Atlas Resources Public #18-2008 10-Q 15 May 15 2015 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
	Mar. 31, 2015
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	FALSE
Document Period End Date	31-Mar-15
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Entity Registrant Name	Atlas Resources Public #18-2008 (A) L.P.
Entity Central Index Key	1432987
Current Fiscal Year End Date	-19
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding	0

CONDENSED_BALANCE_SHEETS

CONDENSED BALANCE SHEETS (USD $)	Mar. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$37,200	$44,900
Accounts receivable trade–affiliate	559,300	572,000
Asset retirement receivable-affiliate	101,700	26,300
Current portion of derivative assets	282,600	269,800
Total current assets	980,800	913,000
Gas and oil properties, net	6,636,400	6,840,400
Long-term derivative assets	121,500	120,700
TOTAL ASSETS	7,738,700	7,874,100
Current liabilities:
Accrued liabilities	30,200	26,600
Accounts payable trade-affiliate	407,200	407,200
Current portion of put premiums payable-affiliate	37,000	35,600
Total current liabilities	474,400	469,400
Asset retirement obligations	3,888,200	3,825,600
Long-term put premiums payable-affiliate	30,600	40,700
Commitments and contingencies
Partners’ capital:
Managing general partner’s interest	-773,800	-746,400
Limited partners’ interest (20,152.50 units)	4,106,600	4,269,100
Accumulated other comprehensive income	12,700	15,700
Total partners’ capital	3,345,500	3,538,400
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$7,738,700	$7,874,100

CONDENSED_BALANCE_SHEETS_Paren

CONDENSED BALANCE SHEETS (Parenthetical)	Mar. 31, 2015
Statement Of Financial Position [Abstract]
Limited partners' units	20,152.50

CONDENSED_STATEMENTS_OF_OPERAT

CONDENSED STATEMENTS OF OPERATIONS (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
REVENUES
Natural gas, oil and liquids	$741,200	$1,375,300
Gain on mark-to-market derivatives	22,300
Total revenues	763,500	1,375,300
COSTS AND EXPENSES
Production	598,900	701,100
Depletion	204,000	435,200
Accretion of asset retirement obligation	62,600	38,200
General and administrative	46,300	46,600
Total costs and expenses	911,800	1,221,100
Net (loss) income	-148,300	154,200
Allocation of net (loss) income:
Managing general partner	-27,100	157,700
Limited partners	($121,200)	($3,500)
Net loss per limited partnership unit	($6)	$0

CONDENSED_STATEMENTS_OF_COMPRE

CONDENSED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Statement Of Income And Comprehensive Income [Abstract]
Net (loss) income	($148,300)	$154,200
Other comprehensive loss:
Unrealized holding loss on cash flow hedging contracts		-192,200
Difference in estimated hedge gains receivable	32,000	147,900
Reclassification adjustment for gains realized in net (loss) income from cash flow hedges	-35,000	-78,600
Total other comprehensive loss	-3,000	-122,900
Comprehensive (loss) income	($151,300)	$31,300

CONDENSED_STATEMENT_OF_CHANGES

CONDENSED STATEMENT OF CHANGES IN PARTNERS' CAPITAL (USD $)	Total	Managing General Partner	Limited Partners	Accumulated Other Comprehensive Income (Loss)
Beginning balance at Dec. 31, 2014	$3,538,400	($746,400)	$4,269,100	$15,700
Participation in revenues, costs and expenses:
Net production revenues	142,300	23,100	119,200
Gain on mark-to-market derivatives	22,300		22,300
Depletion	-204,000	-20,000	-184,000
Accretion of asset retirement obligation	-62,600	-17,300	-45,300
General and administrative	-46,300	-12,900	-33,400
Net (loss) income	-148,300	-27,100	-121,200
Other comprehensive loss	-3,000			-3,000
Distributions to partners	-41,600	-300	-41,300
Ending balance at Mar. 31, 2015	$3,345,500	($773,800)	$4,106,600	$12,700

CONDENSED_STATEMENTS_OF_CASH_F

CONDENSED STATEMENTS OF CASH FLOWS (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Cash flows from operating activities:
Net (loss) income	($148,300)	$154,200
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depletion	204,000	435,200
Non cash (gain) loss on derivative value	-25,300	17,100
Accretion of asset retirement obligation	62,600	38,200
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable trade-affiliate	12,700	-365,500
Increase in asset retirement receivable-affiliate	-75,400
Increase in accrued liabilities	3,600	10,700
Decrease in accounts payable trade-affiliate		-15,300
Net cash provided by operating activities	33,900	274,600
Cash flows from investing activities:
Proceeds from the sale of gas and oil properties		1,003,800
Net cash provided by investing activities		1,003,800
Cash flows from financing activities:
Distributions to partners	-41,600	-695,000
Net cash used in financing activities	-41,600	-695,000
Net change in cash and cash equivalents	-7,700	583,400
Cash and cash equivalents at beginning of period	44,900	467,600
Cash and cash equivalents at end of period	$37,200	$1,051,000

Description_of_Business

Description of Business	3 Months Ended
	Mar. 31, 2015
Organization Consolidation And Presentation Of Financial Statements [Abstract]
DESCRIPTION OF BUSINESS	NOTE 1 - DESCRIPTION OF BUSINESS
	Atlas Resources Public #18-2008 (A) L.P. (the “Partnership”) is a Delaware limited partnership, formed on April 8, 2008 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or the “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP).
	On February 27, 2015, the MGP’s ultimate parent, Atlas Energy, L.P. (“Atlas Energy”), which was a publicly traded master-limited partnership, was acquired by Targa Resources Corp. and distributed to Atlas Energy’s unitholders 100% of the limited liability company interests in ARP’s general partner, Atlas Energy Group, LLC (“Atlas Energy Group”; NYSE: ATLS).  Atlas Energy Group became a separate, publicly traded company and the ultimate parent of the MGP as a result of the distribution. Following the distribution, Atlas Energy Group continues to manage ARP’s operations and activities through its ownership of the ARP’s general partner interest.
	The Partnership has drilled and currently operates wells located in Pennsylvania, Tennessee, Indiana, West Virginia and Ohio. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy (after February 27, 2015, Atlas Energy Group), for administrative services.
	The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. The Partnership intends to produce its wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. The Partnership does not expect to drill additional wells and expects no additional funds will be required for drilling.
	The accompanying condensed financial statements, which are unaudited, except for the balance sheet at December 31, 2014, which is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in the Partnership’s Form 10-K. These interim financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014. The results of operations for the three months ended March 31, 2015 may not necessarily be indicative of the results of operations for the year ended December 31, 2015.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. Management has considered for disclosure any material subsequent events through the date the financial statements were issued.
	In addition to matters discussed further in this note, the Partnership’s significant accounting policies are detailed in its audited financial statements and notes thereto in the Partnership’s annual report on Form 10-K for the year ended December 31, 2014 filed with the Securities and Exchange Commission (“SEC”).
	Use of Estimates
	The preparation of the Partnership’s financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, impairments, fair value of derivative instruments and the probability of forecasted transactions. Actual results could differ from those estimates.
	The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following months’ financial results. Management believes that the operating results presented for the three months ended March 31, 2015 and 2014 represent actual results in all material respects (See “Revenue Recognition”).
	Accounts Receivable
	Accounts receivable on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of its accounts receivable, the MGP performs ongoing credit evaluations of the Partnership’s customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness, as determined by review of such customers’ credit information. Credit is extended on an unsecured basis to many of the Partnership’s energy customers. At March 31, 2015 and December 31, 2014, the MGP’s credit evaluation indicated that the Partnership had no need for an allowance for uncollectible accounts receivable.
	Gas and Oil Properties
	Gas and oil properties are stated at cost. Maintenance and repairs which generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized.
	The Partnership follows the successful efforts method of accounting for gas and oil producing activities. Oil and natural gas liquids (NGLs) are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to six Mcf of natural gas. Mcf is defined as one thousand cubic feet.
	The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties. The Partnership recorded depletion expense on natural gas and oil properties of $204,000 and $435,200 for the three months ended March 31, 2015 and 2014, respectively.
	Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts and the resultant gain or loss is reclassified to the Partnership’s statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depletion within its balance sheets.
	The following is a summary of gas and oil properties at the dates indicated:
		March 31,			December 31,
		2015			2014
	Proved properties:
	Leasehold interests	$	2,387,700		$	2,387,700
	Wells and related equipment		212,713,600			212,713,600
	Total natural gas and oil properties		215,101,300			215,101,300
	Accumulated depletion and impairment		(208,464,900	)		(208,260,900	)
	Gas and oil properties, net	$	6,636,400		$	6,840,400
	Impairment of Long-Lived Assets
	The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount of that asset to its estimated fair value if such carrying amount exceeds the fair value.
	The review of the Partnership’s gas and oil properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion and impairment is less than the estimated expected undiscounted future cash flows including salvage. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of the production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value and the carrying value of the assets.
	The determination of natural gas and oil reserve estimates is a subjective process and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.
	In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods.
	There was no gas and oil properties impairment recorded for the three months ended March 31, 2015 and 2014. During the year ended December 31, 2014, the Partnership recognized an impairment charge of $13,776,200. This impairment relates to the carrying amount of these gas and oil properties being in excess of the Partnership’s estimate of their fair value at December 31, 2014. The estimate of the fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil prices at the date of measurement.
	Working Interest
	The Partnership Agreement establishes that revenues and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). The MGP is also provided an additional working interest of 10% as provided in the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expenses until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues and expenses based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.
	Revenue Recognition
	The Partnership generally sells natural gas, crude oil and NGLs at prevailing market prices. Typically, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil and NGLs, in which the Partnership has an interest with other producers are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty.
	The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP. The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees, which are, in turn, based upon applicable product prices (See “Use of Estimates” for further description). The Partnership had unbilled revenues at March 31, 2015 and December 31, 2014 of $414,700 and $499,800, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.
	Comprehensive Income (Loss)
	Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on the Partnership’s financial statements and, at March 31, 2015, only include changes in the fair value of unsettled derivative contracts which prior to January 1, 2015 were accounted for as cash flow hedges (See Note 4). The Partnership does not have any other type of transaction which would be included within other comprehensive income (loss).
	Recently Issued Accounting Standards
	In January 2015, the Financial Accounting Standards Board (“FASB”) issued ASU 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items (“Update 2015-01”). The amendments in Update 2015-01 simplify the income statement presentation requirements in Subtopic 225-20 by eliminating the concept of extraordinary items. Extraordinary items are events and transactions that are distinguished by their unusual nature and by the infrequency of their occurrence. Eliminating the extraordinary classification simplifies income statement presentation by altogether removing the concept of extraordinary items from consideration. The amendments in Update 2015-01 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A reporting entity may apply the amendments prospectively. A reporting entity may also apply the amendments retrospectively to all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. The Partnership will adopt the requirements of Update 2015-01 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.
	In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. The Partnership will adopt the requirements of Update 2014-15 upon its effective date in 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.
	In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles – Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. The Partnership will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2017, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures. On April 1, 2015, the FASB tentatively decided to defer the effective date of ASU 2014-09 by one year. As a result, public entities would apply the new revenue standard to annual reporting periods beginning after December 15, 2017, and to interim periods within that reporting period, with early adoption permitted.

Asset_Retirement_Obligations

Asset Retirement Obligations	3 Months Ended
	Mar. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS
	NOTE 3 - ASSET RETIREMENT OBLIGATIONS
	The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells. It also recognizes a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depletion.
	The estimated liability is based on the MGP’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in cost estimates, remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for the Partnership’s gas and oil properties, the Partnership determined that there were no other material retirement obligations associated with tangible long-lived assets.
	The MGP’s historical practice and continued intention is to retain distributions from the limited partners as the wells within the Partnership near the end of their useful life. On a partnership-by-partnership basis, the MGP assesses its right to withhold amounts related to plugging and abandonment costs based on several factors including commodity price trends, the natural decline in the production of the wells and current and future costs. Generally, the MGP’s intention is to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approaches the fair value of the future plugging and abandonment cost. Upon the MGP’s decision to retain all future distributions to the limited partners of the Partnership, the MGP will assume the related asset retirement obligations of the limited partners. As of March 31, 2015, the MGP has withheld $101,700 of net production revenue for future plugging and abandonment costs.
	A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the periods indicated is as follows:
		Three Months Ended
		March 31,
		2015		2014
	Asset retirement obligations at beginning of period	$	3,825,600	$	2,572,500
	Accretion expense		62,600		38,200
	Asset retirement obligations at end of period	$	3,888,200	$	2,610,700

Derivative_Instruments

Derivative Instruments	3 Months Ended
	Mar. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS	NOTE 4 - DERIVATIVE INSTRUMENTS
	The MGP, on behalf of the Partnership, uses a number of different derivative instruments, principally swaps, collars and options, in connection with the Partnership’s commodity price risk management activities. Management enters into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under commodity-based swap agreements, the Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. To manage the risk of regional commodity price differences, the Partnership occasionally enters into basis swaps. Basis swaps are contractual arrangements that guarantee a price differential for a commodity from a specified delivery point price and the comparable national exchange price. For natural gas basis swaps, which have negative differentials to New York Mercantile Exchange (“NYMEX”), the Partnership receives or pays a payment from the counterparty if the price differential to NYMEX is greater or less than the stated terms of the contract. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike, price and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged.
	On January 1, 2015, the Partnership discontinued hedge accounting for its qualified commodity derivatives. As such, changes in fair value of these derivatives after December 31, 2014 are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations. The fair values of these commodity derivative instruments at December 31, 2014, which were recognized in accumulated other comprehensive income within partners’ capital on the Partnership’s balance sheet, will be reclassified to the Partnership’s statements of operations in the future at the time the originally hedged physical transactions affect earnings.
	The Partnership enters into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s balance sheets as the initial value of the options. The Partnership reflected net derivative assets on its balance sheets of $404,100 and $390,500 at March 31, 2015, and December 31, 2014, respectively.
	The following table summarizes the gains or losses recognized within the statements of operations for derivative instruments previously designated as cash flow hedges for the periods indicated:
			Three Months Ended
			March 31,
			2015			2014
	Gains reclassified from accumulated other comprehensive income into natural gas and oil revenues		$	35,000		$	78,600
	Gains subsequent to December 31, 2014 recognized in gain on mark-to-market derivatives		$	22,300		$	-
	The Partnership enters into commodity future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in commodity prices. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. NGL fixed price swaps are priced based on a WTI crude oil index. These contracts have been recorded at their fair values.
	At March 31, 2015, the Partnership had the following commodity derivatives:
	Natural Gas Fixed Price Swaps - Limited Partners
	Production			Volumes			Average		Fair Value
	Period Ending						Fixed Price		Asset (2)
	December 31,
				(MMBtu)(1)			(per MMBtu)(1)
	2015				135,000		$	4.224	$	194,100
	2016				75,600			4.46		100,600
									$	294,700
	Natural Gas Put Options - Limited Partners
	Production			Volumes			Average		Fair Value
	Period Ending						Fixed Price		Asset (2)
	December 31,
				(MMBtu)(1)			(per MMBtu)(1)
	2015				39,900		$	4	$	49,100
	2016				53,200			4.15		60,300
									$	109,400
	Limited Partner’s Commodity Derivatives, net								$	404,100
	-1	“MMBtu” represents million British Thermal Units.
	-2	Fair value based on forward NYMEX natural gas prices, as applicable.
	At March 31, 2015, the MGP had a secured hedge facility agreement with a syndicate of banks under which the Partnership has the ability to enter into derivative contracts to manage its exposure to commodity price movements. Under the MGP’s revolving credit facility, the Partnership is required to utilize this secured hedge facility for future commodity risk management activity. The Partnership’s obligations under the facility are secured by mortgages on its gas and oil properties and first priority security interests in substantially all of its assets and are guaranteed by the MGP. The MGP administers the commodity price risk management activity for the Partnership under the secured hedge facility. The secured hedge facility agreement contains covenants that limit the Partnership’s ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions, including a sale of all or substantially all of its assets. As of March 31, 2015, only the Partnership’s natural gas swaps are included in the secured hedge facility.
	As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three months ended March 31, 2015 and 2014 for hedge ineffectiveness.
	Put Premiums Payable
	During June 2012, a premium (“put premium”) was paid to purchase the contracts and will be allocated to natural gas production revenues generated over the contractual term of the purchased hedging instruments. At March 31, 2015 and December 31, 2014, the put premiums were recorded as short-term payables to affiliate, of $37,000 and $35,600, respectively, and long-term payables to affiliate of $30,600 and $40,700, respectively.
	Accumulated Other Comprehensive Income
	As a result of the put options, swaps and the unrealized gains recognized in income in the current and in prior periods due to natural gas and oil property impairments, the Partnership recorded a net deferred gain on its balance sheet in accumulated other comprehensive income of $12,700 as of March 31, 2015. Included in accumulated other comprehensive income are unrealized gains of $240,600, net of the MGP interest, that were recognized in income as a result of gas and oil property impairments during prior periods. During the three months ended March 31, 2015, $59,000 of net gains were recorded by the Partnership and allocated only to the limited partners. Of the remaining $12,700 of net unrealized gain in accumulated other comprehensive income, the Partnership will reclassify $9,700 of net gains to the Partnership’s statements of operations over the next twelve month period and the remaining gains of $3,000 in later periods.

Fair_Value_of_Financial_Instru

Fair Value of Financial Instruments	3 Months Ended
	Mar. 31, 2015
Fair Value Disclosures [Abstract]
FAIR VALUE OF FINANCIAL INSTRUMENTS	NOTE 5 - FAIR VALUE OF FINANCIAL INSTRUMENTS
	The Partnership has established a hierarchy to measure its financial instruments at fair value, which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect the Partnership’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value:
	Level 1 –   Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.
	Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.
	Level 3 – Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	The carrying values of cash, accounts receivable and accounts payable approximate their respective fair values due to the short-term maturities of such financial instruments. The Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (See Note 4). The Partnership manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty. The Partnership’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. The fair values of these derivative instruments are calculated by utilizing commodity indices, quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and the pricing formula utilized in the derivative instrument.
	Information for assets measured at fair value at March 31, 2015 and December 31, 2014 was as follows:
		Level 1		Level 2		Level 3		Total
	As of March 31, 2015
	Derivative assets, gross
	Commodity swaps	$	-	$	294,700	$	-	$	294,700
	Commodity puts		-		109,400		-		109,400
	Total derivative assets, gross	$	-	$	404,100	$	-	$	404,100
		Level 1		Level 2		Level 3		Total
	As of December 31, 2014
	Derivative assets, gross
	Commodity swaps	$	-	$	288,500	$	-	$	288,500
	Commodity puts		-		102,000		-		102,000
	Total derivative assets, gross	$	-	$	390,500	$	-	$	390,500
	Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
	The Partnership estimates the fair value of its asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates (See Note 3). There were no additional assets or liabilities that were measured at fair value on a nonrecurring basis for the three months ended March 31, 2015 and 2014.

Certain_Relationships_and_Rela

Certain Relationships and Related Party Transactions	3 Months Ended
	Mar. 31, 2015
Related Party Transactions [Abstract]
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS	NOTE 6 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
	The Partnership has entered into the following significant transactions with the MGP and its affiliates as provided under its Partnership Agreement. Administrative costs, which are included in general and administrative expenses in the Partnership’s statements of operations, are payable at $75 per well per month. Monthly well supervision fees, which are included in production expense in the Partnership’s statements of operations, are payable at $975 per well per month for Marcellus wells, $1,500 per well per month for New Albany wells, and for all other wells a fee of $392 is charged per well per month for operating and maintaining the wells. Well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of the working interest in a well. Transportation fees are included in production expenses in the Partnership’s statements of operations and are generally payable at 16% of the natural gas sales price. Direct costs, which are included in production and general administrative expenses in the Partnership’s statements of operations, are payable to the MGP and its affiliates as reimbursement for all costs expended on the Partnership’s behalf.
	The following table provides information with respect to these costs and the periods incurred:
		Three Months Ended
		March 31,
		2015		2014
	Administrative fees	$	29,300	$	28,400
	Supervision fees		245,600		242,500
	Transportation fees		96,600		157,300
	Direct costs		273,700		319,500
	Total	$	645,200	$	747,700
	The MGP and its affiliates perform all administrative and management functions for the Partnership including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP. Accounts payable trade-affiliate on the Partnership’s balance sheets include $407,200 relating to well construction for various Cowden wells paid by the MGP at March 31, 2015 and December 31, 2014.

Commitments_and_Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	NOTE 7 - COMMITMENTS AND CONTINGENCIES
	General Commitments
	Subject to certain conditions, investor partners may present their interests for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. The MGP is not obligated to purchase more than 5% of the total outstanding units in any calendar year. In the event that the MGP is unable to obtain the necessary funds, it may suspend its purchase obligation.
	Beginning one year after each of the Partnership’s wells has been placed into production, the MGP, as operator, may retain $200 per month per well to cover estimated future plugging and abandonment costs. As of March 31, 2015, the MGP has withheld $101,700 of net production revenue for future plugging and abandonment costs.
	Legal Proceedings
	The Partnership is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations.
	Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of their respective businesses. The MGP’s management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the MGP’s financial condition or results of operations.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Use of Estimates	Use of Estimates
	The preparation of the Partnership’s financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, impairments, fair value of derivative instruments and the probability of forecasted transactions. Actual results could differ from those estimates.
	The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following months’ financial results. Management believes that the operating results presented for the three months ended March 31, 2015 and 2014 represent actual results in all material respects (See “Revenue Recognition”).
Accounts Receivable	Accounts Receivable
	Accounts receivable on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of its accounts receivable, the MGP performs ongoing credit evaluations of the Partnership’s customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness, as determined by review of such customers’ credit information. Credit is extended on an unsecured basis to many of the Partnership’s energy customers. At March 31, 2015 and December 31, 2014, the MGP’s credit evaluation indicated that the Partnership had no need for an allowance for uncollectible accounts receivable.
Gas and Oil Properties	Gas and Oil Properties
	Gas and oil properties are stated at cost. Maintenance and repairs which generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized.
	The Partnership follows the successful efforts method of accounting for gas and oil producing activities. Oil and natural gas liquids (NGLs) are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to six Mcf of natural gas. Mcf is defined as one thousand cubic feet.
	The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties. The Partnership recorded depletion expense on natural gas and oil properties of $204,000 and $435,200 for the three months ended March 31, 2015 and 2014, respectively.
	Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts and the resultant gain or loss is reclassified to the Partnership’s statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depletion within its balance sheets.
	The following is a summary of gas and oil properties at the dates indicated:
		March 31,			December 31,
		2015			2014
	Proved properties:
	Leasehold interests	$	2,387,700		$	2,387,700
	Wells and related equipment		212,713,600			212,713,600
	Total natural gas and oil properties		215,101,300			215,101,300
	Accumulated depletion and impairment		(208,464,900	)		(208,260,900	)
	Gas and oil properties, net	$	6,636,400		$	6,840,400
Impairment of Long-Lived Assets	Impairment of Long-Lived Assets
	The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount of that asset to its estimated fair value if such carrying amount exceeds the fair value.
	The review of the Partnership’s gas and oil properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion and impairment is less than the estimated expected undiscounted future cash flows including salvage. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of the production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value and the carrying value of the assets.
	The determination of natural gas and oil reserve estimates is a subjective process and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.
	In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods.
	There was no gas and oil properties impairment recorded for the three months ended March 31, 2015 and 2014. During the year ended December 31, 2014, the Partnership recognized an impairment charge of $13,776,200. This impairment relates to the carrying amount of these gas and oil properties being in excess of the Partnership’s estimate of their fair value at December 31, 2014. The estimate of the fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil prices at the date of measurement.
Working Interest	Working Interest
	The Partnership Agreement establishes that revenues and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). The MGP is also provided an additional working interest of 10% as provided in the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expenses until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues and expenses based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.
Revenue Recognition	Revenue Recognition
	The Partnership generally sells natural gas, crude oil and NGLs at prevailing market prices. Typically, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil and NGLs, in which the Partnership has an interest with other producers are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty.
	The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP. The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees, which are, in turn, based upon applicable product prices (See “Use of Estimates” for further description). The Partnership had unbilled revenues at March 31, 2015 and December 31, 2014 of $414,700 and $499,800, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.
Comprehensive Income (Loss)	Comprehensive Income (Loss)
	Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on the Partnership’s financial statements and, at March 31, 2015, only include changes in the fair value of unsettled derivative contracts which prior to January 1, 2015 were accounted for as cash flow hedges (See Note 4). The Partnership does not have any other type of transaction which would be included within other comprehensive income (loss).
Recently Issued Accounting Standards
	Recently Issued Accounting Standards
	In January 2015, the Financial Accounting Standards Board (“FASB”) issued ASU 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items (“Update 2015-01”). The amendments in Update 2015-01 simplify the income statement presentation requirements in Subtopic 225-20 by eliminating the concept of extraordinary items. Extraordinary items are events and transactions that are distinguished by their unusual nature and by the infrequency of their occurrence. Eliminating the extraordinary classification simplifies income statement presentation by altogether removing the concept of extraordinary items from consideration. The amendments in Update 2015-01 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A reporting entity may apply the amendments prospectively. A reporting entity may also apply the amendments retrospectively to all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. The Partnership will adopt the requirements of Update 2015-01 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.
	In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. The Partnership will adopt the requirements of Update 2014-15 upon its effective date in 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.
	In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles – Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. The Partnership will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2017, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures. On April 1, 2015, the FASB tentatively decided to defer the effective date of ASU 2014-09 by one year. As a result, public entities would apply the new revenue standard to annual reporting periods beginning after December 15, 2017, and to interim periods within that reporting period, with early adoption permitted.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Summary of Gas and Oil Properties	The following is a summary of gas and oil properties at the dates indicated:
		March 31,			December 31,
		2015			2014
	Proved properties:
	Leasehold interests	$	2,387,700		$	2,387,700
	Wells and related equipment		212,713,600			212,713,600
	Total natural gas and oil properties		215,101,300			215,101,300
	Accumulated depletion and impairment		(208,464,900	)		(208,260,900	)
	Gas and oil properties, net	$	6,636,400		$	6,840,400

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations
	A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the periods indicated is as follows:
		Three Months Ended
		March 31,
		2015		2014
	Asset retirement obligations at beginning of period	$	3,825,600	$	2,572,500
	Accretion expense		62,600		38,200
	Asset retirement obligations at end of period	$	3,888,200	$	2,610,700

Derivative_Instruments_Tables

Derivative Instruments (Tables)	3 Months Ended
	Mar. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Summary of Gains or Losses Recognized Within Statements of Operations for Derivative Instruments Previously Designated as Cash Flow Hedges	The following table summarizes the gains or losses recognized within the statements of operations for derivative instruments previously designated as cash flow hedges for the periods indicated:
			Three Months Ended
			March 31,
			2015			2014
	Gains reclassified from accumulated other comprehensive income into natural gas and oil revenues		$	35,000		$	78,600
	Gains subsequent to December 31, 2014 recognized in gain on mark-to-market derivatives		$	22,300		$	-
Commodity Derivatives	At March 31, 2015, the Partnership had the following commodity derivatives:
	Natural Gas Fixed Price Swaps - Limited Partners
	Production			Volumes			Average		Fair Value
	Period Ending						Fixed Price		Asset (2)
	December 31,
				(MMBtu)(1)			(per MMBtu)(1)
	2015				135,000		$	4.224	$	194,100
	2016				75,600			4.46		100,600
									$	294,700
	Natural Gas Put Options - Limited Partners
	Production			Volumes			Average		Fair Value
	Period Ending						Fixed Price		Asset (2)
	December 31,
				(MMBtu)(1)			(per MMBtu)(1)
	2015				39,900		$	4	$	49,100
	2016				53,200			4.15		60,300
									$	109,400
	Limited Partner’s Commodity Derivatives, net								$	404,100
	-1	“MMBtu” represents million British Thermal Units.
	-2	Fair value based on forward NYMEX natural gas prices, as applicable.

Fair_Value_of_Financial_Instru1

Fair Value of Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2015
Fair Value Disclosures [Abstract]
Schedule of Fair Value Derivative Instruments
	Information for assets measured at fair value at March 31, 2015 and December 31, 2014 was as follows:
		Level 1		Level 2		Level 3		Total
	As of March 31, 2015
	Derivative assets, gross
	Commodity swaps	$	-	$	294,700	$	-	$	294,700
	Commodity puts		-		109,400		-		109,400
	Total derivative assets, gross	$	-	$	404,100	$	-	$	404,100
		Level 1		Level 2		Level 3		Total
	As of December 31, 2014
	Derivative assets, gross
	Commodity swaps	$	-	$	288,500	$	-	$	288,500
	Commodity puts		-		102,000		-		102,000
	Total derivative assets, gross	$	-	$	390,500	$	-	$	390,500

Certain_Relationships_and_Rela1

Certain Relationships and Related Party Transactions (Tables)	3 Months Ended
	Mar. 31, 2015
Related Party Transactions [Abstract]
Costs Incurred From Related Party Transactions	The following table provides information with respect to these costs and the periods incurred:
		Three Months Ended
		March 31,
		2015		2014
	Administrative fees	$	29,300	$	28,400
	Supervision fees		245,600		242,500
	Transportation fees		96,600		157,300
	Direct costs		273,700		319,500
	Total	$	645,200	$	747,700

Description_of_Business_Detail

Description of Business (Details)	3 Months Ended	0 Months Ended
	Mar. 31, 2015	Feb. 27, 2015
Description Of Business [Line Items]
Atlas Resources Public #18-2008 (A) L.P. Formation Date	8-Apr-08
Atlas Energy Group | Atlas Energy | Spin Off
Description Of Business [Line Items]
Percentage of limited liability company interests distributed to unitholders		100.00%

Summary_of_Significant_Account3

Summary of Significant Accounting Policies (Narrative) (Details) (USD $)	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Accounting Policies [Abstract]
Allowance for Uncollectible Accounts Receivable	$0		$0
Depletion of Oil and Gas Properties	204,000	435,200
Impairment	0	0	13,776,200
Additional working interest	10.00%
Unbilled Revenues	$414,700		$499,800

Summary_of_Significant_Account4

Summary of Significant Accounting Policies (Summary of Gas and Oil Properties) (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Property Plant And Equipment [Line Items]
Total natural gas and oil properties	$215,101,300	$215,101,300
Accumulated depletion and impairment	-208,464,900	-208,260,900
Gas and oil properties, net	6,636,400	6,840,400
Leasehold interests
Property Plant And Equipment [Line Items]
Total natural gas and oil properties	2,387,700	2,387,700
Wells and related equipment
Property Plant And Equipment [Line Items]
Total natural gas and oil properties	$212,713,600	$212,713,600

Asset_Retirement_Obligations_N

Asset Retirement Obligations (Narrative) (Details) (USD $)	3 Months Ended
	Mar. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Net production revenue for future plugging and abandonment costs	$101,700

Asset_Retirement_Obligations_S

Asset Retirement Obligations (Schedule of Asset Retirement Obligations) (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at beginning of period	$3,825,600	$2,572,500
Accretion expense	62,600	38,200
Asset retirement obligations at end of period	$3,888,200	$2,610,700

Derivative_Instruments_Narrati

Derivative Instruments (Narrative) (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Derivative [Line Items]
Net derivative assets	$404,100		$390,500
Gains (Losses) on Fair Value Hedge Ineffectiveness, Net	0	0
Current portion of put premiums payable-affiliate	37,000		35,600
Long-term put premiums payable-affiliate	30,600		40,700
Accumulated other comprehensive income	12,700		15,700
Other Comprehensive Income
Derivative [Line Items]
Unrealized gains (losses) due to natural gas and oil property impairments	240,600
Net Derivative Gains (Losses) Limited Partner	59,000
Cash Flow Hedge Gains (Losses) to be Reclassified within Twelve Months	9,700
Net Deferred Gains (Losses) to be Reclassified into Net Income in Later Periods	$3,000

Derivative_Instruments_Summary

Derivative Instruments (Summary of Gains or Losses Recognized Within Statements of Operations for Derivative Instruments Previously Designated as Cash Flow Hedges) (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Gains reclassified from accumulated other comprehensive income into natural gas and oil revenues	$35,000	$78,600
Gains subsequent to December 31, 2014 recognized in gain on mark-to-market derivatives	$22,300

Derivative_Instruments_Commodi

Derivative Instruments (Commodity Derivatives) (Details) (USD $)	3 Months Ended
	Mar. 31, 2015		Dec. 31, 2014
	MMBTU
Derivative [Line Items]
Fair Value Asset	$404,100		$390,500
Natural Gas Put Options - Limited Partners
Derivative [Line Items]
Fair Value Asset	109,400	[1]
Natural Gas Fixed Price Swaps - Limited Partners
Derivative [Line Items]
Fair Value Asset	294,700	[1]
Limited Partner's Commodity Derivatives, net
Derivative [Line Items]
Fair Value Asset	404,100	[1]
Production Period Ending December 31, 2015 | Natural Gas Put Options - Limited Partners
Derivative [Line Items]
Volumes (MMBtu)	39,900	[2]
Average Fixed Price (per MMBtu)	4	[2]
Fair Value Asset	49,100	[1]
Production Period Ending December 31, 2015 | Natural Gas Fixed Price Swaps - Limited Partners
Derivative [Line Items]
Volumes (MMBtu)	135,000	[2]
Average Fixed Price (per MMBtu)	4.224	[2]
Fair Value Asset	194,100	[1]
Production Period Ending December 31, 2016 | Natural Gas Put Options - Limited Partners
Derivative [Line Items]
Volumes (MMBtu)	53,200	[2]
Average Fixed Price (per MMBtu)	4.15	[2]
Fair Value Asset	60,300	[1]
Production Period Ending December 31, 2016 | Natural Gas Fixed Price Swaps - Limited Partners
Derivative [Line Items]
Volumes (MMBtu)	75,600	[2]
Average Fixed Price (per MMBtu)	4.46	[2]
Fair Value Asset	$100,600	[1]
[1]	Fair value based on forward NYMEX natural gas prices, as applicable.
[2]	bMMBtub represents million British Thermal Units.

Fair_Value_of_Financial_Instru2

Fair Value of Financial Instruments (Assets Measured at Fair Value on a Recurring Basis) (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross	$404,100	$390,500
Commodity Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross	294,700	288,500
Commodity Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross	109,400	102,000
Fair Value, Inputs, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross	404,100	390,500
Fair Value, Inputs, Level 2 | Commodity Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross	294,700	288,500
Fair Value, Inputs, Level 2 | Commodity Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross	$109,400	$102,000

Fair_Value_of_Financial_Instru3

Fair Value of Financial Instruments (Narrative) (Details) (USD $)	Mar. 31, 2015	Mar. 31, 2014
Fair Value Disclosures [Abstract]
Assets measured at fair value on nonrecurring basis	$0	$0
Liabilities measured at fair value on nonrecurring basis	$0	$0

Certain_Relationships_and_Rela2

Certain Relationships and Related Party Transactions (Narrative) (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Accounts payable trade-affiliate	$407,200	$407,200
MGP and Affiliates | Administrative
Related Party Transaction [Line Items]
Monthly Administrative Costs Per Well	75
MGP and Affiliates | Administrative | Marcellus wells
Related Party Transaction [Line Items]
Monthly Supervision Fees Per Well	975
MGP and Affiliates | Administrative | New Albany Wells
Related Party Transaction [Line Items]
Monthly Supervision Fees Per Well	1,500
MGP and Affiliates | Administrative | Other Wells
Related Party Transaction [Line Items]
Monthly Supervision Fees Per Well	392
MGP and Affiliates | Production
Related Party Transaction [Line Items]
Transportation Fee Rate As Percentage Of Natural Gas Sales Price	16.00%

Certain_Relationships_and_Rela3

Certain Relationships and Related Party Transactions (Schedule of Related Party Transactions) (Details) (MGP and Affiliates, USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$645,200	$747,700
Administrative fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	29,300	28,400
Supervision fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	245,600	242,500
Transportation fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	96,600	157,300
Direct Costs
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$273,700	$319,500

Commitments_and_Contingencies_

Commitments and Contingencies (Narrative) (Details) (USD $)	3 Months Ended
	Mar. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
Investor Partners Ownership Interest Presented For Purchase By The MGP, Maximum Percentage	5.00%
Operator Fee Per Well To Cover Estimated Future Plugging And Abandonment Costs, Monthly	200
Net production revenue for future plugging and abandonment costs	$101,700