SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Consolidation and Accounting for Variable Interest Entities. A VIE is consolidated if it is determined that we are the entity's primary beneficiary. The primary beneficiary of a VIE has both the following characteristics: (1) the power to direct the activities of the VIE that most significantly impact the entity's economic performance and (2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. In determining whether we are the primary beneficiary of a VIE, we consider a number of factors, including our ability to direct the activities that most significantly affect the entity's economic success and our contractual rights and responsibilities under arrangements with the entity. As certain events occur, we may reconsider whether those events have caused us to become the primary beneficiary. A reconsideration event may also occur when we acquire new or additional interests in a VIE.

The following table presents the carrying amount and classification of our proportionate share of PDCM's assets and liabilities included in our balance sheets.



	As of December 31,
	2011		2010
Balance Sheets	(in thousands)

Cash and cash equivalents	$	748	$	1,560
Other current assets	8,568		3,206
Property, plant and equipment, net	211,150		101,679
Other assets	4,833		1,986
Total assets	$	225,299	$	108,431

Other current liabilities	$	9,076	$	4,641
Long-term debt	24,000		—
Asset retirement obligation	18,917		8,681
Other liabilities	2,103		1,370
Equity	171,203		93,739
Total liabilities and equity	$	225,299	$	108,431

Cash Equivalents. We consider all highly liquid investments with original maturities of three months or less to be cash equivalents.

Restricted Cash. Pursuant to an oral litigation settlement agreement, in July 2011, we funded an escrow account in the amount of $8.7 million. Final approval of the settlement was received in January 2012, with payment of settlement amount to be distributed during the first half of 2012. See Note 11 for a discussion of this settlement.

We are required by certain government agencies or agreements to maintain bonds or cash accounts for various operating activities. As of December 31, 2011, we had collateral in the form of certificates of deposit and cash totaling $3.8 million which consisted of $2.3 million and $1.5 million included in restricted cash and other assets, respectively. As of December 31, 2010, we had collateral in the form of certificates of deposit and cash totaling $5.1 million, which consisted of $2.5 million and $2.6 included in restricted cash and other assets, respectively.

Inventory. Inventory consists of crude oil, stated at the lower of cost to produce or market, and other production supplies intended to be used in our natural gas and crude oil operations. As of December 31, 2011 and 2010, inventory of $1.1 million and $1.4 million, respectively, is included in prepaid expenses and other current assets on the balance sheets.

Derivative Financial Instruments. We are exposed to the effect of market fluctuations in the prices of natural gas and crude oil. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy prohibits the use of natural gas and crude oil derivative instruments for speculative purposes.

All derivative assets and liabilities are recorded on our balance sheets at fair value. We have elected not to designate any of our derivative instruments as hedges. Classification of realized and unrealized gains and losses resulting from maturities and changes in fair value of open derivatives depends on the purpose for issuing or holding the derivative. Accordingly, changes in the fair value of our derivative instruments are recorded in the statements of operations, with the exception of changes in fair value related to those derivatives we designated to our affiliated partnerships. Changes in the fair value of derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Changes in the fair value of derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of natural gas marketing. Changes in the fair value of the derivative instruments designated to our affiliated partnerships are recorded on the balance sheets in accounts payable affiliates and accounts receivable affiliates. As positions designated to our affiliated partnerships settle, the realized gains and losses are netted for distribution. Net realized gains are paid to the partnerships and net realized losses are deducted from the partnerships’ cash distributions from production. The affiliated partnerships bear their designated share of counterparty risk.

The validation of the derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. See Notes 3 and 4 for a discussion of our derivative fair value measurements and a summary fair value table of our open positions as of December 31, 2011 and 2010, respectively.

Properties and Equipment. Significant accounting polices related to our properties and equipment are discussed below.

Natural Gas and Crude Oil Properties. We account for our natural gas and crude oil properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. We calculate quarterly depreciation, depletion and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted to add back fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the statement of operations as a gain or loss. Upon the sale of individual wells or a portion of a field, the proceeds are credited to accumulated DD&A.

Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to expense if the well is determined to be nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify our completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are expensed to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the same well is removed from the suspended well status and the proper accounting treatment is recorded. See Note 6 for disclosure related to changes in our capitalized exploratory well costs.

Impairment of Natural Gas and Crude Oil Properties. The following table presents impairment charges recorded for natural gas and crude oil properties.



	Year Ended December 31,
	2011		2010		2009
	(in thousands)
Continuing operations:
Impairment of proved properties	$	22,460	$	—	$	926
Impairment of individually significant unproved properties	1,108		1,477		982
Amortization of individually insignificant unproved properties	1,591		5,004		3,126
Total in continuing operations	25,159		6,481		5,034
Discontinued operations:
Impairment of proved properties	—		4,666		—
Impairment of individually significant unproved properties	—		—		3,171
Total in discontinued operations	—		4,666		3,171
Total impairment of natural gas and crude oil properties	$	25,159	$	11,147	$	8,205

Proved Property Impairment. We assess our producing natural gas and crude oil properties for possible impairment, upon a triggering event, by comparing net capitalized costs, or carrying value, to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. The estimates of future prices may differ from current market prices of natural gas and crude oil. Certain events, including but not limited to, downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of our proved natural gas and crude oil properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis and is measured by the amount by which the net capitalized costs exceed their fair value.

In October 2011, pursuant to our plan to divest our northeast Colorado ("NECO") assets, we reclassified our NECO assets as held for sale. Long lived assets held for sale are required to be measured at the lower of carrying value or fair value less costs to sell. We compared the fair value, estimated using Level 3 inputs, which included unrelated third party bids, less costs to sell the assets to their carrying value. The results of the comparison identified that the assets' carrying value exceeded the estimated fair value and, therefore, resulted in an impairment charge of $22.5 million to write-down the assets to fair value. The impairment charge was included in the statement of operations' line item impairment of natural gas and crude oil properties. Late in the fourth quarter, subsequent to the impairment charge, we reversed our decision to divest the assets and the assets were reclassified as held and used as of December 31, 2011. The subsequent decision not to divest the NECO assets did not result in any further write-downs of the related net assets. See Note 13.

In May 2010, pursuant to our entry into an agreement to sell our Michigan assets, we reclassified our Michigan assets as held for sale. We compared the transactional sales price, considered a Level 3 input, less costs to sell to the carrying value of our Michigan net assets. The net carrying value exceeded the net sales price and, therefore, during the second quarter of 2010, we recognized an impairment charge of $4.7 million to reduce the carrying value of the net assets to reflect the net sales price. The impairment charge was included in discontinued operations on the statement of operations. See Note 13.

Unproved Property Impairment. The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired or amortized. Unproved natural gas and crude oil properties with individually significant acquisition costs are periodically assessed for impairment. Unproved natural gas and crude oil properties which are not individually significant are amortized, by field, based on our historical experience, acquisition dates and average lease terms. Impairment and amortization charges related to unproved natural gas and crude oil properties are charged to the statement of operations' line item impairment of natural gas and crude oil properties.

Other Property and Equipment. The following table presents the estimated useful lives of our other property and equipment.



Pipelines and related facilities	10 - 17 years
Transportation and other equipment	3 - 20 years
Buildings	30 - 40 years

Other property and equipment are carried at cost. Depreciation is provided principally on the straight-line method over the assets estimated useful lives. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying

amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds our estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. No impairment was recognized in 2011. Impairments recognized in 2010 and 2009 were immaterial.

Maintenance and repairs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed from the accounts, the proceeds are applied thereto and any resulting gain or loss is reflected in income. Total depreciation expense related to other property and equipment was $6.7 million, $7.5 million and $8.1 million in 2011, 2010 and 2009, respectively.

Capitalized Interest. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved natural gas and crude oil properties and major development projects, on which DD&A is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready for service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our debt outstanding by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is moved to the DD&A pool, the related capitalized interest is also transferred and is amortized over the useful life of the asset. Capitalized interest totaled $1.7 million, $0.3 million and $0.8 million in 2011, 2010 and 2009, respectively.

Assets Held for Sale. Assets held for sale are valued at the lower of their carrying amount or estimated fair value less costs to sell. If the carrying amount of the assets exceed their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques such as a discounted cash flow model, valuations performed by third parties, earnings multiples or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair values that are ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. Depreciation, depletion, and amortization expense is not recorded on assets to be divested once they are classified as held for sale.

Assets to be divested are classified in the consolidated financial statements as held for sale, and the activities of assets to be divested are classified either as discontinued operations or continuing operations. For assets classified as discontinued operations, the balance sheet amounts and results of operations are reclassified from their historical presentation to assets and liabilities held for sale on the consolidated balance sheets and to discontinued operations on the consolidated statements of operations, respectively, for all periods presented. The gains or losses associated with these divested assets are recorded in discontinued operations on the consolidated statements of operations. Management does not expect any continuing involvement with businesses classified as discontinued operations following their divestiture. Businesses classified as held for sale are expected to be disposed of within one year. For businesses classified as held for sale that do not qualify for discontinued operations treatment, the balance sheet amounts are reclassified from their historical presentation to assets and liabilities held for sale for all periods presented. The results of operations continue to be reported in continuing operations.

Production Tax Liability. Production tax liability represents estimated taxes, primarily severance, ad valorem and property, to be paid to the states and counties in which we produce natural gas, NGLs and crude oil, including the production of our affiliated partnerships. Our share of these taxes is expensed to production costs. The partnerships' share, not owned by us, is recognized as a receivable in accounts receivable affiliates on the balance sheets. The long-term portion of the production tax liability is included in other liabilities on the balance sheets, and was $19.4 million and $16.4 million in December 31, 2011 and 2010, respectively.

Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and future credit carryforwards, and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance thereby reducing the deferred tax assets to what we consider realizable. As of December 31, 2011 and 2010, we had no valuation allowance.

Debt Issuance Costs. Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. As of December 31, 2011 and 2010, included in other assets was $12.3 million and $14.6 million, respectively, related to debt issuance costs. The December 31, 2011, amount included $2.4 million in costs related to the issuance of our 3.25% convertible senior notes due 2016, $3.4 million related to our 12% senior notes due 2018 and $6.5 million related to our bank credit facilities.

Asset Retirement Obligations. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the well is completely drilled. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value, through charges to production costs. The initial capitalized costs, net of salvage value, are depleted over the useful lives of the related assets, through charges to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from changes in retirement costs or the estimated timing of settling asset retirement obligations. See Note 9 for a reconciliation of the changes in our asset retirement obligation from January 1, 2010, to December 31, 2011.

Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in shareholders’ equity in the consolidated balance sheets. When we retire treasury shares, we charge any excess of cost over the par value entirely to additional paid-in-capital, to the extent we have amounts in additional paid-in-capital, with any remaining excess cost being charged to retained earnings.

Revenue Recognition. Significant accounting polices related to our revenue recognition are discussed below.

Natural gas, NGL and crude oil sales. Natural gas, NGL and crude oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. We currently use the "net-back" method of accounting for transportation and processing arrangements of our sales when the transportation and/or processing is provided by or through the purchaser. Under these arrangements, we sell gas at the wellhead and collect a price and recognize revenues based on the wellhead sales price since transportation and processing costs downstream of the wellhead are incurred by the purchasers and reflected in the wellhead price. The majority of our natural gas and NGLs in Colorado are sold on a long-term basis ranging from 15 years to the life of the lease. Sales of natural gas and NGLs in other regions, along with crude oil, are sold under contracts with terms ranging from one month to three years. Virtually all of our contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the natural gas and prevailing supply and demand conditions.

Well operations and pipeline income. We are paid a monthly operating fee for each well we operate and the natural gas transported for outside owners including the limited partnerships we sponsored. Well operations and pipeline income is recognized when persuasive evidence of an arrangement exists, services have been rendered, collection of revenues is reasonably assured and the sales price is fixed or determinable.

Natural gas marketing. Natural gas marketing is reported on the gross method of accounting, based on the nature of the agreements between Riley Natural Gas ("RNG"), our suppliers and our customers. RNG, our marketing subsidiary, purchases gas from many small producers and bundles the gas together to sell in larger amounts to purchasers of natural gas for a price advantage. RNG has latitude in establishing price and discretion in supplier and purchaser selection. Natural gas marketing revenues and expenses reflect the full cost and revenue of those transactions because RNG takes title to the gas it purchases from the various producers and bears the risks and rewards of that ownership. Both the realized and unrealized gains and losses of the RNG commodity-based derivative transactions for natural gas marketing are included in sales from or cost of natural gas marketing, as applicable.

Stock-Based Compensation. Stock-based compensation is recognized in our financial statements based on the fair value, on the date of grant or modification, of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the vesting period for the entire award. To the extent compensation cost relates to employees directly involved in natural gas and crude oil exploration and development activities, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the statement of operations. No amounts for stock-based compensation were capitalized in 2011, 2010 or 2009.

Earnings Per Share. Basic earnings (loss) per common share ("EPS") is computed by dividing net income (loss), the numerator, by the weighted-average number of common shares outstanding for the period, the denominator. Diluted EPS is similarly computed except that the denominator includes the effect, using the treasury stock method, of our unamortized portion of restricted stock, outstanding stock appreciation rights ("SARs"), stock options, convertible notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive.

The following table presents a reconciliation of the weighted average diluted shares outstanding.



	Year Ended December 31,
	2011	2010	2009
	(in thousands)

Weighted average common shares outstanding - basic	23,521	19,674	16,448
Dilutive effect of share-based compensation:
Restricted stock	307	119	—
SARs	40	21	—
Non employee director deferred compensation	3	7	—
Weighted average common and common share equivalents outstanding - diluted	23,871	19,821	16,448

For 2009, the weighted average common shares outstanding for both basic and diluted were the same, as the effect of dilutive securities were anti-dilutive due to our net loss. The following table presents the weighted average common share equivalents excluded from the calculation of diluted earnings (loss) per share due to their anti-dilutive effect.



	Year Ended December 31,
	2011	2010	2009
	(in thousands)

Weighted average common share equivalents excluded from diluted earnings
per share due to their anti-dilutive effect:
Restricted stock	220	204	284
SARs	22	—	—
Stock options	9	10	10
Non employee director deferred compensation	—	—	8
Total anti-dilutive common share equivalents	251	214	302

In November 2010, we issued 115,000 convertible senior notes, $1,000 principal amount, that give the holders the right to convert the principal amount into 2.7 million common shares at a conversion price of $42.40 per share. These convertible notes could have a dilutive impact on our earnings per share if the average market share price exceeds the conversion price. The table above does not include those shares issuable upon conversion as the average share price of our common stock did not exceed the conversion price during the period.

Recent Accounting Standards.

The following standard was recently adopted:

Fair Value Measurements and Disclosures. In January 2010, the FASB issued changes related to fair value measurements requiring gross presentation of activities within the Level 3 roll forward, whereby entities must present separately information about purchases, sales, issuances and settlements. These changes were effective for our financial statements issued for annual reporting periods beginning after December 15, 2010. The adoption of this change did not have a material impact on our financial statements.

The following standards were recently issued:

Fair Value Measurement. On May 12, 2011, the FASB issued changes related to fair value measurement. The changes represent the converged guidance of the FASB and the International Accounting Standards Board ("IASB") on fair value measurement. Many of the changes eliminate unnecessary wording differences between International Financial Reporting Standards ("IFRS") and U.S. GAAP. The changes expand existing disclosure requirements for fair value measurements categorized in Level 3 by requiring (1) a quantitative disclosure of the unobservable inputs and assumptions used in the measurement, (2) a description of the valuation processes in place and (3) a narrative description of the sensitivity of the fair value to changes in unobservable inputs and the interrelationships between those inputs. In addition, the changes require the categorization by level in the fair value hierarchy of items that are not measured at fair value in the statement of financial position whose fair value must be disclosed. These changes are to be applied prospectively and are effective for public entities during interim and annual periods beginning after December 15, 2011. Early application is not permitted. With the exception of the disclosure requirements, the adoption of these changes is not expected to have a significant impact on our financial statements.

Presentation of Comprehensive Income. On June 16, 2011, the FASB issued changes related to the presentation of comprehensive income. These changes eliminate the current option to report other comprehensive income and its components in the statement of changes in equity. These changes are intended to enhance comparability between entities that report under U.S. GAAP and those that report under IFRS, and to provide a more consistent method of presenting non-owner transactions that affect an entity's equity. An entity may elect to present items of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate, but consecutive, statements. Each component of net income and each component of other comprehensive income, together with totals for comprehensive income and its two parts, net income and other comprehensive income, would need to be displayed under either alternative. The statement(s) would need to be presented with equal prominence as the other primary financial statements. The new requirement is effective for public entities as of the beginning of a fiscal year that begins after December 15, 2011, and interim and annual periods thereafter. Early adoption is permitted, but full retrospective application is required under both sets of accounting standards. We do not expect the adoption of these changes to have a material impact on our financial statements.