Organization and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Organization and Summary of Significant Accounting Policies [Abstract]

Organization and Summary of Significant Accounting Policies

Note 1—Organization and Summary of Significant Accounting Policies

PetroQuest Energy, Inc. (a Delaware Corporation) (“PetroQuest” or the “Company”) is an independent oil and gas company headquartered in Lafayette, Louisiana with exploration offices in Houston, Texas and Tulsa, Oklahoma. It is engaged in the exploration, development, acquisition and operation of oil and gas properties in Oklahoma, Arkansas, Wyoming and Texas as well as onshore and in the shallow waters offshore the Gulf Coast Basin.

Principles of Consolidation

The Consolidated Financial Statements include the accounts of the Company and its subsidiaries, PetroQuest Energy, L.L.C., PetroQuest Oil & Gas, L.L.C, Pittrans, Inc. and TDC Energy LLC. All intercompany accounts and transactions have been eliminated.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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 those estimates.

Reserve Estimates and Oil and Gas Properties

On December 29, 2008, the SEC adopted revised rules related to modernizing accounting and disclosure requirements for oil and natural gas companies. The revised disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The revised rules also allow companies the option to disclose probable and possible reserves in addition to the existing requirement to disclose proved reserves. The revised disclosure requirements also require companies to report the independence and qualifications of third party preparers of reserves and file reports when a third party is relied upon to prepare reserves estimates. A significant change to the rules involves the pricing at which reserves are measured. The revised rules utilize a 12-month average price using beginning of the month pricing during the 12-month period prior to the ending date of the balance sheet to report oil and natural gas reserves rather than year-end prices. In addition, the 12-month average will also be used to measure ceiling test impairments and to compute depreciation, depletion and amortization. The revised rules were effective for reserve estimates beginning December 31, 2009.

The Company utilizes the full cost method of accounting, which involves capitalizing all acquisition, exploration and development costs incurred for the purpose of finding oil and gas reserves including the costs of drilling and equipping productive wells, dry hole costs, lease acquisition costs and delay rentals. The Company also capitalizes the portion of general and administrative costs, which can be directly identified with acquisition, exploration or development of oil and gas properties. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties, the properties are sold, or management determines these costs to have been impaired. Interest is capitalized on unevaluated property costs. Transactions involving sales of reserves in place, unless significant, are recorded as adjustments to accumulated depreciation, depletion and amortization.

Depreciation, depletion and amortization of oil and gas properties is computed using the unit-of-production method based on estimated proved reserves. All costs associated with evaluated oil and gas properties, including an estimate of future development costs associated therewith, are included in the depreciable base. The costs of investments in unevaluated properties are excluded from this calculation until the costs are evaluated and proved reserves established or impaired. Proved oil and gas reserves are estimated annually by independent petroleum engineers.

The capitalized costs of proved oil and gas properties cannot exceed the present value of the estimated net cash flow from proved reserves based on first of the month average twelve-month oil and gas prices, including the effect of hedges in place (the full cost ceiling). If the capitalized costs of proved oil and gas properties exceed the full cost ceiling, the Company is required to write-down the value of its oil and gas properties to the full cost ceiling amount. The Company follows the provisions of Staff Accounting Bulletin (“SAB”) No. 106, regarding the application of ASC Topic 410-20 by companies following the full cost accounting method. SAB No. 106 indicates that estimated future dismantlement and abandonment costs that are recorded on the balance sheet are to be included in the costs subject to the full cost ceiling limitation. The estimated future cash outflows associated with settling the recorded asset retirement obligations should be excluded from the computation of the present value of estimated future net revenues used in applying the ceiling test.

Cash and Cash Equivalents

The Company considers all highly liquid investments with a stated maturity of three months or less to be cash and cash equivalents. The majority of the Company’s cash and cash equivalents are in overnight securities made through its commercial bank accounts, which result in available funds the next business day.

Accounts Receivable and Other Accrued Liabilities

In its capacity as operator, the Company incurs drilling and operating costs that are billed to its partners based on their respective working interests. As of December 31, 2011 and 2010, the Company had $1.0 million and $0.6 million, respectively, recorded related to an allowance for doubtful accounts. Other accrued liabilities at December 31, 2011 and 2010 included $7.0 million and $6.3 million, respectively, related to accrued incentive compensation costs.

Gas Gathering Assets

During 2006, the Company acquired an interest in a gas gathering system used in the transportation of natural gas. The costs related to this system are depreciated on a straight line basis over the estimated remaining useful life, generally 14 years.

Other Assets

Other assets includes furniture and fixtures, which are depreciated over their useful lives ranging from 3-7 years, and deferred financing costs, which are amortized over the life of the related debt.

Drilling Pipe Inventory

Drilling pipe inventory, which is included in current assets, consists of tubular goods and pipe that the Company either utilizes in its ongoing exploration and development activities or has available for sale. The cost basis of drilling pipe inventory to be utilized is depreciated as a component of oil and gas properties once the inventory is used in drilling or other capitalized operations.

Income Taxes

The Company accounts for income taxes in accordance with ASC Topic 740. Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and gas properties for financial reporting purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures are capitalized and depreciated, depleted and amortized on the unit-of-production method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion. Generally, most other exploratory and development costs are charged to expense as incurred; however, the Company may use certain provisions of the Internal Revenue Code which allow capitalization of intangible drilling costs. Other financial and income tax reporting differences occur primarily as a result of statutory depletion.

Revenue Recognition

The Company records natural gas and oil revenue under the sales method of accounting. Under the sales method, the Company recognizes revenues based on the amount of natural gas or oil sold to purchasers, which may differ from the amounts to which the Company is entitled based on its interest in the properties. Gas balancing obligations as of December 31, 2011 and 2010 were not significant.

Certain Concentrations

The Company’s production is sold on month to month contracts at prevailing prices. The Company attempts to diversify its sales among multiple purchasers and obtain credit protection such as letters of credit and parental guarantees when necessary.

The following table identifies customers from whom the Company derived 10% or more of its net oil and gas revenues during the years presented. Based on the availability of other customers, the Company does not believe the loss of any of these customers would have a significant effect on its business or financial condition.

		September 30,			September 30,			September 30,
	Year Ended December 31,
	2011			2010			2009
Laclede Energy		20	%		17	%		12	%
Shell Trading Co.		18	%		19	%		17	%
Texon LP		15	%		17	%		17	%
Gary Williams		11	%		10	%		(a	)
Atmos Energy		(a	)		(a	)		13	%

(a) Less than 10 percent

Fair Value of Financial Instruments

The fair value of cash and cash equivalents, accounts receivable and accounts payable approximates book value at December 31, 2011 and 2010 due to the short-term nature of these accounts. Hedging instruments are reflected as an asset on the balance sheet at an estimated fair value of approximately $6.4 million at December 31, 2011 and as a liability at an estimated fair value of approximately $1.1 million at December 31, 2010, as required under ASC Topic 815. The estimated fair value of the 10% senior notes due 2017 (the “Notes”) at December 31, 2011 was $151.5 million, as compared to the book value of $150 million. At December 31, 2010, the fair value of the Notes was $154.5 million, as compared to the book value of $150 million. The estimated fair value of the Notes was provided by independent brokers using the actual year-end market quotes for the Notes.

Derivative Instruments

Under ASC Topic 815, the nature of a derivative instrument must be evaluated to determine if it qualifies for hedge accounting treatment. Instruments qualifying for cash flow hedge accounting treatment are recorded as an asset or liability measured at fair value and subsequent changes in fair value are recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is effective. All of the Company’s derivative instruments qualified for cash flow hedge accounting during the periods presented. As a result, the changes in fair value of these instruments were recorded to other comprehensive income (loss). The cash settlements of cash flow hedges are recorded as adjustments to oil and gas sales. Oil and gas revenues include additions related to the net settlement of hedges totaling $2,417,000, $17,538,000 and $79,892,000 during 2011, 2010 and 2009, respectively.

The Company’s hedges are specifically referenced to NYMEX prices. The effectiveness of hedges is evaluated at the time the contracts are entered into, as well as periodically over the life of the contracts, by analyzing the correlation between NYMEX prices and the posted prices received from the designated production. Through this analysis, the Company is able to determine if a high correlation exists between the prices received for its designated production and the NYMEX prices at which the hedges will be settled. At December 31, 2011, the Company’s hedging contracts were considered effective cash flow hedges. See Note 8 for further discussion of the Company’s derivative instruments.