Atlas Resources Series 28-2010 10-K 31 Mar 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013
Document Document And Entity Information [Line Items]	'
Document Type	'10-K
Amendment Flag	'false
Document Period End Date	31-Dec-13
Document Fiscal Year Focus	'2013
Document Fiscal Period Focus	'FY
Entity Registrant Name	'Atlas Resources Series 28-2010 L.P.
Entity Central Index Key	'0001487561
Current Fiscal Year End Date	'--12-31
Entity Filer Category	'Smaller Reporting Company
Entity Common Stock, Shares Outstanding	0
Entity Public Float	$0
Entity Current Reporting Status	'Yes
Entity Well-known Seasoned Issuer	'No
Entity Voluntary Filers	'No

BALANCE_SHEETS

BALANCE SHEETS (USD $)	Dec. 31, 2013	Dec. 31, 2012
Current assets:	'	'
Cash and cash equivalents	$1,257,000	$1,704,000
Accounts receivable trade–affiliate	4,307,300	6,263,800
Proceeds from sale of properties receivable-affiliate	405,700	'
Accounts receivable monetized gains-affiliate	285,300	2,316,000
Current portion of derivative assets	'	532,800
Total current assets	6,255,300	10,816,600
Oil and gas properties, net	80,682,500	91,095,300
Long-term derivative assets	282,900	541,500
TOTAL ASSETS	87,220,700	102,453,400
Current liabilities:	'	'
Accrued liabilities	212,800	191,500
Short-term derivative liabilities	126,900	'
Total current liabilities	339,700	191,500
Asset retirement obligations	1,544,700	2,264,200
Long-term put premiums payable-affiliate	293,000	116,300
Commitments and contingencies	'	'
Partners’ capital:	'	'
Managing general partner’s interest	14,598,900	15,968,600
Limited partners’ interest (7,500 units)	70,382,800	81,150,300
Accumulated other comprehensive income	61,600	2,762,500
Total partners’ capital	85,043,300	99,881,400
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$87,220,700	$102,453,400

BALANCE_SHEETS_Parenthetical

BALANCE SHEETS (Parenthetical)	Dec. 31, 2013
Limited partners' units	7,500

STATEMENTS_OF_OPERATIONS

STATEMENTS OF OPERATIONS (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
REVENUES	'	'
Natural gas	$24,625,400	$27,071,500
Gain on sale of oil and gas properties	409,100	'
Total revenues	25,034,500	27,071,500
COST AND EXPENSES	'	'
Production	7,445,000	9,390,700
Depletion	10,650,900	13,917,300
Asset impairment	'	218,800
Accretion of asset retirement obligation	123,100	110,000
General and administrative	153,800	151,300
Total costs and expenses	18,372,800	23,788,100
Net income	6,661,700	3,283,400
Allocation of net income:	'	'
Managing general partner	4,232,200	3,253,700
Limited partners	$2,429,500	$29,700
Net income per limited partnership unit	$324	$4

STATEMENTS_OF_COMPREHENSIVE_IN

STATEMENTS OF COMPREHENSIVE INCOME (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Net income	$6,661,700	$3,283,400
Other comprehensive loss:	'	'
Unrealized holding (loss) gain on cash flow hedging contracts	-284,000	250,300
Difference in estimated hedge gains receivable	-418,000	-182,600
Reclassification adjustment for gains realized in net income from cash flow hedges	-1,998,900	-3,272,100
Total other comprehensive loss	-2,700,900	-3,204,400
Comprehensive income	$3,960,800	$79,000

STATEMENTS_OF_CHANGES_IN_PARTN

STATEMENTS OF CHANGES IN PARTNERS' CAPITAL (USD $)	Total	Managing General Partner	Limited Partners	Accumulated Other Comprehensive Income (Loss)
Beginning balance at Dec. 31, 2011	$98,875,000	$2,600,500	$90,307,600	$5,966,900
Partners’ capital contributions:	'	'	'	'
Syndication and offering costs	1,400	1,400	'	'
Tangible equipment/leasehold costs	14,269,700	14,269,700	'	'
Total contributions	14,271,100	14,271,100	'	'
Syndication and offerings, immediately charged to capital	-1,400	-1,400	'	'
Total partners' capital contributions net of amounts charged to capital	14,269,700	14,269,700	'	'
Participation in revenue and costs and expenses:	'	'	'	'
Net production revenues	17,680,800	5,400,500	12,280,300	'
Depletion	-13,917,300	-2,019,500	-11,897,800	'
Asset impairment	-218,800	-31,600	-187,200	'
Accretion of asset retirement obligation	-110,000	-40,300	-69,700	'
General and administrative	-151,300	-55,400	-95,900	'
Net income	3,283,400	3,253,700	29,700	'
Other comprehensive loss	-3,204,400	'	'	-3,204,400
Subordination	'	-2,291,600	2,291,600	'
Distributions to partners	-13,342,300	-1,863,700	-11,478,600	'
Ending balance at Dec. 31, 2012	99,881,400	15,968,600	81,150,300	2,762,500
Participation in revenue and costs and expenses:	'	'	'	'
Net production revenues	17,180,400	5,787,400	11,393,000	'
Gain on sale of oil and gas properties	409,100	145,100	264,000	'
Depletion	-10,650,900	-1,650,800	-9,000,100	'
Accretion of asset retirement obligation	-123,100	-45,600	-77,500	'
General and administrative	-153,800	-57,000	-96,800	'
Net income	6,661,700	4,179,100	2,482,600	'
Other comprehensive loss	-2,700,900	'	'	-2,700,900
Subordination	'	-3,102,000	3,102,000	'
Distributions to partners	-19,913,700	-3,223,200	-16,690,500	'
Working interest adjustment	'	-338,400	338,400	'
Assets contributed	1,114,800	1,114,800	'	'
Ending balance at Dec. 31, 2013	$85,043,300	$14,598,900	$70,382,800	$61,600

STATEMENTS_OF_CASH_FLOWS

STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:	'	'
Net income	$6,661,700	$3,283,400
Adjustments to reconcile net income to net cash provided by operating activities:	'	'
Depletion	10,650,900	13,917,300
Asset impairment	'	218,800
Non-cash loss on derivative value, net	424,800	784,100
Accretion of asset retirement obligation	123,100	110,000
Gain on sale of oil and gas properties	-409,100	'
Changes in operating assets and liabilities:	'	'
Decrease (increase) in accounts receivable trade-affiliate	1,956,500	-4,102,900
Increase (decrease) in accrued liabilities	21,300	-496,900
Net cash used in operating activities	19,429,200	13,713,800
Cash flows from investing activities:	'	'
Purchase of tangible equipment	-20,200	'
Proceeds from sale of tangible equipment	57,700	'
Net cash provided by investing activities	37,500	'
Cash flows from financing activities:	'	'
Distributions to partners	-19,913,700	-13,342,300
Net cash used in financing activities	-19,913,700	-13,342,300
Net change in cash and cash equivalents	-447,000	371,500
Cash and cash equivalents at beginning of year	1,704,000	1,332,500
Cash and cash equivalents at end of period	1,257,000	1,704,000
Supplemental schedule of non-cash investing and financing activities:	'	'
Assets contributed by the managing general partner: Tangible equipment	52,800	4,478,300
Assets contributed by managing general partner: Lease costs	'	1,000
Assets contributed by managing general partner: Intangible drilling costs	1,062,000	9,790,400
Assets contributed by managing general partner: Syndication and offering costs	'	1,400
Total assets contributed by managing general partner	1,114,800	14,271,100
Sales proceeds receivable	405,700	'
Asset retirement obligation revision	($742,100)	($4,000)

Basis_of_Presentation

Basis of Presentation	12 Months Ended
	Dec. 31, 2013
BASIS OF PRESENTATION	'
	NOTE 1—BASIS OF PRESENTATION
	Atlas Resources Series 28-2010 L.P. (the “Partnership”) is a Delaware limited partnership, formed on April 1, 2010 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 Resources Partners (“ARP”) (NYSE: ARP).
	In March 2012, the MGP’s ultimate parent, Atlas Energy L.P. (“Atlas Energy”) (NYSE: ATLS), contributed to ARP, a newly-formed exploration and production master limited partnership, substantially all of Atlas Energy’s natural gas and oil development and production assets and its partnership management business, including ownership of the MGP.
	On February 17, 2011, Atlas Energy L.P., formerly known as Atlas Pipeline Holdings, L.P. (“Atlas Energy”) (NYSE: ATLS), a then-majority owned subsidiary of Atlas Energy, Inc. and parent of the general partner of Atlas Pipeline Partners, L.P. (“APL”) (NYSE: APL), completed an acquisition of assets from Atlas Energy, Inc., which included its investment partnership business, its oil and gas exploration, development and production activities conducted in Tennessee, Indiana, and Colorado, certain shallow wells and leases in New York and Ohio, certain well interests in Pennsylvania and Michigan and its ownership and management of investments in Lightfoot Capital Partners, L.P. and related entities (the “Transferred Business”).
	The Partnership has drilled and currently operates wells located in Pennsylvania, Tennessee, Michigan, Indiana, and Colorado. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy, 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 does not plan to sell any of its wells and intends to produce them until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. The Partnership expects that no other wells will be drilled and no additional funds will be required for drilling.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	'
	NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	Use of Estimates
	The preparation of 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, asset impairments, fair value of derivative instruments and the probability of forecasted transactions. Actual results could differ from those estimates.
	Cash Equivalents
	The carrying amounts of the Partnership’s cash equivalents approximate fair values because of the short maturities of these instruments. The Partnership considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents.
	Receivables
	Accounts receivable affiliate 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 its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of the credit information. The Partnership extends credit on sales on an unsecured basis to many of their customers. At December 31, 2013 and 2012, the Partnership had recorded no allowance for uncollectible accounts receivable on its balance sheets.
	Oil and Gas Properties
	Oil and gas properties are stated at cost. Maintenance and repairs that 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 oil and gas producing activities. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to six mcf of natural gas.
	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.
	Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the cost 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 depreciation and depletion within its balance sheets.
	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 oil and gas 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 (as determined by discounted future cash flows) and the carrying value of the assets.
	The determination of oil and natural gas 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 impairment of oil and gas properties for the year ended December 31, 2013. During the year ended December 31, 2012, we recognized $218,800 of asset impairment related to gas and oil properties. This impairment related to the carrying amount of our gas and oil properties being in excess of our estimate of their fair value at December 31, 2012. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices.
	Derivative Instruments
	The MGP enters into certain financial contracts to manage the Partnership’s exposure to movement in commodity prices (see Note 6). The derivative instruments recorded in the balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Partnership’s statements of operations unless specific hedge accounting criteria are met.
	Asset Retirement Obligations
	The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (see Note 5). The Partnership recognizes a liability for its future asset retirement obligations in the current period 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.
	Income Taxes
	The Partnership is not treated as a taxable entity for federal income tax purposes. Any item of income, gain, loss, deduction, or credit flows through to the partners as though each partner had incurred such item directly. As a result, each partner must take into account their pro rata share of all items of partnership income and deductions in computing their federal income tax liability.
	The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. However, the Partnership has not recognized any potential interest or penalties in its financial statements as of December 31, 2013 and 2012.
	The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2009. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2013.
	Environmental Matters
	The Partnership is subject to various federal, state, and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Partnership’s operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. The Partnership maintains insurance which may cover in whole or in part certain environmental expenditures. The Partnership had no environmental matters requiring specific disclosure or requiring the recognition of a liability for the years ended December 31, 2013 and 2012.
	Concentration of Credit Risk
	The Partnership sells natural gas under contracts to various purchasers in the normal course of business. For the year ended December 31, 2013, the Partnership had two customers that individually accounted for approximately 75% and 20% of the Partnership’s natural gas revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2012, the Partnership had two customers that individually accounted for approximately 74% and 20%, of the Partnership’s natural gas and oil combined revenues, excluding the impact of all financial derivative activity.
	Financial instruments, which potentially subject the Partnership to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Partnership places its temporary cash investments in deposits with high-quality financial institutions. At December 31, 2013 and 2012, the Partnership had $1,309,000 and $1,781,000, respectively in deposits at one bank of which $1,059,000 and $1,531,000, respectively was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments.
	Revenue Recognition
	The Partnership generally sells natural gas at prevailing market prices. Generally, 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 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 Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas 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” accounting policy for further description). The Partnership had unbilled revenues at December 31, 2013 and 2012 of $3,009,000 and $4,365,200, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.
	Comprehensive Income
	Comprehensive income includes net income 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. These changes, other than net income, are referred to as “other comprehensive income” and for the Partnership include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges.
	Recently Adopted Accounting Standards
	In February 2013, the FASB issued ASU 2013-02, Comprehensive Income (Topic 220) (“Update 2013-02”). Update 2013-02 requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present significant amounts reclassified out of accumulated other comprehensive income if the amount reclassified to net income in its entirety is in the same reporting period as incurred. For other amounts that are not required to be reclassified in their entirety to net income, an entity is required to reference to other disclosures that provide additional detail about those amounts. Entities are required to implement the amendments prospectively for reporting periods beginning after December 15, 2012, with early adoption being permitted. The Partnership adopted the requirements of Update 2013-02 upon its effective date of January 1, 2013, and it had no material impact on its financial position, results of operations or related disclosures.
	In January 2013, the FASB issued ASU 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“Update 2013-01”). Update 2013-01 clarifies that ordinary trade receivables and payable are not in scope of ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. Specifically, ASU 2011-11 applies only to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with specific criteria contained in the FASB Accounting Standards Codification or subject to a master netting arrangement or similar agreement. The amendments are effective for interim and annual reporting periods beginning after January 1, 2013 and such amendments shall be applied retrospectively for any period presented that begins before the date of application. The Partnership adopted the requirements of Update 2013-01 on December 31, 2012, and it did not have a material impact on its financial position, results of operations or related disclosures.
	Recently Issued Accounting Standards
	In February 2013, the FASB issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements, for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements, for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership will apply the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

Participation_in_Revenues_and_

Participation in Revenues and Costs	12 Months Ended
	Dec. 31, 2013
PARTICIPATION IN REVENUES AND COSTS	'
	NOTE 3—PARTICIPATION IN REVENUES AND COSTS
	Working Interest
	Our Partnership Agreement establishes that revenues and expenses will be allocated to our MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). Our 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 expense 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 based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership. At December 31, 2013, $338,400 of net earnings resulting from the working interest adjustment was reclassified from the MGP’s capital account to the limited partner’s capital account.
	The MGP and the limited partners will generally participate in revenues and costs in the following manner:
		Managing		Limited
		General		Partners
		Partner
	Organization and offering cost		100%		0%
	Lease costs		100%		0%
	Revenues (1)		37%		63%
	Operating costs, administrative costs, direct and all other costs (2)		37%		63%
	Intangible drilling costs		8%		92%
	Tangible equipment costs		52%		48%
	-1	Subject to the MGP’s subordination obligation, substantially all partnership revenues will be shared in the same percentage as capital contributions are to the total partnership capital contributions, except that the MGP will receive an additional 10% of the partnership revenues.
	-2	These costs will be charged to the partners in the same ratio as the related production revenues are credited.

Property_Plant_and_Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2013
PROPERTY, PLANT AND EQUIPMENT	'
	NOTE 4—PROPERTY, PLANT AND EQUIPMENT
	The following is a summary of natural gas and oil properties at the dates indicated:
		December 31,
		2013			2012
	Proved properties:
	Leasehold interests	$	5,599,100		$	5,848,000
	Wells and related equipment		168,471,600			179,678,300
	Total natural gas and oil properties		174,070,700			185,526,300
	Accumulated depletion and impairment		(93,388,200	)		(94,431,000	)
	Oil and gas properties, net	$	80,682,500		$	91,095,300
	The Partnership recorded depletion expense on natural gas and oil properties of $10,650,900 and $13,917,300 for the years ended December 31, 2013 and 2012, respectively. Upon the sale or retirement of a complete or partial unit of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to accumulated depletion. Upon the sale of an entire interest where the property had been assessed for impairment, a gain or loss is recognized in the statements of operations. On December 30, 2013, the Partnership sold its oil and gas properties with a net book value of $3,400 in the Antrim Shale geological formation mostly located in Michigan for $405,700. Cash proceeds from the sale will be distributed to the partnership unit holders in accordance with the terms of the partnership agreement. As a result of the sale, $11,790,800 of oil and gas properties, $11,693,700 of accumulated depletion and impairment, and $100,500 of asset retirement obligations were removed from the partnership accounts resulting in a net gain of $409,100.
	There was no impairment of oil and gas properties for the year ended December 31, 2013. During the year ended December 31, 2012, we recognized $218,800 of asset impairment related to gas and oil properties. This impairment related to the carrying amount of our gas and oil properties being in excess of our estimate of their fair value at December 31, 2012. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
ASSET RETIREMENT OBLIGATIONS	'
	NOTE 5—ASSET RETIREMENT OBLIGATIONS
	The Partnership recognized an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. 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 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.
	A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the periods indicated is as follows:
		Years Ended December 31,
		2013			2012
	Asset retirement obligations, beginning of year	$	2,264,200		$	2,158,200
	Accretion of asset retirement obligations		123,100			110,000
	Asset retirement obligation revision		(742,100	)		(4,000	)
	Liabilities settled due to sale of oil and gas properties		(100,500	)		-
	Asset retirement obligations, end of period	$	1,544,700		$	2,264,200

Derivative_Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2013
DERIVATIVE INSTRUMENTS	'
	NOTE 6—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. 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.
	The MGP formally documents all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity derivative contracts to the forecasted transactions. The MGP assesses, both at the inception of the derivative and on an ongoing basis, whether the derivative was effective in offsetting changes in the forecasted cash flow of the hedged item. If the MGP determines that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the MGP will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which are determined by management of the MGP through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations. For derivatives qualifying as hedges, the Partnership recognizes the effective portion of changes in fair value of derivative instruments as accumulated other comprehensive income and reclassifies the portion relating to the Partnership’s commodity derivatives to gas and oil production revenues within the Partnership’s statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership recognizes changes in fair value within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations as they occur.
	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 sheet of $156,000 and $1,074,300 at December 31, 2013 and 2012, respectively.
	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 qualified and been designated as cash flow hedges and recorded at their fair values.
	At December 31, 2013, the Partnership had the following commodity derivatives:
	Natural Gas Fixed Price Swaps—Limited Partners
	Production Period Ending		Volumes				Average			Fair Value (Liability)
	December 31,		(MMBtu) (1)				Fixed Price			Asset (2)
							(per MMBtu) (1)
	2014			1,689,600			$	4.095		$	(158,200	)
	2015			576,000				4.224			45,200
	2016			229,700				4.46			74,700
										$	(38,300	)
	Natural Gas Put Options—Limited Partners
	Production Period Ending		Volumes				Average			Fair Value
	December 31,		(MMBtu) (1)				Fixed Price			Asset (2)
							(per MMBtu) (1)
	2014			254,500			$	3.8		$	31,300
	2015			203,600				4			68,700
	2016			203,600				4.15			94,300
										$	194,300
				Limited Partner’s Commodity Derivatives, net						$	156,000
	-1	“MMBtu” represents million British Thermal Units.
	-2	Fair value based on forward NYMEX natural gas prices, as applicable.
	Effects of Derivative Instruments on Statements of Operations:
	The following table summarizes the gain or loss recognized in the statements of operations for effective derivative instruments for the years ended December 31, 2013 and 2012:
		Years Ended
		December 31,
		2013				2012
	Gains from cash flow hedges reclassified from accumulated other comprehensive income (loss) into natural gas revenues	$	1,998,900			$	3,272,100
	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 years ended December 31, 2013 and 2012 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.
	The MGP has 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 oil and gas properties and first priority security interests in substantially all of its assets and by a guarantee of 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 December 31, 2013 only the Partnership’s natural gas swaps are included in the secured hedge facility.
	Monetized Gains
	Prior to February 17, 2011, Atlas Energy Inc., (“AEI”) monetized its derivative instruments, including those related to the future natural gas and oil production of the Transferred Business. AEI also monetized derivative instruments that were specifically related to the future natural gas and oil production of the Partnership. At December 31, 2013 and 2012, remaining hedge monetization cash proceeds of $432,300 and $2,520,000, respectively, related to the amounts hedged on behalf of the Partnership’s limited partners were included within accounts receivable monetized gains-affiliate. There were no long-term monetized gains receivable-affiliate at December 31, 2013. At December 31, 2012 $503,700 of monetized gains receivable affiliate were included in long-term put premiums payable-affiliate on the Partnership’s balance sheets. The Partnership will allocate the monetized net proceeds to the limited partners based on the natural gas and oil production generated over the period of the original derivative contracts.
	During June 2012, the MGP used the undistributed monetized funds to purchase natural gas put options on behalf of the limited partners of the Partnership only. 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 December 31, 2013 and 2012, the put premiums were recorded as short-term payables to affiliate of $147,000 and $204,000, respectively, and long-term payables to affiliate of $293,000 and $620,000, respectively. Furthermore, the current portion of the put premium liability was included in accounts receivable monetized gains-affiliate and the long-term receivable monetized gains-affiliate was included in long term put premiums payable-affiliate in the Partnership’s balance sheets, presenting the impact of offsetting the related party assets and liabilities. The put premiums included on the Partnership’s balance sheets are allocable to the limited partners only.
	The following table summarizes the gross and net fair values of the Partnership’s derivative and affiliate balances, presenting the impact of offsetting the derivative and related party assets and liabilities on the Partnership’s balance sheets for the periods indicated:
	Offsetting Derivative Assets		Gross Amounts				Gross Amounts			Net Amount of Assets
			of Recognized				Offset in the			Presented in the Balance
			Assets				Balance Sheets			Sheets
	As of December 31, 2013
	Accounts receivable monetized gains-affiliate		$	432,300			$	(147,000	)	$	285,300
			$	44,000			$	(44,000	)	$	-
	Current portion of derivative assets
	Long-term derivative assets			297,300				(14,400	)		282,900
	Current portion of derivative liabilities			14,600				(14,600	)		-
	Long-term derivative liabilities			6,500				(6,500	)		-
			$	362,400			$	(79,500	)	$	282,900
	Total derivative assets and affiliate balances		$	794,700			$	(226,500	)	$	568,200
	As of December 31, 2012
	Accounts receivable monetized gains-affiliate		$	2,520,000			$	(204,000	)	$	2,316,000
	Long-term receivable monetized gains-affiliate			503,700				(503,700	)		-
			$	3,023,700			$	(707,700	)	$	2,316,000
			$	556,400			$	(23,600	)	$	532,800
	Current portion of derivative assets
	Long-term derivative assets			622,400				(80,900	)		541,500
	Current portion of derivative liabilities			16,000				(16,000	)		-
	Long-term derivative liabilities			2,800				(2,800	)		-
			$	1,197,600			$	(123,300	)	$	1,074,300
	Total derivative assets and affiliate balances		$	4,221,300			$	(831,000	)	$	3,390,300
	Offsetting Derivative Liabilities		Gross Amounts				Gross Amounts			Net Amount of Liabilities
			of Recognized				Offset in the			Presented in the Balance
			Liabilities				Balance Sheets			Sheets
As of December 31, 2013
Put premiums payable -affiliate		$	(147,000	)		$	147,000		$	-
Long-term put premiums payable-affiliate			(293,000	)			-			(293,000	)
		$	(440,000	)		$	147,000		$	(293,000	)
		$	(5,500	)		$	5,500		$	-
Current portion of derivative assets
Long-term derivative assets			(13,900	)			13,900			-
Current portion of derivative liabilities			(179,900	)			53,000			(126,900	)
Long-term derivative liabilities			(7,100	)			7,100			-
		$	(206,400	)		$	79,500		$	(126,900	)
Total derivative liabilities and affiliate balances		$	(646,400	)		$	226,500		$	(419,900	)
As of December 31, 2012
Put premiums payable -affiliate		$	(204,000	)		$	204,000		$	-
Long-term put premiums payable-affiliate			(620,000	)			503,700			(116,300	)
		$	(824,000	)		$	707,700		$	(116,300	)
		$	(23,200	)		$	23,200		$	-
Current portion of derivative assets
Long-term derivative assets			(56,400	)			56,400			-
Current portion of derivative liabilities			(16,400	)			16,400			-
Long-term derivative liabilities			(27,300	)			27,300			-
		$	(123,300	)		$	123,300		$	-
Total derivative liabilities and affiliate balances		$	(947,300	)		$	831,000		$	(116,300	)
Accumulated Other Comprehensive Income
As a result of the monetization and the early settlement of natural gas and oil derivative instruments, the put options, and the unrealized gains recognized in earnings in prior periods due to natural gas and oil property impairments, the Partnership recorded a net deferred gain on its balance sheets in accumulated other comprehensive income of $61,600 as of December 31, 2013. Included in accumulated other comprehensive income are unrealized gains of $86,700, net of the MGP interest, that were recognized into earnings as a result of oil and gas property impairments during prior periods. During the current year, $1,523,500 of net gains were recorded by the Partnership and allocated only to the limited partners. During the current year, $23,600 of net losses were recorded by the Partnership and allocated only to the MGP. Of the remaining $61,600 of net unrealized gain in accumulated other comprehensive income, the Partnership will reclassify $71,700 of net gains to the Partnership’s statements of operations over the next twelve month period and the remaining losses of $10,100 in later periods. Approximately $26,700 of derivative losses were reclassified from other comprehensive income related to derivative instruments entered into during the year ended December 31, 2013.

Fair_Value_of_Financial_Instru

Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 2013
FAIR VALUE OF FINANCIAL INSTRUMENTS	'
	NOTE 7—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 6). 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. 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 pricing formula utilized in the derivative instrument.
	Information for assets and liabilities measured at fair value at December 31, 2013 and 2012 was as follows:
		Level 1		Level 2			Level 3		Total
	As of December 31, 2013
	Derivative assets, gross
	Commodity swaps	$	-	$	168,100		$	-	$	168,100
	Commodity puts		-		194,300			-		194,300
	Total derivative assets, gross	$	-	$	362,400		$	-	$	362,400
	Derivative liabilities, gross
	Commodity swaps	$	-	$	(206,400	)	$	-	$	(206,400	)
	Total derivative, fair value, net	$	-	$	156,000		$	-	$	156,000
	As of December 31, 2012
	Derivative assets, gross
	Commodity swaps	$	-	$	645,700		$	-	$	645,700
	Commodity puts		-		551,900			-		551,900
	Total derivative assets, gross	$	-	$	1,197,600		$	-	$	1,197,600
	Derivative liabilities, gross
	Commodity swaps	$	-	$	(123,300	)	$	-	$	(123,300	)
	Total derivative, fair value, net	$	-	$	1,074,300		$	-	$	1,074,300
	Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
	The Partnership’s other current assets and liabilities on its balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1.
	The Partnership estimates the fair value of its asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such 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. There were no adjustments to retirement obligations measured at fair value on a nonrecurring basis for the years ended December 31, 2013 and 2012.
	There was no impairment for the year ended December 31, 2013. The Partnership estimates the fair value of its long-lived assets in conjunction with the review of asset impairment or whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions, and judgments regarding such events or circumstances. For the year ended December 31, 2012, the Partnership recognized a $218,800, impairment of long-lived assets which was defined as a Level 3 fair value measurement (see Note 2 – Impairment of Long-Lived Assets).

Certain_Relationships_and_Rela

Certain Relationships and Related Party Transactions	12 Months Ended
	Dec. 31, 2013
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS	'
	NOTE 8—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
	The Partnership has entered into the following significant transactions with its 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 general and administrative expenses 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, $600 per well per month for horizontal Antrim Shale wells and for Colorado wells a fee of $400 is charged per well per month for operating and maintaining the wells. 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.
		Years Ended
		December 31,
		2013		2012
	Administrative	$	81,300	$	82,300
	Supervision		958,400		994,100
	Transportation		3,072,100		3,633,100
	Direct Costs		3,487,000		4,832,500
	Total	$	7,598,800	$	9,542,000
	Assets contributed from the MGP, which are disclosed on the Partnership’s statements of cash flows as non-cash investing and financing activities, for the years ended December 31, 2013 and 2012 were $1,114,800 and $14,269,700 respectively. The MGP received a credit to its capital account of $1,400 for the year ended December 31, 2012, for fees, commissions, and reimbursement costs to organize the Partnership. 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.
	Subordination by Managing General Partner
	Under the terms of the Partnership Agreement, the MGP may be required to subordinate up to 50% of its share of net production revenues of the Partnership to the benefit of the limited partners for an amount equal to at least 12% of their net subscriptions in the first 12-month subordination period, 10% of their net subscriptions in each of the next three 12-month subordination periods, and 8% of their net subscriptions in the fifth 12-month subordination period determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution to the limited partners (March 2011) and expiring 60 months from that date. The MGP subordinated $3,102,000 and $2,291,600 of its net production revenues to the limited partners for the years ended December 31, 2013 and 2012, respectively.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
COMMITMENTS AND CONTINGENCIES	'
	NOTE 9—COMMITMENTS AND CONTINGENCIES
	General Commitments
	Subject to certain conditions, investor partners may present their interests beginning in 2015 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 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 December 31, 2013, the MGP has not withheld any such funds. The MGP is currently evaluating its right to exercise this option based on several factors such as commodity prices, the natural decline in well production, and current and future plugging services and 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.

Subsequent_Events

Subsequent Events	12 Months Ended
	Dec. 31, 2013
SUBSEQUENT EVENTS	'
	NOTE 10—SUBSEQUENT EVENTS
	Management has considered for disclosure any material subsequent events through the date the financial statements were issued.

Supplemental_Oil_and_Gas_Infor

Supplemental Oil and Gas Information (Unaudited)	12 Months Ended
	Dec. 31, 2013
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)	'
	NOTE 11—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
	Oil and Gas Reserve Information. The preparation of the Partnership’s natural gas and oil reserve estimates was completed in accordance with our MGP’s prescribed internal control procedures by its reserve engineers. The accompanying reserve information included below is attributable to the reserves of the Partnership and was derived from the reserve reports prepared for Atlas America Series 28-2010 L.P. annual Form 10-K for the years ended December 31, 2013 and 2012 (see Note 2). For the periods presented, Wright and Company, Inc., an independent third-party reserve engineer, was retained to prepare a report of proved reserves related to the Partnership. The reserve information for the Partnership includes natural gas and oil reserves which are all located in the United States. The independent reserves engineer’s evaluation was based on more than 37 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. The MGP’s internal control procedures include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our MGP’s Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 15 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by the MGP’s senior engineering staff and management, with final approval by the MGP’s Chief Operating Officer.
	The reserve disclosures that follow reflect estimates of proved developed reserves net of royalty interests, of natural gas, crude oil, and natural gas liquids owned at year end. Proved developed reserves are those reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. In accordance with the prevailing accounting literature, the proved reserves quantities and future net cash flows as of December 31, 2013, and 2012 were estimated using an unweighted 12-month average pricing based on the prices on the first day of each month during the years ended December 31, 2013 and 2012 and, including adjustments related to regional price differentials and energy content.
	There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of oil and gas reserves included within the Partnership or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil and gas prices and in production and development costs and other factors, for their effects have not been proved.
	Reserve quantity information and a reconciliation of changes in proved reserve quantities included within the Partnership are as follows (unaudited):
		Gas (Mcf)
	Balance, December 31, 2011		63,841,000
	Revisions (1)		(3,494,200	)
	Production		(8,355,400	)
			51,991,400
	Balance, December 31, 2012
	Revisions (2)		8,642,100
	Production		(6,083,500	)
			54,550,000
	Balance, December 31, 2013
	-1	The downward revision in natural gas volumes is primarily due to a decline in SEC base pricing from the prior year, a decrease in the positive gas price basis differentials and a decrease in economic lives resulting from increased expenses.
	-2	The upward revision in natural gas forecasts is primarily due to an increase in SEC base pricing from the prior year, resulting in longer economic life.
	Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to oil and gas producing activities of the Partnership during the periods indicated were as follows:
		Years Ended December 31,
		2013			2012
	Natural gas and oil properties:
	Leasehold interest	$	5,599,100		$	5,848,000
	Wells and related equipment		168,471,600			179,678,300
	Accumulated depletion, accretion and impairment		(93,388,200	)		(94,431,000	)
	Net capitalized costs	$	80,682,500		$	91,095,300
	Results of Operations from Oil and Gas Producing Activities. The results of operations related to the Partnership’s oil and gas producing activities during the periods indicated were as follows:
		Years Ended December 31,
		2013			2012
	Revenues	$	24,625,400		$	27,071,500
	Production costs		(7,445,000	)		(9,390,700	)
	Depletion		(10,650,900	)		(13,917,300	)
	Long-lived asset impairment		-			(218,800	)
		$	6,529,500		$	3,544,700
	Standardized Measure of Discounted Future Cash Flows. The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the Partnership’s proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2013 and 2012, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations:
		Years Ended December 31,
		2013			2012
	Future cash inflows	$	203,683,400		$	146,305,000
	Future production costs		(75,582,300	)		(63,637,000	)
	Future net cash flows		128,101,100			82,668,000
	Less 10% annual discount for estimated timing of cash flows		(69,621,400	)		(39,356,600	)
	Standardized measure of discounted future net cash flows	$	58,479,700		$	43,311,400

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Use of Estimates	'
	Use of Estimates
	The preparation of 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, asset impairments, fair value of derivative instruments and the probability of forecasted transactions. Actual results could differ from those estimates.
Cash Equivalents	'
	Cash Equivalents
	The carrying amounts of the Partnership’s cash equivalents approximate fair values because of the short maturities of these instruments. The Partnership considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents.
Receivables	'
	Receivables
	Accounts receivable affiliate 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 its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of the credit information. The Partnership extends credit on sales on an unsecured basis to many of their customers. At December 31, 2013 and 2012, the Partnership had recorded no allowance for uncollectible accounts receivable on its balance sheets.
Oil and Gas Properties	'
	Oil and Gas Properties
	Oil and gas properties are stated at cost. Maintenance and repairs that 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 oil and gas producing activities. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to six mcf of natural gas.
	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.
	Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the cost 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 depreciation and depletion within its balance sheets.
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 oil and gas 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 (as determined by discounted future cash flows) and the carrying value of the assets.
	The determination of oil and natural gas 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 impairment of oil and gas properties for the year ended December 31, 2013. During the year ended December 31, 2012, we recognized $218,800 of asset impairment related to gas and oil properties. This impairment related to the carrying amount of our gas and oil properties being in excess of our estimate of their fair value at December 31, 2012. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices.
Derivative Instruments	'
	Derivative Instruments
	The MGP enters into certain financial contracts to manage the Partnership’s exposure to movement in commodity prices (see Note 6). The derivative instruments recorded in the balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Partnership’s statements of operations unless specific hedge accounting criteria are met.
Asset Retirement Obligations	'
	Asset Retirement Obligations
	The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (see Note 5). The Partnership recognizes a liability for its future asset retirement obligations in the current period 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.
Income Taxes	'
	Income Taxes
	The Partnership is not treated as a taxable entity for federal income tax purposes. Any item of income, gain, loss, deduction, or credit flows through to the partners as though each partner had incurred such item directly. As a result, each partner must take into account their pro rata share of all items of partnership income and deductions in computing their federal income tax liability.
	The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. However, the Partnership has not recognized any potential interest or penalties in its financial statements as of December 31, 2013 and 2012.
	The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2009. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2013.
Environmental Matters	'
	Environmental Matters
	The Partnership is subject to various federal, state, and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Partnership’s operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. The Partnership maintains insurance which may cover in whole or in part certain environmental expenditures. The Partnership had no environmental matters requiring specific disclosure or requiring the recognition of a liability for the years ended December 31, 2013 and 2012.
Concentration of Credit Risk	'
	Concentration of Credit Risk
	The Partnership sells natural gas under contracts to various purchasers in the normal course of business. For the year ended December 31, 2013, the Partnership had two customers that individually accounted for approximately 75% and 20% of the Partnership’s natural gas revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2012, the Partnership had two customers that individually accounted for approximately 74% and 20%, of the Partnership’s natural gas and oil combined revenues, excluding the impact of all financial derivative activity.
	Financial instruments, which potentially subject the Partnership to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Partnership places its temporary cash investments in deposits with high-quality financial institutions. At December 31, 2013 and 2012, the Partnership had $1,309,000 and $1,781,000, respectively in deposits at one bank of which $1,059,000 and $1,531,000, respectively was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments.
Revenue Recognition	'
	Revenue Recognition
	The Partnership generally sells natural gas at prevailing market prices. Generally, 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 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 Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas 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” accounting policy for further description). The Partnership had unbilled revenues at December 31, 2013 and 2012 of $3,009,000 and $4,365,200, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.
Comprehensive Income	'
	Comprehensive Income
	Comprehensive income includes net income 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. These changes, other than net income, are referred to as “other comprehensive income” and for the Partnership include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges.
Recently Adopted Accounting Standards	'
	Recently Adopted Accounting Standards
	In February 2013, the FASB issued ASU 2013-02, Comprehensive Income (Topic 220) (“Update 2013-02”). Update 2013-02 requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present significant amounts reclassified out of accumulated other comprehensive income if the amount reclassified to net income in its entirety is in the same reporting period as incurred. For other amounts that are not required to be reclassified in their entirety to net income, an entity is required to reference to other disclosures that provide additional detail about those amounts. Entities are required to implement the amendments prospectively for reporting periods beginning after December 15, 2012, with early adoption being permitted. The Partnership adopted the requirements of Update 2013-02 upon its effective date of January 1, 2013, and it had no material impact on its financial position, results of operations or related disclosures.
	In January 2013, the FASB issued ASU 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“Update 2013-01”). Update 2013-01 clarifies that ordinary trade receivables and payable are not in scope of ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. Specifically, ASU 2011-11 applies only to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with specific criteria contained in the FASB Accounting Standards Codification or subject to a master netting arrangement or similar agreement. The amendments are effective for interim and annual reporting periods beginning after January 1, 2013 and such amendments shall be applied retrospectively for any period presented that begins before the date of application. The Partnership adopted the requirements of Update 2013-01 on December 31, 2012, and it did not have a material impact on its financial position, results of operations or related disclosures.
Recently Issued Accounting Standards	'
	Recently Issued Accounting Standards
	In February 2013, the FASB issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements, for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements, for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership will apply the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

Participation_in_Revenues_and_1

Participation in Revenues and Costs (Tables)	12 Months Ended
	Dec. 31, 2013
Schedule of Participation in Revenues and Costs, Allocation	'
	The MGP and the limited partners will generally participate in revenues and costs in the following manner:
		Managing		Limited
		General		Partners
		Partner
	Organization and offering cost		100%		0%
	Lease costs		100%		0%
	Revenues (1)		37%		63%
	Operating costs, administrative costs, direct and all other costs (2)		37%		63%
	Intangible drilling costs		8%		92%
	Tangible equipment costs		52%		48%
	-1	Subject to the MGP’s subordination obligation, substantially all partnership revenues will be shared in the same percentage as capital contributions are to the total partnership capital contributions, except that the MGP will receive an additional 10% of the partnership revenues.
	-2	These costs will be charged to the partners in the same ratio as the related production revenues are credited.

Property_Plant_and_Equipment_T

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment	'
	The following is a summary of natural gas and oil properties at the dates indicated:
		December 31,
		2013			2012
	Proved properties:
	Leasehold interests	$	5,599,100		$	5,848,000
	Wells and related equipment		168,471,600			179,678,300
	Total natural gas and oil properties		174,070,700			185,526,300
	Accumulated depletion and impairment		(93,388,200	)		(94,431,000	)
	Oil and gas properties, net	$	80,682,500		$	91,095,300

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
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:
		Years Ended December 31,
		2013			2012
	Asset retirement obligations, beginning of year	$	2,264,200		$	2,158,200
	Accretion of asset retirement obligations		123,100			110,000
	Asset retirement obligation revision		(742,100	)		(4,000	)
	Liabilities settled due to sale of oil and gas properties		(100,500	)		-
	Asset retirement obligations, end of period	$	1,544,700		$	2,264,200

Derivative_Instruments_Tables

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2013
Commodity Derivatives	'
	At December 31, 2013, the Partnership had the following commodity derivatives:
	Natural Gas Fixed Price Swaps—Limited Partners
	Production Period Ending		Volumes				Average			Fair Value (Liability)
	December 31,		(MMBtu) (1)				Fixed Price			Asset (2)
							(per MMBtu) (1)
	2014			1,689,600			$	4.095		$	(158,200	)
	2015			576,000				4.224			45,200
	2016			229,700				4.46			74,700
										$	(38,300	)
	Natural Gas Put Options—Limited Partners
	Production Period Ending		Volumes				Average			Fair Value
	December 31,		(MMBtu) (1)				Fixed Price			Asset (2)
							(per MMBtu) (1)
	2014			254,500			$	3.8		$	31,300
	2015			203,600				4			68,700
	2016			203,600				4.15			94,300
										$	194,300
				Limited Partner’s Commodity Derivatives, net						$	156,000
	-1	“MMBtu” represents million British Thermal Units.
	-2	Fair value based on forward NYMEX natural gas prices, as applicable.
Effects of Derivative Instruments on Statements of Operations	'
	The following table summarizes the gain or loss recognized in the statements of operations for effective derivative instruments for the years ended December 31, 2013 and 2012:
		Years Ended
		December 31,
		2013				2012
	Gains from cash flow hedges reclassified from accumulated other comprehensive income (loss) into natural gas revenues	$	1,998,900			$	3,272,100
Offsetting Assets	'
	The following table summarizes the gross and net fair values of the Partnership’s derivative and affiliate balances, presenting the impact of offsetting the derivative and related party assets and liabilities on the Partnership’s balance sheets for the periods indicated:
	Offsetting Derivative Assets		Gross Amounts				Gross Amounts			Net Amount of Assets
			of Recognized				Offset in the			Presented in the Balance
			Assets				Balance Sheets			Sheets
	As of December 31, 2013
	Accounts receivable monetized gains-affiliate		$	432,300			$	(147,000	)	$	285,300
			$	44,000			$	(44,000	)	$	-
	Current portion of derivative assets
	Long-term derivative assets			297,300				(14,400	)		282,900
	Current portion of derivative liabilities			14,600				(14,600	)		-
	Long-term derivative liabilities			6,500				(6,500	)		-
			$	362,400			$	(79,500	)	$	282,900
	Total derivative assets and affiliate balances		$	794,700			$	(226,500	)	$	568,200
	As of December 31, 2012
	Accounts receivable monetized gains-affiliate		$	2,520,000			$	(204,000	)	$	2,316,000
	Long-term receivable monetized gains-affiliate			503,700				(503,700	)		-
			$	3,023,700			$	(707,700	)	$	2,316,000
			$	556,400			$	(23,600	)	$	532,800
	Current portion of derivative assets
	Long-term derivative assets			622,400				(80,900	)		541,500
	Current portion of derivative liabilities			16,000				(16,000	)		-
	Long-term derivative liabilities			2,800				(2,800	)		-
			$	1,197,600			$	(123,300	)	$	1,074,300
	Total derivative assets and affiliate balances		$	4,221,300			$	(831,000	)	$	3,390,300
Offsetting Liabilities	'
	Offsetting Derivative Liabilities		Gross Amounts				Gross Amounts			Net Amount of Liabilities
			of Recognized				Offset in the			Presented in the Balance
			Liabilities				Balance Sheets			Sheets
	As of December 31, 2013
	Put premiums payable -affiliate		$	(147,000	)		$	147,000		$	-
	Long-term put premiums payable-affiliate			(293,000	)			-			(293,000	)
			$	(440,000	)		$	147,000		$	(293,000	)
			$	(5,500	)		$	5,500		$	-
	Current portion of derivative assets
	Long-term derivative assets			(13,900	)			13,900			-
	Current portion of derivative liabilities			(179,900	)			53,000			(126,900	)
	Long-term derivative liabilities			(7,100	)			7,100			-
			$	(206,400	)		$	79,500		$	(126,900	)
	Total derivative liabilities and affiliate balances		$	(646,400	)		$	226,500		$	(419,900	)
	As of December 31, 2012
	Put premiums payable -affiliate		$	(204,000	)		$	204,000		$	-
	Long-term put premiums payable-affiliate			(620,000	)			503,700			(116,300	)
			$	(824,000	)		$	707,700		$	(116,300	)
			$	(23,200	)		$	23,200		$	-
	Current portion of derivative assets
	Long-term derivative assets			(56,400	)			56,400			-
	Current portion of derivative liabilities			(16,400	)			16,400			-
	Long-term derivative liabilities			(27,300	)			27,300			-
			$	(123,300	)		$	123,300		$	-
	Total derivative liabilities and affiliate balances		$	(947,300	)		$	831,000		$	(116,300	)

Fair_Value_of_Financial_Instru1

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value of Derivative Instruments	'
	Information for assets and liabilities measured at fair value at December 31, 2013 and 2012 was as follows:
		Level 1		Level 2			Level 3		Total
	As of December 31, 2013
	Derivative assets, gross
	Commodity swaps	$	-	$	168,100		$	-	$	168,100
	Commodity puts		-		194,300			-		194,300
	Total derivative assets, gross	$	-	$	362,400		$	-	$	362,400
	Derivative liabilities, gross
	Commodity swaps	$	-	$	(206,400	)	$	-	$	(206,400	)
	Total derivative, fair value, net	$	-	$	156,000		$	-	$	156,000
	As of December 31, 2012
	Derivative assets, gross
	Commodity swaps	$	-	$	645,700		$	-	$	645,700
	Commodity puts		-		551,900			-		551,900
	Total derivative assets, gross	$	-	$	1,197,600		$	-	$	1,197,600
	Derivative liabilities, gross
	Commodity swaps	$	-	$	(123,300	)	$	-	$	(123,300	)
	Total derivative, fair value, net	$	-	$	1,074,300		$	-	$	1,074,300

Certain_Relationships_and_Rela1

Certain Relationships and Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2013
Costs Incurred from Related Party Transactions	'
	The following table provides information with respect to these costs and the periods incurred.
		Years Ended
		December 31,
		2013		2012
	Administrative	$	81,300	$	82,300
	Supervision		958,400		994,100
	Transportation		3,072,100		3,633,100
	Direct Costs		3,487,000		4,832,500
	Total	$	7,598,800	$	9,542,000

Supplemental_Oil_and_Gas_Infor1

Supplemental Oil and Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Changes in Proved Reserve Quantities	'
	Reserve quantity information and a reconciliation of changes in proved reserve quantities included within the Partnership are as follows (unaudited):
		Gas (Mcf)
	Balance, December 31, 2011		63,841,000
	Revisions (1)		(3,494,200	)
	Production		(8,355,400	)
			51,991,400
	Balance, December 31, 2012
	Revisions (2)		8,642,100
	Production		(6,083,500	)
			54,550,000
	Balance, December 31, 2013
	-1	The downward revision in natural gas volumes is primarily due to a decline in SEC base pricing from the prior year, a decrease in the positive gas price basis differentials and a decrease in economic lives resulting from increased expenses.
	-2	The upward revision in natural gas forecasts is primarily due to an increase in SEC base pricing from the prior year, resulting in longer economic life.
Capitalized Costs Relating to Oil and Gas Producing Activities	'
	Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to oil and gas producing activities of the Partnership during the periods indicated were as follows:
		Years Ended December 31,
		2013			2012
	Natural gas and oil properties:
	Leasehold interest	$	5,599,100		$	5,848,000
	Wells and related equipment		168,471,600			179,678,300
	Accumulated depletion, accretion and impairment		(93,388,200	)		(94,431,000	)
	Net capitalized costs	$	80,682,500		$	91,095,300
Results of Operations for Oil and Gas Producing Activities	'
	Results of Operations from Oil and Gas Producing Activities. The results of operations related to the Partnership’s oil and gas producing activities during the periods indicated were as follows:
		Years Ended December 31,
		2013			2012
	Revenues	$	24,625,400		$	27,071,500
	Production costs		(7,445,000	)		(9,390,700	)
	Depletion		(10,650,900	)		(13,917,300	)
	Long-lived asset impairment		-			(218,800	)
		$	6,529,500		$	3,544,700
Standardized Measure of Future Cash Flows	'
	Standardized Measure of Discounted Future Cash Flows. The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the Partnership’s proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2013 and 2012, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations:
		Years Ended December 31,
		2013			2012
	Future cash inflows	$	203,683,400		$	146,305,000
	Future production costs		(75,582,300	)		(63,637,000	)
	Future net cash flows		128,101,100			82,668,000
	Less 10% annual discount for estimated timing of cash flows		(69,621,400	)		(39,356,600	)
	Standardized measure of discounted future net cash flows	$	58,479,700		$	43,311,400

Basis_of_Presentation_Details

Basis of Presentation (Details)	12 Months Ended
	Dec. 31, 2013
Atlas Resources Series 28-2010 L.P. Formation Date	1-Apr-10

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Allowance for Uncollectible Accounts Receivable	$0	$0
Asset Impairment Charges	0	'
Cash Equivalents, at Carrying Value	1,309,000	1,781,000
Cash, Uninsured Amount	1,059,000	1,531,000
Unbilled Revenues	3,009,000	4,365,200
Current Year Customer 1	'	'
Concentration Risk, Percentage	75.00%	'
Current Year Customer 2	'	'
Concentration Risk, Percentage	20.00%	'
Prior Year Customer 1	'	'
Concentration Risk, Percentage	'	74.00%
Prior Year Customer 2	'	'
Concentration Risk, Percentage	'	20.00%
Oil and Gas Properties	'	'
Asset Impairment Charges	$0	$218,800

Participation_in_Revenues_and_2

Participation in Revenues and Costs (Details)	12 Months Ended
	Dec. 31, 2013
Managing General Partner	'
Capital Unit [Line Items]	'
Additional partnership revenues to receive, Percentage	10.00%
Organization and Offering Cost | Managing General Partner	'
Capital Unit [Line Items]	'
Participation In Revenues And Costs, Percentage	100.00%
Organization and Offering Cost | Limited Partners	'
Capital Unit [Line Items]	'
Participation In Revenues And Costs, Percentage	0.00%
Lease Costs | Managing General Partner	'
Capital Unit [Line Items]	'
Participation In Revenues And Costs, Percentage	100.00%
Lease Costs | Limited Partners	'
Capital Unit [Line Items]	'
Participation In Revenues And Costs, Percentage	0.00%
Revenues | Managing General Partner	'
Capital Unit [Line Items]	'
Participation In Revenues And Costs, Percentage	37.00%	[1]
Revenues | Limited Partners	'
Capital Unit [Line Items]	'
Participation In Revenues And Costs, Percentage	63.00%	[1]
Operating Costs, Administrative Costs, Direct and All Other Costs | Managing General Partner	'
Capital Unit [Line Items]	'
Participation In Revenues And Costs, Percentage	37.00%	[2]
Operating Costs, Administrative Costs, Direct and All Other Costs | Limited Partners	'
Capital Unit [Line Items]	'
Participation In Revenues And Costs, Percentage	63.00%	[2]
Intangible Drilling Costs | Managing General Partner	'
Capital Unit [Line Items]	'
Participation In Revenues And Costs, Percentage	8.00%
Intangible Drilling Costs | Limited Partners	'
Capital Unit [Line Items]	'
Participation In Revenues And Costs, Percentage	92.00%
Tangible Equipment Costs | Managing General Partner	'
Capital Unit [Line Items]	'
Participation In Revenues And Costs, Percentage	52.00%
Tangible Equipment Costs | Limited Partners	'
Capital Unit [Line Items]	'
Participation In Revenues And Costs, Percentage	48.00%
[1]	Subject to the MGPbs subordination obligation, substantially all partnership revenues will be shared in the same percentage as capital contributions are to the total partnership capital contributions, except that the MGP will receive an additional 10% of the partnership revenues.
[2]	These costs will be charged to the partners in the same ratio as the related production revenues are credited.

Participation_in_Revenues_and_3

Participation in Revenues and Costs (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Capital Unit [Line Items]	'
Additional working interest	10.00%
Net earnings resulting from working interest adjustment reclassified	$338,400

Property_Plant_and_Equipment_D

Property, Plant and Equipment (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Property Plant And Equipment [Line Items]	'	'
Natural gas and oil properties	$174,070,700	$185,526,300
Accumulated depletion and impairment	-93,388,200	-94,431,000
Oil and gas properties, net	80,682,500	91,095,300
Leaseholds Interests	'	'
Property Plant And Equipment [Line Items]	'	'
Natural gas and oil properties	5,599,100	5,848,000
Wells and Related Equipment	'	'
Property Plant And Equipment [Line Items]	'	'
Natural gas and oil properties	$168,471,600	$179,678,300

Property_Plant_and_Equipment_N

Property, Plant and Equipment (Narrative) (Details) (USD $)	12 Months Ended		1 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 30, 2013
			Antrim Shale Wells
Property Plant And Equipment [Line Items]	'	'	'
Depletion of Oil and Gas Properties	$10,650,900	$13,917,300	'
Oil and gas properties, net	80,682,500	91,095,300	-3,400
Oil and gas properties sold	'	'	405,700
Gain on sale of oil and gas properties	409,100	'	409,100
Natural gas and oil properties	174,070,700	185,526,300	11,790,800
Accumulated depletion and impairment	93,388,200	94,431,000	11,693,700
Asset retirement obligations	100,500	'	100,500
Impairment	$0	$218,800	'

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligations [Abstract]	'	'
Asset retirement obligations, beginning of year	$2,264,200	$2,158,200
Accretion of asset retirement obligations	123,100	110,000
Asset retirement obligation revision	-742,100	-4,000
Liabilities settled due to sale of oil and gas properties	-100,500	'
Asset retirement obligations, end of period	$1,544,700	$2,264,200

Derivative_Instruments_Narrati

Derivative Instruments (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]	'	'
Fair Value Asset/(Liability)	$156,000	$1,074,300
Gain (Loss) on Fair Value Hedge Ineffectiveness, Net	0	0
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	794,700	4,221,300
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	646,400	947,300
Accumulated other comprehensive income	61,600	2,762,500
Derivative Losses Reclassified from Other Comprehensive Income Related To Derivative Instruments	26,700	'
Unrealized gains (losses) due to natural gas and oil property impairments	'	'
Derivative [Line Items]	'	'
Accumulated other comprehensive income	61,600	'
Cash Flow Hedge Gain (Loss) To Be Reclassified Within Twelve Months	71,700	'
Net Deferred Gain (loss) To Be Reclassified Into Net Income In Later Periods	-10,100	'
Other Comprehensive Income (Loss)	'	'
Derivative [Line Items]	'	'
Unrealized Gains (Losses) Due To Natural Gas And Oil Property Impairments	'	86,700
Allocation To Limited Partner Only | Other Comprehensive Income (Loss)	'	'
Derivative [Line Items]	'	'
Net Derivative Gains (Losses) Limited Partner	1,523,500	'
Allocation To MGP Only | Other Comprehensive Income (Loss)	'	'
Derivative [Line Items]	'	'
Net Derivative Gains (Losses) Managing General Partner	23,600	'
Accounts receivable monetized gains-affiliate	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	432,300	2,520,000
Accounts receivable monetized gains-affiliate | Allocation To Limited Partner Only	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	432,300	2,520,000
Long-term receivable monetized gains-affiliate	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	'	503,700
Long-term receivable monetized gains-affiliate | Allocation To Limited Partner Only	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	0	503,700
Put premiums payable-affiliate	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	147,000	204,000
Put premiums payable-affiliate | Allocation To Limited Partner Only	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	147,000	204,000
Long-term put premiums payable-affiliate	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	293,000	620,000
Long-term put premiums payable-affiliate | Allocation To Limited Partner Only	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	$293,000	$620,000

Derivative_Instruments_Commodi

Derivative Instruments (Commodity Derivatives) (Details) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Natural Gas Fixed Price Swaps - Limited Partners

Natural Gas Put Options - Limited Partners

Limited Partner's Commodity Derivatives, net

Production Period Ending December 31, 2014

Production Period Ending December 31, 2014

Production Period Ending December 31, 2015

Production Period Ending December 31, 2015

Production Period Ending December 31, 2016

Production Period Ending December 31, 2016

Natural Gas Fixed Price Swaps - Limited Partners

Natural Gas Put Options - Limited Partners

Natural Gas Fixed Price Swaps - Limited Partners

Natural Gas Put Options - Limited Partners

Natural Gas Fixed Price Swaps - Limited Partners

Natural Gas Put Options - Limited Partners

MMBTU

MMBTU

MMBTU

MMBTU

MMBTU

MMBTU

Derivative [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Volumes (MMBtu)

'

'

'

'

'

1,689,600

[1]

254,500

[1]

576,000

[1]

203,600

[1]

229,700

[1]

203,600

[1]

Average Fixed Price (per MMBtu)

'

'

'

'

'

4.095

[1]

3.8

[1]

4.224

[1]

4

[1]

4.46

[1]

4.15

[1]

Fair Value (Liability) Asset

$156,000

$1,074,300

($38,300)

[2]

$194,300

[2]

$156,000

[2]

($158,200)

[2]

$31,300

[2]

$45,200

[2]

$68,700

[2]

$74,700

[2]

$94,300

[2]

[1]

bMMBtub represents million British Thermal Units.

[2]

Fair value based on forward NYMEX natural gas prices, as applicable.

Derivative_Instruments_Effects

Derivative Instruments (Effects of Derivative Instruments on Statements of Operations) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments And Hedging Activities Disclosure [Abstract]	'	'
Gains from cash flow hedges reclassified from accumulated other comprehensive income (loss) into natural gas revenues	$1,998,900	$3,272,100

Derivative_Instruments_Offsett

Derivative Instruments (Offsetting Assets) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	$794,700	$4,221,300
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset in the Balance Sheets	-226,500	-831,000
Affiliate Balances, Offsetting Derivative Assets, Net Amount of Assets Presented in the Balance Sheets	568,200	3,390,300
Accounts receivable monetized gains-affiliate	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	432,300	2,520,000
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset in the Balance Sheets	-147,000	-204,000
Affiliate Balances, Offsetting Derivative Assets, Net Amount of Assets Presented in the Balance Sheets	285,300	2,316,000
Long-term receivable monetized gains-affiliate	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	'	503,700
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset in the Balance Sheets	'	-503,700
Affiliate Balances, Offsetting Derivative Assets, Net Amount of Assets Presented in the Balance Sheets	'	'
Current portion of derivative assets	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	44,000	556,400
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset in the Balance Sheets	-44,000	-23,600
Affiliate Balances, Offsetting Derivative Assets, Net Amount of Assets Presented in the Balance Sheets	'	532,800
Long-term derivative assets	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	297,300	622,400
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset in the Balance Sheets	-14,400	-80,900
Affiliate Balances, Offsetting Derivative Assets, Net Amount of Assets Presented in the Balance Sheets	282,900	541,500
Current portion of derivative liabilities	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	14,600	16,000
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset in the Balance Sheets	-14,600	-16,000
Affiliate Balances, Offsetting Derivative Assets, Net Amount of Assets Presented in the Balance Sheets	'	'
Long-term derivative liabilities	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	6,500	2,800
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset in the Balance Sheets	-6,500	-2,800
Affiliate Balances, Offsetting Derivative Assets, Net Amount of Assets Presented in the Balance Sheets	'	'
Total Balance Sheet Location - Assets	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	362,400	1,197,600
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset in the Balance Sheets	-79,500	-123,300
Affiliate Balances, Offsetting Derivative Assets, Net Amount of Assets Presented in the Balance Sheets	282,900	1,074,300
Total Monetized - Assets	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	'	3,023,700
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset in the Balance Sheets	'	-707,700
Affiliate Balances, Offsetting Derivative Assets, Net Amount of Assets Presented in the Balance Sheets	'	$2,316,000

Derivative_Instruments_Offsett1

Derivative Instruments (Offsetting Liabilities) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities	($646,400)	($947,300)
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets	226,500	831,000
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount of Liabilities Presented in the Balance Sheets	-419,900	-116,300
Put premiums payable-affiliate	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities	-147,000	-204,000
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets	147,000	204,000
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount of Liabilities Presented in the Balance Sheets	'	'
Long-term put premiums payable-affiliate	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities	-293,000	-620,000
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets	'	503,700
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount of Liabilities Presented in the Balance Sheets	-293,000	-116,300
Total put premiums - liabilities	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities	-440,000	-824,000
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets	147,000	707,700
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount of Liabilities Presented in the Balance Sheets	-293,000	-116,300
Current portion of derivative assets	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities	-5,500	-23,200
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets	5,500	23,200
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount of Liabilities Presented in the Balance Sheets	'	'
Long-term derivative assets	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities	-13,900	-56,400
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets	13,900	56,400
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount of Liabilities Presented in the Balance Sheets	'	'
Current portion of derivative liabilities	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities	-179,900	-16,400
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets	53,000	16,400
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount of Liabilities Presented in the Balance Sheets	-126,900	'
Long-term derivative liabilities	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities	-7,100	-27,300
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets	7,100	27,300
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount of Liabilities Presented in the Balance Sheets	'	'
Total Balance Sheet Location - Liabilities	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities	-206,400	-123,300
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets	79,500	123,300
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount of Liabilities Presented in the Balance Sheets	($126,900)	'

Fair_Value_of_Financial_Instru2

Fair Value of Financial Instruments (Assets Measured at Fair Value on a Recurring Basis) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative assets, gross	$362,400	$1,197,600
Derivative, Fair Value, Total	156,000	1,074,300
Commodity Swaps	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative assets, gross	168,100	645,700
Derivative liabilities, gross	-206,400	-123,300
Commodity Puts	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative assets, gross	194,300	551,900
Fair Value, Inputs, Level 1	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative assets, gross	'	'
Derivative, Fair Value, Total	'	'
Fair Value, Inputs, Level 1 | Commodity Swaps	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative assets, gross	'	'
Derivative liabilities, gross	'	'
Fair Value, Inputs, Level 1 | Commodity Puts	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative assets, gross	'	'
Fair Value, Inputs, Level 2	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative assets, gross	362,400	1,197,600
Derivative, Fair Value, Total	156,000	1,074,300
Fair Value, Inputs, Level 2 | Commodity Swaps	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative assets, gross	168,100	645,700
Derivative liabilities, gross	-206,400	-123,300
Fair Value, Inputs, Level 2 | Commodity Puts	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative assets, gross	194,300	551,900
Fair Value, Inputs, Level 3	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative assets, gross	'	'
Derivative, Fair Value, Total	'	'
Fair Value, Inputs, Level 3 | Commodity Swaps	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative assets, gross	'	'
Derivative liabilities, gross	'	'
Fair Value, Inputs, Level 3 | Commodity Puts	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative assets, gross	'	'

Fair_Value_of_Financial_Instru3

Fair Value of Financial Instruments (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Asset impairment	'	$218,800
Asset Impairment Charges	0	'
Fair Value, Inputs, Level 3	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Asset impairment	'	$218,800

Certain_Relationships_and_Rela2

Certain Relationships and Related Party Transactions (Schedule of Related Party Transactions) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction [Line Items]	'	'
Related Party Transaction, Expenses from Transactions with Related Party	$7,598,800	$9,542,000
Administrative	'	'
Related Party Transaction [Line Items]	'	'
Related Party Transaction, Expenses from Transactions with Related Party	81,300	82,300
Supervision	'	'
Related Party Transaction [Line Items]	'	'
Related Party Transaction, Expenses from Transactions with Related Party	958,400	994,100
Transportation	'	'
Related Party Transaction [Line Items]	'	'
Related Party Transaction, Expenses from Transactions with Related Party	3,072,100	3,633,100
Direct Costs	'	'
Related Party Transaction [Line Items]	'	'
Related Party Transaction, Expenses from Transactions with Related Party	$3,487,000	$4,832,500

Certain_Relationships_and_Rela3

Certain Relationships and Related Party Transactions (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction [Line Items]	'	'
Monthly Administrative Costs Per Well	$75	'
Assets contributed by managing general partner: Syndication and offering costs	'	1,400
Managing General Partner	'	'
Related Party Transaction [Line Items]	'	'
Managing General Partner Maximum Subordination Percentage Of Share Of Net Production Revenues	50.00%	'
Subordination	3,102,000	2,291,600
Managing General Partner | First 12 Month Subordination Period	'	'
Related Party Transaction [Line Items]	'	'
Subordination Target Return Rate For Limited Partner Subscriptions	12.00%	'
Managing General Partner | Next Three 12 Month Subordination Periods	'	'
Related Party Transaction [Line Items]	'	'
Subordination Target Return Rate For Limited Partner Subscriptions	10.00%	'
Managing General Partner | Fifth 12 Month Subordination Period	'	'
Related Party Transaction [Line Items]	'	'
Subordination Target Return Rate For Limited Partner Subscriptions	8.00%	'
Assets Contributed From Mgp	'	'
Related Party Transaction [Line Items]	'	'
Non-Cash Financing Activities, Excluding Syndication And Offering Costs	1,114,800	14,269,700
Assets contributed by managing general partner: Syndication and offering costs	'	1,400
Administrative	'	'
Related Party Transaction [Line Items]	'	'
Monthly Administrative Costs Per Well	975	'
Supervision	'	'
Related Party Transaction [Line Items]	'	'
Monthly Supervision Fees Per Well	400	'
Supervision | Marcellus wells	'	'
Related Party Transaction [Line Items]	'	'
Monthly Supervision Fees Per Well	1,500	'
Supervision | New Albany wells	'	'
Related Party Transaction [Line Items]	'	'
Monthly Supervision Fees Per Well	$600	'
Transportation	'	'
Related Party Transaction [Line Items]	'	'
Transportation Fee Rate As Percentage Of Natural Gas Sales Price	16.00%	'

Commitments_and_Contingencies_

Commitments and Contingencies (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Disclosure Commitments And Contingencies Details [Line Items]	'
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

Supplemental_Oil_and_Gas_Infor2

Supplemental Oil and Gas Information (Unaudited) (Changes in Proved Reserve Quantities) (Details) (Gas (Mcf))	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
	Mcf		Mcf
Gas (Mcf)	'		'
Reserve Quantities [Line Items]	'		'
Balance	51,991,400		63,841,000
Revisions	8,642,100	[1]	-3,494,200	[2]
Production	-6,083,500		-8,355,400
Balance	54,550,000		51,991,400
[1]	The upward revision in natural gas forecasts is primarily due to an increase in SEC base pricing from the prior year, resulting in longer economic life.
[2]	The downward revision in natural gas volumes is primarily due to a decline in SEC base pricing from the prior year, a decrease in the positive gas price basis differentials and a decrease in economic lives resulting from increased expenses.

Supplemental_Oil_and_Gas_Infor3

Supplemental Oil and Gas Information (Unaudited) (Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Natural Gas and Oil Producing Activities [Abstract]	'	'
Natural gas and oil properties: Leasehold interest	$5,599,100	$5,848,000
Natural gas and oil properties: Wells and related equipment	168,471,600	179,678,300
Accumulated depletion, accretion and impairment	-93,388,200	-94,431,000
Net capitalized costs	$80,682,500	$91,095,300

Supplemental_Oil_and_Gas_Infor4

Supplemental Oil and Gas Information (Unaudited) (Results of Operations for Oil and Gas Producing Activities) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Natural Gas and Oil Producing Activities [Abstract]	'	'
Revenues	$24,625,400	$27,071,500
Production costs	-7,445,000	-9,390,700
Depletion	-10,650,900	-13,917,300
Long-lived asset impairment	'	-218,800
Total Results from Operations from Oil and Gas Producing Activities	$6,529,500	$3,544,700

Supplemental_Oil_and_Gas_Infor5

Supplemental Oil and Gas Information (Unaudited) (Standardized Measure of Future Cash Flows) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Natural Gas and Oil Producing Activities [Abstract]	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Cash Inflows	$203,683,400	$146,305,000
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Production Costs	-75,582,300	-63,637,000
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Net Cash Flows, Total	128,101,100	82,668,000
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, 10 Percent Annual Discount for Estimated Timing of Cash Flows	-69,621,400	-39,356,600
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure, Total	$58,479,700	$43,311,400