Everflow Eastern Partners 10-K 27 Mar 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Jun. 30, 2014
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Entity Registrant Name	EVERFLOW EASTERN PARTNERS LP
Entity Central Index Key	868082
Current Fiscal Year End Date	-19
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		4,470,114
Entity Public Float		$0

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
CURRENT ASSETS
Cash and equivalents	$25,353,579	$24,461,680
Accounts receivable:
Production	1,461,882	2,195,519
Joint venture partners	6,775	10,623
Employees' notes receivable	70,000	95,000
Other	56,438	139,681
Total current assets	26,948,674	26,902,503
PROPERTY AND EQUIPMENT
Proved properties (successful efforts accounting method)	177,223,180	174,811,480
Pipeline and support equipment	631,757	666,667
Corporate and other	2,114,844	2,092,582
Gross property and equipment	179,969,781	177,570,729
Less accumulated depreciation, depletion, amortization and write down	148,217,198	145,560,225
Net property and equipment	31,752,583	32,010,504
OTHER ASSETS
Employees' notes receivable	70,549	118,262
Other	187,302	165,279
Total other assets	257,851	283,541
Total assets	58,959,108	59,196,548
CURRENT LIABILITIES
Accounts payable	1,819,932	1,684,610
Accrued expenses	1,466,931	1,364,183
Total current liabilities	3,286,863	3,048,793
DEFERRED INCOME TAXES	194,000	214,000
JOINT VENTURE PARTNER ADVANCES	956,072	880,270
ASSET RETIREMENT OBLIGATIONS	10,808,044	7,095,841
COMMITMENTS AND CONTINGENCIES
LIMITED PARTNERS' EQUITY, SUBJECT TO REPURCHASE RIGHT
Authorized - 8,000,000 Units Issued and outstanding - 5,601,003 and 5,606,985 Units, respectively	43,196,649	47,390,528
GENERAL PARTNER'S EQUITY	517,480	567,116
Total partners' equity	43,714,129	47,957,644
Total liabilities and partners' equity	$58,959,108	$59,196,548

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical)	Dec. 31, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Limited partners' equity, Units authorized	8,000,000	8,000,000
Limited partners' equity, Units issued	5,601,003	5,606,985
Limited partners' equity, Units outstanding	5,601,003	5,606,985

Consolidated_Statements_of_Inc

Consolidated Statements of Income (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
REVENUES
Crude oil and natural gas sales	$13,247,538	$16,804,745
Well management and operating	582,134	620,583
Other	10,531	12,426
Total revenues	13,840,203	17,437,754
DIRECT COST OF REVENUES
Production costs	3,655,764	4,018,918
Well management and operating	287,419	371,109
Depreciation, depletion and amortization	3,405,318	3,546,003
Accretion expense	642,799	406,479
Write down/impairment and abandonment of crude oil and natural gas properties	107,018	34,385
Total direct cost of revenues	8,098,318	8,376,894
GENERAL AND ADMINISTRATIVE EXPENSE	2,906,989	2,745,658
Total cost of revenues	11,005,307	11,122,552
INCOME FROM OPERATIONS BEFORE GAIN ON SALE OF DEEP RIGHTS	2,834,896	6,315,202
GAIN ON SALE OF DEEP RIGHTS		2,761,705
INCOME FROM OPERATIONS	2,834,896	9,076,907
OTHER INCOME
Interest income	42,821	50,246
Gain (loss) on sale of property and equipment	4,791	-1,599
Total other income	47,612	48,647
INCOME BEFORE INCOME TAXES	2,882,508	9,125,554
INCOME TAX EXPENSE (BENEFIT)
Current	18,963	25,020
Deferred	-20,000	489,000
Total income tax (benefit) expense	-1,037	514,020
NET INCOME	2,883,545	8,611,534
Allocation of Partnership Net Income
Limited Partners	2,849,428	8,509,742
General Partner	34,117	101,792
NET INCOME	$2,883,545	$8,611,534
Net income per unit	$0.51	$1.52

Consolidated_Statements_of_Par

Consolidated Statements of Partners' Equity (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Statement of Partners' Capital [Abstract]
PARTNERS' EQUITY - JANUARY 1	$47,957,644	$49,303,756
Net income	2,883,545	8,611,534
Quarterly cash distributions ($1.25 per unit in 2014 and $1.75 per unit in 2013)	-7,088,117	-9,934,375
Repurchase of Units	-77,886	-46,543
Options exercised	38,943	23,272
PARTNERS' EQUITY - DECEMBER 31	$43,714,129	$47,957,644

Consolidated_Statements_of_Par1

Consolidated Statements of Partners' Equity (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Statement of Partners' Capital [Abstract]
Quarterly cash distributions per unit	$1.25	$1.75

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$2,883,545	$8,611,534
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	3,495,201	3,635,345
Accretion expense	642,799	406,479
Write down/impairment and abandonment of crude oil and natural gas properties	107,018	34,385
Gain on sale of deep rights		-2,761,705
(Gain) loss on sale of property and equipment	-4,791	1,599
Deferred income taxes	-20,000	489,000
Changes in assets and liabilities:
Accounts receivable	737,485	76,348
Other current assets	83,243	-13,150
Other assets	-22,023	-5,680
Accounts payable	135,322	-385,253
Accrued expenses	48,703	-176,726
Joint venture partner advances	75,802	154,510
Total adjustments	5,278,759	1,455,152
Net cash provided by operating activities	8,162,304	10,066,686
CASH FLOWS FROM INVESTING ACTIVITIES
Payments received on notes receivables from employees	82,778	92,080
Advances disbursed to employees	-10,065	-33,875
Purchase of property and equipment	-234,058	-1,141,182
Proceeds from sale of property and equipment	18,000	38,500
Net cash used in investing activities	-143,345	-1,044,477
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions	-7,088,117	-9,934,375
Repurchase of Units	-77,886	-46,543
Proceeds from options exercised	38,943	23,272
Net cash used in financing activities	-7,127,060	-9,957,646
NET CHANGE IN CASH AND EQUIVALENTS	891,899	-935,437
CASH AND EQUIVALENTS AT BEGINNING OF PERIOD	24,461,680	25,397,117
CASH AND EQUIVALENTS AT END OF PERIOD	25,353,579	24,461,680
Cash paid during the year for:
Income taxes	$11,131	$247,932

Organization_and_Summary_of_Si

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Organization and Summary of Significant Accounting Policies	Note 1.	Organization and Summary of Significant Accounting Policies
		A.	Organization – Everflow Eastern Partners, L.P. (“Everflow”) is a Delaware limited partnership which was organized in September 1990 to engage in the business of oil and gas acquisition, exploration, development and production. Everflow was formed to consolidate the business and crude oil and natural gas properties of Everflow Eastern, Inc. (“EEI”) and subsidiaries and the crude oil and natural gas properties owned by certain limited partnership and working interest programs managed or sponsored by EEI (“EEI Programs” or the “Programs”).
	Everflow Management Limited, LLC (“EML”), an Ohio limited liability company, is the general partner of Everflow and, as such, is authorized to perform all acts necessary or desirable to carry out the purposes and conduct of the business of Everflow. The members of EML are Everflow Management Corporation (“EMC”); two individuals who are officers and directors of EEI and employees of Everflow; one individual who is the Chairman of the Board of EEI; one individual who is an employee of Everflow; and one private limited liability company founded by an individual who is a director of EEI. EMC is an Ohio corporation formed in September 1990 and is the managing member of EML. EML holds no assets other than its general partner’s interest in Everflow, nor does it have any liabilities. In addition, EML has no separate operations or role apart from its role as the Company’s general partner.
		B.	Principles of Consolidation – The consolidated financial statements include the accounts of Everflow, its wholly-owned subsidiaries, including EEI, and interests with joint venture partners (collectively, the “Company”), which are accounted for under the proportional consolidation method. All significant accounts and transactions between the consolidated entities have been eliminated.
		C.	Use of Estimates – The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“generally accepted accounting principles” or “GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates impacting the Company’s financial statements include revenue and expense accruals and oil and gas reserve quantities. In the oil and gas industry, and especially as related to the Company’s natural gas sales, the processing of actual transactions generally occurs 60-90 days after the month of delivery of its product. Consequently, accounts receivable from production and crude oil and natural gas sales are recorded using estimated production volumes and market or contract prices. Differences between estimated and actual amounts are recorded in subsequent period’s financial results. As is typical in the oil and gas industry, a significant portion of the Company’s accounts receivable from production and crude oil and natural gas sales consists of unbilled receivables. Oil and gas reserve quantities are utilized in the calculation of depreciation, depletion and amortization and the impairment of crude oil and natural gas wells and also impact the timing and costs associated with asset retirement obligations. The Company’s estimates, especially those related to oil and gas reserves, could change in the near term and could significantly impact the Company’s results of operations and financial position.
		D.	Fair Value of Financial Instruments – The fair values of cash and equivalents, accounts and notes receivable, accounts payable and other short-term obligations approximate their carrying values because of the short maturity of these financial instruments. The carrying values of the Company’s long-term obligations approximate their fair value. In accordance with generally accepted accounting principles, rates available to the Company at the balance sheet dates are used to estimate the fair value of existing obligations.
		E.	Cash and Equivalents – The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. The Company maintains, at various financial institutions, cash and equivalents which may exceed federally insured amounts and which may, at times, significantly exceed balance sheet amounts due to float. Cash and equivalents include $956,072 and $880,270 of joint venture partner advances at December 31, 2014 and 2013, respectively, which are funds collected and held on behalf of joint venture partners for their anticipated share of future plugging and abandonment costs, including interest earned.
		F.	Property and Equipment – The Company uses the successful efforts method of accounting for oil and gas exploration and production activities. Under successful efforts, costs to acquire mineral interests in oil and gas properties, to drill and equip development wells and related asset retirement costs are capitalized. Costs of development wells (on properties the Company has no further interest in) that do not find proved reserves and geological and geophysical costs are expensed. The Company has not participated in exploratory drilling and owns no interest in unproved properties.
	Capitalized costs of proved properties, after considering estimated dismantlement and abandonment costs and estimated salvage values, are amortized by the unit-of-production method based upon estimated proved developed reserves. Depletion, depreciation and amortization on proved properties amounted to $3,362,240 and $3,493,540 during 2014 and 2013, respectively.
	On sale or retirement of a unit of a proved property (which generally constitutes the amortization base), the cost and related accumulated depreciation, depletion, amortization and write down are eliminated from the property accounts, and the resultant gain or loss is recognized.
	Generally accepted accounting principles require that long-lived assets (including oil and gas properties) and certain identifiable intangibles be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The Company, at least annually, reviews its proved crude oil and natural gas properties (on a field by field basis) for impairment by comparing the carrying value of its properties to the properties’ undiscounted estimated future net cash flows. Estimates of future crude oil and natural gas prices, operating costs, and production are utilized in determining undiscounted future net cash flows. The estimated future production of oil and gas reserves is based upon the Company’s independent reserve engineer’s estimate of proved reserves which includes assumptions regarding field decline rates and future prices and costs. For properties where the carrying value exceeds undiscounted future net cash flows, the Company recognizes as impairment the difference between the carrying value and fair market value of the properties. The Company determines fair market value, using the income approach, as the properties’ discounted estimated future net cash flows. The key assumptions above are not observable in the market and therefore the fair value of the oil and gas properties is classified as Level 3. The Company wrote down crude oil and natural gas properties by $107,018 and $34,385 during 2014 and 2013, respectively, to provide for impairment and abandonment on certain of its crude oil and natural gas properties.
	Additions to proved properties include changes to asset retirement obligations (see Note 1.G).
	Pipeline and support equipment and other corporate property and equipment are recorded at cost and depreciated principally on the straight-line method over their estimated useful lives (pipeline and support equipment - 10 to 15 years, other corporate equipment - 3 to 7 years, other corporate property - building and improvements with a cost of $1,536,288 – 39 to 40 years). Depreciation on pipeline and support equipment amounted to $43,078 and $52,463 for the years ended December 31, 2014 and 2013, respectively. Depreciation on other corporate property and equipment, included in general and administrative expense, amounted to $89,883 and $89,342 for the years ended December 31, 2014 and 2013, respectively.
	Maintenance and repairs of property and equipment are expensed as incurred. Major renewals and improvements are capitalized, and the assets replaced are retired.
		G.	Asset Retirement Obligations – Generally accepted accounting principles require the fair value of a liability for an asset retirement obligation to be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. For the Company, these obligations include dismantlement, plugging and abandonment of crude oil and natural gas wells and associated pipelines and equipment. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depleted over the estimated useful life of the related asset.
	The estimated liability is based on historical experience in dismantling, plugging and abandoning wells, estimated remaining lives of those wells based on reserves estimates, estimates of the external cost to dismantle, plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability will likely occur due to: changes in estimates of dismantlement, plugging and abandonment costs; changes in estimated remaining lives of the wells; changes in federal or state regulations regarding plugging and abandonment requirements; and other factors. At December 31, 2014, the Company made revisions in estimates of plugging costs and remaining lives of wells.
	The Company has no assets legally restricted for purposes of settling asset retirement obligations. The Company has determined that there are no other material retirement obligations associated with tangible long-lived assets.
	The schedule below is a reconciliation of the Company’s liability for the years ended December 31:
			2014			2013
	Beginning of period		$	7,395,841		$	6,996,744
	Liabilities incurred			819			6,295
	Liabilities settled			(54,045	)		(13,677	)
	Accretion expense			642,799			406,479
	Revisions in estimated cash flows			3,122,630			—
	End of period		$	11,108,044		$	7,395,841
	The current portion of asset retirement obligations of $300,000 at December 31, 2014 and 2013, respectively, is included in accrued expenses in the Company’s consolidated balance sheets.
		H.	Revenue Recognition – The Company recognizes crude oil and natural gas revenues when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred, title and risk of loss have transferred to the purchaser, and collectability of the revenue is reasonably assured. The Company utilizes the sales method to account for gas production volume imbalances. Under this method, revenue is recognized only when gas is produced and sold on the Company’s behalf. The Company had no material gas imbalances at December 31, 2014 or 2013. Other revenue is recognized at the time services are rendered, the Company has a contractual right to such revenue and collection is reasonably assured. Gain on sale of deep rights is recognized when title to deep mineral interests has been transferred and all terms and conditions to the sale have been met. Substantially all of the Company’s gain on sale of deep rights recognized during 2013 represents funds previously recognized as deferred revenue.
	The Company participates (and may act as drilling contractor) with unaffiliated joint venture partners and employees in the drilling, development and operation of jointly owned crude oil and natural gas properties. Each owner, including the Company, has an undivided interest in the jointly owned properties. Generally, the joint venture partners and employees participate on the same drilling/development cost basis as the Company and, therefore, no revenue, expense or income is recognized on the drilling and development of the properties. Accounts and notes receivable from joint venture partners and employees consist principally of drilling and development costs the Company has advanced or incurred on behalf of joint venture partners and employees (see Note 6). Accounts payable to joint venture partners consist principally of deposits received from joint venture partners for drilling and development costs not yet incurred (see Note 2). The Company earns and receives monthly management and operating fees from certain joint venture partners and employees after the properties are completed and placed into production.
		I.	Income Taxes – Everflow is not a tax-paying entity and the net taxable income or loss, other than the taxable income or loss allocable to EEI, which is a C corporation owned by Everflow, will be allocated directly to its respective partners. The Company is not able to determine the net difference between the tax bases and the reported amounts of Everflow’s assets and liabilities due to separate elections that were made by owners of the working interests and limited partnership interests that comprised Programs.
	As referred to in Note 4, EEI accounts for income taxes under generally accepted accounting principles, which require income taxes be provided for all items (as they relate to EEI) in the consolidated statements of income regardless of the period when such items are reported for income tax purposes. Therefore, deferred tax assets and liabilities are recognized for temporary differences between the financial reporting basis and tax basis of certain EEI assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled. The impact on deferred taxes of changes in tax rates and laws, if any, is reflected in the financial statements in the period of enactment.
	The Company believes that it has appropriate support for any tax positions taken and, as such, does not have any uncertain tax positions that are material to the financial statements. The Company’s tax returns are subject to examination by the Internal Revenue Service, as well as various state and local taxing authorities, generally for three years after they are filed.
		J.	Allocation of Income and Per Unit Data – Under the terms of the limited partnership agreement, initially 99% of revenues and costs were allocated to the Unitholders (the limited partners) and 1% of revenues and costs were allocated to the general partner. Such allocation has changed and will likely change in the future as Unitholders elect to exercise the Repurchase Right and select officers and employees elect to exercise options (see Note 3).
	Earnings per limited partner Unit have been computed based on the weighted average number of Units outstanding during each year presented. Average outstanding Units for earnings per Unit calculations amount to 5,603,994 and 5,609,350 in 2014 and 2013, respectively.
		K.	Subsequent Events - Everflow paid a cash distribution in January 2015 of $0.25 per Unit. The distribution amounted to approximately $1,417,000.
		L.	New Accounting Standards – In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update No. 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”). ASU 2014-09 is intended to improve the financial reporting requirements for revenue from contracts with customers by providing a principle based approach. The core principle of the standard is that revenue should be recognized when the transfer of promised goods or services is made in an amount that the entity expects to be entitled to in exchange for the transfer of goods and services. ASU 2014-09 also requires disclosures enabling users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. This standard will be effective for financial statements issued by public companies for annual reporting periods beginning after December 15, 2016. Early adoption is not permitted. The Company is currently evaluating the potential impact of ASU 2014-09 on the financial statements.
	The Company has reviewed all other recently issued accounting standards in order to determine their effects, if any, on the consolidated financial statements. Based on that review, the Company believes that none of these standards will have a significant effect on current or future earnings or operations.

Current_Liabilities

Current Liabilities	12 Months Ended
	Dec. 31, 2014
Payables and Accruals [Abstract]
Current Liabilities	Note 2.	Current Liabilities
	The Company’s accounts payable and accrued expenses consist of the following at December 31:
			2014		2013
	Accounts Payable:
	Production and related other		$	1,420,238	$	1,274,763
	Other			288,521		287,460
	Joint venture partner deposits			111,173		122,387
			$	1,819,932	$	1,684,610
	Accrued Expenses:
	Payroll and retirement plan contributions		$	1,055,255	$	963,783
	Current portion of asset retirement obligations			300,000		300,000
	Other			80,300		72,200
	Federal, state and local taxes			31,376		28,200
			$	1,466,931	$	1,364,183

Partners_Equity

Partners' Equity	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Partners' Equity	Note 3.	Partners’ Equity
	Units represent limited partnership interests in Everflow. The Units are transferable subject only to the approval of any transfer by EML and to the laws governing the transfer of securities. The Units are not listed for trading on any securities exchange nor are they quoted in the automated quotation system of a registered securities association. However, Unitholders have an opportunity to require Everflow to repurchase their Units pursuant to the Repurchase Right.
	The partnership agreement provides that Everflow will repurchase for cash up to 10% of the then outstanding Units, to the extent Unitholders offer Units to Everflow for repurchase pursuant to the Repurchase Right. The Repurchase Right entitles any Unitholder, between May 1 and June 30 of each year, to notify Everflow that the Unitholder elects to exercise the Repurchase Right and have Everflow acquire certain or all Units. The price to be paid for any such Units is calculated based upon the audited financial statements of the Company as of December 31 of the year prior to the year in which the Repurchase Right is to be effective and independently prepared reserve reports. The price per Unit equals 66% of the adjusted book value of the Company allocable to the Units, divided by the number of Units outstanding at the beginning of the year in which the applicable Repurchase Right is to be effective less all interim cash distributions received by a Unitholder. The adjusted book value is calculated by adding partners’ equity, the standardized measure of discounted future net cash flows and the tax effect included in the standardized measure and subtracting from that sum the carrying value of oil and gas properties (net of undeveloped lease costs). If more than 10% of the then outstanding Units are tendered during any period during which the Repurchase Right is to be effective, the investors’ Units tendered shall be prorated for purposes of calculating the actual number of Units to be acquired during any such period. The price associated with the 2015 Repurchase Right, based upon the December 31, 2014 calculation, is estimated to be $4.56 per Unit, net of the distributions made in January 2015 ($0.25 per Unit) and expected to be made in April 2015 ($0.125 per Unit).
	The Company has an Option Repurchase Plan (the “Option Plan”) which permits the grant of options to repurchase certain Units to select officers and employees (the “Option Plan Participants”). The purpose of the Option Plan is to assist the Company in attracting and retaining officers and other key employees and to enable those individuals to acquire or increase their ownership interest in the Company in order to encourage them to promote the growth and profitability of the Company. The Option Plan is designed to align directly the financial interests of the Option Plan Participants with the financial interests of the Unitholders. In June 2014 and 2013, the Company granted options to officers and an employee. All options granted were exercised on the same date. Compensation expense associated with these grants was not material to the financial statements.
	Units repurchased pursuant to the Repurchase Right and Units issued through the exercise of options pursuant to the Option Plan (collectively the “Units Activity”) for the three years ended December 31, 2014, are as follows:
	Year		Price for		Less Interim		Net Price Paid		Units		Units Issued		Units
			Repurchase		Distributions				Repurchased				Outstanding
			Right										Following
													Units Activity
	2012		$	9.17	$	0.88	$	8.29		9,414		4,707		5,611,715
	2013		$	5.92	$	1	$	4.92		9,460		4,730		5,606,985
	2014		$	7.01	$	0.5	$	6.51		11,964		5,982		5,601,003
	All Units repurchased pursuant to the Repurchase Right were retired except for those Units issued through the exercise of options pursuant to the Option Plan. There were no instruments outstanding at December 31, 2014 or 2013 that would potentially dilute net income per Unit.

Provision_for_Income_Taxes

Provision for Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Provision for Income Taxes	Note 4.	Provision for Income Taxes
	A reconciliation between taxes computed at the Federal statutory rate and the effective tax rate in the statements of income follows:
			Year Ended December 31,
			2014						2013
			Amount			%			Amount			%
	Provision based on the statutory rate		$	980,000			34		$	3,103,000			34
	Tax effect of:
	Non-taxable status of the Programs and Everflow			(981,000	)		(34.0	)		(2,517,000	)		(27.6	)
	Excess statutory depletion			(53,000	)		(1.8	)		(55,000	)		(0.6	)
	Graduated tax rates, permanent differences between book and tax items, tax credits and other - net			52,963			1.8			(16,980	)		(0.2	)
	Total		$	(1,037	)		—		$	514,020			5.6
	As referred to in Note 1, EEI accounts for current and deferred income taxes under the provisions of generally accepted accounting principles. Items giving rise to deferred taxes consist of temporary differences arising from differences in financial reporting and tax reporting methods for EEI’s proved properties and deferred revenue. The Company recognized $509,000 of deferred income tax expense during 2013 related to deferred tax assets recognized at December 31, 2012. The Company recognized $20,000 of deferred income tax benefit during 2014 and 2013, respectively, related to deferred tax liabilities recognized at December 31, 2013 and 2012, respectively. At December 31, 2014 and 2013, the Company recognized deferred tax liabilities of $194,000 and $214,000, respectively.

Retirement_Plans

Retirement Plans	12 Months Ended
	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Retirement Plans	Note 5.	Retirement Plans
	The Company has a defined contribution plan pursuant to Section 401(k) of the Internal Revenue Code for all employees who have reached the age of 21 and completed one year of service (the “Defined Contribution Plan”, or the “DC Plan”). The Company makes safe harbor contributions and matches employees’ contributions to the Defined Contribution Plan as annually determined by EMC’s Board of Directors. Additionally, the DC Plan has a profit sharing component which provides for contributions to the DC Plan at the discretion of EMC’s Board of Directors. Amounts contributed to the DC Plan vest immediately. The Company’s total contributions to the Defined Contribution Plan amounted to approximately $212,000 and $224,000 for the years ended December 31, 2014 and 2013, respectively.
	The Company has a qualified non-contributory cash balance defined benefit retirement plan covering certain eligible employees (the “Pension Plan”, or the “Plan”). Participants accumulate annual service credits as determined by their participation level according to the plan document and become fully vested after three years of service, including credits given for prior service. Interest is accrued on these accumulated amounts at an annual rate of 5%.
	Net periodic benefit cost recognized in the consolidated statements of income consists of the following during the years ended December 31:
			2014			2013
	Service cost		$	323,900		$	308,500
	Interest cost			30,700			14,500
	Expected return on plan assets			(27,300	)		(18,500	)
	Net periodic benefit cost		$	327,300		$	304,500
	The projected benefit obligation (the “PBO”) and accumulated benefit obligation are determined as the actuarial present value of the vested benefits to which the employees are currently entitled but based on their expected date of separation or retirement. The change in the projected benefit obligation of the Pension Plan and the change in assets at fair value are as follows during the years ended December 31:
			2014			2013
	Change in PBO:
	PBO, beginning of year		$	620,000		$	290,500
	Service cost			323,900			308,500
	Interest cost			30,700			14,500
	Actuarial loss			19,200			8,500
	Benefits paid			(3,100	)		(2,000	)
	PBO, end of year			990,700			620,000
	Change in Plan assets:
	Fair value, beginning of year			301,500			1,000
	Actual return on plan assets			23,700			13,500
	Company contributions			318,500			289,000
	Benefits paid			(3,100	)		(2,000	)
	Fair value, end of year		$	640,600		$	301,500
	Funded status at December 31		$	(350,100	)	$	(318,500	)
	The Company’s funding policy is to fund at least the amount actuarially determined necessary to comply with the minimum funding standards as defined by the Employee Retirement Income Security Act. The entire underfunded amounts at December 31, 2014 and 2013, which are recognized as accrued expenses in the consolidated balance sheets, were funded in March of their subsequent years and no other contributions are expected to be made in 2015.
	Assumptions used in accounting for the projected benefit obligations at December 31, 2014 and 2013 include a discount rate of 5% and long-term asset return of 7%.
	The Plan’s investment policy reflects the long-term nature of the plan’s funding obligations. The assets are invested to provide the opportunity for both income and growth of principal. This objective is pursued as a long-term goal designed to provide required benefits for participants without undue risk. It is expected that this objective can be achieved through a well-diversified asset portfolio. As such, the Plan’s assets, which are classified as Level 1 assets, were invested in a publicly traded mutual fund with a domestic blend of stocks and bonds at December 31, 2014 and 2013.
	Future benefit payments, which reflect expected future service, as appropriate, are estimated to be $40,000 in the aggregate over the next five years and $1,666,300 in the aggregate over the next five years thereafter.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Related Party Transactions	Note 6.	Related Party Transactions
	The Company’s Officers, Directors, affiliates and certain employees have frequently participated, and will likely continue to participate in the future, as working interest owners in wells in which the Company has an interest. Frequently, the Company has loaned the funds necessary for certain employees to participate in the drilling and development of such wells. Initial terms of the unsecured loans call for repayment of all principal and accrued interest at the end of four years, however, the loan amounts are reduced as production proceeds attributable to the employees’ working interests are not remitted to the employees but rather used to reduce the amounts owed by the employees to the Company. If an outstanding balance remains after the initial four-year term, the Company and employee shall, acting in good faith, agree upon further repayment terms.
	Employees remain obligated for the entire loan amount regardless of a dry-hole event or otherwise insufficient production. The loans carry no loan forgiveness provisions, and no loans have ever been forgiven. The loans accrue interest at the prime rate, which was 3.25% at December 31, 2014.
	In accordance with the Sarbanes-Oxley Act of 2002, the Company has not extended any loans to officers or directors since 2002. At December 31, 2014 and 2013, the Company has extended various loans, evidenced by notes, to two employees with origination dates ranging from December 2010 to December 2014. In addition, two subsequent addenda extending additional two-year payment terms to certain notes are outstanding at December 31, 2014. Employee notes receivables, including accrued interest, amounted to $140,549 and $213,262 at December 31, 2014 and 2013, respectively.

Business_Segments_Risks_and_Ma

Business Segments, Risks and Major Customers	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Business Segments, Risks and Major Customers	Note 7.	Business Segments, Risks and Major Customers
	The Company operates exclusively in the United States, almost entirely in Ohio and Pennsylvania, in the acquisition, exploration, development and production of oil and gas.
	The Company operates in an environment with many financial risks, including, but not limited to, the ability to acquire additional economically recoverable oil and gas reserves, the inherent risks of the search for, development of and production of oil and gas, the ability to sell oil and gas at prices which will provide attractive rates of return, the volatility and seasonality of oil and gas production and prices, and the highly competitive and, at times, seasonal nature of the industry and worldwide economic conditions. The Company’s ability to expand its reserve base and diversify its operations is also dependent upon the Company’s ability to obtain the necessary capital through operating cash flow, borrowings or equity offerings. Various federal, state and governmental agencies are considering, and some have adopted, laws and regulations regarding environmental protection which could adversely affect the proposed business activities of the Company. The Company cannot predict what effect, if any, current and future regulations may have on the operations of the Company.
	Management of the Company continually evaluates whether the Company can develop oil and gas properties at historical levels given current industry and market conditions. If the Company is unable to do so, it could be determined that it is in the best interests of the Company and its Unitholders to reorganize, liquidate or sell the Company. However, management cannot predict whether any sale transaction will be a viable alternative for the Company in the immediate future.
	Natural gas sales accounted for 64% and 65% of total crude oil and natural gas sales in 2014 and 2013, respectively. Approximately 72% of total crude oil and natural gas sales were derived from operated wells in 2014 and 2013, respectively. The Company had two significant purchasers of natural gas production from operated wells for the years ended December 31, 2014 and 2013. Natural gas sales to these significant purchasers as a percentage of consolidated crude oil and natural gas sales were as follows:
	Natural Gas Purchaser		2014			2013
	Dominion Field Services, Inc. (“Dominion”)			29	%		31	%
	Interstate Gas Supply, Inc. (“IGS”)			13			13
				42	%		44	%
	As of December 31, 2014, natural gas purchased by Dominion covers production from approximately 470 gross operated wells, while natural gas purchased by IGS covers production from approximately 200 gross operated wells. Production purchased by Dominion and IGS from operated wells comprised approximately 66% and 67% of the Company’s consolidated natural gas sales in 2014 and 2013, respectively.
	Substantially all of the Company’s crude oil production from operated wells is purchased by Ergon Oil Purchasing, Inc. (“Ergon Oil”).
	The Company’s production accounts receivable result from sales of natural gas and crude oil. A significant portion of the Company’s production accounts receivable is due from the Company’s major customers. The Company does not view such concentration as an unusual credit risk. However, the Company does not require collateral from its customers and could incur losses if its customers fail to pay. As a result of management’s review of current and historical credit losses and economic activity, a valuation allowance was not deemed necessary at December 31, 2014 and 2013. The Company expects that Dominion, IGS and Ergon Oil will continue to be the only major customers for natural gas and crude oil production from its operated wells in 2015. Historically, the Company has not tracked the purchasers of natural gas and crude oil derived from third party operated wells which may have the same customers.
	The Company has multiple annual contracts with Dominion and IGS (the “Major Gas Purchasers”), which obligate the Major Gas Purchasers to purchase, and the Company to sell and deliver, certain quantities of natural gas production from the Company’s oil and gas properties throughout the contract periods. The Company may elect to lock-in specific volumes of natural gas to be sold in specific months at a mutually agreeable price. The Company has elected to lock-in various monthly quantities of natural gas which total 780,000 MCF through October 2015 at various monthly weighted-average pricing provisions averaging approximately $3.26 per MCF, net of estimated regional basis adjustments. Pricing provisions with the Major Gas Purchasers apply to certain fixed quantities on a monthly basis with excess monthly quantities being priced based on the current spot market price, plus or minus a current regional basis adjustment. The impact of these contracts on the Company’s future oil and gas sales cannot fully be measured until actual production volumes and prices have been determined.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 8.	Commitments and Contingencies
	As referred to in Note 7, the Company has natural gas delivery commitments to Dominion and IGS. Management believes the Company can meet its delivery commitments based on estimated production. If, however, the Company cannot meet its delivery commitments, it may be required to purchase natural gas at market prices to meet such commitments which may result in a gain or loss for the difference between the delivery commitment price and the price at which the Company is able to purchase the gas for redelivery (resale) to its customers.
	In conjunction with the sale of approximately 28,800 acres of deep rights made in 2012, the Company agreed to perpetuate the producing leases for a minimum period of five years. If the Company fails to perpetuate the producing leases during such five-year period, it shall refund to the purchaser the portion of the purchase price attributable to the affected properties based on an allocated value of $1,250 per acre (the “Refund Price”), provided however, that should the Company revive or otherwise renew such expired leases within three months of their expiration, the purchaser shall have the right to acquire the deep rights on such revived or renewed leases for the Refund Price. The Company has assessed the shallow operations of all properties from which deep acreage was sold and does not believe a reserve for potential refunded acreage to be necessary at December 31, 2014.
	The Company is party to various legal proceedings and claims in the ordinary course of its business. The Company believes certain of these matters will be covered by insurance and that the outcome of other matters will not have a material adverse effect on its consolidated financial position, results of operations, or liquidity.

Supplemental_Information_Relat

Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited)	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited)	Note 9.	Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited)
	The following supplemental unaudited oil and gas information is required by generally accepted accounting principles.
	The tables on the following pages set forth pertinent data with respect to the Company’s oil and gas properties, all of which are located within the continental United States.
	CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
			Years ended December 31,
			2014			2013
	Proved oil and gas properties		$	177,223,180		$	174,811,480
	Pipeline and support equipment			631,757			666,667
				177,854,937			175,478,147
	Accumulated depreciation, depletion, amortization and write down			147,304,820			144,715,506
	Net capitalized costs		$	30,550,117		$	30,762,641
	COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
			Years ended December 31,
			2014			2013
	Property acquisition costs		$	13,015		$	42,846
	Development costs			149,405			956,611
	The Company had no purchases of producing oil and gas properties in 2014 or 2013.
	RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
			Years ended December 31,
			2014			2013
	Crude oil and natural gas sales		$	13,247,538		$	16,804,745
	Production costs			(3,655,764	)		(4,018,918	)
	Depreciation, depletion and amortization			(3,405,318	)		(3,546,003	)
	Accretion expense			(642,799	)		(406,479	)
	Write down/impairment and abandonment of crude oil and natural gas properties			(107,018	)		(34,385	)
				5,436,639			8,798,960
	Income tax expense			19,000			25,000
	Results of operations for oil and gas producing activities (excluding corporate overhead and financing costs)		$	5,417,639		$	8,773,960
	Income tax expense was computed using statutory tax rates and reflects permanent differences that are reflected in the Company’s consolidated income tax expense for the year.
	ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
			Oil			Gas
			(BBLS)			(MCFS)
	Balance, January 1, 2013			579,000			25,644,000
	Extensions, discoveries and other additions			25,000			177,000
	Production			(62,000	)		(2,846,000	)
	Revision of previous estimates			44,000			4,678,000
	Balance, December 31, 2013			586,000			27,653,000
	Extensions, discoveries and other additions			2,000			8,000
	Production			(53,000	)		(2,269,000	)
	Revision of previous estimates			(24,000	)		(1,668,000	)
	Balance, December 31, 2014			511,000			23,724,000
	PROVED DEVELOPED RESERVES:
	December 31, 2012			579,000			25,644,000
	December 31, 2013			586,000			27,653,000
	December 31, 2014			511,000			23,724,000
	The Company has not determined proved reserves associated with its proved and other undeveloped properties, including its deep property interests. At December 31, 2014 and 2013, the Company had 394 and 498 net proved undeveloped acres, respectively. The net carrying cost of the proved undeveloped acreage that is included in proved properties amounted to approximately $214,600 and $341,600 at December 31, 2014 and 2013, respectively.
	STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
			December 31,
			2014			2013
			(Thousands of Dollars)
	Future cash inflows from sales of oil and gas		$	124,127		$	150,370
	Future production and development costs			(60,296	)		(67,947	)
	Future asset retirement obligations, net of salvage			(16,506	)		(11,668	)
	Future income tax expense			(1,159	)		(1,570	)
	Future net cash flows			46,166			69,185
	Effect of discounting future net cash flows at 10% per annum			(18,009	)		(27,524	)
	Standardized measure of discounted future net cash flows		$	28,157		$	41,661
	CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
			Years Ended December 31,
			2014			2013
			(Thousands of Dollars)
	Balance, beginning of year		$	41,661		$	33,543
	Extensions, discoveries and other additions			29			1,401
	Development costs incurred			42			—
Revision of quantity estimates			(1,538	)		5,335
Sales of crude oil and natural gas, net of production costs			(9,592	)		(12,786	)
Net change in income taxes			226			(118	)
Net changes in prices and production costs			(3,912	)		5,670
Accretion of discount			4,166			3,354
Other			(2,925	)		5,262
Balance, end of year		$	28,157		$	41,661
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures including many factors beyond the control of the Company. The estimated future cash flows are determined based on crude oil and natural gas pricing parameters established by generally accepted accounting principles, adjusted for contract terms within contract periods, estimated production of proved crude oil and natural gas reserves, estimated future production and development costs of reserves and future retirement obligations (net of salvage), based on current economic conditions, and the estimated future income tax expense, based on year-end statutory tax rates (with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less the tax basis of the properties involved. Such cash flows are then discounted using a 10% rate.
The methodology and assumptions used in calculating the standardized measure are those required by generally accepted accounting principles and United States Securities and Exchange Commission reporting requirements. It is not intended to be representative of the fair market value of the Company’s proved reserves. The valuation of revenues and costs does not necessarily reflect the amounts to be received or expended by the Company. In addition to the valuations used, numerous other factors are considered in evaluating known and prospective oil and gas reserves.
Average adjusted natural gas prices used in the estimation of proved reserves were $3.28 and $3.43 at December 31, 2014 and 2013, respectively, and the average adjusted crude oil prices used in the estimation of proved reserves were $90.53 and $94.49 at December 31, 2014 and 2013, respectively.

Organization_and_Summary_of_Si1

Organization and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Organization		A.	Organization – Everflow Eastern Partners, L.P. (“Everflow”) is a Delaware limited partnership which was organized in September 1990 to engage in the business of oil and gas acquisition, exploration, development and production. Everflow was formed to consolidate the business and crude oil and natural gas properties of Everflow Eastern, Inc. (“EEI”) and subsidiaries and the crude oil and natural gas properties owned by certain limited partnership and working interest programs managed or sponsored by EEI (“EEI Programs” or the “Programs”).
	Everflow Management Limited, LLC (“EML”), an Ohio limited liability company, is the general partner of Everflow and, as such, is authorized to perform all acts necessary or desirable to carry out the purposes and conduct of the business of Everflow. The members of EML are Everflow Management Corporation (“EMC”); two individuals who are officers and directors of EEI and employees of Everflow; one individual who is the Chairman of the Board of EEI; one individual who is an employee of Everflow; and one private limited liability company founded by an individual who is a director of EEI. EMC is an Ohio corporation formed in September 1990 and is the managing member of EML. EML holds no assets other than its general partner’s interest in Everflow, nor does it have any liabilities. In addition, EML has no separate operations or role apart from its role as the Company’s general partner.
Principles of Consolidation	B.	Principles of Consolidation – The consolidated financial statements include the accounts of Everflow, its wholly-owned subsidiaries, including EEI, and interests with joint venture partners (collectively, the “Company”), which are accounted for under the proportional consolidation method. All significant accounts and transactions between the consolidated entities have been eliminated.
Use of Estimates	C.	Use of Estimates – The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“generally accepted accounting principles” or “GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates impacting the Company’s financial statements include revenue and expense accruals and oil and gas reserve quantities. In the oil and gas industry, and especially as related to the Company’s natural gas sales, the processing of actual transactions generally occurs 60-90 days after the month of delivery of its product. Consequently, accounts receivable from production and crude oil and natural gas sales are recorded using estimated production volumes and market or contract prices. Differences between estimated and actual amounts are recorded in subsequent period’s financial results. As is typical in the oil and gas industry, a significant portion of the Company’s accounts receivable from production and crude oil and natural gas sales consists of unbilled receivables. Oil and gas reserve quantities are utilized in the calculation of depreciation, depletion and amortization and the impairment of crude oil and natural gas wells and also impact the timing and costs associated with asset retirement obligations. The Company’s estimates, especially those related to oil and gas reserves, could change in the near term and could significantly impact the Company’s results of operations and financial position.
Fair Value of Financial Instruments	D.	Fair Value of Financial Instruments – The fair values of cash and equivalents, accounts and notes receivable, accounts payable and other short-term obligations approximate their carrying values because of the short maturity of these financial instruments. The carrying values of the Company’s long-term obligations approximate their fair value. In accordance with generally accepted accounting principles, rates available to the Company at the balance sheet dates are used to estimate the fair value of existing obligations.
Cash and Equivalents	E.	Cash and Equivalents – The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. The Company maintains, at various financial institutions, cash and equivalents which may exceed federally insured amounts and which may, at times, significantly exceed balance sheet amounts due to float. Cash and equivalents include $956,072 and $880,270 of joint venture partner advances at December 31, 2014 and 2013, respectively, which are funds collected and held on behalf of joint venture partners for their anticipated share of future plugging and abandonment costs, including interest earned.
Property and Equipment		F.	Property and Equipment – The Company uses the successful efforts method of accounting for oil and gas exploration and production activities. Under successful efforts, costs to acquire mineral interests in oil and gas properties, to drill and equip development wells and related asset retirement costs are capitalized. Costs of development wells (on properties the Company has no further interest in) that do not find proved reserves and geological and geophysical costs are expensed. The Company has not participated in exploratory drilling and owns no interest in unproved properties.
	Capitalized costs of proved properties, after considering estimated dismantlement and abandonment costs and estimated salvage values, are amortized by the unit-of-production method based upon estimated proved developed reserves. Depletion, depreciation and amortization on proved properties amounted to $3,362,240 and $3,493,540 during 2014 and 2013, respectively.
	On sale or retirement of a unit of a proved property (which generally constitutes the amortization base), the cost and related accumulated depreciation, depletion, amortization and write down are eliminated from the property accounts, and the resultant gain or loss is recognized.
	Generally accepted accounting principles require that long-lived assets (including oil and gas properties) and certain identifiable intangibles be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The Company, at least annually, reviews its proved crude oil and natural gas properties (on a field by field basis) for impairment by comparing the carrying value of its properties to the properties’ undiscounted estimated future net cash flows. Estimates of future crude oil and natural gas prices, operating costs, and production are utilized in determining undiscounted future net cash flows. The estimated future production of oil and gas reserves is based upon the Company’s independent reserve engineer’s estimate of proved reserves which includes assumptions regarding field decline rates and future prices and costs. For properties where the carrying value exceeds undiscounted future net cash flows, the Company recognizes as impairment the difference between the carrying value and fair market value of the properties. The Company determines fair market value, using the income approach, as the properties’ discounted estimated future net cash flows. The key assumptions above are not observable in the market and therefore the fair value of the oil and gas properties is classified as Level 3. The Company wrote down crude oil and natural gas properties by $107,018 and $34,385 during 2014 and 2013, respectively, to provide for impairment and abandonment on certain of its crude oil and natural gas properties.
	Additions to proved properties include changes to asset retirement obligations (see Note 1.G).
	Pipeline and support equipment and other corporate property and equipment are recorded at cost and depreciated principally on the straight-line method over their estimated useful lives (pipeline and support equipment - 10 to 15 years, other corporate equipment - 3 to 7 years, other corporate property - building and improvements with a cost of $1,536,288 – 39 to 40 years). Depreciation on pipeline and support equipment amounted to $43,078 and $52,463 for the years ended December 31, 2014 and 2013, respectively. Depreciation on other corporate property and equipment, included in general and administrative expense, amounted to $89,883 and $89,342 for the years ended December 31, 2014 and 2013, respectively.
	Maintenance and repairs of property and equipment are expensed as incurred. Major renewals and improvements are capitalized, and the assets replaced are retired.
Asset Retirement Obligations		G.	Asset Retirement Obligations – Generally accepted accounting principles require the fair value of a liability for an asset retirement obligation to be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. For the Company, these obligations include dismantlement, plugging and abandonment of crude oil and natural gas wells and associated pipelines and equipment. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depleted over the estimated useful life of the related asset.
	The estimated liability is based on historical experience in dismantling, plugging and abandoning wells, estimated remaining lives of those wells based on reserves estimates, estimates of the external cost to dismantle, plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability will likely occur due to: changes in estimates of dismantlement, plugging and abandonment costs; changes in estimated remaining lives of the wells; changes in federal or state regulations regarding plugging and abandonment requirements; and other factors. At December 31, 2014, the Company made revisions in estimates of plugging costs and remaining lives of wells.
	The Company has no assets legally restricted for purposes of settling asset retirement obligations. The Company has determined that there are no other material retirement obligations associated with tangible long-lived assets.
	The schedule below is a reconciliation of the Company’s liability for the years ended December 31:
			2014			2013
	Beginning of period		$	7,395,841		$	6,996,744
	Liabilities incurred			819			6,295
	Liabilities settled			(54,045	)		(13,677	)
	Accretion expense			642,799			406,479
	Revisions in estimated cash flows			3,122,630			—
	End of period		$	11,108,044		$	7,395,841
	The current portion of asset retirement obligations of $300,000 at December 31, 2014 and 2013, respectively, is included in accrued expenses in the Company’s consolidated balance sheets.
Revenue Recognition		H.	Revenue Recognition – The Company recognizes crude oil and natural gas revenues when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred, title and risk of loss have transferred to the purchaser, and collectability of the revenue is reasonably assured. The Company utilizes the sales method to account for gas production volume imbalances. Under this method, revenue is recognized only when gas is produced and sold on the Company’s behalf. The Company had no material gas imbalances at December 31, 2014 or 2013. Other revenue is recognized at the time services are rendered, the Company has a contractual right to such revenue and collection is reasonably assured. Gain on sale of deep rights is recognized when title to deep mineral interests has been transferred and all terms and conditions to the sale have been met. Substantially all of the Company’s gain on sale of deep rights recognized during 2013 represents funds previously recognized as deferred revenue.
	The Company participates (and may act as drilling contractor) with unaffiliated joint venture partners and employees in the drilling, development and operation of jointly owned crude oil and natural gas properties. Each owner, including the Company, has an undivided interest in the jointly owned properties. Generally, the joint venture partners and employees participate on the same drilling/development cost basis as the Company and, therefore, no revenue, expense or income is recognized on the drilling and development of the properties. Accounts and notes receivable from joint venture partners and employees consist principally of drilling and development costs the Company has advanced or incurred on behalf of joint venture partners and employees (see Note 6). Accounts payable to joint venture partners consist principally of deposits received from joint venture partners for drilling and development costs not yet incurred (see Note 2). The Company earns and receives monthly management and operating fees from certain joint venture partners and employees after the properties are completed and placed into production.
Income Taxes		I.	Income Taxes – Everflow is not a tax-paying entity and the net taxable income or loss, other than the taxable income or loss allocable to EEI, which is a C corporation owned by Everflow, will be allocated directly to its respective partners. The Company is not able to determine the net difference between the tax bases and the reported amounts of Everflow’s assets and liabilities due to separate elections that were made by owners of the working interests and limited partnership interests that comprised Programs.
	As referred to in Note 4, EEI accounts for income taxes under generally accepted accounting principles, which require income taxes be provided for all items (as they relate to EEI) in the consolidated statements of income regardless of the period when such items are reported for income tax purposes. Therefore, deferred tax assets and liabilities are recognized for temporary differences between the financial reporting basis and tax basis of certain EEI assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled. The impact on deferred taxes of changes in tax rates and laws, if any, is reflected in the financial statements in the period of enactment.
	The Company believes that it has appropriate support for any tax positions taken and, as such, does not have any uncertain tax positions that are material to the financial statements. The Company’s tax returns are subject to examination by the Internal Revenue Service, as well as various state and local taxing authorities, generally for three years after they are filed.
Allocation of Income and Per Unit Data		J.	Allocation of Income and Per Unit Data – Under the terms of the limited partnership agreement, initially 99% of revenues and costs were allocated to the Unitholders (the limited partners) and 1% of revenues and costs were allocated to the general partner. Such allocation has changed and will likely change in the future as Unitholders elect to exercise the Repurchase Right and select officers and employees elect to exercise options (see Note 3).
	Earnings per limited partner Unit have been computed based on the weighted average number of Units outstanding during each year presented. Average outstanding Units for earnings per Unit calculations amount to 5,603,994 and 5,609,350 in 2014 and 2013, respectively.
Subsequent Events	K.
	Subsequent Events - Everflow paid a cash distribution in January 2015 of $0.25 per Unit. The distribution amounted to approximately $1,417,000.
New Accounting Standards		L.	New Accounting Standards – In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update No. 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”). ASU 2014-09 is intended to improve the financial reporting requirements for revenue from contracts with customers by providing a principle based approach. The core principle of the standard is that revenue should be recognized when the transfer of promised goods or services is made in an amount that the entity expects to be entitled to in exchange for the transfer of goods and services. ASU 2014-09 also requires disclosures enabling users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. This standard will be effective for financial statements issued by public companies for annual reporting periods beginning after December 15, 2016. Early adoption is not permitted. The Company is currently evaluating the potential impact of ASU 2014-09 on the financial statements.
	The Company has reviewed all other recently issued accounting standards in order to determine their effects, if any, on the consolidated financial statements. Based on that review, the Company believes that none of these standards will have a significant effect on current or future earnings or operations.

Organization_and_Summary_of_Si2

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Reconciliation of Company's Asset Retirement Obligations	The schedule below is a reconciliation of the Company’s liability for the years ended December 31:
		2014			2013
	Beginning of period	$	7,395,841		$	6,996,744
	Liabilities incurred		819			6,295
	Liabilities settled		(54,045	)		(13,677	)
	Accretion expense		642,799			406,479
	Revisions in estimated cash flows		3,122,630			—
	End of period	$	11,108,044		$	7,395,841

Current_Liabilities_Tables

Current Liabilities (Tables)	12 Months Ended
	Dec. 31, 2014
Payables and Accruals [Abstract]
Components of Accounts Payable and Accrued Expenses	The Company’s accounts payable and accrued expenses consist of the following at December 31:
		2014		2013
	Accounts Payable:
	Production and related other	$	1,420,238	$	1,274,763
	Other		288,521		287,460
	Joint venture partner deposits		111,173		122,387
		$	1,819,932	$	1,684,610
	Accrued Expenses:
	Payroll and retirement plan contributions	$	1,055,255	$	963,783
	Current portion of asset retirement obligations		300,000		300,000
	Other		80,300		72,200
	Federal, state and local taxes		31,376		28,200
		$	1,466,931	$	1,364,183

Partners_Equity_Tables

Partners' Equity (Tables)	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Units Repurchased Pursuant to Repurchase Right and Issued Pursuant to Option Plan	Units repurchased pursuant to the Repurchase Right and Units issued through the exercise of options pursuant to the Option Plan (collectively the “Units Activity”) for the three years ended December 31, 2014, are as follows:
	Year	Price for		Less Interim		Net Price Paid		Units		Units Issued		Units
		Repurchase		Distributions				Repurchased				Outstanding
		Right										Following
												Units Activity
	2012	$	9.17	$	0.88	$	8.29		9,414		4,707		5,611,715
	2013	$	5.92	$	1	$	4.92		9,460		4,730		5,606,985
	2014	$	7.01	$	0.5	$	6.51		11,964		5,982		5,601,003

Provision_for_Income_Taxes_Tab

Provision for Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Reconciliation Taxes Computed at Federal Statutory Rate and Effective Tax Rate in Statements of Income	A reconciliation between taxes computed at the Federal statutory rate and the effective tax rate in the statements of income follows:
		Year Ended December 31,
		2014						2013
		Amount			%			Amount			%
	Provision based on the statutory rate	$	980,000			34		$	3,103,000			34
	Tax effect of:
	Non-taxable status of the Programs and Everflow		(981,000	)		(34.0	)		(2,517,000	)		(27.6	)
	Excess statutory depletion		(53,000	)		(1.8	)		(55,000	)		(0.6	)
	Graduated tax rates, permanent differences between book and tax items, tax credits and other - net		52,963			1.8			(16,980	)		(0.2	)
	Total	$	(1,037	)		—		$	514,020			5.6

Retirement_Plans_Tables

Retirement Plans (Tables)	12 Months Ended
	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Schedule of Net Periodic Benefit Cost	Net periodic benefit cost recognized in the consolidated statements of income consists of the following during the years ended December 31:
		2014			2013
	Service cost	$	323,900		$	308,500
	Interest cost		30,700			14,500
	Expected return on plan assets		(27,300	)		(18,500	)
	Net periodic benefit cost	$	327,300		$	304,500
Schedule of Change in Projected Benefit Obligation of Pension Plan and Change in Assets at Fair Value	The change in the projected benefit obligation of the Pension Plan and the change in assets at fair value are as follows during the years ended December 31:
		2014			2013
	Change in PBO:
	PBO, beginning of year	$	620,000		$	290,500
	Service cost		323,900			308,500
	Interest cost		30,700			14,500
	Actuarial loss		19,200			8,500
	Benefits paid		(3,100	)		(2,000	)
	PBO, end of year		990,700			620,000
	Change in Plan assets:
	Fair value, beginning of year		301,500			1,000
	Actual return on plan assets		23,700			13,500
	Company contributions		318,500			289,000
	Benefits paid		(3,100	)		(2,000	)
	Fair value, end of year	$	640,600		$	301,500
	Funded status at December 31	$	(350,100	)	$	(318,500	)

Business_Segments_Risks_and_Ma1

Business Segments, Risks and Major Customers (Tables)	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Table of Natural Gas Sales to Significant Purchasers as a Percentage of Consolidated Crude Oil and Natural Gas Sales	The Company had two significant purchasers of natural gas production from operated wells for the years ended December 31, 2014 and 2013. Natural gas sales to these significant purchasers as a percentage of consolidated crude oil and natural gas sales were as follows:
	Natural Gas Purchaser	2014			2013
	Dominion Field Services, Inc. (“Dominion”)		29	%		31	%
	Interstate Gas Supply, Inc. (“IGS”)		13			13
			42	%		44	%

Supplemental_Information_Relat1

Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Capitalized Costs Relating to Oil and Gas Producing Activities	CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
		Years ended December 31,
		2014			2013
	Proved oil and gas properties	$	177,223,180		$	174,811,480
	Pipeline and support equipment		631,757			666,667
			177,854,937			175,478,147
	Accumulated depreciation, depletion, amortization and write down		147,304,820			144,715,506
	Net capitalized costs	$	30,550,117		$	30,762,641
Costs Incurred in Oil and Gas Producing Activities	COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
		Years ended December 31,
		2014			2013
	Property acquisition costs	$	13,015		$	42,846
	Development costs		149,405			956,611
Results of Operations for Oil and Gas Producing Activities	RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
		Years ended December 31,
		2014			2013
	Crude oil and natural gas sales	$	13,247,538		$	16,804,745
	Production costs		(3,655,764	)		(4,018,918	)
	Depreciation, depletion and amortization		(3,405,318	)		(3,546,003	)
	Accretion expense		(642,799	)		(406,479	)
	Write down/impairment and abandonment of crude oil and natural gas properties		(107,018	)		(34,385	)
			5,436,639			8,798,960
	Income tax expense		19,000			25,000
	Results of operations for oil and gas producing activities (excluding corporate overhead and financing costs)	$	5,417,639		$	8,773,960
Estimated Quantities of Proved Oil and Gas Reserves	ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
		Oil			Gas
		(BBLS)			(MCFS)
	Balance, January 1, 2013		579,000			25,644,000
	Extensions, discoveries and other additions		25,000			177,000
	Production		(62,000	)		(2,846,000	)
	Revision of previous estimates		44,000			4,678,000
	Balance, December 31, 2013		586,000			27,653,000
	Extensions, discoveries and other additions		2,000			8,000
	Production		(53,000	)		(2,269,000	)
	Revision of previous estimates		(24,000	)		(1,668,000	)
	Balance, December 31, 2014		511,000			23,724,000
	PROVED DEVELOPED RESERVES:
	December 31, 2012		579,000			25,644,000
	December 31, 2013		586,000			27,653,000
	December 31, 2014		511,000			23,724,000
Standardized Measure of Discounted Future Net Cash Flows	STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
		December 31,
		2014			2013
		(Thousands of Dollars)
	Future cash inflows from sales of oil and gas	$	124,127		$	150,370
	Future production and development costs		(60,296	)		(67,947	)
	Future asset retirement obligations, net of salvage		(16,506	)		(11,668	)
	Future income tax expense		(1,159	)		(1,570	)
	Future net cash flows		46,166			69,185
	Effect of discounting future net cash flows at 10% per annum		(18,009	)		(27,524	)
	Standardized measure of discounted future net cash flows	$	28,157		$	41,661
Changes in the Standardized Measure of Discounted Future Cash Flows	CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
		Years Ended December 31,
		2014			2013
		(Thousands of Dollars)
	Balance, beginning of year	$	41,661		$	33,543
	Extensions, discoveries and other additions		29			1,401
	Development costs incurred		42			—
	Revision of quantity estimates		(1,538	)		5,335
	Sales of crude oil and natural gas, net of production costs		(9,592	)		(12,786	)
	Net change in income taxes		226			(118	)
	Net changes in prices and production costs		(3,912	)		5,670
	Accretion of discount		4,166			3,354
	Other		(2,925	)		5,262
	Balance, end of year	$	28,157		$	41,661

Organization_and_Summary_of_Si3

Organization and Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended		1 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Jan. 31, 2015
	Tax_Positions
Summary Of Significant Accounting Policies [Line Items]
General partner's assets other than interest in the Company	$0
General partner's liabilities	0
JOINT VENTURE PARTNER ADVANCES	956,072	880,270
Cash and equivalents maturity period	3 months
Interest in unproved properties	0
Amount of depletion, depreciation and amortization on proved properties	3,362,240	3,493,540
Write down/impairment and abandonment of crude oil and natural gas properties	107,018	34,385
Buildings and Improvements	1,536,288
Depreciation on pipeline and support equipment	43,078	52,463
Depreciation on other corporate property and equipment	89,883	89,342
Assets legally restricted for purposes of settling asset retirement obligations	0
Other material retirement obligations associated with tangible long lived assets	0
Current portion of asset retirement obligations	300,000	300,000
Material gas imbalances	0	0
Examination period of tax returns	3 years
Number of uncertain tax positions	0
Cash distributions per unit	$1.25	$1.75
Quarterly cash distributions	7,088,117	9,934,375
Subsequent Event [Member]
Summary Of Significant Accounting Policies [Line Items]
Cash distributions per unit			$0.25
Quarterly cash distributions			$1,417,000
Limited Partner [Member]
Summary Of Significant Accounting Policies [Line Items]
Initial partners' revenue and cost allocations	99.00%
Average outstanding units	5,603,994	5,609,350
General Partner [Member]
Summary Of Significant Accounting Policies [Line Items]
Initial partners' revenue and cost allocations	1.00%
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Sales transaction processing time	60 days
Estimated useful lives of pipeline and support equipment	10 years
Estimated useful lives of corporate equipment	3 years
Estimated useful lives of buildings and improvements	39 years
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Sales transaction processing time	90 days
Estimated useful lives of pipeline and support equipment	15 years
Estimated useful lives of corporate equipment	7 years
Estimated useful lives of buildings and improvements	40 years

Organization_and_Summary_of_Si4

Organization and Summary of Significant Accounting Policies - Reconciliation of Company's Asset Retirement Obligations (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Regulatory Assets [Abstract]
Beginning of period	$7,395,841	$6,996,744
Liabilities incurred	819	6,295
Liabilities settled	-54,045	-13,677
Accretion expense	642,799	406,479
Revisions in estimated cash flows	3,122,630
End of period	$11,108,044	$7,395,841

Current_Liabilities_Components

Current Liabilities - Components of Accounts Payable and Accrued Expenses (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Accounts Payable:
Production and related other	$1,420,238	$1,274,763
Other	288,521	287,460
Joint venture partner deposits	111,173	122,387
Total Accounts Payable	1,819,932	1,684,610
Accrued Expenses:
Payroll and retirement plan contributions	1,055,255	963,783
Current portion of asset retirement obligations	300,000	300,000
Other	80,300	72,200
Federal, state and local taxes	31,376	28,200
Total Accrued Expenses	$1,466,931	$1,364,183

Partners_Equity_Additional_Inf

Partners' Equity - Additional Information (Detail) (USD $)	12 Months Ended			1 Months Ended		6 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jan. 31, 2015	Apr. 30, 2015	Jun. 30, 2015
Equity [Line Items]
Maximum percentage of units to be repurchased	10.00%
Percentage of adjusted book value of company allocable to the repurchase price per unit	66.00%
Minimum percentage of outstanding units	10.00%
Net price paid for repurchase right	$6.51	$4.92	$8.29
Interim cash distribution per unit	$0.50	$1	$0.88
Potentially dilutive outstanding instruments	0	0
Subsequent Event [Member]
Equity [Line Items]
Interim cash distribution per unit				$0.25
Scenario, Forecast [Member]
Equity [Line Items]
Net price paid for repurchase right						$4.56
Interim cash distribution per unit					$0.13

Partners_Equity_Units_Repurcha

Partners' Equity - Units Repurchased Pursuant to Repurchase Right and Issued Pursuant to Option Repurchase Plan (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Equity [Abstract]
Price for Repurchase Right	$7.01	$5.92	$9.17
Less Interim Distributions	$0.50	$1	$0.88
Net Price Paid	$6.51	$4.92	$8.29
Units Repurchased	11,964	9,460	9,414
Units Issued	5,982	4,730	4,707
Units Outstanding Following Units Activity	5,601,003	5,606,985	5,611,715

Provision_for_Income_Taxes_Rec

Provision for Income Taxes - Reconciliation Taxes Computed at Federal Statutory Rate and Effective Tax Rate in Statements of Income (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Provision based on the statutory rate	$980,000	$3,103,000
Tax effect of:
Non-taxable status of the Programs and Everflow	-981,000	-2,517,000
Excess statutory depletion	-53,000	-55,000
Graduated tax rates, permanent differences between book and tax items, tax credits and other - net	52,963	-16,980
Total income tax (benefit) expense	($1,037)	$514,020
Provision based on the statutory rate	34.00%	34.00%
Non-taxable status of the Programs and Everflow	-34.00%	-27.60%
Excess statutory depletion	-1.80%	-0.60%
Graduated tax rates, permanent differences between book and tax items, tax credits and other - net	1.80%	-0.20%
Total	0.00%	5.60%

Provision_for_Income_Taxes_Add

Provision for Income Taxes - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Deferred income tax expense		$509,000
Deferred income tax benefit	20,000	20,000
Deferred tax liabilities	$194,000	$214,000

Retirement_Plans_Additional_In

Retirement Plans - Additional Information (Detail) (USD $)	12 Months Ended		9 Months Ended	3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015	Mar. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Employee requirements for defined contribution plan participation	Age of 21 and completed one year
Company's total contributions to the Defined Contribution Plan	$212,000	$224,000
Defined benefit plan vesting period	3 years
Interest credits per year	5.00%
Employer contributions	318,500	289,000
Net periodic benefit cost, discount rate	5.00%
Long-term asset return	7.00%
Benefits estimated to be paid over the next five years	40,000
Benefits estimated to be paid over the next five years thereafter	1,666,300
Scenario, Forecast [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions			0
Subsequent Event [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions				$350,100

Retirement_Plans_Schedule_of_N

Retirement Plans - Schedule of Net Periodic Benefit Cost (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]
Service cost	$323,900	$308,500
Interest cost	30,700	14,500
Expected return on plan assets	-27,300	-18,500
Net periodic benefit cost	$327,300	$304,500

Retirement_Plans_Schedule_of_C

Retirement Plans - Schedule of Change in Projected Benefit Obligation of Pension Plan and Change in Assets at Fair Value (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]
PBO, beginning of year	$620,000	$290,500
Service cost	323,900	308,500
Interest cost	30,700	14,500
Actuarial loss	19,200	8,500
Benefits paid	-3,100	-2,000
PBO, end of year	990,700	620,000
Fair value, beginning of year	301,500	1,000
Actual return on plan assets	23,700	13,500
Company contributions	318,500	289,000
Benefits paid	-3,100	-2,000
Fair value, end of year	640,600	301,500
Funded status at December 31	($350,100)	($318,500)

Related_Party_Transactions_Add

Related Party Transactions - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
	Loans	Employees
	Employees	Addendum
	Addendum
Related Party Transactions [Abstract]
Term of employee receivables	4 years
Loan forgiveness provisions	0
Loans forgiven	0
Interest rate charged on employee loans	3.25%
Number of employees to whom loans have been extended	2	2
Employee receivables	$140,549	$213,262
Additional extended term of employee receivables	2 years	2 years
Subsequent addenda	2	2

Business_Segments_Risks_and_Ma2

Business Segments, Risks and Major Customers - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
	Mcf	Purchaser
	Purchaser
Revenue, Major Customer [Line Items]
Natural gas sales as percentage of total crude oil and natural gas sales	64.00%	65.00%
Percentage of crude oil and natural gas sales derived from operating wells	72.00%	72.00%
Significant natural gas purchasers	2	2
Percentage of natural gas production purchased by major customers from operated wells	66.00%	67.00%
Lock-in quantities of natural gas	780,000
Weighted-average pricing provisions	3.26
Dominion Field Services, Inc. ("Dominion") [Member]
Revenue, Major Customer [Line Items]
Number of gross operated wells from which production is covered	470
Interstate Gas Supply, Inc. ("IGS") [Member]
Revenue, Major Customer [Line Items]
Number of gross operated wells from which production is covered	200

Business_Segments_Risks_and_Ma3

Business Segments, Risks and Major Customers - Table of Natural Gas Sales to Significant Purchasers as a Percentage of Consolidated Crude Oil and Natural Gas Sales (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Revenue, Major Customer [Line Items]
Natural gas sales to major gas purchasers	42.00%	44.00%
Dominion Field Services, Inc. ("Dominion") [Member]
Revenue, Major Customer [Line Items]
Natural gas sales to major gas purchasers	29.00%	31.00%
Interstate Gas Supply, Inc. ("IGS") [Member]
Revenue, Major Customer [Line Items]
Natural gas sales to major gas purchasers	13.00%	13.00%

Commitments_and_Contingencies_

Commitments and Contingencies - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2012
		acre
Supply Commitment [Line Items]
Acreage sold with future production requirements		28,800
Lease renewal period	3 months
Refund price per acre	1,250
Reserve for potential refunded acreage	$0
Minimum [Member]
Supply Commitment [Line Items]
Minimum production term for leases sold with production term contingencies	5 years

Supplemental_Information_Relat2

Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) - Capitalized Costs Relating to Oil and Gas Producing Activities (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Proved oil and gas properties	$177,223,180	$174,811,480
Pipeline and support equipment	631,757	666,667
Gross capitalized costs	177,854,937	175,478,147
Accumulated depreciation, depletion, amortization and write down	147,304,820	144,715,506
Net capitalized costs	$30,550,117	$30,762,641

Supplemental_Information_Relat3

Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) - Costs Incurred in Oil and Gas Producing Activities (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract]
Property acquisition costs	$13,015	$42,846
Development costs	$149,405	$956,611

Supplemental_Information_Relat4

Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
	acre	acre
Extractive Industries [Abstract]
Purchases of producing oil and gas properties	$0	$0
Net proved undeveloped acres	394	498
Net carrying cost of the proved undeveloped acreage	$214,600	$341,600
Discount rate for cash flows	10.00%
Natural gas prices used in the estimation of proved reserves	3.28	3.43
Crude oil prices used in the estimation of proved reserves	90.53	94.49

Supplemental_Information_Relat5

Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) - Results of Operations for Oil and Gas Producing Activities (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Crude oil and natural gas sales	$13,247,538	$16,804,745
Production costs	-3,655,764	-4,018,918
Depreciation, depletion and amortization	-3,405,318	-3,546,003
Accretion expense	-642,799	-406,479
Write down/impairment and abandonment of crude oil and natural gas properties	-107,018	-34,385
Income before income taxes	5,436,639	8,798,960
Income tax expense	19,000	25,000
Results of operations for oil and gas producing activities (excluding corporate overhead and financing costs)	$5,417,639	$8,773,960

Supplemental_Information_Relat6

Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) - Estimated Quantities of Proved Oil and Gas Reserves (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	bbl	bbl	bbl
Oil (BBLS) [Member]
Reserve Quantities [Line Items]
Beginning Balance	586,000	579,000
Extensions, discoveries and other additions	2,000	25,000
Production	-53,000	-62,000
Revision of previous estimates	-24,000	44,000
Ending Balance	511,000	586,000
PROVED DEVELOPED RESERVES:
Proved developed reserves	511,000	586,000	579,000
Gas (MCFS) [Member]
Reserve Quantities [Line Items]
Beginning Balance	27,653,000	25,644,000
Extensions, discoveries and other additions	8,000	177,000
Production	-2,269,000	-2,846,000
Revision of previous estimates	-1,668,000	4,678,000
Ending Balance	23,724,000	27,653,000
PROVED DEVELOPED RESERVES:
Proved developed reserves	23,724,000	27,653,000	25,644,000

Supplemental_Information_Relat7

Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Abstract]
Future cash inflows from sales of oil and gas	$124,127	$150,370
Future production and development costs	-60,296	-67,947
Future asset retirement obligations, net of salvage	-16,506	-11,668
Future income tax expense	-1,159	-1,570
Future net cash flows	46,166	69,185
Effect of discounting future net cash flows at 10% per annum	-18,009	-27,524
Standardized measure of discounted future net cash flows	$28,157	$41,661	$33,543

Supplemental_Information_Relat8

Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) - Changes in Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract]
Balance, beginning of year	$41,661	$33,543
Extensions, discoveries and other additions	29	1,401
Development costs incurred	42
Revision of quantity estimates	-1,538	5,335
Sales of crude oil and natural gas, net of production costs	-9,592	-12,786
Net change in income taxes	226	-118
Net changes in prices and production costs	-3,912	5,670
Accretion of discount	4,166	3,354
Other	-2,925	5,262
Balance, end of year	$28,157	$41,661