Atlas America Series 27-2006 10-K 31 Mar 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Entity Registrant Name	ATLAS AMERICA SERIES 27-2006 L.P.
Entity Central Index Key	1379763
Current Fiscal Year End Date	-19
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, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents		$62,800
Accounts receivable trade–affiliate	200,000	379,400
Asset retirement receivable-affiliate	34,400
Accounts receivable monetized gains-affiliate		24,100
Current portion of derivative assets	20,500	2,900
Total current assets	254,900	469,200
Gas and oil properties, net	3,330,200	5,545,000
Long-term derivative assets	17,100	15,300
TOTAL ASSETS	3,602,200	6,029,500
Current liabilities:
Accrued liabilities	9,700	10,400
Current portion of put premiums payable-affiliate	13,100
Total current liabilities	22,800	10,400
Asset retirement obligations	4,403,700	3,210,500
Long-term put premiums payable-affiliate	15,000	27,400
Commitments and contingencies
Partners’ capital:
Managing general partner’s interest	-294,000	828,700
Limited partners’ interest (2,840 units)	-554,700	1,956,700
Accumulated other comprehensive income (loss)	9,400	-4,200
Total partners’ capital	-839,300	2,781,200
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$3,602,200	$6,029,500

BALANCE_SHEETS_Parenthetical

BALANCE SHEETS (Parenthetical)	Dec. 31, 2014
Statement Of Financial Position [Abstract]
Limited partners' units	2,840

STATEMENTS_OF_OPERATIONS

STATEMENTS OF OPERATIONS (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
REVENUES
Natural gas and oil	$1,886,000	$2,218,200
Total revenues	1,886,000	2,218,200
COST AND EXPENSES
Production	1,278,000	1,301,800
Depletion	391,500	1,029,000
Impairment	2,826,200	0
Accretion of asset retirement obligation	190,600	179,800
General and administrative	186,600	201,900
Total costs and expenses	4,872,900	2,712,500
Net loss	-2,986,900	-494,300
Allocation of net loss:
Managing general partner	-932,400	-27,800
Limited partners	($2,054,500)	($466,500)
Net loss per limited partnership unit	($723)	($164)

STATEMENTS_OF_COMPREHENSIVE_LO

STATEMENTS OF COMPREHENSIVE LOSS (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Statement Of Income And Comprehensive Income [Abstract]
Net loss	($2,986,900)	($494,300)
Other comprehensive income (loss):
Unrealized holding gain (loss) on cash flow hedging contracts	9,400	-23,000
Difference in estimated hedge gains receivable	33,000	87,600
Reclassification adjustment for gains realized in net loss from cash flow hedges	-28,800	-82,200
Total other comprehensive income (loss)	13,600	-17,600
Comprehensive loss	($2,973,300)	($511,900)

STATEMENTS_OF_CHANGES_IN_PARTN

STATEMENTS OF CHANGES IN PARTNERS' CAPITAL (USD $)	Total	Managing General Partner	Limited Partners	Accumulated Other Comprehensive Income (Loss)
Balance at Dec. 31, 2012	$4,240,600	$1,099,900	$3,127,300	$13,400
Participation in revenue and costs and expenses:
Net production revenues	916,400	284,300	632,100
Depletion	-1,029,000	-187,900	-841,100
Accretion of asset retirement obligation	-179,800	-58,500	-121,300
General and administrative	-201,900	-65,700	-136,200
Net loss	-494,300	-27,800	-466,500
Other comprehensive income (loss)	-17,600			-17,600
Distributions to partners	-947,500	-243,400	-704,100
Balance at Dec. 31, 2013	2,781,200	828,700	1,956,700	-4,200
Participation in revenue and costs and expenses:
Net production revenues	608,000	196,100	411,900
Depletion	-391,500	-123,500	-268,000
Impairment	-2,826,200	-882,300	-1,943,900
Accretion of asset retirement obligation	-190,600	-62,000	-128,600
General and administrative	-186,600	-60,700	-125,900
Net loss	-2,986,900	-932,400	-2,054,500
Other comprehensive income (loss)	13,600			13,600
Distributions to partners	-647,200	-190,300	-456,900
Balance at Dec. 31, 2014	($839,300)	($294,000)	($554,700)	$9,400

STATEMENTS_OF_CASH_FLOWS

STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net loss	($2,986,900)	($494,300)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion	391,500	1,029,000
Non-cash loss on derivative value, net	19,000	111,100
Impairment	2,826,200	0
Accretion of asset retirement obligation	190,600	179,800
Changes in operating assets and liabilities:
Decrease in accounts receivable trade-affiliate	179,400	148,600
(Decrease) increase in accrued liabilities	-700	7,200
Asset retirement receivable-affiliate	-34,400
Asset retirement obligations settled	-300
Net cash provided by operating activities	584,400	981,400
Cash flows from financing activities:
Distributions to partners	-647,200	-947,500
Net cash used in financing activities	-647,200	-947,500
Net change in cash and cash equivalents	-62,800	33,900
Cash and cash equivalents at beginning of period	62,800	28,900
Cash and cash equivalents at end of period		62,800
Supplemental schedule of non-cash investing and financing activities:
Asset retirement obligation revision	$1,002,900	($275,300)

Basis_of_Presentation

Basis of Presentation	12 Months Ended
	Dec. 31, 2014
Organization Consolidation And Presentation Of Financial Statements [Abstract]
BASIS OF PRESENTATION	NOTE 1—BASIS OF PRESENTATION
	Atlas America Series 27-2006 L.P. (the “Partnership”) is a Delaware limited partnership, formed on July 21, 2006 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or the “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP).
	On October 13, 2014, the MGP’s ultimate parent, Atlas Energy L.P. (“Atlas Energy”) (NYSE: ATLS), and its midstream subsidiary, Atlas Pipeline Partners, L.P. (“APL”), entered into definitive agreements to be acquired by Targa Resources Corp. and Targa Resources Partners LP, respectively. Immediately prior to the acquisition, Atlas Energy distributed to its unitholders 100% of the limited liability company interests in ARP’s general partner, which changed its name to Atlas Energy Group, LLC (“New Atlas”) and became a separate, publicly traded company as a result of the distribution. Following the distribution, New Atlas continues to hold the Partnership’s business as well as ARP’s general partner interest and incentive distribution rights, and now holds the non-midstream assets and ARP limited partner units previously held by Atlas Energy.
	In March 2012, Atlas Energy 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 our MGP.
	On February 17, 2011, Atlas Energy, a then-majority owned subsidiary of Atlas Energy, Inc. and parent of the general partner of APL, completed an acquisition of assets from Atlas Energy, Inc., which included its investment partnership business, its gas and oil exploration, development, and production activities conducted in Tennessee, Indiana, and Colorado, certain shallow wells and leases in New York and Ohio, and 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, New York and Tennessee. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy (after February 27, 2015, New Atlas), for administrative services.
	The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. The Partnership intends to produce its wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. The Partnership does not expect to drill additional wells and expects no additional funds will be required for drilling.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
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, 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, 2014 and 2013, the Partnership had recorded no allowance for uncollectible accounts receivable on its balance sheets.
	Gas and Oil Properties
	Gas and oil 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 gas and oil producing activities. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil 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 gas and oil properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion and impairment is less than the estimated expected undiscounted future cash flows including salvage. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of the production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value and the carrying value of the assets.
	The determination of 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.
	During the year ended December 31, 2014, the Partnership recognized $2,826,200 of impairment related to gas and oil properties. This impairment relates to the carrying amount of these gas and oil properties being in excess of the Partnership’s estimate of their fair value at December 31, 2014. The estimate of the fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil prices at the date of measurement. There was no impairment of gas and oil properties for the year ended December 31, 2013.
	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, 2014 and 2013.
	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 2010. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2014.
	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, 2014 and 2013.
	Concentration of Credit Risk
	The Partnership sells natural gas and crude oil under contracts to various purchasers in the normal course of business. For the year ended December 31, 2014, the Partnership had two customers that individually accounted for approximately 60% and 24%, of the Partnership’s natural gas and oil combined revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2013, the Partnership had two customers that individually accounted for approximately 62% and 18%, of the Partnership’s natural gas and oil combined revenues, excluding the impact of all financial derivative activity.
	Revenue Recognition
	The Partnership generally sells natural gas and crude oil 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 and crude oil in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty.
	The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP. The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, crude oil and condensate, and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (See Note 2: “Use of Estimates” for further description). The Partnership had unbilled revenues at December 31, 2014 and 2013 of $223,900 and $283,900, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.
	Comprehensive Loss
	Comprehensive loss includes net loss and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net loss. These changes, other than net loss, are referred to as “other comprehensive income (loss)” 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 2013-04, 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 adopted the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it had no material impact on its financial position, results of operations or related disclosures.
	Recently Issued Accounting Standards
	In January 2015, the FASB issued ASU 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items (“Update 2015-01”). The amendments in Update 2015-01 simplify the income statement presentation requirements in Subtopic 225-20 by eliminating the concept of extraordinary items. Extraordinary items are events and transactions that are distinguished by their unusual nature and by the infrequency of their occurrence. Eliminating the extraordinary classification simplifies income statement presentation by altogether removing the concept of extraordinary items from consideration. The amendments in Update 2015-01 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A reporting entity may apply the amendments prospectively. A reporting entity may also apply the amendments retrospectively to all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. The Partnership will adopt the requirements of Update 2015-01 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.
	In November 2014, the FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815) – Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share is More Akin to Debt or to Equity (“Update 2014-16”). Certain classes of shares include features that entitle the holders to preferences and rights (such as conversion rights, redemption rights, voting powers, and liquidation and dividend payment preferences) over the other shareholders. Shares that include embedded derivative features are referred to as hybrid financial instruments, which must be separated from the host contract and accounted for as a derivative if certain criteria are met under Subtopic 815-10. One criterion requires evaluating whether the nature of the host contract is more akin to debt or to equity and whether the economic characteristics and risks of the embedded derivative feature are “clearly and closely related” to the host contract. In making that evaluation, an issuer or investor may consider all terms and features in a hybrid financial instrument including the embedded derivative feature that is being evaluated for separate accounting or may consider all terms and features in the hybrid financial instrument except for the embedded derivative feature that is being evaluated for separate accounting. The use of different methods can result in different accounting outcomes for economically similar hybrid financial instruments. Additionally, there is diversity in practice with respect to the consideration of redemption features in relation to other features when determining whether the nature of a host contract is more akin to debt or to equity. The amendments in Update 2014-16 clarify how current GAAP should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. The effects of initially adopting the amendments in Update 2014-16 should be applied on a modified retrospective basis to existing hybrid financial instruments issued in the form of a share as of the beginning of the fiscal year for which the amendments are effective. Retrospective application is permitted to all relevant prior periods. The amendments in Update 2014-16 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption, including adoption in an interim period, is permitted. The Partnership will adopt the requirements of Update 2014-16 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.
	In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. The Partnership will adopt the requirements of Update 2014-15 upon its effective date of January 1, 2017, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.
	In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles – Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. The Partnership will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2017, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

Participation_in_Revenues_and_

Participation in Revenues and Costs	12 Months Ended
	Dec. 31, 2014
Partners Capital Notes [Abstract]
PARTICIPATION IN REVENUES AND COSTS	NOTE 3—PARTICIPATION IN REVENUES AND COSTS
	Working Interest
	The Partnership Agreement establishes that revenues and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). The MGP is also provided an additional working interest of 7% 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.
	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)		33%		67%
	Operating costs, administrative costs, direct and all other costs (2)		33%		67%
	Intangible drilling costs		5%		95%
	Tangible equipment costs		60%		40%
	-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 7% 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, 2014
Property Plant And Equipment [Abstract]
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,
		2014			2013
	Proved properties:
	Leasehold interests	$	1,684,000		$	1,687,400
	Wells and related equipment		86,777,900			85,908,800
	Total natural gas and oil properties		88,461,900			87,596,200
	Accumulated depletion and impairment		(85,131,700	)		(82,051,200	)
	Gas and oil properties, net	$	3,330,200		$	5,545,000
	The Partnership recorded depletion expense on natural gas and oil properties of $391,500 and $1,029,000 for the years ended December 31, 2014 and 2013, 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. As a result of retirements, the Partnership reclassified $137,200, from gas and oil properties to accumulated depletion for the year ended December 31, 2014. 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.
	During the year ended December 31, 2014, the Partnership recognized $2,826,200, of impairment related to gas and oil properties on its balance sheet. This impairment related to the carrying amount of these gas and oil properties being in excess of the Partnership’s estimate of their fair value at December 31, 2014. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil prices at the date of measurement. There was no impairment of gas and oil properties recognized for the year ended December 31, 2013.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	NOTE 5—ASSET RETIREMENT OBLIGATIONS
	The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil 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. As of December 31, 2014, the MGP withheld $34,400 of net production revenue for future plugging and abandonment costs.
	A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the periods indicated is as follows:
		Years Ended December 31,
		2014			2013
	Asset retirement obligations, beginning of period	$	3,210,500		$	3,306,000
	Accretion of asset retirement obligations		190,600			179,800
	Asset retirement obligations settled		(300	)		-
	Asset retirement obligation revision		1,002,900			(275,300	)
	Asset retirement obligations, end of period	$	4,403,700		$	3,210,500

Derivative_Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2014
Derivative Instruments And Hedging Activities Disclosure [Abstract]
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 uses financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under commodity-based swap agreements, the Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. To manage the risk of regional commodity price differences, the Partnership occasionally enters into basis swaps. Basis swaps are contractual arrangements that guarantee a price differential for a commodity from a specified delivery point price and the comparable national exchange price. For natural gas basis swaps, which have negative differentials to NYMEX, the Partnership receives or pays a payment from the counterparty if the price differential to NYMEX is greater or less than the stated terms of the contract. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike price, and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged.
	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 sheets of $37,600 and $18,200 at December 31, 2014 and 2013, 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, 2014, the Partnership had the following commodity derivatives:
	Natural Gas Put Options
	Production			Volumes				Average			Fair Value
	Period Ending			(MMBtu) (1)				Fixed Price			Asset (2)
	December 31,							(per MMBtu) (1)
	2015				19,600			$	4		$	20,500
	2016				19,600				4.15			17,100
											$	37,600
	-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, 2014 and 2013:
		Years Ended December 31,
		2014				2013
	Gains from cash flow hedges reclassified from accumulated other comprehensive loss into natural gas and oil revenues	$	28,800			$	82,200
	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, 2014 and 2013, for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.
	Monetized Gains
	At December 31, 2013, remaining hedge monetization cash proceeds of $37,900 related to the amounts hedged on behalf of the Partnership’s limited partners were included within accounts receivable monetized gains-affiliate. The Partnership allocated 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. There were no amounts for monetized gains remaining due to the Partnership at December 31, 2014.
	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, 2014 and 2013, the put premiums were recorded as short-term payables to affiliate of $13,100 and $13,800, respectively, and long-term payables to affiliate of $15,000 and $27,400, respectively.
	The following table summarizes the gross and net fair values of the Partnership’s balances on the Partnership’s balance sheets for the periods indicated:
	Offsetting Assets		Gross				Gross			Net Amount of Assets
			Amounts of				Amounts			Presented in the
			Recognized				Offset in the			Balance Sheets
			Assets				Balance Sheets
	As of December 31, 2014
	Accounts receivable monetized gains-affiliate		$	-			$	-		$	-
	Total		$	-			$	-		$	-
	As of December 31, 2013
	Accounts receivable monetized gains-affiliate		$	37,900			$	(13,800	)	$	24,100
	Total		$	37,900			$	(13,800	)	$	24,100
	Offsetting Liabilities		Gross				Gross			Net Amount of
			Amounts of				Amounts			Liabilities Presented
			Recognized				Offset in the			in the Balance Sheets
			Liabilities				Balance Sheets
	As of December 31, 2014
	Put premiums payable-affiliate		$	(13,100			$	-		$	(13,100	)
					)
	Long-term put premiums payable-affiliate			(15,000	)			-			(15,000	)
	Total		$	(28,100	)		$	-		$	(28,100	)
	As of December 31, 2013
	Put premiums payable-affiliate		$	(13,800	)		$	13,800		$	-
	Long-term put premiums payable-affiliate			(27,400	)			-			(27,400	)
	Total		$	(41,200	)		$	13,800		$	(27,400	)
	Accumulated Other Comprehensive Income
	As a result of the put options the Partnership recorded a net deferred gain on its balance sheet in accumulated other comprehensive income of $9,400 as of December 31, 2014. During the current year, $5,300 of net gains were recorded by the Partnership and allocated only to the limited partners. Of the remaining $9,400 of net unrealized gains in accumulated other comprehensive income, the Partnership will reclassify $7,300 of net gains to the Partnership’s statements of operations over the next twelve month period and the remaining $2,100 of gains in later periods.

Fair_Value_of_Financial_Instru

Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
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. The fair values of these derivative instruments are calculated by utilizing commodity indices, quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and the pricing formula utilized in the derivative instrument.
	Information for assets and liabilities measured at fair value at December 31, 2014 and 2013 was as follows:
	As of December 31, 2014	Level 1		Level 2		Level 3		Total
	Derivative assets, gross
	Commodity puts	$	-	$	37,600	$	-	$	37,600
	Derivative liabilities, gross
	Commodity puts		-		-		-		-
	Total derivative, fair value, net	$	-	$	37,600	$	-	$	37,600
	As of December 31, 2013
	Derivative assets, gross
	Commodity puts	$	-	$	18,200	$	-	$	18,200
	Derivative liabilities, gross
	Commodity puts		-		-		-		-
	Total derivative, fair value, net	$	-	$	18,200	$	-	$	18,200
	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 factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates (See Note 5). Adjustments to retirement obligations, defined as Level 3, measured at fair value on a nonrecurring basis was $1,002,900, for the year ended December 31, 2014.  There were no adjustments to retirement obligations, defined as Level 3, measured at fair value on a nonrecurring basis, for the year ended December 31, 2013.
	The Partnership estimates the fair value of its long-lived assets in conjunction with the review of assets for 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, 2014, the Partnership recognized a $2,826,200 impairment of long-lived assets which were defined as a Level 3 fair value measurement (See Note 2: Impairment of Long-Lived Assets). No impairment was recognized for the year ended December 31, 2013.

Certain_Relationships_and_Rela

Certain Relationships and Related Party Transactions	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
	NOTE 8—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
	The Partnership has entered into the following significant transactions with the MGP and its affiliates as provided under its Partnership Agreement. Administrative costs, which are included in general and administrative expenses in the Partnership’s statements of operations, are payable at $75 per well per month. Monthly well supervision fees which are included in production expenses in the Partnership’s statements of operations are payable at $376 per well per month for operating and maintaining the wells. Well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of the working interest in a well. Transportation fees are included in production expenses in the Partnership’s statements of operations and are generally payable at 13% 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,
		2014		2013
	Administrative fees	$	134,800	$	137,500
	Supervision fees		675,500		689,000
	Transportation fees		250,300		316,700
	Direct Costs		404,000		360,500
	Total	$	1,464,600	$	1,503,700
	The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments And Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	NOTE 9—COMMITMENTS AND CONTINGENCIES
	General Commitments
	Subject to certain conditions, investor partners may present their interests for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. The MGP is not obligated to purchase more than 5% of the total outstanding units in any calendar year. In the event that the MGP is unable to obtain the necessary funds, it may suspend its purchase obligation.
	Beginning one year after each of the Partnership’s wells has been placed into production, the MGP, as operator, may retain $200 per month per well to cover estimated future plugging and abandonment costs. As of December 31, 2014, the MGP withheld $34,400 of net production revenue for future plugging and abandonment costs.
	Legal Proceedings
	The Partnership is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations.
	Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of their respective businesses. The MGP’s management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the MGP’s financial condition or results of operations.

Subsequent_Events

Subsequent Events	12 Months Ended
	Dec. 31, 2014
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	NOTE 10—SUBSEQUENT EVENTS
	Management has considered for disclosure any material subsequent events through the date the financial statements were issued.

Supplemental_Gas_and_Oil_Infor

Supplemental Gas and Oil Information (Unaudited)	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
SUPPLEMENTAL GAS AND OIL INFORMATION (UNAUDITED)	NOTE 11—SUPPLEMENTAL GAS AND OIL INFORMATION (UNAUDITED)
	Gas and Oil 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 27-2006 L.P. annual Form 10-K for the years ended December 31, 2014 and 2013 (See Note 2). For the periods presented, Wright & 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 38 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 16 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, 2014 and 2013 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, 2014 and 2013, 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 gas and oil reserves included within the Partnership or the present value of future cash flows of equivalent reserves, due to anticipated future changes in gas and oil 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)			Oil (Bbls)
	Balance, December 31, 2012		1,621,400			6,100
	Revisions (1)		2,578,100			3,800
	Production		(533,600	)		(1,100	)
			3,665,900			8,800
	Balance, December 31, 2013
	Revisions (2)		(165,300	)		(1,000	)
	Production		(474,600	)		(800	)
			3,026,000			7,000
	Balance, December 31, 2014
	-1	The upward revision in natural gas volumes 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 forecasts is primarily due to forecast adjustments in order to reflect actual production. The downward revision in oil forecasts is primarily due to forecast adjustment in order to better reflect actual production.
	Capitalized Costs Related to Gas and Oil Producing Activities. The components of capitalized costs related to gas and oil producing activities of the Partnership during the periods indicated were as follows:
		Years Ended December 31,
		2014			2013
	Natural gas and oil properties:
	Leasehold interest	$	1,684,000		$	1,687,400
	Wells and related equipment		86,777,900			85,908,800
	Accumulated depletion, accretion and impairment		(85,131,700	)		(82,051,200	)
	Net capitalized costs	$	3,330,200		$	5,545,000
	Results of Operations from Gas and Oil Producing Activities. The results of operations related to the Partnership’s gas and oil producing activities during the periods indicated were as follows:
		Years Ended December 31,
		2014			2013
	Revenues	$	1,886,000		$	2,218,200
	Production costs		(1,278,000	)		(1,301,800	)
	Depletion		(391,500	)		(1,029,000	)
	Impairment		(2,826,200	)		-
		$	(2,609,700	)	$	(112,600	)
	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 gas and oil reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2014 and 2013, 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,
		2014			2013
	Future cash inflows	$	11,421,500		$	14,639,800
	Future production costs		(7,579,700	)		(9,152,000	)
	Future net cash flows		3,841,800			5,487,800
	Less 10% annual discount for estimated timing of cash flows		-1,318,000			(2,065,500	)
	Standardized measure of discounted future net cash flows	$	2,523,800		$	3,422,300

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
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, 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, 2014 and 2013, the Partnership had recorded no allowance for uncollectible accounts receivable on its balance sheets.
Gas and Oil Properties	Gas and Oil Properties
	Gas and oil 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 gas and oil producing activities. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil 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 gas and oil properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion and impairment is less than the estimated expected undiscounted future cash flows including salvage. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of the production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value and the carrying value of the assets.
	The determination of 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.
	During the year ended December 31, 2014, the Partnership recognized $2,826,200 of impairment related to gas and oil properties. This impairment relates to the carrying amount of these gas and oil properties being in excess of the Partnership’s estimate of their fair value at December 31, 2014. The estimate of the fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil prices at the date of measurement. There was no impairment of gas and oil properties for the year ended December 31, 2013.
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, 2014 and 2013.
	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 2010. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2014.
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, 2014 and 2013.
Concentration of Credit Risk
	Concentration of Credit Risk
	The Partnership sells natural gas and crude oil under contracts to various purchasers in the normal course of business. For the year ended December 31, 2014, the Partnership had two customers that individually accounted for approximately 60% and 24%, of the Partnership’s natural gas and oil combined revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2013, the Partnership had two customers that individually accounted for approximately 62% and 18%, of the Partnership’s natural gas and oil combined revenues, excluding the impact of all financial derivative activity.
Revenue Recognition	Revenue Recognition
	The Partnership generally sells natural gas and crude oil 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 and crude oil in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty.
	The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP. The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, crude oil and condensate, and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (See Note 2: “Use of Estimates” for further description). The Partnership had unbilled revenues at December 31, 2014 and 2013 of $223,900 and $283,900, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.
Comprehensive Loss	Comprehensive Loss
	Comprehensive loss includes net loss and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net loss. These changes, other than net loss, are referred to as “other comprehensive income (loss)” 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 2013-04, 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 adopted the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it had no material impact on its financial position, results of operations or related disclosures.
Recently Issued Accounting Standards
	Recently Issued Accounting Standards
	In January 2015, the FASB issued ASU 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items (“Update 2015-01”). The amendments in Update 2015-01 simplify the income statement presentation requirements in Subtopic 225-20 by eliminating the concept of extraordinary items. Extraordinary items are events and transactions that are distinguished by their unusual nature and by the infrequency of their occurrence. Eliminating the extraordinary classification simplifies income statement presentation by altogether removing the concept of extraordinary items from consideration. The amendments in Update 2015-01 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A reporting entity may apply the amendments prospectively. A reporting entity may also apply the amendments retrospectively to all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. The Partnership will adopt the requirements of Update 2015-01 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.
	In November 2014, the FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815) – Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share is More Akin to Debt or to Equity (“Update 2014-16”). Certain classes of shares include features that entitle the holders to preferences and rights (such as conversion rights, redemption rights, voting powers, and liquidation and dividend payment preferences) over the other shareholders. Shares that include embedded derivative features are referred to as hybrid financial instruments, which must be separated from the host contract and accounted for as a derivative if certain criteria are met under Subtopic 815-10. One criterion requires evaluating whether the nature of the host contract is more akin to debt or to equity and whether the economic characteristics and risks of the embedded derivative feature are “clearly and closely related” to the host contract. In making that evaluation, an issuer or investor may consider all terms and features in a hybrid financial instrument including the embedded derivative feature that is being evaluated for separate accounting or may consider all terms and features in the hybrid financial instrument except for the embedded derivative feature that is being evaluated for separate accounting. The use of different methods can result in different accounting outcomes for economically similar hybrid financial instruments. Additionally, there is diversity in practice with respect to the consideration of redemption features in relation to other features when determining whether the nature of a host contract is more akin to debt or to equity. The amendments in Update 2014-16 clarify how current GAAP should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. The effects of initially adopting the amendments in Update 2014-16 should be applied on a modified retrospective basis to existing hybrid financial instruments issued in the form of a share as of the beginning of the fiscal year for which the amendments are effective. Retrospective application is permitted to all relevant prior periods. The amendments in Update 2014-16 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption, including adoption in an interim period, is permitted. The Partnership will adopt the requirements of Update 2014-16 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.
	In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. The Partnership will adopt the requirements of Update 2014-15 upon its effective date of January 1, 2017, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.
	In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles – Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. The Partnership will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2017, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

Participation_in_Revenues_and_1

Participation in Revenues and Costs (Tables)	12 Months Ended
	Dec. 31, 2014
Partners Capital Notes [Abstract]
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)		33%		67%
	Operating costs, administrative costs, direct and all other costs (2)		33%		67%
	Intangible drilling costs		5%		95%
	Tangible equipment costs		60%		40%
	-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 7% 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, 2014
Property Plant And Equipment [Abstract]
Property, Plant and Equipment	The following is a summary of natural gas and oil properties at the dates indicated:
		December 31,
		2014			2013
	Proved properties:
	Leasehold interests	$	1,684,000		$	1,687,400
	Wells and related equipment		86,777,900			85,908,800
	Total natural gas and oil properties		88,461,900			87,596,200
	Accumulated depletion and impairment		(85,131,700	)		(82,051,200	)
	Gas and oil properties, net	$	3,330,200		$	5,545,000

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations
	A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the periods indicated is as follows:
		Years Ended December 31,
		2014			2013
	Asset retirement obligations, beginning of period	$	3,210,500		$	3,306,000
	Accretion of asset retirement obligations		190,600			179,800
	Asset retirement obligations settled		(300	)		-
	Asset retirement obligation revision		1,002,900			(275,300	)
	Asset retirement obligations, end of period	$	4,403,700		$	3,210,500

Derivative_Instruments_Tables

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Commodity Derivatives	At December 31, 2014, the Partnership had the following commodity derivatives:
	Natural Gas Put Options
	Production			Volumes				Average			Fair Value
	Period Ending			(MMBtu) (1)				Fixed Price			Asset (2)
	December 31,							(per MMBtu) (1)
	2015				19,600			$	4		$	20,500
	2016				19,600				4.15			17,100
											$	37,600
	-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	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, 2014 and 2013:
		Years Ended December 31,
		2014				2013
	Gains from cash flow hedges reclassified from accumulated other comprehensive loss into natural gas and oil revenues	$	28,800			$	82,200
Offsetting Derivative Assets	The following table summarizes the gross and net fair values of the Partnership’s balances on the Partnership’s balance sheets for the periods indicated:
	Offsetting Assets		Gross				Gross			Net Amount of Assets
			Amounts of				Amounts			Presented in the
			Recognized				Offset in the			Balance Sheets
			Assets				Balance Sheets
	As of December 31, 2014
	Accounts receivable monetized gains-affiliate		$	-			$	-		$	-
	Total		$	-			$	-		$	-
	As of December 31, 2013
	Accounts receivable monetized gains-affiliate		$	37,900			$	(13,800	)	$	24,100
	Total		$	37,900			$	(13,800	)	$	24,100
Offsetting Derivative Liabilities
	Offsetting Liabilities		Gross				Gross			Net Amount of
			Amounts of				Amounts			Liabilities Presented
			Recognized				Offset in the			in the Balance Sheets
			Liabilities				Balance Sheets
	As of December 31, 2014
	Put premiums payable-affiliate		$	(13,100			$	-		$	(13,100	)
					)
	Long-term put premiums payable-affiliate			(15,000	)			-			(15,000	)
	Total		$	(28,100	)		$	-		$	(28,100	)
	As of December 31, 2013
	Put premiums payable-affiliate		$	(13,800	)		$	13,800		$	-
	Long-term put premiums payable-affiliate			(27,400	)			-			(27,400	)
	Total		$	(41,200	)		$	13,800		$	(27,400	)

Fair_Value_of_Financial_Instru1

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Schedule of Fair Value Derivative Instruments	Information for assets and liabilities measured at fair value at December 31, 2014 and 2013 was as follows:
	As of December 31, 2014	Level 1		Level 2		Level 3		Total
	Derivative assets, gross
	Commodity puts	$	-	$	37,600	$	-	$	37,600
	Derivative liabilities, gross
	Commodity puts		-		-		-		-
	Total derivative, fair value, net	$	-	$	37,600	$	-	$	37,600
	As of December 31, 2013
	Derivative assets, gross
	Commodity puts	$	-	$	18,200	$	-	$	18,200
	Derivative liabilities, gross
	Commodity puts		-		-		-		-
	Total derivative, fair value, net	$	-	$	18,200	$	-	$	18,200

Certain_Relationships_and_Rela1

Certain Relationships and Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Costs Incurred From Related Party Transactions	The following table provides information with respect to these costs and the periods incurred:
		Years Ended December 31,
		2014		2013
	Administrative fees	$	134,800	$	137,500
	Supervision fees		675,500		689,000
	Transportation fees		250,300		316,700
	Direct Costs		404,000		360,500
	Total	$	1,464,600	$	1,503,700

Supplemental_Gas_and_Oil_Infor1

Supplemental Gas and Oil Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
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)			Oil (Bbls)
	Balance, December 31, 2012		1,621,400			6,100
	Revisions (1)		2,578,100			3,800
	Production		(533,600	)		(1,100	)
			3,665,900			8,800
	Balance, December 31, 2013
	Revisions (2)		(165,300	)		(1,000	)
	Production		(474,600	)		(800	)
			3,026,000			7,000
	Balance, December 31, 2014
	-1	The upward revision in natural gas volumes 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 forecasts is primarily due to forecast adjustments in order to reflect actual production. The downward revision in oil forecasts is primarily due to forecast adjustment in order to better reflect actual production.
Capitalized Costs Relating to Gas and Oil Producing Activities	Capitalized Costs Related to Gas and Oil Producing Activities. The components of capitalized costs related to gas and oil producing activities of the Partnership during the periods indicated were as follows:
		Years Ended December 31,
		2014			2013
	Natural gas and oil properties:
	Leasehold interest	$	1,684,000		$	1,687,400
	Wells and related equipment		86,777,900			85,908,800
	Accumulated depletion, accretion and impairment		(85,131,700	)		(82,051,200	)
	Net capitalized costs	$	3,330,200		$	5,545,000
Results of Operations for Gas and Oil Producing Activities	Results of Operations from Gas and Oil Producing Activities. The results of operations related to the Partnership’s gas and oil producing activities during the periods indicated were as follows:
		Years Ended December 31,
		2014			2013
	Revenues	$	1,886,000		$	2,218,200
	Production costs		(1,278,000	)		(1,301,800	)
	Depletion		(391,500	)		(1,029,000	)
	Impairment		(2,826,200	)		-
		$	(2,609,700	)	$	(112,600	)
Standardized Measure of Discounted 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 gas and oil reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2014 and 2013, 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,
		2014			2013
	Future cash inflows	$	11,421,500		$	14,639,800
	Future production costs		(7,579,700	)		(9,152,000	)
	Future net cash flows		3,841,800			5,487,800
	Less 10% annual discount for estimated timing of cash flows		-1,318,000			(2,065,500	)
	Standardized measure of discounted future net cash flows	$	2,523,800		$	3,422,300

Basis_of_Presentation_Details

Basis of Presentation (Details)	12 Months Ended	0 Months Ended
	Dec. 31, 2014	Oct. 13, 2014
Description Of Business [Line Items]
Atlas America Series 27-2006 L.P. Formation Date	21-Jul-06
Atlas Energy | New Atlas | Spin Off
Description Of Business [Line Items]
Percentage of limited liability company interests distributed to unitholders		100.00%

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
	Customer	Customer
Summary Of Significant Accounting Policies [Line Items]
Allowance for Uncollectible Accounts Receivable	$0	$0
Impairment	2,826,200	0
Number of major customers	2	2
Unbilled Revenues	$223,900	$283,900
Customer Concentration Risk | Customer 1 | Sales Revenues
Summary Of Significant Accounting Policies [Line Items]
Concentration Risk, Percentage	60.00%	62.00%
Customer Concentration Risk | Customer 2 | Sales Revenues
Summary Of Significant Accounting Policies [Line Items]
Concentration Risk, Percentage	24.00%	18.00%

Participation_in_Revenues_and_2

Participation in Revenues and Costs (Narrative) (Details) (Managing General Partner)	12 Months Ended
	Dec. 31, 2014
Managing General Partner
Capital Unit [Line Items]
Additional partnership revenues to receive, Percentage	7.00%

Participation_in_Revenues_and_3

Participation in Revenues and Costs (Details)	12 Months Ended
	Dec. 31, 2014
Managing General Partner
Capital Unit [Line Items]
Additional partnership revenues to receive, Percentage	7.00%
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	33.00%	[1]
Revenues | Limited Partners
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	67.00%	[1]
Operating Costs, Administrative Costs, Direct And All Other Costs | Managing General Partner
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	33.00%	[2]
Operating Costs, Administrative Costs, Direct And All Other Costs | Limited Partners
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	67.00%	[2]
Intangible Drilling Costs | Managing General Partner
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	5.00%
Intangible Drilling Costs | Limited Partners
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	95.00%
Tangible Equipment Costs | Managing General Partner
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	60.00%
Tangible Equipment Costs | Limited Partners
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	40.00%
[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 7% 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_D

Property, Plant and Equipment (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Property Plant And Equipment [Line Items]
Natural gas and oil properties	$88,461,900	$87,596,200
Accumulated depletion and impairment	-85,131,700	-82,051,200
Gas and oil properties, net	3,330,200	5,545,000
Leasehold interests
Property Plant And Equipment [Line Items]
Natural gas and oil properties	1,684,000	1,687,400
Wells and related equipment
Property Plant And Equipment [Line Items]
Natural gas and oil properties	$86,777,900	$85,908,800

Property_Plant_and_Equipment_N

Property, Plant and Equipment (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Property Plant And Equipment [Abstract]
Depletion of gas and oil properties	$391,500	$1,029,000
Reclassification from gas and oil properties to accumulated depletion due to asset retirements	137,200
Impairment of Long-Lived Assets Held-for-use	$2,826,200	$0

Asset_Retirement_Obligations_N

Asset Retirement Obligations (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Net production revenue for future plugging and abandonment costs	$34,400

Asset_Retirement_Obligations_S

Asset Retirement Obligations (Schedule of Asset Retirement Obligations) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligations, Roll Forward Analysis [Roll Forward]
Asset retirement obligations, beginning of period	$3,210,500	$3,306,000
Accretion of asset retirement obligation	190,600	179,800
Asset retirement obligations settled	-300
Asset retirement obligation revision	1,002,900	-275,300
Asset retirement obligations, end of period	$4,403,700	$3,210,500

Derivative_Instruments_Narrati

Derivative Instruments (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Net derivative liability and asset	$37,600	$18,200
Gains (Losses) on Fair Value Hedge Ineffectiveness, Net	0	0
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets		37,900
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	28,100	41,200
Accumulated other comprehensive income (loss)	9,400	-4,200
Other Comprehensive Income (Loss)
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	-7,300
Net Deferred Gain (Loss) To Be Reclassified Into Net Income In Later Periods	-2,100
Other Comprehensive Income (Loss) | Allocation To Limited Partner Only
Derivative [Line Items]
Net Derivative Gains (Losses) Limited Partner	5,300
Accounts receivable monetized gains-affiliate
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets		37,900
Put premiums payable-affiliate
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	13,100	13,800
Long-term put premiums payable-affiliate
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	$15,000	$27,400

Derivative_Instruments_Commodi

Derivative Instruments (Commodity Derivatives) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
	MMBTU
Derivative [Line Items]
Fair Value Asset	$37,600		$18,200
Natural Gas Put Options
Derivative [Line Items]
Fair Value Asset	37,600	[1]
Production Period Ending December 31, 2015 | Natural Gas Put Options
Derivative [Line Items]
Volumes(MMBtu)	19,600	[2]
Average Fixed Price (per MMBtu)	4	[2]
Fair Value Asset	20,500	[1]
Production Period Ending December 31, 2016 | Natural Gas Put Options
Derivative [Line Items]
Volumes(MMBtu)	19,600	[2]
Average Fixed Price (per MMBtu)	4.15	[2]
Fair Value Asset	$17,100	[1]
[1]	Fair value based on forward NYMEX natural gas prices, as applicable.
[2]	bMMBtub represents million British Thermal Units.

Derivative_Instruments_Effects

Derivative Instruments (Effects of Derivative Instruments on Statements of Operations) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Gains from cash flow hedges reclassified from accumulated other comprehensive loss into natural gas and oil revenues	$28,800	$82,200

Derivative_Instruments_Offsett

Derivative Instruments (Offsetting Derivative Assets) (Details) (USD $)	Dec. 31, 2013
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	$37,900
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset in the Balance Sheets	-13,800
Affiliate Balances, Offsetting Derivative Assets, Net Amount of Assets Presented in the Balance Sheets	24,100
Accounts receivable monetized gains-affiliate
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	37,900
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset in the Balance Sheets	-13,800
Affiliate Balances, Offsetting Derivative Assets, Net Amount of Assets Presented in the Balance Sheets	$24,100

Derivative_Instruments_Offsett1

Derivative Instruments (Offsetting Derivative Liabilities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities	($28,100)	($41,200)
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets		13,800
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount of Liabilities Presented in the Balance Sheets	-28,100	-27,400
Put premiums payable-affiliate
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities	-13,100	-13,800
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets		13,800
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount of Liabilities Presented in the Balance Sheets	-13,100
Long-term put premiums payable-affiliate
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities	-15,000	-27,400
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount of Liabilities Presented in the Balance Sheets	($15,000)	($27,400)

Fair_Value_of_Financial_Instru2

Fair Value of Financial Instruments (Assets and Liabilities Measured at Fair Value on a Recurring Basis) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative, Fair Value, Total	$37,600	$18,200
Commodity Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross	37,600	18,200
Fair Value, Inputs, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative, Fair Value, Total	37,600	18,200
Fair Value, Inputs, Level 2 | Commodity Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross	$37,600	$18,200

Fair_Value_of_Financial_Instru3

Fair Value of Financial Instruments (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment	$2,826,200	$0
Fair Value, Inputs, Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment	2,826,200	0
Asset Retirement Obligation | Fair Value, Inputs, Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Adjustments to retirement obligations	$1,002,900	$0

Certain_Relationships_and_Rela2

Certain Relationships and Related Party Transactions (Narrative) (Details) (MGP and Affiliates)	12 Months Ended
	Dec. 31, 2014
Administrative
Related Party Transaction [Line Items]
Monthly Administrative Costs Per Well	75
Monthly Supervision Fees Per Well	376
Transportation
Related Party Transaction [Line Items]
Transportation Fee Rate As Percentage Of Natural Gas Sales Price	13.00%

Certain_Relationships_and_Rela3

Certain Relationships and Related Party Transactions (Schedule of Related Party Transactions) (Details) (Payable To The M G P And Affiliates, USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$1,464,600	$1,503,700
Administrative fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	134,800	137,500
Supervision fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	675,500	689,000
Transportation fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	250,300	316,700
Direct Costs
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$404,000	$360,500

Commitments_and_Contingencies_

Commitments and Contingencies (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014
Commitments And Contingencies Disclosure [Abstract]
Investor Partners Ownership Interest Presented For Purchase By The MGP, Maximum Percentage	5.00%
Operator Fee Per Well To Cover Estimated Future Plugging And Abandonment Costs, Monthly	200
Net production revenue for future plugging and abandonment costs	$34,400

Supplemental_Oil_and_Gas_Infor

Supplemental Oil and Gas Information (Unaudited) (Changes In Proved Reserve Quantities) (Details)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
	Mcf		Mcf
Gas (Mcf)
Reserve Quantities [Line Items]
Balance	3,665,900		1,621,400
Revisions	-165,300	[1]	2,578,100	[2]
Production	-474,600		-533,600
Balance	3,026,000		3,665,900
Oil (Bbls)
Reserve Quantities [Line Items]
Balance	8,800		6,100
Revisions	-1,000	[1]	3,800	[2]
Production	-800		-1,100
Balance	7,000		8,800
[1]	The downward revision in natural gas forecasts is primarily due to forecast adjustments in order to reflect actual production. The downward revision in oil forecasts is primarily due to forecast adjustment in order to better reflect actual production.
[2]	The upward revision in natural gas volumes is primarily due to an increase in SEC base pricing from the prior year resulting in longer economic life.

Supplemental_Oil_and_Gas_Infor1

Supplemental Oil and Gas Information (Unaudited) (Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Natural Gas and Oil Producing Activities [Abstract]
Natural gas and oil properties: Leasehold interest	$1,684,000	$1,687,400
Natural gas and oil properties: Wells and related equipment	86,777,900	85,908,800
Accumulated depletion, accretion and impairment	-85,131,700	-82,051,200
Net capitalized costs	$3,330,200	$5,545,000

Supplemental_Oil_and_Gas_Infor2

Supplemental Oil and Gas Information (Unaudited) (Results of Operations for Oil and Gas Producing Activities) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Natural Gas and Oil Producing Activities [Abstract]
Revenues	$1,886,000	$2,218,200
Production costs	-1,278,000	-1,301,800
Depletion	-391,500	-1,029,000
Impairment	-2,826,200	0
Total Results from Operations from Oil and Gas Producing Activities	($2,609,700)	($112,600)

Supplemental_Oil_and_Gas_Infor3

Supplemental Oil and Gas Information (Unaudited) (Narrative) (Details)	12 Months Ended
	Dec. 31, 2014
Natural Gas and Oil Producing Activities [Abstract]
Present value of discount factor	10.00%

Supplemental_Oil_and_Gas_Infor4

Supplemental Oil and Gas Information (Unaudited) (Standardized Measure of Future Cash Flows) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Natural Gas and Oil Producing Activities [Abstract]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Cash Inflows	$11,421,500	$14,639,800
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Production Costs	-7,579,700	-9,152,000
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Net Cash Flows, Total	3,841,800	5,487,800
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, 10 Percent Annual Discount for Estimated Timing of Cash Flows	-1,318,000	-2,065,500
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure, Total	$2,523,800	$3,422,300