Nature of operations and summary of significant accounting policies

Chaparral Energy, Inc. and its subsidiaries, (collectively, “we”, “our”, “us”, or the “Company”) are involved in the acquisition, exploration, development, production and operation of oil and natural gas properties. Properties are located primarily in Oklahoma, Texas, New Mexico, Louisiana, Arkansas, and Kansas.

A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows.

Principles of consolidation

The consolidated financial statements include the accounts of Chaparral Energy, Inc. and its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated.

Use of estimates

The preparation of 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. Actual results could differ from these estimates. Significant estimates affecting these financial statements include estimates for quantities of proved oil and natural gas reserves, valuation allowances associated with deferred income taxes, asset retirement obligations, fair value of derivative instruments, and others, and are subject to change.

Reclassifications

Certain reclassifications have been made to prior period financial statements to conform to current period presentation.

Cash and cash equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We maintain cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. As of December 31, 2011, cash with a recorded balance totaling $32,232 was held at JP Morgan Chase Bank, N.A. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on such accounts.

Accounts receivable

We have receivables from joint interest owners and oil and natural gas purchasers which are generally uncollateralized. We generally review our oil and natural gas purchasers for credit worthiness and general financial condition. We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties of which we are the operator. Accounts receivable from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts. Accounts receivable are generally due within 30 days and accounts outstanding longer than 60 days are considered past due. We determine our allowance by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties we operate, and the owner’s ability to pay its obligation, among other things.

We write off accounts receivable when they are determined to be uncollectible. Bad debt expense for the years ended December 31, 2011, 2010, and 2009 was $179, $17, and $317, respectively. Accounts receivable consisted of the following at December 31:



	2011			2010
Joint interests	$	16,926		$	17,835
Accrued oil and natural gas sales	47,667			41,316
Derivative settlements	449			3,431
Other	380			831
Allowance for doubtful accounts	(634		)	(633		)
	$	64,788		$	62,780

Inventories

Inventories are comprised of equipment used in developing oil and natural gas properties, oil and natural gas product inventories, and equipment for resale. Equipment inventory and inventory for resale are carried at the lower of cost or market using the average cost method. Oil and natural gas product inventories are stated at the lower of production cost or market. We regularly review inventory quantities on hand and record provisions for excess or obsolete inventory, if necessary. The provision for excess or obsolete inventory for the years ended December 31, 2011, 2010, and 2009 was $602, $810, and $274, respectively. Inventories consisted of the following at December 31:



	2011			2010
Equipment inventory	$	6,164		$	6,399
Oil and natural gas product	3,793			3,624
Inventory for resale	—			2,866
Inventory valuation allowance	(1,316		)	(1,821		)
	$	8,641		$	11,068

Property and equipment

Property and equipment are capitalized and stated at cost, while maintenance and repairs are expensed currently.

Depreciation and amortization are provided in amounts sufficient to relate the cost of depreciable assets to operations over their estimated service lives using the straight-line method. Estimated useful lives are as follows:



Furniture and fixtures	10 years
Automobiles and trucks	5 years
Machinery and equipment	10 - 20 years
Office and computer equipment	5 - 10 years
Building and improvements	10 - 40 years

Oil and natural gas properties

We use the full cost method of accounting for oil and natural gas properties and activities. Accordingly, we capitalize all costs incurred in connection with the exploration for and development of oil and natural gas reserves. Proceeds from the disposition of oil and natural gas properties are accounted for as a reduction in capitalized costs, with no gain or loss generally recognized unless such dispositions involve a significant alteration in the depletion rate. We capitalize internal costs that can be directly identified with exploration and development activities, but do not include any costs related to production, general corporate overhead or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, drilling and completing and equipping oil and natural gas wells, including salaries, benefits and other internal costs directly attributable to these activities.

Depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties are provided using the units-of-production method based on estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. Our cost basis for depletion includes estimated future development costs to be incurred on proved undeveloped properties. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs, and the anticipated proceeds from salvaging equipment.

In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related estimated future net revenues discounted at 10% (“PV-10 value”), as adjusted for our cash flow hedge positions and net of tax considerations, plus the cost of unproved properties not being amortized. During the first quarter of 2009, we recorded a ceiling test impairment of oil and natural gas properties of $240,790 as a result of a decline in natural gas prices at the measurement date. The impairment was calculated based on March 31, 2009 spot prices of $49.66 per Bbl of oil and $3.63 per Mcf of natural gas. The effect of derivative contracts accounted for as cash flow hedges, based on the March 31, 2009 spot prices, increased the full cost ceiling by $169,013, thereby reducing the ceiling test write down by the same amount.

Our estimates of oil and natural gas reserves as of December 31, 2011, 2010, and 2009 were prepared using an average price for oil and natural gas based upon the first day of each month for the prior twelve months as required by the SEC’s Modernization of Oil and Gas Reporting and the updated guidance of the Financial Accounting Standard Board (“FASB”) relating to Oil and Gas Reserve Estimation and Disclosures, which we adopted effective December 31, 2009. As of December 31, 2011, the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties, and no additional ceiling test impairment was recorded. The PV-10 value of our reserves was estimated based on average prices of $96.19 per Bbl of oil and $4.11 per Mcf of gas for the year ended December 31, 2011.

A decline in oil and natural gas prices subsequent to December 31, 2011 could result in additional ceiling test write downs in future periods. The amount of any future impairment is difficult to predict, and will depend on the average oil and gas prices during each period, the incremental proved reserves added during each period, and additional capital spent.

Impairment of long-lived assets

Impairment losses are recorded on property and equipment used in operations and other long lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset.

We own an interest in the Levelland/Hockley County ethanol plant in Levelland, Texas, and we own a pipeline constructed for the sole purpose of supplying natural gas to the ethanol plant. Due to changes in the price and availability of grain, the plant has experienced significant supply issues, ceased operations, filed Chapter 11 bankruptcy, and is exploring alternatives for additional sources of capital. During the fourth quarter of 2010, we determined that any future cash flows generated by either the ethanol plant or by our pipeline, which supplies gas to the ethanol plant, would probably not be sufficient to allow us to recover our investment in these assets. We accordingly recorded an impairment charge of $4,150, which included our $2,042 investment in the ethanol plant and the $2,108 carrying value of our pipeline assets.

Deferred income taxes

Deferred income taxes are provided for significant carryforwards and temporary differences between the tax basis of an asset or liability and its reported amount in the financial statements that will result in taxable or deductible amounts in future years. Deferred income tax assets or liabilities are determined by applying the presently enacted tax rates and laws. We record a valuation allowance for the amount of net deferred tax assets when, in management’s opinion, it is more likely than not that such assets will not be realized.

Realization of our deferred tax assets is dependent upon generating sufficient future taxable income. Although realization is not assured, we believe it is more likely than not that the deferred tax asset will be realized. The amount of the deferred tax asset considered realizable, however, could be reduced in the near-term if estimates of future taxable income are reduced.

If applicable, we would report a liability for tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return, and would recognize interest and penalties related to uncertain tax positions in interest expense. As of December 31, 2011 and 2010, we have not recorded a liability or accrued interest or penalties related to uncertain tax positions.

Tax years beginning with 1999 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject.

Derivative transactions

We use derivative instruments to reduce the effect of fluctuations in crude oil and natural gas prices, and we recognize all derivatives as either assets or liabilities measured at fair value. The accounting for changes in the fair value of a derivative depends on the use of the derivative and the resulting designation.

Changes in the fair value of derivatives that are not accounted for as hedges are reported immediately in non-hedge derivative gains (losses) in the statement of operations. Cash flows associated with non-hedge derivatives are reported as investing activities in the statement of cash flows unless the derivatives contain a significant financing element, in which case they are reported as financing activities.

If the derivative qualifies and is designated as a cash flow hedge, the effective portion of changes in the fair value of the derivative is recognized in other comprehensive income (loss) until the hedged item is recognized in income. The ineffective portion of a derivative’s change in fair value, as measured using the dollar offset method, is immediately recognized in gain (loss) from oil and natural gas hedging activities in the statement of operations. Cash flows associated with hedges are reported as operating activities in the statement of cash flows unless the hedges contain a significant financing element, in which case they are reported as financing activities.

If it is probable the oil or natural gas sales which are hedged will not occur, hedge accounting is discontinued and the gain or loss reported in accumulated other comprehensive income (loss) (“AOCI”) is immediately reclassified into income. If a derivative which qualified for cash flow hedge accounting ceases to be highly effective, or is liquidated or sold prior to maturity, hedge accounting is discontinued. The gain or loss associated with the discontinued hedges remains in AOCI and is reclassified into income as the hedged transactions occur. Effective April 1, 2010, we have elected to de-designate all of our commodity derivative contracts that had previously been designated as cash flow hedges and to discontinue hedge accounting prospectively.

We offset assets and liabilities for derivative contracts executed with the same counterparty under a master netting arrangement. See Note 5 for additional information regarding our derivative transactions.

Fair value measurements

Fair value is defined by the FASB as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity.

Assets and liabilities recorded at fair value in the balance sheet are categorized according to the fair value hierarchy defined by the FASB. The hierarchical levels are based upon the level of judgment associated with the inputs used to measure the fair value of the assets and liabilities. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the asset or liability is categorized based on the lowest level input that is significant to the fair value measurement in its entirety. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Level 2 inputs include adjusted quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities included in this category are derivatives with fair values based on published forward commodity price curves and other observable inputs. Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Assets carried at fair value and included in this category are certain financial derivatives, additions to our asset retirement obligations, and assets acquired through a non-monetary exchange transaction.

See Note 5 for additional information regarding our fair value measurements.

Asset retirement obligations

We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of oil and natural gas properties. The accretion of the asset retirement obligations is included in depreciation, depletion and amortization on the consolidated statements of operations. See Note 6 for additional information regarding our asset retirement obligations.

Environmental liabilities

We are subject to extensive federal, state and local environmental laws and regulations covering discharge of materials into the environment. Because these laws and regulations change regularly, we are unable to predict the conditions and other factors over which we do not exercise control that may give rise to environmental liabilities affecting us. Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of December 31, 2011 and 2010, we have not accrued for or been fined or cited for any environmental violations which would have a material adverse effect upon our financial position, operating results, or cash flows.

Sale of common stock

On April 12, 2010, we closed the sale of an aggregate of 475,043 shares of our common stock to CCMP Capital Investors II (AV-2), L.P., CCMP Energy I LTD., and CCMP Capital Investors (Cayman) II, L.P. (collectively, “CCMP”). Proceeds from the sale were $313,231, net of fees and other expenses of $11,769, and were used to repay the amounts owing under our Seventh Restated Credit Agreement.

Comprehensive income (loss)

Comprehensive income (loss) consists of net income (loss) and the unrealized gain or loss for the effective portion of derivative instruments classified as cash flow hedges. Comprehensive income (loss) is presented net of income taxes in the accompanying consolidated statements of stockholders’ equity and comprehensive income (loss).

Revenue recognition

Oil revenue is recognized when the product is delivered to the purchaser and natural gas revenue when delivered to the gas purchaser’s sales meter. Well supervision fees and overhead reimbursements from producing properties are recognized as expense reimbursements from outside interest owners when the services are performed. Sales of products or services are recognized at the time of delivery of materials or performance of service.

Gas balancing

In certain instances, the owners of the natural gas produced from a well will select different purchasers for their respective ownership interest in the wells. If one purchaser takes more than its rateable portion of the gas, the owners selling to that purchaser will be required to satisfy the imbalance in the future by cash payments or by allowing the other owners to sell more than their share of production. We recognize gas imbalances on the sales method and, accordingly, have recognized revenue on all production delivered to our purchasers. To the extent future reserves exist to enable the other owners to sell more than their rateable share of gas, no liability is recorded for our obligation for natural gas taken by our purchasers which exceeds our ownership interest of the well’s total production. As of December 31, 2011 and 2010, our aggregate imbalance due to under production was approximately 2,860 MMcf and 2,900 MMcf , respectively. As of December 31, 2011 and 2010, our aggregate imbalance due to over production was approximately1,802 MMcf and 1,835 MMcf, respectively, and a liability for gas imbalances of $1,819 and $1,456, respectively, was included in accounts payable and accrued liabilities.

Stock-based compensation

Our stock-based compensation programs consist of phantom stock and restricted stock awards issued to employees. Generally, we use new shares to grant restricted stock awards, and we cancel restricted shares forfeited or repurchased for tax withholding. Canceled shares are available to be issued as new grants under our 2010 Equity Incentive Plan.

The estimated fair value of the phantom stock awards is remeasured at the end of each reporting period until settlement. The estimated fair market value of these awards is calculated based on our total asset value less total liabilities, with both assets and liabilities being adjusted to fair value in accordance with the terms of the Phantom Stock Plan. Compensation cost associated with the phantom stock awards is recognized on a straight-line basis over the five-year vesting period.

The fair value of our restricted stock awards that include a service condition is based upon the estimated fair market value of our common equity per share on a minority, non-marketable basis on the date of grant, and is remeasured at the end of each reporting period until settlement. We recognize compensation cost over the requisite service period using the accelerated method for awards with graded vesting.

We use a Monte Carlo model to estimate the grant date fair value of restricted stock awards that include a market condition. This model includes various significant assumptions, including the expected volatility of the share awards and the probabilities of certain vesting conditions. Compensation cost associated with restricted stock awards that include a market condition is recognized over the requisite service period using the straight-line method.

The assumptions used to value our stock-based compensation awards reflect our best estimates, but they involve inherent uncertainties based on market conditions generally outside of our control. As a result, if other assumptions had been used, stock-based compensation expense could have been significantly impacted.

The costs associated with our stock-based compensation programs is calculated net of forfeitures, which are estimated based on our historical and expected turnover rates. If our actual forfeiture rate is materially different from our estimate, the stock-based compensation cost could be different from what we have recorded in the current period.

See Note 8 for additional information relating to stock-based compensation.

Production tax benefit

During 2006, we purchased interests in two venture capital limited liability companies resulting in a total investment of $15,000. Our expected return on the investment was the receipt of $2 of tax credits for every $1 invested and was recouped from our Oklahoma production taxes. The investments were accounted for as a production tax benefit asset and were netted against tax credits realized in other income using the effective yield method over the expected recovery period. Oklahoma production tax credits of $13,544 were included in “Other income” in the consolidated statement of operations for the year ended December 31, 2009. There was no income associated with these credits during 2011 or 2010, and no further income from these credits is expected.

Discontinued operations

The operations of the Electric Submersible Pumps (“ESP”) and Chemicals divisions of Green Country Supply, Inc. (“GCS”), a wholly owned subsidiary, have been presented as discontinued operations. See Note 12 for additional information relating to discontinued operations.

Recently adopted and issued accounting pronouncements

In December 2008, the SEC issued its Modernization of Oil and Gas Reporting, which revises reserves requirements for oil and natural gas companies. In addition, in January 2010, the FASB issued guidance regarding Oil and Gas Reserve Estimation and Disclosures to provide consistency with the new SEC rules. The new guidance amended existing standards to align the reserves calculation and disclosure requirements under GAAP with the requirements in the SEC rules.

We adopted the new SEC reserves requirements and GAAP reserves guidance as a change in accounting principle that is inseparable from a change in estimate, and applied the guidance prospectively effective December 31, 2009. As of December 31, 2011, 2010, and 2009:


•	economic producibility of reserves and discounted cash flows were estimated using an average price for oil and natural gas based upon the first day of each month for the prior twelve months rather than prices on the last day of the reporting period;


•	reserves were classified as proved undeveloped if there was a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years; and


•	additional disclosures regarding our reserve estimates were provided.

As a result of adopting the new requirements, our estimated reserves as of December 31, 2009 were approximately 18,810 MBoe lower than they would have been under the previous guidelines.

In May 2011, the FASB issued authoritative guidance that clarifies the application of fair value measurement and disclosure requirements and changes particular principles or requirements for measuring fair value. This guidance is effective for interim and annual periods beginning after December 15, 2011, and we will adopt it on January 1, 2012. We are currently evaluating the provisions of this guidance and its anticipated impact on our fair value disclosures.

In June 2011, the FASB issued new authoritative guidance that requires entities that report other comprehensive income to present the components of net income and comprehensive income in either one continuous financial statement or two consecutive financial statements. It does not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. This guidance is effective for interim and annual periods beginning after December 15, 2011, and we will apply it retrospectively beginning on January 1, 2012. We are currently evaluating the provisions of this guidance and its anticipated impact on our presentation of other comprehensive income.

In December 2011, the FASB issued authoritative guidance requiring entities to provide enhanced disclosures that will enable users of its financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. The guidance is effective for interim and annual periods beginning after January 1, 2013. We are currently evaluating the provisions of this guidance and its anticipated impact on our disclosures.