Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation

The accompanying consolidated financial statements include the accounts of all of our subsidiaries. Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting and are carried at our share of net assets plus loans and advances. Income from equity method investments represents our proportionate share of income generated by equity method investees and is included in other revenues in the accompanying consolidated statements of operations. All material intercompany balances and transactions have been eliminated.

Discontinued Operations

During February 2011, we entered into an agreement to sell our Barnett Shale assets. Accordingly, in the first quarter 2011, we classified these assets and liabilities as discontinued operations in the accompanying consolidated balance sheets along with the historical results of the operations from such properties as discontinued operations, net of tax, in the accompanying statements of operations. See also Note 3 and Note 4 for more information regarding the sale of our Barnett Shale assets. Unless otherwise indicated, the information in these notes relate to our continuing operations.

Use of Estimates

The preparation of financial statements in accordance with generally accepted accounting principles in the United States requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at year-end, the reported amounts of revenues and expenses during the year and the reported amount of proved natural gas, natural gas liquids (“NGLs”) and oil reserves. We base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments that are not readily apparent from other sources. Actual results could differ from these estimates and changes in these estimates are recorded when known.

Reclassifications

Certain reclassifications have been made to prior years’ reported amounts in order to conform with the current year presentation. This includes the reclassification of transportation and gathering revenue into other revenue. These reclassifications did not impact our net income from continuing operations, stockholders’ equity or cash flows.

Revision for Transportation, Gathering and Compression Expenses

As a result of our production growth and commencement of various transportation and gathering agreements in 2010 and 2011, we have revised our presentation of third party transportation and gathering costs to properly report such costs as a component of operating expenses in the accompanying statement of operations in accordance with Financial Accounting Standards Board (“FASB”) Section 605-45-05 of Subtopic 605-45 for Revenue Recognition. Previously, these costs were reflected as a component of natural gas, NGLs and oil sales. For more information on the accounting for these agreements, see Revenue Recognition, Gas Imbalances and Receivables below. We have concluded that this revision is not material to our financial statements and the net effect of these revisions did not impact our net income, stockholders’ equity or cash flows; however, previously reported natural gas, NGL and oil sales have increased and total operating expenses have increased by the same amount. The following reflects the revisions made (in thousands):

	2010		2009
Natural gas, NGL and oil sales, previously reported	$	760,453	$	714,564
Revision of transportation, gathering and compression expenses		62,837		37,185
Natural gas, NGL and oil sales, reported	$	823,290	$	751,749

The corresponding amounts have been reflected in transportation, gathering and compression expenses for 2010 and 2009 as shown below (in thousands):

	2010		2009
Transportation, gathering and compression expenses, previously reported	$	—	$	—
Revision of transportation, gathering and compression expenses		62,837		37,185
Transportation, gathering and compression, reported	$	62,837	$	37,185

Income per Common Share

Basic income (loss) per common share is calculated based on the weighted average number of common shares outstanding. Diluted income (loss) per common share assumes issuance of stock compensation awards, provided the effect is not antidilutive.

Business Segment Information

We have evaluated how we are organized and managed and have identified only one operating segment, which is the exploration and production of natural gas, NGLs and oil. We consider our gathering, processing and marketing functions as ancillary to our natural gas and oil producing activities. Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and this information is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance.

We have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on an area-by-area basis. Throughout the year, we allocate capital resources on a project-by-project basis, across our entire asset base to maximize profitability without regard to individual areas or segments.

Revenue Recognition, Gas Imbalances and Receivables

Natural gas, NGL and oil sales are recognized when the products are sold and delivery to the purchaser has occurred. We generally sell natural gas, NGLs and oil under two types of agreements, which are common in our industry. Both types of agreements include transportation charges. As described in the revision section above, we are reporting our gathering and transportation costs in accordance with FASB Section 605-45-05 of Subtopic 605-45 for Revenue Recognition. One type of agreement is a netback arrangement, under which we sell natural gas and oil at the wellhead and collect a price, net of transportation incurred by the purchaser. In this case, we record revenue at the price we received from the purchaser. In the case of NGLs, we generally receive a net price from the purchaser (which is net of processing costs) which is also recorded in revenue at the net price we generally receive from the purchaser. Under the other arrangement, we sell natural gas or oil at a specific delivery point, pay transportation expenses to a third party and receive proceeds from the purchaser with no transportation deduction. In that case, we record revenue at the price received from the purchaser and record the expenses we incur as transportation, gathering and compression expense.

Although receivables are concentrated in the oil and gas industry, we do not view this as an unusual credit risk. We provide for an allowance for doubtful accounts for specific receivables judged unlikely to be collected based on the age of the receivable, our experience with the debtor, potential offsets to the amount owed and economic conditions. In certain instances, we require purchasers to post stand-by letters of credit. Many of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We have allowances for doubtful accounts relating to exploration and production receivables of $4.0 million at December 31, 2011 compared to $5.0 million at December 31, 2010. During the year ended 2011, we recorded bad debt expense of $946,000 compared to $3.6 million in 2010 and $1.4 million in 2009.

We use the sales method to account for gas imbalances, recognizing revenue based on gas delivered rather than our working interest share of the gas produced. A liability is recognized when the imbalance exceeds the estimate of remaining reserves. At December 31, 2011, we had recorded a net liability of $50,000 for those wells where it was determined that there were insufficient reserves to recover the imbalance situation.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with maturities of three months or less.

Marketable Securities

Investments in unaffiliated equity securities held in our deferred compensation plans qualify as trading securities and are recorded at fair value. Investments held in the deferred compensation plans consist of various publicly-traded mutual funds. These funds are made up of investments which include equity securities and money market instruments.

Inventories

Inventories consist primarily of tubular goods used in our operations and are stated at the lower of specific cost of each inventory item or market, on a first-in, first-out basis. Our inventory is primarily acquired for use in future drilling operations or repair operations. In 2011, we sold tubular goods and other inventory for proceeds of $8.0 million and recorded a gain of $359,000.

Natural Gas and Oil Properties

We follow the successful efforts method of accounting for natural gas and oil producing activities. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, delay rentals and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. The status of suspended well costs is monitored continuously and reviewed not less than quarterly. We capitalize successful exploratory wells and all developmental wells, whether successful or not. NGLs and oil are converted to gas equivalent basis or mcfe at the rate of one barrel of oil equating to 6 mcf of natural gas which is based upon the approximated relative energy content of oil to natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices. Depreciation, depletion and amortization of proved producing properties is provided on the units of production method. Historically, we have adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report and other times during the year when circumstances indicate there has been a significant change in reserves or costs. We adopted the new SEC accounting and disclosure regulations for oil and gas companies effective December 31, 2009. Accounting Standards Codification (ASC) 2010-3 clarified that the effect of the change in price encompassed in the new SEC rules was a change in accounting principle inseparable from a change in estimate for 2009 and was accounted for prospectively. For 2009, we estimated the effect of this change in estimate increased depletion, depreciation and amortization expense by approximately $3.4 million ($2.2 million after tax) primarily due to lower prices reflected in our estimated reserves.

Our natural gas and oil producing properties are reviewed for impairment periodically as events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. These assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. The review is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization is less than the estimated expected undiscounted future net cash flows. The expected future net cash flows are estimated based on our plans to produce and develop reserves. Expected future net cash inflow from the sale of produced reserves is calculated based on estimated future prices and estimated operating and development costs. We estimate prices based upon market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. In certain circumstances, we also consider potential sales of properties to third parties in our estimates of cash flows. When the carrying value exceeds the sum of future net cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future net cash flows using a discount rate similar to that used by market participants) and the carrying value of the asset. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future natural gas and oil prices, an estimate of the ultimate amount of recoverable natural gas and oil reserves that will be produced from an asset group, the timing of future production, future production costs, future abandonment costs and future inflation. We cannot predict whether impairment charges may be required in the future. If natural gas, NGLs and oil prices decrease or drilling efforts are unsuccessful, we may be required to record additional impairments. For additional information regarding proved property impairments, see Note 12.

Proceeds from the disposal of natural gas and oil producing properties that are part of an amortization group are credited to the net book value of the amortization group with no immediate effect on income. However, gain or loss is recognized if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base.

We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leasehold costs. The costs are capitalized and evaluated (at least quarterly) as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. Impairment of individually significant unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors. Unproved properties had a net book value of $748.6 million in 2011 compared to $648.1 million in 2010. Assets of discontinued operations include unproved properties of $163.7 million at December 31, 2010. We have recorded abandonment and impairment expense related to unproved properties from continuing operations of $79.7 million in 2011 compared to $49.7 million in 2010 and to $36.9 million in 2009.

Transportation and Field Assets

Our gas transportation and gathering systems are generally located in proximity to certain of our principal fields. Depreciation on these pipeline systems is provided on the straight-line method based on estimated useful lives of 10 to 15 years. We receive third-party income for providing field service and certain transportation services, which is recognized as earned. Depreciation on the associated assets is calculated on the straight-line method based on estimated useful lives ranging from five to seven years. Transportation and field assets also includes other property and equipment such as buildings, furniture and fixtures, leasehold improvements, data processing and communication equipment. These items are generally depreciated by individual components on a straight line basis over their economic useful life, which is generally from 3 to 15 years. Leasehold improvements are amortized over the lesser of their economic useful lives or the underlying terms of the associated leases. Depreciation expense was $16.2 million in 2011 compared to $16.1 million in 2010 and $31.6 million in 2009. The fourth quarter 2009 includes accelerated depreciation expense of $10.3 million related to an interim processing plant in our Appalachian region that was dismantled in first quarter 2010 and replaced with permanent facilities.

Other Assets

The expenses of issuing debt are capitalized and included in other assets in the accompanying consolidated balance sheets. These costs are amortized over the expected life of the related instruments. When a security is retired before maturity or modifications significantly change the cash flows, related unamortized costs are expensed. Other assets at December 31, 2011 include $39.4 million of unamortized debt issuance costs, $50.2 million of marketable securities held in our deferred compensation plans and $14.4 million of other investments including land.

Accounts Payable

Included in accounts payable at December 31, 2011 and 2010, are liabilities of approximately $45.7 million and $97.2 million representing the amount by which checks issued, but not presented to our banks for collection, exceeded balances in our applicable bank accounts.

Stock-based Compensation Arrangements

The fair value of stock options and stock-settled SARs is estimated on the date of grant using the Black-Scholes-Merton option-pricing model. The model employs various assumptions, based on management’s best estimates at the time of the grant, which impact the fair value calculated and ultimately, the expense that is recognized over the life of the award. We have utilized historical data and analyzed current information to reasonably support these assumptions. The fair value of restricted stock awards (“Liability Awards”) and restricted stock unit awards (“Equity Awards”) is determined based on the fair market value of our common stock on the date of grant.

We recognize stock-based compensation expense on a straight-line basis over the requisite service period for the entire award. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. Substantially all Liability Awards are deposited in our deferred compensation plans at the time of grant and are classified as a liability due to the fact that these awards are expected to be settled wholly or partially in cash. The fair value of the Liability Awards is updated at each balance sheet date with changes in the fair value of the vested portion of the awards recorded as increases or decreases to deferred compensation plan expense in the accompanying statement of operations.

Derivative Financial Instruments and Hedging

All of our derivative instruments are issued to manage the price risk attributable to our expected natural gas, NGLs and oil production. While there is risk that the financial benefit of rising natural gas, NGLs and oil prices may not be captured, we believe the benefits of stable and predictable cash flow are more important. Among these benefits are more efficient utilization of existing personnel and planning for future staff additions, the flexibility to enter into long-term projects requiring substantial committed capital, smoother and more efficient execution of our ongoing development drilling and production enhancement programs, more consistent returns on invested capital and better access to bank and other capital markets. Every unsettled derivative instrument is recorded on the accompanying consolidated balance sheets as either an asset or a liability measured at its fair value. Changes in a derivative’s fair value are recognized in earnings unless specific hedge accounting criteria are met. Cash flows from derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows.

Through December 2011, we have elected to designate our commodity derivative instruments that qualify for hedge accounting as cash flow hedges. To designate a derivative as a cash flow hedge, we document at the hedge’s inception our assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the item hedged. The ineffective portion of the hedge is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. If, during the derivative’s term, we determine the hedge is no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings as natural gas, NGLs and oil sales when the underlying transaction occurs. If it is determined that the designated hedged transaction is probable to not occur, any unrealized gains or losses is recognized immediately in derivative fair value income in the accompanying consolidated statements of operations. During 2010, we recognized a pre-tax gain of $11.6 million compared to a pre-tax gain of $5.4 million in 2009 as a result of the discontinuance of hedge accounting treatment for certain of our derivatives. In 2011, we did not discontinue hedge accounting on any of our hedges.

We apply hedge accounting to qualifying derivatives (or “hedge derivatives”) used to manage price risk associated with our natural gas, NGLs and oil production. Accordingly, we record changes in the fair value of our hedge derivative contracts, including changes associated with time value, in accumulated other comprehensive income (“AOCI”) in the stockholders’ equity section of the accompanying consolidated balance sheets. Gains or losses on these hedge derivative contracts are reclassified out of AOCI and into natural gas, NGLs and oil sales when the underlying physical transaction occurs and the hedging contract is settled. Any hedge ineffectiveness associated with a contract qualifying and designated as a cash flow hedge (which represents the amount by which the change in the fair value of the derivative differs from the change in the cash flows of the forecasted sale of production) is reported currently each period in derivative fair value income on the accompanying consolidated statement of operations. Ineffectiveness can be associated with open positions (unrealized) or can be associated with closed contracts (realized).

Realized and unrealized gains and losses on derivatives that are not designated as hedges (or “non-hedge derivatives”) are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in each period in derivative fair value income in the accompanying consolidated statements of operations. At times, we have also entered into basis swap agreements which do not qualify for hedge accounting and are marked to market. The price we receive for our gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we may enter into basis swap agreement that effectively fix our basis adjustments.

Asset Retirement Obligations

The fair value of asset retirement obligations is recognized in the period they are incurred, if a reasonable estimate of fair value can be made. Asset retirement obligations primarily relate to the abandonment of natural gas and oil producing facilities and include costs to dismantle and relocate or dispose of production platforms, gathering systems, wells and related structures. Estimates are based on historical experience of plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. The depreciation will generally be determined on a units-of-production basis while accretion to be recognized will escalate over the life of the producing assets.

Deferred Taxes

Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. Deferred tax assets are recorded when it is more likely than not that they will be realized. The realization of deferred tax assets is assessed periodically based on several interrelated factors. These factors include our expectation to generate sufficient taxable income including tax credits and operating loss carryforwards. We do not recognize a deferred tax asset for excess tax benefits that have not been realized.

Accumulated Other Comprehensive Income

The following details the components of AOCI and related tax effects for the three years ended December 31, 2011. Amounts included in AOCI relate to our derivative activity (in thousands).

	Gross			Tax Effect			Net of Tax
Accumulated other comprehensive income at December 31, 2008	$	122,252		$	(44,745	)	$	77,507
Contract settlements reclassified to income		(203,119	)		75,154			(127,965	)
Change in unrealized deferred hedging gains		91,059			(34,180	)		56,879
Accumulated other comprehensive income at December 31, 2009		10,192			(3,771	)		6,421
Contract settlements reclassified to income		(64,772	)		24,841			(39,931	)
Change in unrealized deferred hedging gains		165,642			(64,662	)		100,980
Accumulated other comprehensive income at December 31, 2010		111,062			(43,592	)		67,470
Contract settlements reclassified to income		(132,201	)		50,005			(82,196	)
Change in unrealized deferred hedging gains		275,817			(104,464	)		171,353
Accumulated other comprehensive income at December 31, 2011	$	254,678		$	(98,051	)	$	156,627

Accounting Pronouncements Implemented

Recently Adopted

In June 2011, the FASB issued Accounting Standards Update (“ASU”) No. 201-05, “Presentation of Comprehensive Income,” which was issued to enhance comparability between entities that report under U.S. GAAP and International Financial Reporting Standards (“IFRS”), and to provide a more consistent method of presenting non-owner transactions that affect an entity’s equity. ASU 2011-05 eliminates the option to report other comprehensive income and its components in the statement of changes in stockholders’ equity and requires an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. This pronouncement is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Early adoption of the new guidance is permitted and full retrospective application is required. We adopted this new requirement in third quarter 2011 and since ASU 2011-05 only amended presentation requirements, it did not have a material effect on our consolidated financial statements.

Accounting Pronouncements Not Yet Adopted

In May 2011, the FASB issued ASU No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS.” This pronouncement was issued to provide a consistent definition of fair value and ensure that the fair value measurement and disclosure requirements are similar between U.S. GAAP and IFRS. ASU 2011-04 changes certain fair value measurement principles and enhances the disclosure requirements, particularly for Level 3 fair value measurements. This pronouncement is effective for reporting periods beginning on or after December 15, 2011, with early adoption prohibited. The new guidance will require prospective application. The adoption of ASU 2011-04 is not expected to have a material effect on our consolidated financial statements, but may require additional disclosures.