PrimeEnergy Resources (PNRG) 10-K 26 Mar 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Mar. 24, 2014	Jun. 30, 2013
Document And Entity Information [Abstract]	'	'	'
Document Type	'10-K	'	'
Amendment Flag	'false	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Trading Symbol	'PNRG	'	'
Entity Registrant Name	'PRIMEENERGY CORPORATION	'	'
Entity Central Index Key	'0000056868	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Filer Category	'Smaller Reporting Company	'	'
Entity Common Stock, Shares Outstanding	'	2,369,552	'
Entity Public Float	'	'	$52,677,788

Consolidated_Balance_Sheet

Consolidated Balance Sheet (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current Assets	'	'
Cash and cash equivalents	$9,526	$8,602
Restricted cash and cash equivalents	2,065	4,672
Accounts receivable, net	17,693	13,212
Prepaid obligations	1,188	1,656
Derivative contracts	357	1,229
Other current assets	1,846	1,081
Total Current Assets	32,675	30,452
Property and Equipment	'	'
Oil and gas properties at cost	364,123	338,204
Less: Accumulated depletion and depreciation	-169,100	-150,276
Oil and gas properties, Net	195,023	187,928
Field and office equipment at cost	26,653	23,974
Less: Accumulated depreciation	-13,251	-15,052
Field and office equipment, Net	13,402	8,922
Total Property and Equipment, Net	208,425	196,850
Derivative Contracts Long-Term	1,066	118
Other Assets	756	666
Total Assets	242,922	228,086
Current Liabilities	'	'
Accounts payable	16,249	19,568
Accrued liabilities	6,832	7,618
Current portion of long-term debt	1,870	'
Current portion of asset retirement and other long-term obligations	3,310	2,148
Derivative liability short-term	2,194	994
Due to related parties	23	67
Total Current Liabilities	30,478	30,395
Long-Term Bank Debt	120,023	122,000
Asset Retirement Obligations	7,227	6,864
Derivative Liability Long-Term	94	431
Deferred Income Taxes	31,962	24,194
Total Liabilities	189,784	183,884
Commitments and Contingencies	'	'
Equity	'	'
Common stock, $.10 par value; 2013 and 2012: Authorized: 4,000,000 shares, issued: 3,836,397 shares; outstanding 2013: 2,388,784 shares; 2012: 2,510,560 shares	383	383
Paid-in capital	6,803	6,690
Retained earnings	78,616	66,345
Accumulated other comprehensive loss, net	-123	-35
Treasury stock, at cost; 2013: 1,447,613 shares; 2012: 1,325,837 shares	-40,251	-36,113
Total Stockholders' Equity-PrimeEnergy	45,428	37,270
Non-controlling interest	7,710	6,932
Total Equity	53,138	44,202
Total Liabilities and Equity	$242,922	$228,086

Consolidated_Balance_Sheet_Par

Consolidated Balance Sheet (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Statement Of Financial Position [Abstract]	'	'
Common stock, par value	$0.10	$0.10
Common stock, shares authorized	4,000,000	4,000,000
Common stock, shares issued	3,836,397	3,836,397
Common stock, shares outstanding	2,388,784	2,510,560
Treasury stock, shares	1,447,613	1,325,837

Consolidated_Statement_of_Oper

Consolidated Statement of Operations (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Revenues	'	'
Oil and gas sales	$92,785	$87,834
Realized gain (loss) on derivative instruments, net	-1,322	502
Field service income	24,934	20,421
Administrative overhead fees	9,255	8,585
Unrealized gain (loss) on derivative instruments	-649	3,483
Other income	64	154
Total Revenues	125,067	120,979
Costs and Expenses	'	'
Lease operating expense	43,809	39,868
Field service expense	21,027	17,576
Depreciation, depletion, amortization and accretion on discounted liabilities	21,861	23,269
Loss on settlement of asset retirement obligations	40	'
General and administrative expense	16,659	15,870
Exploration costs	8	10
Total Costs and Expenses	103,404	96,593
Gain on Sale and Exchange of Assets	2,816	730
Income from Operations	24,479	25,116
Other Income and Expenses	'	'
Less: Interest expense	4,223	3,577
Add: Interest income	2	91
Income Before Provision for Income Taxes	20,258	21,630
Provision for Income Taxes	6,818	6,856
Net Income	13,440	14,774
Less: Net Income (Loss) Attributable to Non-Controlling Interest	1,169	-282
Net Income Attributable to PrimeEnergy	$12,271	$15,056
Basic Income Per Common Share	$5.04	$5.74
Diluted Income Per Common Share	$3.86	$4.48

Consolidated_Statement_of_Comp

Consolidated Statement of Comprehensive Income (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Statement Of Income And Comprehensive Income [Abstract]	'	'
Net income	$13,440	$14,774
Other Comprehensive Loss, net of taxes:	'	'
Changes in fair value of hedge positions, net of taxes of $50 and $19, respectively	-88	-35
Total other comprehensive loss	-88	-35
Comprehensive income	13,352	14,739
Less: Comprehensive income (loss) attributable to non-controlling interest	1,169	-282
Comprehensive income attributable to PrimeEnergy	$12,183	$15,021

Consolidated_Statement_of_Comp1

Consolidated Statement of Comprehensive Income (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Statement Of Income And Comprehensive Income [Abstract]	'	'
Changes in fair value of hedge positions, tax	$50	$19

Consolidated_Statement_of_Equi

Consolidated Statement of Equity (USD $)	Total	Common Stock [Member]	Additional Paid-In Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Treasury Stock [Member]	Total Stockholders' Equity - PrimeEnergy [Member]	Non-Controlling Interest [Member]
In Thousands, except Share data
Balance at Dec. 31, 2011	$35,753	$383	$6,446	$51,289	'	($31,120)	$26,998	$8,755
Balance, shares at Dec. 31, 2011	'	3,836,397	'	'	'	'	'	'
Common stock shares purchase	-4,993	'	'	'	'	-4,993	-4,993	'
Net income	14,774	'	'	15,056	'	'	15,056	-282
Other comprehensive loss, net of taxes	-35	'	'	'	-35	'	-35	'
Purchase of non-controlling interest	-149	'	244	'	'	'	244	-393
Distributions to non-controlling interest	-1,148	'	'	'	'	'	'	-1,148
Balance at Dec. 31, 2012	44,202	383	6,690	66,345	-35	-36,113	37,270	6,932
Balance, shares at Dec. 31, 2012	3,836,397	3,836,397	'	'	'	'	'	'
Common stock shares purchase	-4,138	'	'	'	'	-4,138	-4,138	'
Net income	13,440	'	'	12,271	'	'	12,271	1,169
Other comprehensive loss, net of taxes	-88	'	'	'	-88	'	-88	'
Purchase of non-controlling interest	-48	'	113	'	'	'	113	-161
Distributions to non-controlling interest	-230	'	'	'	'	'	'	-230
Balance at Dec. 31, 2013	$53,138	$383	$6,803	$78,616	($123)	($40,251)	$45,428	$7,710
Balance, shares at Dec. 31, 2013	3,836,397	3,836,397	'	'	'	'	'	'

Consolidated_Statement_of_Equi1

Consolidated Statement of Equity (Parenthetical)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Purchase of common stock, shares	121,776	191,309
Treasury Stock [Member]	'	'
Purchase of common stock, shares	121,776	191,309
Total Stockholders' Equity - PrimeEnergy [Member]	'	'
Purchase of common stock, shares	121,776	191,309

Consolidated_Statement_of_Cash

Consolidated Statement of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Cash Flows from Operating Activities:	'	'
Net income	$13,440	$14,774
Adjustments to reconcile net income to net cash provided by operating activities:	'	'
Depreciation, depletion, amortization and accretion on discounted liabilities	21,861	23,269
Gain on sale of properties	-2,816	-730
Unrealized (gain) loss on derivative instruments	649	-3,483
Provision for deferred income taxes	7,014	6,970
Loss on settlement of asset retirement obligations	40	'
Changes in assets and liabilities:	'	'
(Increase) decrease in accounts receivable	-4,481	3,294
Increase in due from related parties	-96	-25
(Increase) decrease in inventories	91	-2
Decrease in prepaid expenses and other assets	378	5,761
Decrease in accounts payable	-712	-9,500
Increase (decrease) in accrued liabilities	332	-616
Net Cash Provided by Operating Activities	35,700	39,712
Cash Flows from Investing Activities:	'	'
Capital expenditures, including exploration expense	-33,934	-86,305
Proceeds from sale of properties and equipment	3,681	881
Net Cash Used in Investing Activities	-30,253	-85,424
Cash Flows from Financing Activities:	'	'
Purchase of stock for treasury	-4,138	-4,993
Purchase of non-controlling interests	-48	-149
Increase in long-term bank debt and other long-term obligations	68,750	111,800
Repayment of long-term bank debt and other long-term obligations	-68,857	-59,857
Distribution to non-controlling interest	-230	-1,148
Net Cash (Used in) Provided by Financing Activities	-4,523	45,653
Net Increase (Decrease) in Cash and Cash Equivalents	924	-59
Cash and Cash Equivalents at the Beginning of the Year	8,602	8,661
Cash and Cash Equivalents at the End of the Year	9,526	8,602
Supplemental Disclosures:	'	'
Income taxes paid during the year	754	536
Interest paid during the year	$4,183	$3,535

Description_of_Operations_and_

Description of Operations and Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Description of Operations and Significant Accounting Policies	'
	1. Description of Operations and Significant Accounting Policies
	Nature of Operations:
	PrimeEnergy Corporation (“PEC”), a Delaware corporation, was organized in March 1973 and is engaged in the development, acquisition and production of oil and natural gas properties. PrimeEnergy Corporation and its subsidiaries are herein referred to as the “Company.” The Company owns leasehold, mineral and royalty interests in producing and non-producing oil and gas properties across the United States, including Colorado, Kansas, Louisiana, Mississippi, Montana, New Mexico, North Dakota, Oklahoma, Texas, West Virginia and Wyoming and the Gulf of Mexico. The Company operates approximately 1,600 wells and owns non-operating interests in over 800 additional wells. Additionally, the Company provides well-servicing support operations, site-preparation and construction services for oil and gas drilling and reworking operations, both in connection with the Company’s activities and providing contract services for third parties. The Company is publicly traded on the NASDAQ under the symbol “PNRG.” PEC owns Eastern Oil Well Service Company (“EOWSC”), EOWS Midland Company (“EMID”) and Southwest Oilfield Construction Company (“SOCC”), all of which perform oil and gas field servicing. PEC also owns Prime Operating Company (“POC”), which serves as operator for most of the producing oil and gas properties owned by the Company and affiliated entities. PEC also owns Prime Offshore L.L.C. (“Prime Offshore”), formerly F-W Oil Exploration LLC, which has owned and operated properties in the Gulf of Mexico. PrimeEnergy Management Corporation (“PEMC”), a wholly-owned subsidiary, acts as the managing general partner, providing administration, accounting and tax preparation services for 18 limited partnerships and 2 trusts (collectively, the “Partnerships”). The markets for the Company’s products are highly competitive, as oil and gas are commodity products and prices depend upon numerous factors beyond the control of the Company, such as economic, political and regulatory developments and competition from alternative energy sources.
	Consolidation and Presentation:
	The consolidated financial statements include the accounts of PrimeEnergy Corporation, its subsidiaries and the Partnerships, using the full consolidation method for those partnerships which are controlled by the Company. The proportionate consolidation method is used to account for those undivided interests in oil and gas properties owned by the Company as well as interests held in unincorporated legal entities, such as partnerships, engaged in oil and gas production, which are not controlled by the Company. For those entities which are proportionately consolidated, the proportionate share of each entity’s assets, liabilities, revenue and expenses is included in the appropriate classifications in the consolidated financial statements. Reserve estimates associated with the proportionately consolidated oil and gas interests are calculated for each property at the Partnership level, and depletion, depreciation and amortization (“DD&A”) rates are determined at the Partnership level. The Company’s reserve estimates are based on the ownership percentage of Partnership reserve reports. DD&A expense and evaluation of impairment may differ from the Partnership as the Company’s cost basis for the Partnership interests acquired may be different than the cost basis at the Partnership level for properties acquired by the Partnership. All significant intercompany balances and transactions are eliminated in preparing the consolidated financial statements.
	Reclassifications:
	Certain reclassifications have been made to prior year statements to conform with the current year presentation. These reclassifications have no impact on net income and no material impact on any other financial statement captions.
	Subsequent Events:
	Subsequent events have been evaluated through the date that the consolidated financial statements were issued. During this period, there were no material subsequent items requiring disclosure.
	Use of Estimates:
	The preparation of financial statements in conformity with U.S. generally accepted accounting principles 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.
	Estimates of oil and gas reserves, as determined by independent petroleum engineers, are continually subject to revision based on price, production history and other factors. Depletion expense, which is computed based on the units of production method, could be significantly impacted by changes in such estimates. Additionally, U.S. generally accepted accounting principles require that if the expected future undiscounted cash flows from an asset is less than its carrying cost, that asset must be written down to its fair market value. As the fair market value of an oil and gas property will usually be significantly less than the total undiscounted future net revenues expected from that asset, slight changes in the estimates used to determine future net revenues from an asset could lead to the necessity of recording a significant impairment of that asset.
	Property and Equipment:
	The Company follows the “successful efforts” method of accounting for its oil and gas properties. Under the successful efforts method, costs of acquiring undeveloped oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations. Annual lease rentals and exploration expenses, including geological and geophysical expenses and exploratory dry hole costs, are charged against income as incurred. Costs of drilling and equipping productive wells, including development dry holes and related production facilities, are capitalized. All other property and equipment are carried at cost. Depreciation and depletion of oil and gas production equipment and properties are determined under the unit-of-production method based on estimated proved developed recoverable oil and gas reserves. Depreciation of all other equipment is determined under the straight-line method using various rates based on useful lives generally ranging from 5 to 10 years. The cost of assets and related accumulated depreciation is removed from the accounts when such assets are disposed of, and any related gains or losses are reflected in current earnings.
	Capitalization of Interest:
	Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until the projects are substantially complete and ready for their intended use if the projects are evaluated and successful.
	Impairment of Long-Lived Assets:
	The Company reviews long-lived assets, including oil and gas properties, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts are not expected to be recovered by undiscounted cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows.
	Fair Value:
	The Company follows the authoritative guidance that establishes a formal framework for measuring fair values of assets and liabilities in financial statements that are already required by U.S. generally accepted accounting principles to be measured at fair value. The guidance defines fair value 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 (exit price). The transaction is based on a hypothetical transaction in the principal or most advantageous market considered from the perspective of the market participant that holds the asset or owes the liability.
	The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company attempts to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company is able to classify fair value balances based on the observability of those inputs. The guidance establishes a formal fair value hierarchy based on the inputs used to measure fair value. The hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.
	Asset Retirement Obligation:
	The Company follows the accounting standard for asset retirement obligation. The asset retirement obligation primarily represents the estimated present value of the amount the Company will incur to plug, abandon and remediate producing properties (including removal of offshore platforms) at the end of their productive lives, in accordance with applicable state laws. The Company determined its asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The asset retirement obligation is recorded as a liability at its estimated present value at its inception, with an offsetting increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the statement of operations.
	Income Taxes:
	The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the 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 the tax rate in effect for the year in which those temporary differences are expected to turn around. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
	The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties.
	General and Administrative Expenses:
	General and administrative expenses represent cost and expenses associated with the operation of the Company.
	Earnings Per Common Share:
	Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods.
	Statements of Cash Flows:
	For purposes of the consolidated statements of cash flows, the Company considers short-term, highly liquid investments with original maturities of less than ninety days to be cash equivalents.
	Concentration of Credit Risk:
	The Company maintains significant banking relationships with financial institutions in the State of Texas. The Company limits its risk by periodically evaluating the relative credit standing of these financial institutions. The Company’s oil and gas production purchasers consist primarily of independent marketers and major gas pipeline companies.
	Hedging:
	The Company periodically enters into oil and gas financial instruments to manage its exposure to oil and gas price volatility. The oil and gas reference prices upon which the price hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company.
	The financial instruments are accounted for in accordance with applicable accounting standards for derivative instruments and hedging activities. Such standards require that applicable derivative instruments be measured at fair market value and recognized as assets or liabilities in the balance sheet. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation is generally established at the inception of a derivative. For derivatives designated as cash flow hedges and meeting applicable effectiveness guidelines, changes in fair value, to the extent effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. At December 31, 2013 and 2012, the entire other comprehensive income amount comprised of the impact of cash flow hedges. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value of a derivative resulting from ineffectiveness or an excluded component of the gain/loss is recognized immediately in the statement of operations.
	Recently Adopted Accounting Standards:
	In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-11, “Disclosures about Offsetting Assets and Liabilities.” This ASU requires enhanced disclosures including both gross and net information about financial and derivative instruments eligible for offset or subject to an enforceable master netting arrangement or similar agreement. This new guidance is effective for annual reporting periods beginning on or after January 1, 2013 and subsequent interim periods. In January 2013, the FASB issued ASU 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” ASU 2013-01 clarifies the scope of ASU 2011-11 to apply to derivative instruments that are offset or subject to an enforceable master netting arrangement or similar agreement. This clarified guidance is effective for annual reporting periods beginning on or after January 1, 2013 and subsequent interim periods. The revised requirements of ASU 2011-11 and ASU 2013-01 impacted the disclosures associated with the Company’s derivative instruments (Note 11) and did not have a material impact on the Company’s consolidated financial statements for the year ended December 31, 2013.
	In February 2013, the FASB issued ASU 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income” (“AOCI”). ASU 2013-02 requires a rollforward of changes in AOCI by component and information about significant reclassifications from AOCI to net earnings to be presented in one location, either on the face of the financial statements or in the notes. This new guidance is effective for fiscal years beginning after December 15, 2012 and subsequent interim periods. There was no amounts reclassified out of accumulated other comprehensive income for the year ended December 31, 2013. The requirements of ASU 2013-02 did not have a material impact on the Company’s consolidated financial statements for the year ended December 31, 2013.
	In July 2013, the FASB issued ASU 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a similar Tax Loss, or a Tax Credit Carryforward Exists.” ASU 2013-11 provided guidance on the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. This guidance requires entities to present unrecognized tax benefits as a decrease in a net operating loss, similar tax loss, or tax credit carryforward if certain criteria are met. The guidance will eliminate the diversity in practice in the presentation of unrecognized tax benefits but will not alter the way in which entities assess deferred tax assets for realizability. ASU No. 2013-11 is effective for annual and interim reporting periods beginning after December 15, 2013. The Company will apply all changes prospectively and does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

Acquisitions_and_Dispositions

Acquisitions and Dispositions	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Acquisitions and Dispositions	'
	2. Acquisitions and Dispositions
	Historically, the Company has repurchased the noncontrolling interests of the partners and trust unit holders in certain of the Partnerships, which consist primarily of oil and gas interests. The Company purchased such noncontrolling interests in an amount totaling $48,000 in 2013 and $149,000 in 2012.

Additional_Balance_Sheet_Infor

Additional Balance Sheet Information	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Additional Balance Sheet Information	'
	3. Additional Balance Sheet Information
	Accounts receivable at December 31, 2013 and 2012 consisted of the following:
		December 31,
	(Thousands of dollars)	2013			2012
	Joint interest billings	$	6,287		$	2,189
	Trade receivables		2,014			1,580
	Oil and gas sales		9,604			9,362
	Other		122			436
			18,027			13,567
	Less: Allowance for doubtful accounts		(334	)		(355	)
	Total	$	17,693		$	13,212
	Accounts payable at December 31, 2013 and 2012 consisted of the following:
		December 31,
	(Thousands of dollars)	2013			2012
	Trade	$	1,596		$	3,968
	Royalty and other owners		7,391			9,652
	Partner advances		3,378			3,589
	Prepaid drilling deposits		978			306
	Other		2,906			2,053
	Total	$	16,249		$	19,568
	Accrued liabilities at December 31, 2013 and 2012 consisted of the following:
		December 31,
	(Thousands of dollars)	2013			2012
	Compensation and related expenses	$	3,062		$	2,517
	Property costs		3,119			4,549
	Income tax		268			—
	Other		383			552
	Total	$	6,832		$	7,618

Property_and_Equipment

Property and Equipment	12 Months Ended
	Dec. 31, 2013
Property Plant And Equipment [Abstract]	'
Property and Equipment	'
	4. Property and Equipment
	Capitalized interest is included as part of the cost of oil and gas properties. The capitalized rates are based upon the Company’s weighted-average cost of borrowings used to finance the expenditures. There was no interest capitalized during 2013 or 2012.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Long-Term Debt	'
	5. Long-Term Debt
	Bank Debt:
	Effective July 30, 2010, the Company entered into a Second Amended and Restated Credit Agreement between Compass Bank as agent and a syndicated group of lenders (“Credit Agreement”). The Credit Agreement has a revolving line of credit and letter of credit facility of up to $250 million with a final maturity date of July 30, 2017. The credit facility is secured by substantially all of the Company’s oil and gas properties. The credit facility is subject to a borrowing base determined by the lenders taking into consideration the estimated value of PEC’s oil and gas properties in accordance with the lenders’ customary practices for oil and gas loans. This process involves reviewing PEC’s estimated proved reserves and their valuation. The borrowing base is redetermined semi-annually, and the available borrowing amount could be increased or decreased as a result of such redetermination. In addition, PEC and the lenders each have at their discretion the right to request the borrowing base be redetermined with a maximum of one such request each year. A revision to PEC’s reserves may prompt such a request on the part of the lenders, which could possibly result in a reduction in the borrowing base and availability under the credit facility. At any time if the sum of the outstanding borrowings and letter of credit exposures exceed the applicable portion of the borrowing base, PEC would be required to repay the excess amount within a prescribed period.
	The Credit Agreement has been amended from time to time to further define the limitations on loans or advances and investments made in the Company’s limited partnerships; modify the Company’s borrowing base and monthly reduction amounts; remove the floor rate component of LIBO rate loans; modify financial reporting requirements to the agent; increase hedging allowances; allow for a one-time advance to be made to the Company’s offshore subsidiary; and amend restrictions on the payments for dividends, distributions or repurchase of PEC’s stock.
	The Credit Agreement includes terms and covenants that require the Company to maintain a minimum current ratio, total indebtedness to EBITDAX (earnings before depreciation, depletion, amortization, taxes, interest expense and exploration costs) ratio and interest coverage ratio, as defined, and restrictions are placed on the payment of dividends, the amount of treasury stock the Company may purchase, commodity hedge agreements, and loans and investments in its consolidated subsidiaries and limited partnerships.
	Under the Credit Agreement, the maximum percentage of production available to enter into commodity hedge agreements is 90% of proved developed producing reserves for each of the next succeeding four calendar years for crude oil and natural gas computed separately. In addition, the Company’s restrictions on the payment of dividends, distributions or purchase of treasury stock is limited to an aggregate of $5.0 million in each calendar year.
	At December 31, 2013, the credit facility borrowing base was $140.0 million with no monthly reduction amount. The borrowings made within the credit facility may be placed in a base rate loan or LIBO rate loan. The Company’s borrowing rates in the credit facility provide for base rate loans at the prime rate (3.25% at December 31, 2013) plus applicable margin utilization rates that range from 1.50% to 2.00%, and LIBO rate loans at LIBO published rates plus applicable utilization rates that range from 2.50% to 3.00%. At December 31, 2013, the Company had in place one base rate loan and one LIBO rate loan with effective rates of 5.00% and 2.92%, respectively.
	At December 31, 2013, the Company had $112.5 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 3.06%, and $27.5 million available for future borrowings. The combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest was 3.58% for the year ended December 31, 2013, as compared to 3.81% for the year ended December 31, 2012.
	The Company has entered into interest rate hedge agreements to help manage interest rate exposure. These contracts include interest rate swaps. Interest rate swap transactions generally involve the exchange of fixed and floating rate interest payment obligations without the exchange of the underlying principal amounts. In July 2012, the Company entered into interest swap agreements for a period of two years, which commence in January 2014, related to $75 million of the Company’s bank debt resulting in a fixed rate of 0.563% plus the Company’s current applicable margin.
	Equipment Loan:
	On July 31, 2013, the Company entered into a $10.0 million Loan and Security Agreement with JP Morgan Chase Bank (“Equipment Loan”). The Equipment Loan is secured by substantially all of the Company’s field service equipment, carries an interest rate of 3.95% per annum, requires monthly payments (principal and interest) of $184,000, and has a final maturity date of July 31, 2018. As of December 30, 2013, the Company had a total of $9.4 million outstanding on the Equipment Loan.

Commitments

Commitments	12 Months Ended
	Dec. 31, 2013
Commitments And Contingencies Disclosure [Abstract]	'
Commitments	'
	6. Commitments
	Operating Leases:
	The Company has several non-cancelable operating leases, primarily for rental of office space, that have a term of more than one year. The future minimum lease payments for the operating leases at December 31, 2013 are as follows.
	(Thousands of dollars)	Operating
		Leases
	2014	$	747
	2015		651
	2016		545
	2017		46
	Total minimum payments	$	1,989
	Rent expense for office space for the years ended December 31, 2013 and 2012 was $699,000 and $755,000, respectively.
	Asset Retirement Obligation:
	A reconciliation of the liability for plugging and abandonment costs for the years ended December 31, 2013 and 2012 is as follows:
		Year Ended December 31,
	(Thousands of dollars)	2013			2012
	Asset retirement obligation at beginning of period	$	9,012		$	19,013
	Liabilities incurred		338			733
	Loss on settlement of obligations		40			—
	Liabilities settled		(776	)		(15,361	)
	Accretion expense		394			1,053
	Revisions in estimated liabilities		1,529			3,574
	Asset retirement obligation at end of period	$	10,537		$	9,012
	The Company’s liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive life of wells and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of the Company’s wells, the costs to ultimately retire the wells may vary significantly from previous estimates. During 2013 and 2012 revisions in estimated liabilities for asset retirement obligation resulted primarily from the enactment of new federal regulation requirements for plugging and abandonment.

Contingent_Liabilities

Contingent Liabilities	12 Months Ended
	Dec. 31, 2013
Commitments And Contingencies Disclosure [Abstract]	'
Contingent Liabilities	'
	7. Contingent Liabilities
	The Company, as managing general partner of the affiliated Partnerships, is responsible for all Partnership activities, including the drilling of development wells and the production and sale of oil and gas from productive wells. The Company also provides the administration, accounting and tax preparation work for the Partnerships, and is liable for all debts and liabilities of the affiliated Partnerships, to the extent that the assets of a given limited Partnership are not sufficient to satisfy its obligations. At December 31, 2013, the affiliated Partnerships have established cash reserves in excess of their debts and liabilities, and the Company believes these reserves will be sufficient to satisfy Partnership obligations.
	The Company is subject to environmental laws and regulations. Management believes that future expenses, before recoveries from third parties, if any, will not have a material effect on the Company’s financial condition. This opinion is based on expenses incurred to date for remediation and compliance with laws and regulations, which have not been material to the Company’s results of operations.
	From time to time, the Company is party to certain legal actions arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company.

Stock_Options_and_Other_Compen

Stock Options and Other Compensation	12 Months Ended
	Dec. 31, 2013
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]	'
Stock Options and Other Compensation	'
	8. Stock Options and Other Compensation
	In May 1989, non-statutory stock options were granted by the Company to four key executive officers for the purchase of shares of common stock. At December 31, 2013 and 2012, options on 767,500 shares were outstanding and exercisable at prices ranging from $1.00 to $1.25. According to their terms, the options have no expiration date.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	9. Income Taxes
	The components of the provision (benefit) for income taxes for the years ended December 31, 2013 and 2012 are as follows:
		Year Ended December 31,
	(Thousands of dollars)	2013			2012
	Current:
	Federal	$	(462	)	$	16
	State		266			(130	)
	Total current		(196	)		(114	)
	Deferred:
	Federal		6,549			7,009
	State		465			(39	)
	Total deferred		7,014			6,970
	Total income tax provision	$	6,818		$	6,856
	The components of net deferred tax assets and liabilities are as follows:
		At December 31,
	(Thousands of dollars)	2013			2012
	Current Assets:
	Accrued liabilities	$	683		$	613
	Allowance for doubtful accounts		118			124
	Derivative contracts		677			(83	)
	Total current deferred income tax assets	$	1,478		$	654
	Non-Current Assets:
	Alternative minimum tax credits	$	5,852		$	5,890
	Net operating loss carry-forwards		168			114
	Percentage depletion carry-forwards		4,543			4,287
	Derivative contracts		—			91
	Total non-current assets		10,563			10,382
	Non-Current Liabilities:
	Basis differences relating to managed partnerships		2,462			1,492
	Depletion and depreciation		39,694			33,084
	Derivative contracts		369			—
	Total non-current liabilities		42,525			34,576
	Net non-current deferred income tax liabilities	$	31,962		$	24,194
	The total provision for income taxes for the years ended December 31, 2013 and 2012 varies from the federal statutory tax rate as a result of the following:
		Year Ended December 31,
	(Thousands of dollars)	2013			2012
	Expected tax expense	$	6,491		$	7,450
	State income tax, net of federal benefit		488			(112	)
	Percentage depletion		(422	)		(902	)
	Other, net		261			420
	Total income tax provision	$	6,818		$	6,856
	The Company showed a net operating loss on its 2012 federal income tax return, which was carried back to the 2010 and 2011 tax years, resulting in total refunds of $685,000. The net operating loss and related refunds were the result of elections to deduct intangible drilling costs in 2012 which was made upon filing the return in 2013, and the refunds result in the lowering of the current federal income tax expense in 2013.
	Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. Differences relating to oil and gas properties owned through Prime Offshore are reflected under “Depletion and depreciation,” while basis differences relating to the managed partnerships are reflected under “Basis differences relating to managed partnerships.”
	The Company is entitled to percentage depletion on certain of its wells, which is calculated without reference to the basis of the property. To the extent that such depletion exceeds a property’s basis, it creates a permanent difference, which lowers the Company’s effective rate.
	The Company has $5.9 million in alternative minimum tax (“AMT”) credits which can be used to lower the regular tax liability to the tentative AMT amount in years where the tentative AMT amount is less. These credits do not expire.
	The Company has not recorded any provision for uncertain tax positions. The Company files income tax returns in the U.S. federal jurisdiction and various state and local jurisdictions. The 2004, 2005, 2006, and 2009 federal income tax returns have been audited by the Internal Revenue Service, while the 2010, 2011 and 2012 returns remain open for examination. Returns for unexamined earlier years may be examined and adjustments made to the amount of percentage depletion and AMT credit carryforwards flowing from those years into an open tax year, although in general no assessment of income tax may be made for those years on which the statute has closed. State returns for the years 2010, 2011 and 2012 remain open for examination by the relevant taxing authorities.

Segment_Information_and_Major_

Segment Information and Major Customers	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Segment Information and Major Customers	'
	10. Segment Information and Major Customers
	The Company operates in one industry—oil and gas exploration, development, operation and servicing. The Company’s oil and gas activities are entirely in the United States.
	The Company sells its oil and gas production to a number of purchasers. Listed below are the percent of the Company’s total oil and gas sales made to each of the customers whose purchases represented more than 10% of the Company’s oil and gas sales in the year 2013.
	Oil Purchasers:			Gas Purchasers:
	Plains All American Inc.	52	%	Atlas Pipeline Mid-Continent	40	%
	Sunoco, Inc.	28	%	Unimark LLC	13	%
	Although there are no long-term oil and gas purchasing agreements with these purchasers, the Company believes that they will continue to purchase its oil and gas products and, if not, could be replaced by other purchasers.

Financial_Instruments

Financial Instruments	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Financial Instruments	'
	11. Financial Instruments
	Fair Value Measurements:
	Authoritative guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value. The fair values of the Company’s interest rate swaps, natural gas and crude oil price collars and swaps are designated as Level 3. The following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis at December 31, 2013 and 2012:
	31-Dec-13		Quoted Prices in				Significant				Significant			Balance at
	(Thousands of dollars)		Active Markets				Other				Unobservable			December 31,
			For Identical				Observable				Inputs (Level 3)			2013
			Assets (Level 1)				Inputs (Level 2)
	Assets
	Commodity derivative contracts		$	—			$	—			$	1,337		$	1,337
	Interest rate derivative contracts			—				—				86			86
	Total assets		$	—			$	—			$	1,423		$	1,423
	Liabilities
	Commodity derivative contracts		$	—			$	—			$	(2,010	)	$	(2,010	)
	Interest rate derivative contracts			—				—				(278	)		(278	)
	Total liabilities		$	—			$	—			$	(2,288	)	$	(2,288	)
	31-Dec-12		Quoted Prices in				Significant				Significant			Balance at
	(Thousands of dollars)		Active Markets				Other				Unobservable			December 31,
			For Identical				Observable				Inputs (Level 3)			2012
			Assets (Level 1)				Inputs (Level 2)
	Assets
	Commodity derivative contracts		$	—			$	—			$	1,347		$	1,347
	Total assets		$	—			$	—			$	1,347		$	1,347
	Liabilities
	Commodity derivative contracts		$	—			$	—			$	(1,371	)	$	(1,371	)
	Interest rate derivative contracts			—				—				(54	)		(54	)
	Total liabilities		$	—			$	—			$	(1,425	)	$	(1,425	)
	The derivative contracts were measured based on quotes from the Company’s counterparties. Such quotes have been derived using valuation models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable. These estimates are verified using comparable NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness.
	The significant unobservable inputs for Level 3 derivative contracts include basis differentials and volatility factors. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided.
	The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the years ended December 31, 2013 and 2012.
			Year Ended December 31,
	(Thousands of dollars)		2013				2012
	Net liabilities at beginning of period		$	(78	)		$	(3,507	)
	Total realized and unrealized (gains) losses:
	Included in earnings(a)			(1,971	)			3,985
	Included in other comprehensive loss			(138	)			(54	)
	Purchases, sales, issuances and settlements			1,322				(502	)
	Net liabilities at end of period		$	(865	)		$	(78	)
	(a)	Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item captioned unrealized gain/loss on derivative instruments, and interest rate swap instruments are reported as a reduction to interest expense.
	Derivative Instruments:
	The Company is exposed to commodity price and interest rate risk, and management considers periodically the Company’s exposure to cash flow variability resulting from the commodity price changes and interest rate fluctuations. Futures, swaps and options are used to manage the Company’s exposure to commodity price risk inherent in the Company’s oil and gas production operations. The Company does not apply hedge accounting to any of its commodity based derivatives. Both realized and unrealized gains and losses associated with commodity derivative instruments are recognized in earnings.
	Interest rate swap derivatives continue to be treated as cash-flow hedges and are used to fix or float interest rates on existing debt. The value of these interest rate swaps at December 31, 2013 is located in accumulated other comprehensive loss, net of tax. Settlement of the swaps, currently scheduled to begin in January 2014, will be recorded within interest expense.
	The following table sets forth the effect of derivative instruments on the consolidated balance sheets at December 31, 2013 and 2012:
					Fair Value at December 31,
	(Thousands of dollars)		Balance Sheet Location		2013				2012
	Asset Derivatives:
	Derivatives designated as cash-flow hedging instruments:
	Interest rate swap contracts		Other assets		$	86			$	—
	Derivatives not designated as cash-flow hedging instruments:
	Crude oil commodity contracts		Derivative contracts			307				189
	Natural gas commodity contracts		Derivative contracts			50				1,040
	Crude oil commodity contracts		Other assets			980				118
	Total				$	1,423			$	1,347
	Liability Derivatives:
	Derivatives designated as cash-flow hedging instruments:
	Interest rate swap contracts		Derivative liability short-term		$	(209	)		$	—
	Interest rate swap contracts		Derivative liability long-term			(69	)			(54	)
	Derivatives not designated as cash-flow hedging instruments:
	Crude oil commodity contracts		Derivative liability short-term			(1,667	)			(994	)
	Natural gas commodity contracts		Derivative liability short-term			(318	)			—
	Crude oil commodity contracts		Derivative liability long-term			(25	)			(377	)
	Total				$	(2,288	)		$	(1,425	)
	Total derivative instruments				$	(865	)		$	(78	)
	The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the years ended December 31, 2013 and 2012:
(Thousands of dollars)		Location of gain/loss recognized		Amount of gain/loss
		in income		recognized in income
				2013				2012
Derivatives not designated as cash-flow hedge instruments:
Natural gas commodity contracts		Unrealized gain (loss) on derivative instruments, net		$	(1,309	)		$	1,040
Crude oil commodity contracts		Unrealized gain on derivative instruments, net			660				2,443
Natural gas commodity contracts(a)		Realized gain on derivative instruments, net			796				—
Crude oil commodity contracts(a)		Realized gain (loss) on derivative instruments, net			(2,118	)			502
				$	(1,971	)		$	3,985
(a)	In January 2012, March 2012 and May 2012, the Company unwound and monetized crude oil swaps with original settlement dates from January 2012 through December 2013 for aggregated net proceeds of $1.03 million. The $1.03 million gain associated with these early settlement transactions is included in realized gain on derivative instruments for the year ended December 31, 2012.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	12. Related Party Transactions
	The Company, as managing general partner or managing trustee, makes an annual offer to repurchase the interests of the partners and trust unit holders in certain of the Partnerships or Trusts. The Company purchased such interests in an amount totaling $48,000 during 2013 and $149,000 during 2012.
	Treasury stock purchases in any reported period may include shares from a related party. In April 2012, the Company purchased 45,179 shares of common stock as treasury shares from a Director for $1.13 million. In December 2013, the Company purchased 4,500 shares of common stock as treasury shares from a Director for $222,750. There were no other related party treasury stock purchases during the years ended December 31, 2013 and 2012.
	Receivables from related parties consist of reimbursable general and administrative costs, lease operating expenses and reimbursement for property development and related costs. These receivables are due from joint venture partners, which may include members of the Company’s Board of Directors.
	Payables owed to related parties primarily represent receipts collected by the Company as agent for the joint venture partners, which may include members of the Company’s Board of Directors, for oil and gas sales net of expenses.

Restricted_Cash_and_Cash_Equiv

Restricted Cash and Cash Equivalents	12 Months Ended
	Dec. 31, 2013
Cash And Cash Equivalents [Abstract]	'
Restricted Cash and Cash Equivalents	'
	13. Restricted Cash and Cash Equivalents
	Restricted cash and cash equivalents include $2.01 million and $4.44 million at December 31, 2013 and 2012, respectively, of cash primarily pertaining to oil and gas revenue payments. There were corresponding accounts payable recorded at December 31, 2013 and 2012 for these liabilities. Both the restricted cash and the accounts payable are classified as current on the accompanying consolidated balance sheets.

Salary_Deferral_Plan

Salary Deferral Plan	12 Months Ended
	Dec. 31, 2013
Compensation And Retirement Disclosure [Abstract]	'
Salary Deferral Plan	'
	14. Salary Deferral Plan
	The Company maintains a salary deferral plan (the “Plan”) in accordance with Internal Revenue Code Section 401(k), as amended. The Plan provides for matching contributions of which $525,000 and $463,000 were made in 2013 and 2012, respectively.

Earnings_per_Share

Earnings per Share	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Earnings per Share	'
	15. Earnings per Share
	Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods. The following reconciles amounts reported in the financial statements:
		Year Ended December 31,
		2013						2012
		Net Income		Weighted		Per Share		Net Income		Weighted		Per Share
		(In  000’s)		Average		Amount		(In  000’s)		Average		Amount
				Number of						Number of
				Shares						Shares
				Outstanding						Outstanding
	Basic	$	12,271		2,436,821	$	5.04	$	15,056		2,624,335	$	5.74
	Effect of dilutive securities:
	Options		—		746,085				—		735,244
	Diluted	$	12,271		3,182,906	$	3.86	$	15,056		3,359,579	$	4.48

Shareholders_Equity

Shareholder's Equity	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Shareholder's Equity	'
	16. Shareholder’s Equity
	The Company has in place a stock repurchase program whereby it may purchase outstanding shares of its common stock from time-to-time, in open market transactions or negotiated sales. The Company uses the cost method to account for its treasury share purchases.

Supplementary_Information

Supplementary Information	12 Months Ended
	Dec. 31, 2013
Organization Consolidation And Presentation Of Financial Statements [Abstract]	'
Supplementary Information	'
	SUPPLEMENTARY INFORMATION
	CAPITALIZED COSTS RELATING TO
	OIL AND GAS PRODUCING ACTIVITIES
	Years Ended December 31, 2013 and 2012
	(Unaudited)
		As of December 31,
	(Thousands of dollars)	2013			2012
	Proved Developed oil and gas properties	$	362,186		$	336,135
	Proved Undeveloped oil and gas properties		1,937			2,069
	Unproved oil and gas properties		—			—
	Total Capitalized Costs		364,123			338,204
	Accumulated depreciation, depletion and valuation allowance		169,100			150,276
	Net Capitalized Costs	$	195,023		$	187,928
	COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION,
	EXPLORATION AND DEVELOPMENT ACTIVITIES
	Years Ended December 31, 2013 and 2012
	(Unaudited)
		Year Ended December 31,
	(Thousands of dollars)	2013			2012
	Acquisition of Properties, Developed	$	7		$	6,482
	Acquisition of Properties, Undeveloped		—			2,030
	Exploration Costs		8			10
	Development Costs		25,912			66,671
	STANDARDIZED MEASURE OF DISCOUNTED FUTURE
	NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES
	Years Ended December 31, 2013 and 2012
	(Unaudited)
		As of December 31,
	(Thousands of dollars)	2013			2012
	Future cash inflows	$	1,880,389		$	1,524,137
	Future production costs		(769,172	)		(673,629	)
	Future development costs		(313,754	)		(179,568	)
	Future income tax expenses		(234,191	)		(186,072	)
	Future Net Cash Flows		563,272			484,868
	10% annual discount for estimated timing of cash flows		(325,044	)		(271,595	)
	Standardized Measure of Discounted Future Net Cash Flows	$	238,228		$	213,273
	See accompanying Notes to Supplementary Information
	PRIMEENERGY CORPORATION AND SUBSIDIARIES
	SUPPLEMENTARY INFORMATION
	STANDARDIZED MEASURE OF DISCOUNTED FUTURE
	NET CASH FLOWS AND CHANGES THEREIN
	RELATING TO PROVED OIL AND GAS RESERVES
	Years Ended December 31, 2013 and 2012
	(Unaudited)
	The following are the principal sources of change in the standardized measure of discounted future net cash flows during 2013 and 2012:
		Year Ended December 31,
	(Thousands of dollars)	2013			2012
	Sales of oil and gas produced, net of production costs	$	(48,976	)	$	(48,673	)
	Net changes in prices and production costs		(10,149	)		504
	Extensions, discoveries and improved recovery		218,648			164,557
	Revisions of previous quantity estimates		(733	)		40,964
	Net change in development costs		(129,672	)		(145,382	)
	Reserves sold		—			—
	Reserves purchased		—			6,563
	Accretion of discount		21,327			18,451
	Net change in income taxes		(23,007	)		(5,952	)
	Changes in production rates (timing) and other		(2,483	)		(2,267	)
	Net change		24,955			28,765
	Standardized measure of discounted future net cash flow:
	Beginning of year		213,273			184,508
	End of year	$	238,228		$	213,273
	See accompanying Notes to Supplementary Information
	PRIMEENERGY CORPORATION AND SUBSIDIARIES
SUPPLEMENTARY INFORMATION
RESERVE QUANTITY INFORMATION
Years Ended December 31, 2013 and 2012
(Unaudited)
	As of December 31,
	2013									2012
	Oil			NGLs			Gas			Oil			NGLs		Gas
	(MBbls)			(MBbls)			(MMcf)			(MBbls)			(MBbls)		(MMcf)
Proved Developed Reserves:
Beginning of year		7,178			2,909			27,833			6,418			—		43,631
Extensions, discoveries and improved recovery		87			—			402			224			49		1,000
Revisions of previous estimates		(361	)		(712	)		6,456			252			2,860		(15,821	)
Converted from undeveloped reserves		513			199			1,207			861			—		3,527
Reserves sold		—			—			—			—			—		—
Reserves purchased		—			—			—			168			—		211
Production		(730	)		(173	)		(4,270	)		(745	)		—		(4,715	)
End of year		6,687			2,223			31,628			7,178			2,909		27,833
Proved Undeveloped Reserves:
Beginning of year		5,907			2,877			12,613			2,435			—		9,765
Extensions, discoveries and improved recovery		4,536			1,541			9,538			3,446			1,401		6,158
Revisions of previous estimates		864			(512	)		(1,172	)		887			1,476		217
Converted to developed reserves		(513	)		199			(1,207	)		(861	)		—		(3,527	)
Reserves sold		—			—			—			—			—		—
Reserves purchased		—			—			—			—			—		—
End of year		9,066			3,707			19,772			5,907			2,877		12,613
Total Proved Reserves at the End of the Year		15,753			5,930			51,400			13,085			5,786		40,446
RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES
Years Ended December 31, 2013 and 2012
(Unaudited)
	Year Ended December 31,
(Thousands of dollars)	2013			2012
Revenue:
Oil and gas sales	$	92,785		$	88,336
Costs and Expenses:
Lease operating expenses		43,809			39,868
Exploration costs		8			10
Depreciation, depletion and accretion		19,218			19,883
Income tax expense		10,012			8,941
Total Costs and Expenses		73,047			68,702
Results of Operations From Producing Activities (excluding corporate overhead and interest costs)	$	19,738		$	19,634
See accompanying Notes to Supplementary Information
PRIMEENERGY CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTARY INFORMATION
(Unaudited)
1. Presentation of Reserve Disclosure Information
Reserve disclosure information is presented in accordance with U.S. generally accepted accounting principles. The Company’s reserves include amounts attributable to non-controlling interests in the Partnerships. These interests represent less than 10% of the Company’s reserves.
2. Determination of Proved Reserves
The estimates of the Company’s proved reserves were determined by an independent petroleum engineer in accordance with U.S. generally accepted accounting principles. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development and other factors. Estimated future net revenues were computed by reserves, less estimated future development and production costs based on current costs.
Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward of downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that proved reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.
3. Results of Operations from Oil and Gas Producing Activities
The results of operations from oil and gas producing activities were prepared in accordance with U.S. generally accepted accounting principles. General and administrative expenses, interest costs and other unrelated costs are not deducted in computing results of operations from oil and gas activities.
4. Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves
The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes of standardized measure of discounted future net cash flows relating to proved oil and gas reserves were prepared in accordance with U.S. generally accepted accounting principles.
Future cash inflows are computed as described in Note 2 by applying current prices to year-end quantities of proved reserves.
Future production and development costs are computed estimating the expenditures to be incurred in developing and producing the oil and gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions.
Future income tax expenses are calculated by applying the year-end U.S. tax rate to future pre-tax cash inflows relating to proved oil and gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences and tax credits and allowances relating to the proved oil and gas reserves.
Future net cash flows are discounted at a rate of 10% annually (pursuant to applicable guidance) to derive the standardized measure of discounted future net cash flows. This calculation does not necessarily represent an estimate of fair market value or the present value of such cash flows since future prices and costs can vary substantially from year-end and the use of a 10% discount figure is arbitrary.
5. Changes in Reserves
The 2013 and 2012 extensions and discoveries reflect the successful drilling activity in the Company’s West Texas and Mid-Continent areas. The Company is employing technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being used in the estimation of its proved reserves include, but are not limited to, electrical logs, radioactivity logs, geologic maps, production data and well test data. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques.

Description_of_Operations_and_1

Description of Operations and Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Nature of Operations	'
	Nature of Operations:
	PrimeEnergy Corporation (“PEC”), a Delaware corporation, was organized in March 1973 and is engaged in the development, acquisition and production of oil and natural gas properties. PrimeEnergy Corporation and its subsidiaries are herein referred to as the “Company.” The Company owns leasehold, mineral and royalty interests in producing and non-producing oil and gas properties across the United States, including Colorado, Kansas, Louisiana, Mississippi, Montana, New Mexico, North Dakota, Oklahoma, Texas, West Virginia and Wyoming and the Gulf of Mexico. The Company operates approximately 1,600 wells and owns non-operating interests in over 800 additional wells. Additionally, the Company provides well-servicing support operations, site-preparation and construction services for oil and gas drilling and reworking operations, both in connection with the Company’s activities and providing contract services for third parties. The Company is publicly traded on the NASDAQ under the symbol “PNRG.” PEC owns Eastern Oil Well Service Company (“EOWSC”), EOWS Midland Company (“EMID”) and Southwest Oilfield Construction Company (“SOCC”), all of which perform oil and gas field servicing. PEC also owns Prime Operating Company (“POC”), which serves as operator for most of the producing oil and gas properties owned by the Company and affiliated entities. PEC also owns Prime Offshore L.L.C. (“Prime Offshore”), formerly F-W Oil Exploration LLC, which has owned and operated properties in the Gulf of Mexico. PrimeEnergy Management Corporation (“PEMC”), a wholly-owned subsidiary, acts as the managing general partner, providing administration, accounting and tax preparation services for 18 limited partnerships and 2 trusts (collectively, the “Partnerships”). The markets for the Company’s products are highly competitive, as oil and gas are commodity products and prices depend upon numerous factors beyond the control of the Company, such as economic, political and regulatory developments and competition from alternative energy sources.
Consolidation and Presentation	'
	Consolidation and Presentation:
	The consolidated financial statements include the accounts of PrimeEnergy Corporation, its subsidiaries and the Partnerships, using the full consolidation method for those partnerships which are controlled by the Company. The proportionate consolidation method is used to account for those undivided interests in oil and gas properties owned by the Company as well as interests held in unincorporated legal entities, such as partnerships, engaged in oil and gas production, which are not controlled by the Company. For those entities which are proportionately consolidated, the proportionate share of each entity’s assets, liabilities, revenue and expenses is included in the appropriate classifications in the consolidated financial statements. Reserve estimates associated with the proportionately consolidated oil and gas interests are calculated for each property at the Partnership level, and depletion, depreciation and amortization (“DD&A”) rates are determined at the Partnership level. The Company’s reserve estimates are based on the ownership percentage of Partnership reserve reports. DD&A expense and evaluation of impairment may differ from the Partnership as the Company’s cost basis for the Partnership interests acquired may be different than the cost basis at the Partnership level for properties acquired by the Partnership. All significant intercompany balances and transactions are eliminated in preparing the consolidated financial statements.
Reclassifications	'
	Reclassifications:
	Certain reclassifications have been made to prior year statements to conform with the current year presentation. These reclassifications have no impact on net income and no material impact on any other financial statement captions.
Subsequent Events	'
	Subsequent Events:
	Subsequent events have been evaluated through the date that the consolidated financial statements were issued. During this period, there were no material subsequent items requiring disclosure.
Use of Estimates	'
	Use of Estimates:
	The preparation of financial statements in conformity with U.S. generally accepted accounting principles 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.
	Estimates of oil and gas reserves, as determined by independent petroleum engineers, are continually subject to revision based on price, production history and other factors. Depletion expense, which is computed based on the units of production method, could be significantly impacted by changes in such estimates. Additionally, U.S. generally accepted accounting principles require that if the expected future undiscounted cash flows from an asset is less than its carrying cost, that asset must be written down to its fair market value. As the fair market value of an oil and gas property will usually be significantly less than the total undiscounted future net revenues expected from that asset, slight changes in the estimates used to determine future net revenues from an asset could lead to the necessity of recording a significant impairment of that asset.
Property and Equipment	'
	Property and Equipment:
	The Company follows the “successful efforts” method of accounting for its oil and gas properties. Under the successful efforts method, costs of acquiring undeveloped oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations. Annual lease rentals and exploration expenses, including geological and geophysical expenses and exploratory dry hole costs, are charged against income as incurred. Costs of drilling and equipping productive wells, including development dry holes and related production facilities, are capitalized. All other property and equipment are carried at cost. Depreciation and depletion of oil and gas production equipment and properties are determined under the unit-of-production method based on estimated proved developed recoverable oil and gas reserves. Depreciation of all other equipment is determined under the straight-line method using various rates based on useful lives generally ranging from 5 to 10 years. The cost of assets and related accumulated depreciation is removed from the accounts when such assets are disposed of, and any related gains or losses are reflected in current earnings.
Capitalization of Interest	'
	Capitalization of Interest:
	Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until the projects are substantially complete and ready for their intended use if the projects are evaluated and successful.
Impairment of Long-Lived Assets:	'
	Impairment of Long-Lived Assets:
	The Company reviews long-lived assets, including oil and gas properties, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts are not expected to be recovered by undiscounted cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows.
Fair Value	'
	Fair Value:
	The Company follows the authoritative guidance that establishes a formal framework for measuring fair values of assets and liabilities in financial statements that are already required by U.S. generally accepted accounting principles to be measured at fair value. The guidance defines fair value 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 (exit price). The transaction is based on a hypothetical transaction in the principal or most advantageous market considered from the perspective of the market participant that holds the asset or owes the liability.
	The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company attempts to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company is able to classify fair value balances based on the observability of those inputs. The guidance establishes a formal fair value hierarchy based on the inputs used to measure fair value. The hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.
Asset Retirement Obligation	'
	Asset Retirement Obligation:
	The Company follows the accounting standard for asset retirement obligation. The asset retirement obligation primarily represents the estimated present value of the amount the Company will incur to plug, abandon and remediate producing properties (including removal of offshore platforms) at the end of their productive lives, in accordance with applicable state laws. The Company determined its asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The asset retirement obligation is recorded as a liability at its estimated present value at its inception, with an offsetting increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the statement of operations.
Income Taxes	'
	Income Taxes:
	The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the 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 the tax rate in effect for the year in which those temporary differences are expected to turn around. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
	The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties.
General and Administrative Expenses	'
	General and Administrative Expenses:
	General and administrative expenses represent cost and expenses associated with the operation of the Company.
Earnings Per Common Share	'
	Earnings Per Common Share:
	Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods.
Statements of Cash Flows	'
	Statements of Cash Flows:
	For purposes of the consolidated statements of cash flows, the Company considers short-term, highly liquid investments with original maturities of less than ninety days to be cash equivalents.
Concentration of Credit Risk	'
	Concentration of Credit Risk:
	The Company maintains significant banking relationships with financial institutions in the State of Texas. The Company limits its risk by periodically evaluating the relative credit standing of these financial institutions. The Company’s oil and gas production purchasers consist primarily of independent marketers and major gas pipeline companies.
Hedging	'
	Hedging:
	The Company periodically enters into oil and gas financial instruments to manage its exposure to oil and gas price volatility. The oil and gas reference prices upon which the price hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company.
	The financial instruments are accounted for in accordance with applicable accounting standards for derivative instruments and hedging activities. Such standards require that applicable derivative instruments be measured at fair market value and recognized as assets or liabilities in the balance sheet. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation is generally established at the inception of a derivative. For derivatives designated as cash flow hedges and meeting applicable effectiveness guidelines, changes in fair value, to the extent effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. At December 31, 2013 and 2012, the entire other comprehensive income amount comprised of the impact of cash flow hedges. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value of a derivative resulting from ineffectiveness or an excluded component of the gain/loss is recognized immediately in the statement of operations.
Recently Adopted Accounting Standards	'
	Recently Adopted Accounting Standards:
	In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-11, “Disclosures about Offsetting Assets and Liabilities.” This ASU requires enhanced disclosures including both gross and net information about financial and derivative instruments eligible for offset or subject to an enforceable master netting arrangement or similar agreement. This new guidance is effective for annual reporting periods beginning on or after January 1, 2013 and subsequent interim periods. In January 2013, the FASB issued ASU 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” ASU 2013-01 clarifies the scope of ASU 2011-11 to apply to derivative instruments that are offset or subject to an enforceable master netting arrangement or similar agreement. This clarified guidance is effective for annual reporting periods beginning on or after January 1, 2013 and subsequent interim periods. The revised requirements of ASU 2011-11 and ASU 2013-01 impacted the disclosures associated with the Company’s derivative instruments (Note 11) and did not have a material impact on the Company’s consolidated financial statements for the year ended December 31, 2013.
	In February 2013, the FASB issued ASU 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income” (“AOCI”). ASU 2013-02 requires a rollforward of changes in AOCI by component and information about significant reclassifications from AOCI to net earnings to be presented in one location, either on the face of the financial statements or in the notes. This new guidance is effective for fiscal years beginning after December 15, 2012 and subsequent interim periods. There was no amounts reclassified out of accumulated other comprehensive income for the year ended December 31, 2013. The requirements of ASU 2013-02 did not have a material impact on the Company’s consolidated financial statements for the year ended December 31, 2013.
	In July 2013, the FASB issued ASU 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a similar Tax Loss, or a Tax Credit Carryforward Exists.” ASU 2013-11 provided guidance on the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. This guidance requires entities to present unrecognized tax benefits as a decrease in a net operating loss, similar tax loss, or tax credit carryforward if certain criteria are met. The guidance will eliminate the diversity in practice in the presentation of unrecognized tax benefits but will not alter the way in which entities assess deferred tax assets for realizability. ASU No. 2013-11 is effective for annual and interim reporting periods beginning after December 15, 2013. The Company will apply all changes prospectively and does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.
Presentation of Reserve Disclosure Information	'
	1. Presentation of Reserve Disclosure Information
	Reserve disclosure information is presented in accordance with U.S. generally accepted accounting principles. The Company’s reserves include amounts attributable to non-controlling interests in the Partnerships. These interests represent less than 10% of the Company’s reserves.
Determination of Proved Reserves	'
	2. Determination of Proved Reserves
	The estimates of the Company’s proved reserves were determined by an independent petroleum engineer in accordance with U.S. generally accepted accounting principles. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development and other factors. Estimated future net revenues were computed by reserves, less estimated future development and production costs based on current costs.
	Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward of downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that proved reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.
Results of Operations from Oil and Gas Producing Activities	'
	3. Results of Operations from Oil and Gas Producing Activities
	The results of operations from oil and gas producing activities were prepared in accordance with U.S. generally accepted accounting principles. General and administrative expenses, interest costs and other unrelated costs are not deducted in computing results of operations from oil and gas activities.
Standardized Measure of Discounted Future Net Cash Flows and Changes therein Relating to Proved Oil and Gas Reserves	'
	4. Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves
	The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes of standardized measure of discounted future net cash flows relating to proved oil and gas reserves were prepared in accordance with U.S. generally accepted accounting principles.
	Future cash inflows are computed as described in Note 2 by applying current prices to year-end quantities of proved reserves.
	Future production and development costs are computed estimating the expenditures to be incurred in developing and producing the oil and gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions.
	Future income tax expenses are calculated by applying the year-end U.S. tax rate to future pre-tax cash inflows relating to proved oil and gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences and tax credits and allowances relating to the proved oil and gas reserves.
	Future net cash flows are discounted at a rate of 10% annually (pursuant to applicable guidance) to derive the standardized measure of discounted future net cash flows. This calculation does not necessarily represent an estimate of fair market value or the present value of such cash flows since future prices and costs can vary substantially from year-end and the use of a 10% discount figure is arbitrary.
Changes in Reserves	'
	5. Changes in Reserves
	The 2013 and 2012 extensions and discoveries reflect the successful drilling activity in the Company’s West Texas and Mid-Continent areas. The Company is employing technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being used in the estimation of its proved reserves include, but are not limited to, electrical logs, radioactivity logs, geologic maps, production data and well test data. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques.

Additional_Balance_Sheet_Infor1

Additional Balance Sheet Information (Tables)	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Components of Balance Sheet Amounts	'
	Accounts receivable at December 31, 2013 and 2012 consisted of the following:
		December 31,
	(Thousands of dollars)	2013			2012
	Joint interest billings	$	6,287		$	2,189
	Trade receivables		2,014			1,580
	Oil and gas sales		9,604			9,362
	Other		122			436
			18,027			13,567
	Less: Allowance for doubtful accounts		(334	)		(355	)
	Total	$	17,693		$	13,212
	Accounts payable at December 31, 2013 and 2012 consisted of the following:
		December 31,
	(Thousands of dollars)	2013			2012
	Trade	$	1,596		$	3,968
	Royalty and other owners		7,391			9,652
	Partner advances		3,378			3,589
	Prepaid drilling deposits		978			306
	Other		2,906			2,053
	Total	$	16,249		$	19,568
	Accrued liabilities at December 31, 2013 and 2012 consisted of the following:
		December 31,
	(Thousands of dollars)	2013			2012
	Compensation and related expenses	$	3,062		$	2,517
	Property costs		3,119			4,549
	Income tax		268			—
	Other		383			552
	Total	$	6,832		$	7,618

Commitments_Tables

Commitments (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments And Contingencies Disclosure [Abstract]	'
Summary of Future Minimum Lease Payments for Non-Cancelable Operating Leases	'
	The future minimum lease payments for the operating leases at December 31, 2013 are as follows.
	(Thousands of dollars)	Operating
		Leases
	2014	$	747
	2015		651
	2016		545
	2017		46
	Total minimum payments	$	1,989
Reconciliation of Liability for Plugging and Abandonment Costs	'
	A reconciliation of the liability for plugging and abandonment costs for the years ended December 31, 2013 and 2012 is as follows:
		Year Ended December 31,
	(Thousands of dollars)	2013			2012
	Asset retirement obligation at beginning of period	$	9,012		$	19,013
	Liabilities incurred		338			733
	Loss on settlement of obligations		40			—
	Liabilities settled		(776	)		(15,361	)
	Accretion expense		394			1,053
	Revisions in estimated liabilities		1,529			3,574
	Asset retirement obligation at end of period	$	10,537		$	9,012

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Components of Provision (Benefit) for Income Taxes	'
	The components of the provision (benefit) for income taxes for the years ended December 31, 2013 and 2012 are as follows:
		Year Ended December 31,
	(Thousands of dollars)	2013			2012
	Current:
	Federal	$	(462	)	$	16
	State		266			(130	)
	Total current		(196	)		(114	)
	Deferred:
	Federal		6,549			7,009
	State		465			(39	)
	Total deferred		7,014			6,970
	Total income tax provision	$	6,818		$	6,856
Components of Net Deferred Tax Assets and Liabilities	'
	The components of net deferred tax assets and liabilities are as follows:
		At December 31,
	(Thousands of dollars)	2013			2012
	Current Assets:
	Accrued liabilities	$	683		$	613
	Allowance for doubtful accounts		118			124
	Derivative contracts		677			(83	)
	Total current deferred income tax assets	$	1,478		$	654
	Non-Current Assets:
	Alternative minimum tax credits	$	5,852		$	5,890
	Net operating loss carry-forwards		168			114
	Percentage depletion carry-forwards		4,543			4,287
	Derivative contracts		—			91
	Total non-current assets		10,563			10,382
	Non-Current Liabilities:
	Basis differences relating to managed partnerships		2,462			1,492
	Depletion and depreciation		39,694			33,084
	Derivative contracts		369			—
	Total non-current liabilities		42,525			34,576
	Net non-current deferred income tax liabilities	$	31,962		$	24,194
Provision for Income Taxes Varies from Federal Statutory Tax Rate	'
	The total provision for income taxes for the years ended December 31, 2013 and 2012 varies from the federal statutory tax rate as a result of the following:
		Year Ended December 31,
	(Thousands of dollars)	2013			2012
	Expected tax expense	$	6,491		$	7,450
	State income tax, net of federal benefit		488			(112	)
	Percentage depletion		(422	)		(902	)
	Other, net		261			420
	Total income tax provision	$	6,818		$	6,856

Segment_Information_and_Major_1

Segment Information and Major Customers (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Segment Information by Major Customers	'
	The Company sells its oil and gas production to a number of purchasers. Listed below are the percent of the Company’s total oil and gas sales made to each of the customers whose purchases represented more than 10% of the Company’s oil and gas sales in the year 2013.
	Oil Purchasers:			Gas Purchasers:
	Plains All American Inc.	52	%	Atlas Pipeline Mid-Continent	40	%
	Sunoco, Inc.	28	%	Unimark LLC	13	%

Financial_Instruments_Tables

Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Schedule of Assets and Liabilities Measured at Fair Value on Recurring Basis	'
	The following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis at December 31, 2013 and 2012:
	31-Dec-13		Quoted Prices in				Significant				Significant			Balance at
	(Thousands of dollars)		Active Markets				Other				Unobservable			December 31,
			For Identical				Observable				Inputs (Level 3)			2013
			Assets (Level 1)				Inputs (Level 2)
	Assets
	Commodity derivative contracts		$	—			$	—			$	1,337		$	1,337
	Interest rate derivative contracts			—				—				86			86
	Total assets		$	—			$	—			$	1,423		$	1,423
	Liabilities
	Commodity derivative contracts		$	—			$	—			$	(2,010	)	$	(2,010	)
	Interest rate derivative contracts			—				—				(278	)		(278	)
	Total liabilities		$	—			$	—			$	(2,288	)	$	(2,288	)
	31-Dec-12		Quoted Prices in				Significant				Significant			Balance at
	(Thousands of dollars)		Active Markets				Other				Unobservable			December 31,
			For Identical				Observable				Inputs (Level 3)			2012
			Assets (Level 1)				Inputs (Level 2)
	Assets
	Commodity derivative contracts		$	—			$	—			$	1,347		$	1,347
	Total assets		$	—			$	—			$	1,347		$	1,347
	Liabilities
	Commodity derivative contracts		$	—			$	—			$	(1,371	)	$	(1,371	)
	Interest rate derivative contracts			—				—				(54	)		(54	)
	Total liabilities		$	—			$	—			$	(1,425	)	$	(1,425	)
Schedule of Changes in Fair Value of Financial Assets and Liabilities Classified as Level 3	'
	The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the years ended December 31, 2013 and 2012.
			Year Ended December 31,
	(Thousands of dollars)		2013				2012
	Net liabilities at beginning of period		$	(78	)		$	(3,507	)
	Total realized and unrealized (gains) losses:
	Included in earnings(a)			(1,971	)			3,985
	Included in other comprehensive loss			(138	)			(54	)
	Purchases, sales, issuances and settlements			1,322				(502	)
	Net liabilities at end of period		$	(865	)		$	(78	)
	(a)	Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item captioned unrealized gain/loss on derivative instruments, and interest rate swap instruments are reported as a reduction to interest expense.
Effect of Derivative Instruments on Consolidated Balance Sheets	'
	The following table sets forth the effect of derivative instruments on the consolidated balance sheets at December 31, 2013 and 2012:
					Fair Value at December 31,
	(Thousands of dollars)		Balance Sheet Location		2013				2012
	Asset Derivatives:
	Derivatives designated as cash-flow hedging instruments:
	Interest rate swap contracts		Other assets		$	86			$	—
	Derivatives not designated as cash-flow hedging instruments:
	Crude oil commodity contracts		Derivative contracts			307				189
	Natural gas commodity contracts		Derivative contracts			50				1,040
	Crude oil commodity contracts		Other assets			980				118
	Total				$	1,423			$	1,347
	Liability Derivatives:
	Derivatives designated as cash-flow hedging instruments:
	Interest rate swap contracts		Derivative liability short-term		$	(209	)		$	—
	Interest rate swap contracts		Derivative liability long-term			(69	)			(54	)
	Derivatives not designated as cash-flow hedging instruments:
	Crude oil commodity contracts		Derivative liability short-term			(1,667	)			(994	)
	Natural gas commodity contracts		Derivative liability short-term			(318	)			—
	Crude oil commodity contracts		Derivative liability long-term			(25	)			(377	)
	Total				$	(2,288	)		$	(1,425	)
	Total derivative instruments				$	(865	)		$	(78	)
Effect of Derivative Instruments on Consolidated Statements of Operations	'
	The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the years ended December 31, 2013 and 2012:
	(Thousands of dollars)		Location of gain/loss recognized		Amount of gain/loss
			in income		recognized in income
					2013				2012
	Derivatives not designated as cash-flow hedge instruments:
	Natural gas commodity contracts		Unrealized gain (loss) on derivative instruments, net		$	(1,309	)		$	1,040
	Crude oil commodity contracts		Unrealized gain on derivative instruments, net			660				2,443
	Natural gas commodity contracts(a)		Realized gain on derivative instruments, net			796				—
	Crude oil commodity contracts(a)		Realized gain (loss) on derivative instruments, net			(2,118	)			502
					$	(1,971	)		$	3,985
	(a)	In January 2012, March 2012 and May 2012, the Company unwound and monetized crude oil swaps with original settlement dates from January 2012 through December 2013 for aggregated net proceeds of $1.03 million. The $1.03 million gain associated with these early settlement transactions is included in realized gain on derivative instruments for the year ended December 31, 2012.

Earnings_per_Share_Tables

Earnings per Share (Tables)	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Computation of Basic and Diluted Earnings (Loss) Per Share	'
	The following reconciles amounts reported in the financial statements:
		Year Ended December 31,
		2013						2012
		Net Income		Weighted		Per Share		Net Income		Weighted		Per Share
		(In  000’s)		Average		Amount		(In  000’s)		Average		Amount
				Number of						Number of
				Shares						Shares
				Outstanding						Outstanding
	Basic	$	12,271		2,436,821	$	5.04	$	15,056		2,624,335	$	5.74
	Effect of dilutive securities:
	Options		—		746,085				—		735,244
	Diluted	$	12,271		3,182,906	$	3.86	$	15,056		3,359,579	$	4.48

Supplementary_Information_Tabl

Supplementary Information (Tables)	12 Months Ended
	Dec. 31, 2013
Organization Consolidation And Presentation Of Financial Statements [Abstract]	'
Capitalized Costs Relating to Oil and Gas Producing Activities	'
	CAPITALIZED COSTS RELATING TO
	OIL AND GAS PRODUCING ACTIVITIES
	Years Ended December 31, 2013 and 2012
	(Unaudited)
		As of December 31,
	(Thousands of dollars)	2013			2012
	Proved Developed oil and gas properties	$	362,186		$	336,135
	Proved Undeveloped oil and gas properties		1,937			2,069
	Unproved oil and gas properties		—			—
	Total Capitalized Costs		364,123			338,204
	Accumulated depreciation, depletion and valuation allowance		169,100			150,276
	Net Capitalized Costs	$	195,023		$	187,928
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities	'
	COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION,
	EXPLORATION AND DEVELOPMENT ACTIVITIES
	Years Ended December 31, 2013 and 2012
	(Unaudited)
		Year Ended December 31,
	(Thousands of dollars)	2013			2012
	Acquisition of Properties, Developed	$	7		$	6,482
	Acquisition of Properties, Undeveloped		—			2,030
	Exploration Costs		8			10
	Development Costs		25,912			66,671
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves	'
	STANDARDIZED MEASURE OF DISCOUNTED FUTURE
	NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES
	Years Ended December 31, 2013 and 2012
	(Unaudited)
		As of December 31,
	(Thousands of dollars)	2013			2012
	Future cash inflows	$	1,880,389		$	1,524,137
	Future production costs		(769,172	)		(673,629	)
	Future development costs		(313,754	)		(179,568	)
	Future income tax expenses		(234,191	)		(186,072	)
	Future Net Cash Flows		563,272			484,868
	10% annual discount for estimated timing of cash flows		(325,044	)		(271,595	)
	Standardized Measure of Discounted Future Net Cash Flows	$	238,228		$	213,273
Standardized Measure of Discounted Future Net Cash Flows and Changes therein Relating to Proved Oil and Gas Reserves	'
	The following are the principal sources of change in the standardized measure of discounted future net cash flows during 2013 and 2012:
		Year Ended December 31,
	(Thousands of dollars)	2013			2012
	Sales of oil and gas produced, net of production costs	$	(48,976	)	$	(48,673	)
	Net changes in prices and production costs		(10,149	)		504
	Extensions, discoveries and improved recovery		218,648			164,557
	Revisions of previous quantity estimates		(733	)		40,964
	Net change in development costs		(129,672	)		(145,382	)
	Reserves sold		—			—
	Reserves purchased		—			6,563
	Accretion of discount		21,327			18,451
	Net change in income taxes		(23,007	)		(5,952	)
	Changes in production rates (timing) and other		(2,483	)		(2,267	)
	Net change		24,955			28,765
	Standardized measure of discounted future net cash flow:
	Beginning of year		213,273			184,508
	End of year	$	238,228		$	213,273
Reserve Quantity Information	'
	RESERVE QUANTITY INFORMATION
	Years Ended December 31, 2013 and 2012
	(Unaudited)
		As of December 31,
		2013									2012
		Oil			NGLs			Gas			Oil			NGLs		Gas
		(MBbls)			(MBbls)			(MMcf)			(MBbls)			(MBbls)		(MMcf)
	Proved Developed Reserves:
	Beginning of year		7,178			2,909			27,833			6,418			—		43,631
	Extensions, discoveries and improved recovery		87			—			402			224			49		1,000
	Revisions of previous estimates		(361	)		(712	)		6,456			252			2,860		(15,821	)
	Converted from undeveloped reserves		513			199			1,207			861			—		3,527
	Reserves sold		—			—			—			—			—		—
	Reserves purchased		—			—			—			168			—		211
	Production		(730	)		(173	)		(4,270	)		(745	)		—		(4,715	)
	End of year		6,687			2,223			31,628			7,178			2,909		27,833
	Proved Undeveloped Reserves:
	Beginning of year		5,907			2,877			12,613			2,435			—		9,765
	Extensions, discoveries and improved recovery		4,536			1,541			9,538			3,446			1,401		6,158
	Revisions of previous estimates		864			(512	)		(1,172	)		887			1,476		217
	Converted to developed reserves		(513	)		199			(1,207	)		(861	)		—		(3,527	)
	Reserves sold		—			—			—			—			—		—
	Reserves purchased		—			—			—			—			—		—
	End of year		9,066			3,707			19,772			5,907			2,877		12,613
	Total Proved Reserves at the End of the Year		15,753			5,930			51,400			13,085			5,786		40,446
Results of Operations from Oil and Gas Producing Activities	'
	RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES
	Years Ended December 31, 2013 and 2012
	(Unaudited)
		Year Ended December 31,
	(Thousands of dollars)	2013			2012
	Revenue:
	Oil and gas sales	$	92,785		$	88,336
	Costs and Expenses:
	Lease operating expenses		43,809			39,868
	Exploration costs		8			10
	Depreciation, depletion and accretion		19,218			19,883
	Income tax expense		10,012			8,941
	Total Costs and Expenses		73,047			68,702
	Results of Operations From Producing Activities (excluding corporate overhead and interest costs)	$	19,738		$	19,634

Description_of_Operations_and_2

Description of Operations and Significant Accounting Policies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013
	Trust
	Well
	Partnership
Property, Plant and Equipment [Line Items]	'
Number of wells operating by the company	1,600
Minimum number of wells under non-operating interests	800
Number of limited partnerships	18
Number of business income trusts	2
Maximum maturity period of cash and cash equivalents	'90 days
Maximum [Member]	'
Property, Plant and Equipment [Line Items]	'
Depreciation period of equipment	'10 years
Minimum [Member]	'
Property, Plant and Equipment [Line Items]	'
Depreciation period of equipment	'5 years

Acquisitions_and_Dispositions_

Acquisitions and Dispositions - Additional Information (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Business Combinations [Abstract]	'	'
Purchase of non-controlling interests	$48	$149

Additional_Balance_Sheet_Infor2

Additional Balance Sheet Information - Components of Balance Sheet Amounts (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Accounts Receivable:	'	'
Joint interest billings	$6,287	$2,189
Trade receivables	2,014	1,580
Oil and gas sales	9,604	9,362
Other	122	436
Accounts Receivable, Gross	18,027	13,567
Less: Allowance for doubtful accounts	-334	-355
Total	17,693	13,212
Accounts Payable:	'	'
Trade	1,596	3,968
Royalty and other owners	7,391	9,652
Partner advances	3,378	3,589
Prepaid drilling deposits	978	306
Other	2,906	2,053
Total	16,249	19,568
Accrued Liabilities:	'	'
Compensation and related expenses	3,062	2,517
Property costs	3,119	4,549
Income tax	268	'
Other	383	552
Total	$6,832	$7,618

Property_and_Equipment_Additio

Property and Equipment - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Property Plant And Equipment [Abstract]	'	'
Interest capitalized	$0	$0

LongTerm_Debt_Additional_Infor

Long-Term Debt - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Jul. 31, 2013	Dec. 31, 2013
			Minimum [Member]	Maximum [Member]	Equipment Loan [Member]	Equipment Loan [Member]	Interest Rate Swap [Member]
Debt Instrument [Line Items]	'	'	'	'	'	'	'
Credit facility borrowing capacity	$250,000,000	'	'	'	'	'	'
Maturity date of amended and restated credit agreement	30-Jul-17	'	'	'	'	'	'
Maximum percentage of production	90.00%	'	'	'	'	'	'
Restrictions on the payment of dividends, distributions or purchase of treasury stock	5,000,000	'	'	'	'	'	'
Credit facility borrowing base	140,000,000	'	'	'	'	'	'
Credit facility, interest rate description	'The Company's borrowing rates in the credit facility provide for base rate loans at the prime rate (3.25% at December 31, 2013) plus applicable margin utilization rates that range from 1.50% to 2.00%, and LIBO rate loans at LIBO published rates plus applicable utilization rates that range from 2.50% to 3.00%. At December 31, 2013, the Company had in place one base rate loan and one LIBO rate loan with effective rates of 5.00% and 2.92%, respectively.	'	'	'	'	'	'
Percentage for base rate loans at the prime rate	3.25%	'	'	'	3.95%	'	0.56%
Minimum range for applicable margin utilization rate	1.50%	'	'	'	'	'	'
Maximum range for applicable margin utilization rate	2.00%	'	'	'	'	'	'
Debt instrument interest one base rate basis for effective rate	5.00%	'	'	'	'	'	'
LIBOR rate loans	'	'	2.50%	3.00%	'	'	'
Effective LIBOR loan rate	2.92%	'	'	'	'	'	'
Outstanding borrowings under revolving credit facility	112,500,000	'	'	'	'	'	'
Weighted-average interest rate of borrowings	3.06%	'	'	'	'	'	'
Credit facility remaining borrowing capacity	27,500,000	'	'	'	'	'	'
Debt instrument basis weighted average interest rate spread on variable rate	3.58%	3.81%	'	'	'	'	'
Interest swap agreements period	'2 years	'	'	'	'	'	'
Company's bank debt	'	'	'	'	9,400,000	'	75,000,000
Equipment Loan, face amount	'	'	'	'	'	10,000,000	'
Equipment Loan, monthly payment	'	'	'	'	$184,000	'	'
Equipment Loan, maturity date	'	'	'	'	31-Jul-18	'	'

Commitments_Additional_Informa

Commitments - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Commitments And Contingencies Disclosure [Abstract]	'	'
Lease period description	'Term of more than one year	'
Rent expense for office space	$699,000	$755,000

Commitments_Summary_of_Future_

Commitments - Summary of Future Minimum Lease Payments for Non-Cancelable Operating Leases (Detail) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Commitments And Contingencies Disclosure [Abstract]	'
2014	$747
2015	651
2016	545
2017	46
Total minimum payments	$1,989

Commitments_Reconciliation_of_

Commitments - Reconciliation of Liability for Plugging and Abandonment Costs (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Commitments And Contingencies Disclosure [Abstract]	'	'
Asset retirement obligation at beginning of period	$9,012	$19,013
Liabilities incurred	338	733
Loss on settlement of obligations	40	'
Liabilities settled	-776	-15,361
Accretion expense	394	1,053
Revisions in estimated liabilities	1,529	3,574
Asset retirement obligation at end of period	$10,537	$9,012

Stock_Options_and_Other_Compen1

Stock Options and Other Compensation - Additional Information (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	31-May-89
			Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Options outstanding, shares	767,500	767,500	'
Option exercisable, shares	767,500	767,500	'
Number of key executive officers to whom non-statutory stock options granted	'	'	4
Minimum [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Average exercise price	1	1	'
Maximum [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Average exercise price	1.25	1.25	'

Income_Taxes_Components_of_Pro

Income Taxes - Components of Provision (Benefit) for Income Taxes (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current:	'	'
Federal	($462)	$16
State	266	-130
Total current	-196	-114
Deferred:	'	'
Federal	6,549	7,009
State	465	-39
Total deferred	7,014	6,970
Total income tax provision	$6,818	$6,856

Income_Taxes_Components_of_Net

Income Taxes - Components of Net Deferred Tax Assets and Liabilities (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current Assets:	'	'
Accrued liabilities	$683	$613
Allowance for doubtful accounts	118	124
Derivative contracts	677	-83
Total current deferred income tax assets	1,478	654
Non-Current Assets:	'	'
Alternative minimum tax credits	5,852	5,890
Net operating loss carry-forwards	168	114
Percentage depletion carry-forwards	4,543	4,287
Derivative contracts	'	91
Total non-current assets	10,563	10,382
Non-Current Liabilities:	'	'
Basis differences relating to managed partnerships	2,462	1,492
Depletion and depreciation	39,694	33,084
Derivative contracts	369	'
Total non-current liabilities	42,525	34,576
Net non-current deferred income tax liabilities	$31,962	$24,194

Income_Taxes_Provision_for_Inc

Income Taxes - Provision for Income Taxes Varies from Federal Statutory Tax Rate (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]	'	'
Expected tax expense	$6,491	$7,450
State income tax, net of federal benefit	488	-112
Percentage depletion	-422	-902
Other, net	261	420
Total income tax provision	$6,818	$6,856

Income_Taxes_Additional_Inform

Income Taxes - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]	'	'
Federal income tax return, total refunds	$685,000	'
Alternative minimum tax credits	5,852,000	5,890,000
Provision for uncertain tax positions	$0	'

Segment_Information_and_Major_2

Segment Information and Major Customers - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013
	Industry
Revenue, Major Customer [Line Items]	'
Number of industry in which company operates	1
Minimum [Member] | Sales [Member]	'
Revenue, Major Customer [Line Items]	'
Customer purchases with respect of company's sales	10.00%

Segment_Information_and_Major_3

Segment Information and Major Customers - Segment Information by Major Customers (Detail) (Sales [Member])	12 Months Ended
	Dec. 31, 2013
Plains All American Inc., Oil Purchasers [Member]	'
Revenue, Major Customer [Line Items]	'
Revenue by major customers	52.00%
Sunoco Inc., Oil Purchasers [Member]	'
Revenue, Major Customer [Line Items]	'
Revenue by major customers	28.00%
Atlas Pipeline Mid-Continent, Gas Purchasers [Member]	'
Revenue, Major Customer [Line Items]	'
Revenue by major customers	40.00%
Unimark LLC, Gas Purchasers [Member]	'
Revenue, Major Customer [Line Items]	'
Revenue by major customers	13.00%

Financial_Instruments_Schedule

Financial Instruments - Schedule of Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Assets	'	'
Derivative assets	$1,423	$1,347
Liabilities	'	'
Derivative liabilities	-2,288	-1,425
Fair Value, Measurements, Recurring [Member]	'	'
Assets	'	'
Derivative assets	1,423	1,347
Liabilities	'	'
Derivative liabilities	-2,288	-1,425
Commodity Derivative Contracts [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Assets	'	'
Derivative assets	1,337	1,347
Liabilities	'	'
Derivative liabilities	-2,010	-1,371
Interest Rate Derivative Contracts [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Assets	'	'
Derivative assets	86	'
Liabilities	'	'
Derivative liabilities	-278	-54
Quoted Prices in Active Markets For Identical Assets (Level 1) [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Assets	'	'
Derivative assets	'	'
Liabilities	'	'
Derivative liabilities	'	'
Quoted Prices in Active Markets For Identical Assets (Level 1) [Member] | Commodity Derivative Contracts [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Assets	'	'
Derivative assets	'	'
Liabilities	'	'
Derivative liabilities	'	'
Quoted Prices in Active Markets For Identical Assets (Level 1) [Member] | Interest Rate Derivative Contracts [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Assets	'	'
Derivative assets	'	'
Liabilities	'	'
Derivative liabilities	'	'
Significant Other Observable Inputs (Level 2) [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Assets	'	'
Derivative assets	'	'
Liabilities	'	'
Derivative liabilities	'	'
Significant Other Observable Inputs (Level 2) [Member] | Commodity Derivative Contracts [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Assets	'	'
Derivative assets	'	'
Liabilities	'	'
Derivative liabilities	'	'
Significant Other Observable Inputs (Level 2) [Member] | Interest Rate Derivative Contracts [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Assets	'	'
Derivative assets	'	'
Liabilities	'	'
Derivative liabilities	'	'
Significant Unobservable Inputs (Level 3) [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Assets	'	'
Derivative assets	1,423	1,347
Liabilities	'	'
Derivative liabilities	-2,288	-1,425
Significant Unobservable Inputs (Level 3) [Member] | Commodity Derivative Contracts [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Assets	'	'
Derivative assets	1,337	1,347
Liabilities	'	'
Derivative liabilities	-2,010	-1,371
Significant Unobservable Inputs (Level 3) [Member] | Interest Rate Derivative Contracts [Member] | Fair Value, Measurements, Recurring [Member]	'	'
Assets	'	'
Derivative assets	86	'
Liabilities	'	'
Derivative liabilities	($278)	($54)

Financial_Instruments_Schedule1

Financial Instruments - Schedule of Changes in Fair Value of Financial Assets and Liabilities Classified as Level 3 (Detail) (Significant Unobservable Inputs (Level 3) [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Significant Unobservable Inputs (Level 3) [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Net liabilities at beginning of period	($78)	($3,507)
Total realized and unrealized (gains) losses:	'	'
Included in earnings	-1,971	3,985
Included in other comprehensive loss	-138	-54
Purchases, sales, issuances and settlements	1,322	-502
Net liabilities at end of period	($865)	($78)

Financial_Instruments_Effect_o

Financial Instruments - Effect of Derivative Instruments on Consolidated Balance Sheets (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivatives, Fair Value [Line Items]	'	'
Derivative assets	$1,423	$1,347
Derivative liabilities	-2,288	-1,425
Total derivative instruments	-865	-78
Other Assets [Member] | Interest Rate Swap [Member] | Derivatives Designated as Cash-Flow Hedging Instruments [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative assets	86	'
Other Assets [Member] | Crude Oil Commodity Contracts [Member] | Derivatives Not Designated as Cash-Flow Hedging Instruments [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative assets	980	118
Derivative Contracts [Member] | Crude Oil Commodity Contracts [Member] | Derivatives Not Designated as Cash-Flow Hedging Instruments [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative assets	307	189
Derivative Contracts [Member] | Natural Gas Commodity Contracts [Member] | Derivatives Not Designated as Cash-Flow Hedging Instruments [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative assets	50	1,040
Derivative Liability Short-Term [Member] | Interest Rate Swap [Member] | Derivatives Designated as Cash-Flow Hedging Instruments [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative liabilities	-209	'
Derivative Liability Short-Term [Member] | Crude Oil Commodity Contracts [Member] | Derivatives Not Designated as Cash-Flow Hedging Instruments [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative liabilities	-1,667	-994
Derivative Liability Short-Term [Member] | Natural Gas Commodity Contracts [Member] | Derivatives Not Designated as Cash-Flow Hedging Instruments [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative liabilities	-318	'
Derivative Liability Long-Term [Member] | Interest Rate Swap [Member] | Derivatives Designated as Cash-Flow Hedging Instruments [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative liabilities	-69	-54
Derivative Liability Long-Term [Member] | Crude Oil Commodity Contracts [Member] | Derivatives Not Designated as Cash-Flow Hedging Instruments [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative liabilities	($25)	($377)

Financial_Instruments_Effect_o1

Financial Instruments - Effect of Derivative Instruments on Consolidated Statements of Operations (Detail) (Derivatives Not Designated as Cash-Flow Hedging Instruments [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivatives not designated as cash-flow hedge instruments:	'	'
Amount of gain/loss recognized in income	($1,971)	$3,985
Unrealized Gain (Loss) on Derivative Instruments, Net [Member] | Natural Gas Commodity Contracts [Member]	'	'
Derivatives not designated as cash-flow hedge instruments:	'	'
Amount of gain/loss recognized in income	-1,309	1,040
Unrealized Gain (Loss) on Derivative Instruments, Net [Member] | Crude Oil Commodity Contracts [Member]	'	'
Derivatives not designated as cash-flow hedge instruments:	'	'
Amount of gain/loss recognized in income	660	2,443
Realized Gain (Loss) on Derivative Instruments, Net [Member] | Natural Gas Commodity Contracts [Member]	'	'
Derivatives not designated as cash-flow hedge instruments:	'	'
Amount of gain/loss recognized in income	796	'
Realized Gain (Loss) on Derivative Instruments, Net [Member] | Crude Oil Commodity Contracts [Member]	'	'
Derivatives not designated as cash-flow hedge instruments:	'	'
Amount of gain/loss recognized in income	($2,118)	$502

Financial_Instruments_Effect_o2

Financial Instruments - Effect of Derivative Instruments on Consolidated Statements of Operations (Parenthetical) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012
Fair Value Disclosures [Abstract]	'
Gain on settlement of derivative instruments	$1.03
Net proceeds from derivative instruments	$1.03

Related_Party_Transactions_Add

Related Party Transactions - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Apr. 30, 2012	Dec. 31, 2013	Dec. 31, 2012
			Board of Directors [Member]	Board of Directors [Member]	Other Related Party [Member]	Other Related Party [Member]
Related Party Transaction [Line Items]	'	'	'	'	'	'
Repurchase interests of partners and trust unit holders	$48,000	$149,000	'	'	'	'
Treasury stock, shares	1,447,613	1,325,837	4,500	45,179	0	0
Treasury stock	$40,251,000	$36,113,000	$222,750	$1,130,000	'	'

Restricted_Cash_and_Cash_Equiv1

Restricted Cash and Cash Equivalents - Additional Information (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Cash And Cash Equivalents [Abstract]	'	'
Restricted cash and cash equivalents pertaining to oil and gas revenue payments	$2.01	$4.44

Salary_Deferral_Plan_Additiona

Salary Deferral Plan - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Compensation And Retirement Disclosure [Abstract]	'	'
Salary deferral plan, discretionary and matching contribution	$525,000	$463,000

Earnings_per_Share_Computation

Earnings per Share - Computation of Basic and Diluted Earnings (Loss) Per Share (Detail) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Share [Abstract]	'	'
Net Income, Basic	$12,271	$15,056
Net Income, Diluted	$12,271	$15,056
Weighted Average Number of Shares Outstanding, Basic	2,436,821	2,624,335
Effect of dilutive securities, Options	746,085	735,244
Weighted Average Number of Shares Outstanding, Diluted	3,182,906	3,359,579
Net Income Per Share, Basic	$5.04	$5.74
Net Income Per Share, Diluted	$3.86	$4.48

Supplementary_Information_Capi

Supplementary Information - Capitalized Costs Relating to Oil and Gas Producing Activities (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Organization Consolidation And Presentation Of Financial Statements [Abstract]	'	'
Proved Developed oil and gas properties	$362,186	$336,135
Proved Undeveloped oil and gas properties	1,937	2,069
Unproved oil and gas properties	'	'
Total Capitalized Costs	364,123	338,204
Accumulated depreciation, depletion and valuation allowance	169,100	150,276
Net Capitalized Costs	$195,023	$187,928

Supplementary_Information_Cost

Supplementary Information - Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Organization Consolidation And Presentation Of Financial Statements [Abstract]	'	'
Acquisition of Properties, Developed	$7	$6,482
Acquisition of Properties, Undeveloped	'	2,030
Exploration Costs	8	10
Development Costs	$25,912	$66,671

Supplementary_Information_Stan

Supplementary Information - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Organization Consolidation And Presentation Of Financial Statements [Abstract]	'	'
Future cash inflows	$1,880,389	$1,524,137
Future production costs	-769,172	-673,629
Future development costs	-313,754	-179,568
Future income tax expenses	-234,191	-186,072
Future Net Cash Flows	563,272	484,868
10% annual discount for estimated timing of cash flows	-325,044	-271,595
Standardized Measure of Discounted Future Net Cash Flows	$238,228	$213,273

Supplementary_Information_Stan1

Supplementary Information - Standardized Measure of Discounted Future Net Cash Flows and Changes therein Relating to Proved Oil and Gas Reserves (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Organization Consolidation And Presentation Of Financial Statements [Abstract]	'	'
Sales of oil and gas produced, net of production costs	($48,976)	($48,673)
Net changes in prices and production costs	-10,149	504
Extensions, discoveries and improved recovery	218,648	164,557
Revisions of previous quantity estimates	-733	40,964
Net change in development costs	-129,672	-145,382
Reserves sold	'	'
Reserves purchased	'	6,563
Accretion of discount	21,327	18,451
Net change in income taxes	-23,007	-5,952
Changes in production rates (timing) and other	-2,483	-2,267
Net change	24,955	28,765
Standardized measure of discounted future net cash flow:	'	'
Beginning of year	213,273	184,508
End of year	$238,228	$213,273

Supplementary_Information_Rese

Supplementary Information - Reserve Quantity Information (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
	MBbls	MBbls
Oil [Member]	'	'
Proved Developed Reserves:	'	'
Beginning of year	7,178	6,418
Extensions, discoveries and improved recovery	87	224
Revisions of previous estimates	-361	252
Converted from undeveloped reserves	513	861
Reserves sold	'	'
Reserves purchased	'	168
Production	-730	-745
End of year	6,687	7,178
Proved Undeveloped Reserves:	'	'
Beginning of year	5,907	2,435
Extensions, discoveries and improved recovery	4,536	3,446
Revisions of previous estimates	864	887
Converted to developed reserves	-513	-861
Reserves sold	'	'
Reserves purchased	'	'
End of year	9,066	5,907
Total Proved Reserves at the End of the Year	15,753	13,085
NGLs [Member]	'	'
Proved Developed Reserves:	'	'
Beginning of year	2,909	'
Extensions, discoveries and improved recovery	'	49
Revisions of previous estimates	-712	2,860
Converted from undeveloped reserves	199	'
Reserves sold	'	'
Production	-173	'
End of year	2,223	2,909
Proved Undeveloped Reserves:	'	'
Beginning of year	2,877	'
Extensions, discoveries and improved recovery	1,541	1,401
Revisions of previous estimates	-512	1,476
Converted to developed reserves	-199	'
Reserves sold	'	'
Reserves purchased	'	'
End of year	3,707	2,877
Total Proved Reserves at the End of the Year	5,930	5,786
Gas [Member]	'	'
Proved Developed Reserves:	'	'
Beginning of year	27,833	43,631
Extensions, discoveries and improved recovery	402	1,000
Revisions of previous estimates	6,456	-15,821
Converted from undeveloped reserves	1,207	3,527
Reserves sold	'	'
Reserves purchased	'	211
Production	-4,270	-4,715
End of year	31,628	27,833
Proved Undeveloped Reserves:	'	'
Beginning of year	12,613	9,765
Extensions, discoveries and improved recovery	9,538	6,158
Revisions of previous estimates	-1,172	217
Converted to developed reserves	-1,207	-3,527
Reserves sold	'	'
Reserves purchased	'	'
End of year	19,772	12,613
Total Proved Reserves at the End of the Year	51,400	40,446

Supplementary_Information_Resu

Supplementary Information - Results of Operations from Oil and Gas Producing Activities (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Revenue:	'	'
Oil and gas sales	$92,785	$88,336
Costs and Expenses:	'	'
Lease operating expenses	43,809	39,868
Exploration costs	8	10
Depreciation, depletion and accretion	19,218	19,883
Income tax expense	10,012	8,941
Total Costs and Expenses	73,047	68,702
Results of Operations From Producing Activities (excluding corporate overhead and interest costs)	$19,738	$19,634

Supplementary_Information_Addi

Supplementary Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013
Organization Consolidation And Presentation Of Financial Statements [Abstract]	'
Interest rate of Company's reserves	10.00%
Rate of discounted future net cash flows	10.00%
Percentage of discounted future prices	10.00%