparties to minimize its exposure to any individual counterparty. A default by the Company under its senior credit facility constitutes a default under its derivative contracts with counterparties that are lenders under the senior credit facility. The Company does not require collateral or other security from counterparties to support derivative instruments. The Company has master netting agreements with all of its derivative counterparties, which allow the Company to net its derivative assets and liabilities with the same counterparty. As a result of the netting provisions, the Company’s maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivative contracts. The Company’s loss is further limited as any amounts due from a defaulting counterparty that is a lender under the senior credit facility can be offset against amounts owed to such counterparty under the Company’s senior credit facility. As of December 31, 2012, the counterparties to the Company’s open derivative contracts consisted of 15 financial institutions, 13 of which are also lenders under the Company’s senior credit facility. As a result, the Company is not required to post additional collateral under derivative contracts as the majority of the counterparties to the Company’s derivative contracts share in the collateral supporting the Company’s senior credit facility. To secure their obligations under the derivative contracts novated by the Company, the Permian Trust and Mississippian Trust II have each given the counterparties to such contracts a lien on its royalty interests. See Note 4 for additional information on the Permian Trust’s and Mississippian Trust II’s derivative contracts. The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payment for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s joint interest partners consist primarily of independent oil and gas producers. If the oil and gas exploration and production industry in general was adversely affected, the ability of the joint interest partners to reimburse the Company could be adversely affected. The purchasers of the Company’s oil and natural gas production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. See Note 23 for information regarding the Company’s major customers. The Company believes alternate purchasers are available in its areas of operations and does not believe the loss of any one purchaser would materially affect the Company’s ability to sell the oil and natural gas it produces. Additionally, the Company has not experienced any significant losses from uncollectible accounts. See Note 6 for information regarding the Company’s allowance for doubtful accounts. Recently Adopted Accounting Pronouncements. In May 2011, the Financial Accounting Standards Board (“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”), which clarifies the FASB’s intent regarding the application of existing fair value measurements and requires additional disclosure of information regarding valuation processes and inputs used. The new disclosure requirements, which are effective for interim and annual reporting periods beginning after December 15, 2011, were implemented by the Company in the first quarter of 2012. The implementation of ASU 2011-04 had no impact on the Company’s financial position or results of operations. See Note 5 for the Company’s fair value disclosures. In September 2011, the FASB issued ASU 2011-08, which allows an entity the option of performing a qualitative assessment to determine whether it is necessary to perform the previously required two-step annual impairment test. If an entity determines, on the basis of qualitative factors, that the fair value of the reporting unit more-likely-than-not exceeds the carrying amount, the two-step impairment test is not required. ASU 2011-08 does not change how goodwill is calculated or assigned to reporting units, nor does it revise the requirement to test goodwill annually for impairment or amend the requirement to test goodwill for impairment between annual tests if events or circumstances warrant. ASU 2011-08 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The adoption of ASU 2011-08 did not impact the carrying value of the Company’s goodwill. See Note 9 for discussion of goodwill and the Company’s impairment assessments. Recent Accounting Pronouncement Not Yet Adopted. In December 2011, the FASB issued Accounting Standards Update 2011-11, “Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”), and in January 2013 issued Accounting Standards Update 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities” (“ASU 2013-01”). These updates require disclosures about the nature of an entity’s rights of offset and related arrangements associated with its recognized derivatives contracts. The guidance is effective for interim and annual periods beginning on or after January 1, 2013. As the additional requirements under ASU 2011-11 and ASU 2013-01, which will be implemented January 1, 2013, pertain to disclosures of offsetting assets and liabilities, no effect on the Company’s financial position or results of operations is expected.

Summary of Significant Accounting Policies

Nature of Business. SandRidge Energy, Inc. (the “Company” or “SandRidge”) is an independent oil and natural gas company concentrating on development and production activities in the Mid-Continent, Gulf of Mexico and Permian Basin in west Texas. The Company’s primary area of focus is the Mississippian formation in the Mid-Continent area of Oklahoma and Kansas. The Company owns and operates additional interests in the Mid-Continent, Gulf of Mexico, Permian Basin, West Texas Overthrust (“WTO”) and Gulf Coast. The Company also operates businesses that are complementary to its primary development and production activities, including gas gathering and processing facilities, an oil and natural gas marketing business and an oil field services business, including a drilling rig business.

Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its wholly owned or majority owned subsidiaries and variable interest entities (“VIEs”) for which the Company is the primary beneficiary. All significant intercompany accounts and transactions have been eliminated in consolidation.

Reclassifications. Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Company’s previously reported results of operations.

Use of Estimates. The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The more significant areas requiring the use of assumptions, judgments and estimates include: oil and natural gas reserves; cash flow estimates used in impairment tests of goodwill and other long-lived assets; depreciation, depletion and amortization; asset retirement obligations; assigning fair value and allocating purchase price in connection with business combinations; income taxes; valuation of derivative instruments; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could significantly differ from these estimates.

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 overall oil and natural gas production and inventories in relevant markets, economic conditions, the global political environment, 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. See Note 14 for the Company’s open oil and natural gas commodity derivative contracts.

Production targets contained in certain gathering and treating agreements require the Company to incur capital expenditures or make associated shortfall payments. Additionally, the Company has a drilling obligation to each of SandRidge Mississippian Trust I (the “Mississippian Trust I”), SandRidge Permian Trust (the “Permian Trust”) and SandRidge Mississippian Trust II (the “Mississippian Trust II”). See Note 4 for discussion of these drilling obligations. The Company depends on cash flows from operating activities, funding commitments from third parties for drilling carries and the availability of borrowings under its senior secured revolving credit facility (the “senior credit facility”) to fund its capital expenditures. Additionally, the Company may use proceeds from the issuance of equity and debt securities in the capital markets and from sales or other monetizations of assets to fund its capital expenditures. Based on existing cash balances (including proceeds from the sale of the Permian Properties), cash flows from operating activities and funding commitments from third parties for drilling carries, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs for 2013. 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 13 for discussion of the financial covenants in the senior credit facility.

Cash and Cash Equivalents. The Company considers all highly-liquid instruments with an original maturity of three months or less to be cash equivalents as these instruments are readily convertible to known amounts of cash and bear insignificant risk of changes in value due to their short maturity period.

Accounts Receivable, Net. The Company has receivables for sales of oil and natural gas, as well as receivables related to the exploration and treating services for oil and natural gas. An allowance for doubtful accounts has been established based on management’s review of the collectability of the receivables in light of historical experience, the nature and volume of the receivables and other subjective factors. Accounts receivable are charged against the allowance, upon approval by management, when they are deemed uncollectible. Refer to Note 6 for further information on the Company’s accounts receivable and allowance for doubtful accounts.

Inventories. Inventories consist of oil field services supplies and are stated at the lower of cost or market with cost determined on an average cost basis. Inventories are shown net of a provision for obsolescence, commensurate with known or estimated exposure, of $0.3 million and $0.2 million at December 31, 2012 and 2011, respectively.

Fair Value of Financial Instruments. Certain of the Company’s financial assets and liabilities are measured at fair value. Fair value represents the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The Company’s financial instruments, not otherwise recorded at fair value, consist primarily of cash, trade receivables, trade payables and long-term debt. The carrying value of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short-term maturity of these instruments. See Note 5 for further discussion of the Company’s fair value measurements.

Fair Value of Non-financial Assets and Liabilities. The Company also applies fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as business acquisitions, property, plant and equipment and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production or other applicable sales estimates, operational costs and a risk-adjusted discount rate. The Company primarily uses the present value of estimated future cash inflows and/or outflows to value its non-financial assets and liabilities when circumstances dictate determining fair value is necessary. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy discussed in Note 5. See Note 3 for additional discussion of the Company’s acquisitions. Additionally, the Company prepared fair value analyses of its gas treating plants and CO₂ compression facilities in 2012 as discussed further in Note 8.

Derivative Financial Instruments. To manage risks related to price fluctuations in oil and natural gas prices and changes in interest rates, the Company enters into oil, natural gas and interest rate derivative contracts.

The Company recognizes its derivative instruments as either assets or liabilities at fair value with changes in the derivative’s fair value being recognized in earnings unless designated as a hedging instrument with specific hedge accounting criteria being met. The commodity derivative instruments that the Company utilizes are to manage the price risk attributable to its expected oil and natural gas production. The Company has elected not to designate price risk management activities as accounting hedges under applicable accounting guidance, and, accordingly, accounts for its commodity derivative contracts at fair value with changes in fair value reported currently in earnings. The Company also utilizes derivatives to manage its exposure to variable interest rates and has not designated its interest rate swap as a hedging instrument. As such, the interest rate swap is recorded at fair value with the change in fair value reported currently in earnings. The Company nets derivative assets and liabilities whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. The related cash flow impact of the Company’s derivative activities are reflected as cash flows from operating activities unless the derivative contract contains a significant financing element; in this case, the cash settlements for these derivatives are classified as cash flows from financing activities in the consolidated statement of cash flows. See Note 14 for further discussion of the Company’s derivatives.

Oil and Natural Gas Operations. The Company uses the full cost method to account for its oil and natural gas properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of oil and natural gas reserves are capitalized into a full cost pool. These capitalized costs include costs of all unproved properties and internal costs directly related to the Company’s acquisition, exploration and development activities and capitalized interest. The Company capitalized internal costs of $61.3 million, $37.1 million and $28.6 million to the full cost pool in 2012, 2011 and 2010, respectively. Capitalized costs are amortized using a unit-of-production method. Under this method, depreciation and depletion is computed at the end of each quarter by multiplying total production for the quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter. Costs associated with unproved properties are excluded from the amortizable cost base until a determination has been made as to the existence of proved reserves. Unproved properties are reviewed at the end of each quarter to determine whether the costs incurred should be reclassified to the full cost pool and, thereby, subjected to amortization. The costs associated with unproved properties relate primarily to costs to acquire unproved acreage. Unproved leasehold costs are transferred to the amortization base with the costs of drilling the related well upon determination of the existence of proved reserves or upon impairment of a lease. Costs of seismic data are allocated to various unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis.

All items classified as unproved property are assessed on a quarterly basis for possible impairment or reduction in value. Properties are assessed on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization.

Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and impairment, less related deferred income taxes may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties, plus estimated salvage value, less the related tax effects (the “ceiling limitation”). A ceiling limitation calculation is performed at the end of each quarter. If total capitalized costs, net of accumulated depreciation, depletion and impairment, less related deferred taxes are greater than the ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation and depletion expense in future periods. Once incurred, a write-down is not reversible at a later date.

The ceiling limitation calculation is prepared using a 12-month oil and natural gas average price, as adjusted for basis or location differentials using a 12-month average, held constant over the life of the reserves (“net wellhead prices”). If applicable, these net wellhead prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil and natural gas. The Company may, from time-to-time, use derivative financial instruments to hedge against the volatility of oil and natural gas prices. Derivative contracts that qualify and are designated as cash flow hedges are included in estimated future cash flows. Historically, the Company has not designated any of its derivative contracts as cash flow hedges and has therefore not included its derivative contracts in estimating future cash flows. The future cash outflows associated with future development or abandonment of wells are included in the computation of the discounted present value of future net revenues for purposes of the ceiling limitation calculation. See Note 7 for further discussion of the full cost ceiling limitation.

Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved oil and natural gas reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the proved reserve quantities of the cost center.

Property, Plant and Equipment, Net. Other capitalized costs, including drilling equipment, natural gas gathering and treating equipment, transportation equipment and other property and equipment are carried at cost. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 10 to 39 years for buildings and 3 to 30 years for equipment. When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed and any resulting gain or loss is reflected in the consolidated statement of operations.

Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying value of such asset may not be recoverable. Assets are considered to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset or asset group including disposal value, if any, is less than the carrying amount of the asset or asset group. If any asset or asset group is considered to be impaired, the impairment loss is measured as the amount by which the carrying amount of the asset or asset group exceeds its fair value. See Note 8 for further discussion of impairments.

Capitalized Interest. Interest is capitalized on assets being made ready for use using a weighted average interest rate based on the Company’s outstanding borrowings. During 2012, 2011 and 2010, interest of approximately $10.1 million, $1.0 million and $0.3 million, respectively, was capitalized on unproved properties that were not currently being depreciated or depleted and on which exploration activities were in progress. Additionally, $4.7 million, $2.0 million and $1.0 million were capitalized in 2012, 2011 and 2010, respectively, on midstream and corporate assets which were under construction.

Restricted Deposits. Restricted deposits represent bank trust and escrow accounts required by the Bureau of Ocean Energy Management, Bureau of Safety and Environmental Enforcement, surety bond underwriters, purchase agreements or other settlement agreements to satisfy the Company’s eventual responsibility to plug and abandon wells and remove structures when certain offshore fields are no longer in use. During 2010, $5.1 million was liquidated from the escrow accounts upon compliance with certain plugging and abandonment obligations. At December 31, 2012 and 2011, the Company had $27.9 million of such restricted deposits included as a long-term asset in the accompanying consolidated balance sheets.

Restricted deposits may also include escrow deposits received on pending sales of oil and natural gas properties. Amounts are considered restricted until the transaction closes. In December 2012, the Company entered into an agreement to sell certain of its oil and natural gas properties in the Permian Basin and received a $255.0 million deposit. At December 31, 2012, this deposit was included in current assets and current liabilities in the accompanying consolidated balance sheets. See Note 22 for further discussion of the sale of the oil and natural gas properties in the Permian Basin.

Goodwill. Goodwill represents the excess of the consideration paid over the fair value of identifiable net assets acquired as part of the acquisition of Arena Resources, Inc. (“Arena”). See Note 3 for discussion of this acquisition. Goodwill was assigned to the Company’s exploration and production segment and is not deductible for income tax purposes.

Goodwill is not amortized, but rather tested annually for impairment. The Company performs its annual goodwill impairment test as of July 1st and between annual evaluations if events occur or circumstances exist that would more-likely-than-not reduce the fair value of the reporting unit below its carrying amount. Such circumstances could include, but are not limited to (1) a significant or sustained decrease in oil and natural gas prices, (2) a significant adverse change in the economic or business climate, (3) an adverse action or assessment by a regulator and (4) the likelihood that a reporting unit or a significant portion of a reporting unit will be sold or otherwise disposed. When a portion of a reporting unit that constitutes a business is disposed, goodwill is allocated to that business based on the relationship of the fair value of the portion sold to the total reporting unit’s fair value.

When evaluating whether goodwill is impaired, the Company may elect to perform a qualitative assessment to determine whether it is necessary to perform the current two-step annual impairment test. If the Company determines, on the basis of qualitative factors, that the fair value of the reporting unit more-likely-than-not exceeds the carrying amount, the two-step impairment test is not required. However, if the Company determines it is necessary or elects to perform the two-step impairment test, the Company compares the fair value of the reporting unit to which the goodwill is assigned to the reporting unit’s carrying amount, including goodwill. The fair value of the reporting unit is estimated using the income, or discounted cash flow, approach. If the carrying amount of the reporting unit exceeds its fair value, then the amount of the impairment loss must be measured. The impairment loss would be calculated by comparing the implied fair value of reporting unit goodwill to the carrying amount of goodwill. In calculating the implied fair value of reporting unit goodwill, the fair value of the reporting unit is allocated to all of its other assets and liabilities based on their fair values. The excess of the fair value of a reporting unit over the amount assigned to its other assets and liabilities is the implied fair value of goodwill. An impairment loss would be recognized when the carrying amount of goodwill exceeds its implied fair value.

Entry by the Company in December 2012 into an agreement to sell the Permian Properties was determined to be a triggering event. As such, an impairment test was performed as of December 31, 2012. See Note 9 for further discussion of goodwill and the impairment test performed.

Investments. Investments in marketable equity securities have been designated as available for sale and measured at fair value pursuant to the fair value option which requires unrealized gains and losses be reported in earnings.

Debt Issuance Costs. The Company amortizes debt issuance costs related to its long-term debt as interest expense over the scheduled maturity period of the related debt. The Company includes unamortized debt issuance costs in other assets in the consolidated balance sheet.

Asset Retirement Obligations. The Company owns oil and natural gas properties that require expenditures to plug, abandon and remediate wells at the end of their productive lives, in accordance with applicable federal and state laws. Liabilities for these asset retirement obligations are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired) at the estimated present value at the asset’s inception, with the offsetting increase to property cost. These property costs are depreciated on a unit-of-production basis within the full cost pool. The liability accretes each period until the liability is settled or the well is sold, at which time the liability is removed. Both the accretion and the depreciation are included in the consolidated statement of operations. The Company determines its asset retirement obligations by calculating the present value of estimated expenses related to the liability. Estimating the future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability and what constitutes adequate restoration. Inherent in the present value calculation rates are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. See Note 15 for further discussion of the Company’s asset retirement obligations.

In certain instances, the Company is required to make deposits to escrow accounts for future plugging and abandonment obligations. See Restricted Deposits discussed above.

Revenue Recognition and Natural Gas Balancing. Oil and natural gas revenues are recorded when title of sold oil and natural gas production passes to the customer, net of royalties, discounts and allowances, as applicable. Taxes assessed by governmental authorities on oil and natural gas sales are presented separately from such revenues and included in production tax expense in the consolidated statement of operations.

The Company accounts for natural gas production imbalances using the sales method, whereby it recognizes revenue on all natural gas sold to its customers notwithstanding the fact that its ownership may be less than 100% of the natural gas sold. Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves. The Company has recorded a liability for natural gas imbalance positions related to natural gas properties with insufficient proved reserves of $3.6 million and $1.7 million at December 31, 2012 and 2011, respectively. The Company includes the gas imbalance positions in other long-term obligations in the consolidated balance sheet.

The Company accounts for its two construction contracts, discussed in Note 12, using the completed-contract method, under which contract revenues and costs are recognized when work under the contract is completed or substantially completed and assets have been transferred. In the interim, costs incurred on and billings related to contracts in process are accumulated on the balance sheet. Contract gains or losses are recorded as development costs within the Company’s oil and natural gas properties as part of the full cost pool. Contract losses are recorded at the time it is determined that a loss will be incurred. Contract gains, if any, are recorded at the end of the project.

The Company recognizes revenues and expenses generated from daywork and footage drilling contracts as the services are performed as the Company does not bear the risk of completion of the well. The Company may receive lump-sum fees for the mobilization of equipment and personnel. Mobilization fees received and costs incurred to mobilize a rig from one market to another are recognized over the term of the related drilling contract. The contract terms can range from one month to two years.

Midstream services revenues are recognized upon delivery of natural gas to customers and/or when services are rendered, pricing is determined and collectability is reasonably assured. Revenues from third-party midstream services are presented on a gross basis, as the Company acts as a principal by taking ownership of the natural gas purchased and taking responsibility of fulfillment for natural gas volumes sold. Revenue from sales of CO₂ is recognized when the product is delivered to the customer.

Stock-Based Compensation. The Company grants restricted stock awards to members of its Board of Directors and its employees. Such awards and the related stock-based compensation cost are measured based on the calculated fair value of the award on the grant date. The expense is recognized on a straight-line basis over the employee’s requisite service period, generally the vesting period of the award. To the extent stock-based compensation cost relates to employees directly involved in oil and natural gas exploration and development activities, such amounts are capitalized to oil and natural gas properties. Amounts not capitalized are recognized as general and administrative expense, production expense, midstream and marketing expense and drilling and services expense in the consolidated statement of operations. The related excess tax benefit received upon vesting of restricted stock, if any, is reflected in the consolidated statement of cash flows as a financing activity. The related excess tax expense due upon vesting of restricted stock, if any, is reflected in the consolidated statement of cash flows as an operating activity.

Advertising Costs. The Company expenses advertising costs as incurred. Advertising and promotional costs were $11.8 million, $4.8 million, and $5.4 million, respectively, during the years ended December 31, 2012, 2011 and 2010.

Income Taxes. Deferred income taxes reflect the net tax effects 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 assets will not be realized based on all available evidence.

The Company has elected an accounting policy in which interest and penalties on income taxes are presented as a component of the income tax provision, rather than as a component of interest expense. Interest and penalties resulting from the underpayment or the late payment of income taxes due to a taxing authority and interest and penalties accrued relating to income tax contingencies, if any, are presented, on a net of tax basis, as a component of the income tax provision.

Variable Interest Entities. An entity is referred to as a VIE if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity’s residual economics, or (v) the entity was established with non-substantive voting interests. The Company consolidates a VIE when it has determined it is the primary beneficiary, which requires significant judgment. The primary beneficiary of a VIE has both the power to direct the activities that most significantly impact the activities of the VIE and the right to receive benefits or the obligation to absorb losses of the entity that could be potentially significant to the VIE. In addition to the VIEs that the Company consolidates, the Company also holds a variable interest in another VIE that is not consolidated as it was determined that the Company is not the primary beneficiary. The Company continually monitors both consolidated and unconsolidated VIEs to determine if any events have occurred that could cause the primary beneficiary to change.

Noncontrolling Interest. Noncontrolling interest represents third-party ownership interests in the Company’s subsidiaries and consolidated VIEs and is included as a component of equity in the consolidated balance sheet and consolidated statement of changes in equity. The Company’s subsidiary Cholla Pipeline, L.P. had a 1.29% noncontrolling interest for the years ended December 31, 2012, 2011 and 2010. Other noncontrolling interest is third-party ownership in the Company’s VIEs. See Note 4 for discussion of the Company’s VIEs.

Earnings per Share. Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted earnings per share calculation consist of unvested restricted stock awards, using the treasury method, and convertible preferred stock. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. See Note 20 for additional information on the Company’s earnings per share calculation.

Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Environmental expenditures are expensed or capitalized, as appropriate, depending on future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and costs can be reasonably estimated. See Note 16 for discussion of the Company’s commitments and contingencies.

Concentration of Risk. All of the Company’s hedging transactions have been carried out in the over-the-counter market. The use of hedging transactions in the over-the-counter market involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties for all of the Company’s hedging transactions have an “investment grade” credit rating. The Company monitors on an ongoing basis the credit ratings of its hedging counterparties and considers its counterparties’ credit default risk ratings in determining the fair value of its derivative contracts. The Company’s derivative contracts are with multiple counterparties to minimize its exposure to any individual counterparty.

A default by the Company under its senior credit facility constitutes a default under its derivative contracts with counterparties that are lenders under the senior credit facility. The Company does not require collateral or other security from counterparties to support derivative instruments. The Company has master netting agreements with all of its derivative counterparties, which allow the Company to net its derivative assets and liabilities with the same counterparty. As a result of the netting provisions, the Company’s maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivative contracts. The Company’s loss is further limited as any amounts due from a defaulting counterparty that is a lender under the senior credit facility can be offset against amounts owed to such counterparty under the Company’s senior credit facility. As of December 31, 2012, the counterparties to the Company’s open derivative contracts consisted of 15 financial institutions, 13 of which are also lenders under the Company’s senior credit facility. As a result, the Company is not required to post additional collateral under derivative contracts as the majority of the counterparties to the Company’s derivative contracts share in the collateral supporting the Company’s senior credit facility. To secure their obligations under the derivative contracts novated by the Company, the Permian Trust and Mississippian Trust II have each given the counterparties to such contracts a lien on its royalty interests. See Note 4 for additional information on the Permian Trust’s and Mississippian Trust II’s derivative contracts.

The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payment for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s joint interest partners consist primarily of independent oil and gas producers. If the oil and gas exploration and production industry in general was adversely affected, the ability of the joint interest partners to reimburse the Company could be adversely affected.

The purchasers of the Company’s oil and natural gas production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. See Note 23 for information regarding the Company’s major customers. The Company believes alternate purchasers are available in its areas of operations and does not believe the loss of any one purchaser would materially affect the Company’s ability to sell the oil and natural gas it produces. Additionally, the Company has not experienced any significant losses from uncollectible accounts. See Note 6 for information regarding the Company’s allowance for doubtful accounts.

Recently Adopted Accounting Pronouncements. In May 2011, the Financial Accounting Standards Board (“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”), which clarifies the FASB’s intent regarding the application of existing fair value measurements and requires additional disclosure of information regarding valuation processes and inputs used. The new disclosure requirements, which are effective for interim and annual reporting periods beginning after December 15, 2011, were implemented by the Company in the first quarter of 2012. The implementation of ASU 2011-04 had no impact on the Company’s financial position or results of operations. See Note 5 for the Company’s fair value disclosures.

In September 2011, the FASB issued ASU 2011-08, which allows an entity the option of performing a qualitative assessment to determine whether it is necessary to perform the previously required two-step annual impairment test. If an entity determines, on the basis of qualitative factors, that the fair value of the reporting unit more-likely-than-not exceeds the carrying amount, the two-step impairment test is not required. ASU 2011-08 does not change how goodwill is calculated or assigned to reporting units, nor does it revise the requirement to test goodwill annually for impairment or amend the requirement to test goodwill for impairment between annual tests if events or circumstances warrant. ASU 2011-08 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The adoption of ASU 2011-08 did not impact the carrying value of the Company’s goodwill. See Note 9 for discussion of goodwill and the Company’s impairment assessments.

Recent Accounting Pronouncement Not Yet Adopted. In December 2011, the FASB issued Accounting Standards Update 2011-11, “Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”), and in January 2013 issued Accounting Standards Update 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities” (“ASU 2013-01”). These updates require disclosures about the nature of an entity’s rights of offset and related arrangements associated with its recognized derivatives contracts. The guidance is effective for interim and annual periods beginning on or after January 1, 2013. As the additional requirements under ASU 2011-11 and ASU 2013-01, which will be implemented January 1, 2013, pertain to disclosures of offsetting assets and liabilities, no effect on the Company’s financial position or results of operations is expected.