Atlas America Public #15-2006 10-Q 14 Aug 14 2014 Q2 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	6 Months Ended
	Jun. 30, 2014
Document Document And Entity Information [Line Items]	'
Document Type	'10-Q
Amendment Flag	'false
Document Period End Date	30-Jun-14
Document Fiscal Year Focus	'2014
Document Fiscal Period Focus	'Q2
Entity Registrant Name	'Atlas America Public #15-2006 (B) L.P.
Entity Central Index Key	'0001357361
Current Fiscal Year End Date	'--12-31
Entity Filer Category	'Smaller Reporting Company
Entity Common Stock, Shares Outstanding	0

CONDENSED_BALANCE_SHEETS

CONDENSED BALANCE SHEETS (USD $)	Jun. 30, 2014	Dec. 31, 2013
Current assets:	'	'
Cash and cash equivalents	'	$167,100
Accounts receivable trade–affiliate	1,246,800	937,400
Asset retirement receivable-affiliate	47,500	'
Accounts receivable monetized gains-affiliate	10,500	56,200
Current portion of derivative assets	5,900	6,700
Total current assets	1,310,700	1,167,400
Oil and gas properties, net	12,970,200	13,336,000
Long-term derivative assets	24,600	35,400
TOTAL ASSETS	14,305,500	14,538,800
Current liabilities:	'	'
Accrued liabilities	6,000	6,700
Total current liabilities	6,000	6,700
Long-term put premiums payable-affiliate	48,800	63,600
Asset retirement obligation	7,920,200	7,692,200
Commitments and contingencies	'	'
Partners’ capital:	'	'
Managing general partner’s interest	3,220,100	3,278,400
Limited partners interest (14,772.60 units)	3,157,400	3,542,800
Accumulated other comprehensive loss	-47,000	-44,900
Total partners' capital	6,330,500	6,776,300
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$14,305,500	$14,538,800

CONDENSED_BALANCE_SHEETS_Paren

CONDENSED BALANCE SHEETS (Parenthetical)	Jun. 30, 2014
Limited partners' units	14,772.60

CONDENSED_STATEMENTS_OF_OPERAT

CONDENSED STATEMENTS OF OPERATIONS (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
REVENUES	'	'	'	'
Natural gas and oil	$1,457,100	$1,503,400	$2,885,500	$2,635,600
Total revenues	1,457,100	1,503,400	2,885,500	2,635,600
COSTS AND EXPENSES	'	'	'	'
Production	757,300	842,600	1,451,800	1,590,400
Depletion	191,700	637,400	365,500	1,207,600
Accretion of asset retirement obligation	114,100	110,300	228,300	220,700
General and administrative	100,200	105,100	202,800	221,500
Total costs and expenses	1,163,300	1,695,400	2,248,400	3,240,200
Net income (loss)	293,800	-192,000	637,100	-604,600
Allocation of net (income) loss:	'	'	'	'
Managing general partner	124,200	19,100	261,800	-42,600
Limited partners	$169,600	($211,100)	$375,300	($562,000)
Net income (loss) per limited partnership unit	$11	($14)	$25	($38)

CONDENSED_STATEMENTS_OF_COMPRE

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Net income (loss)	$293,800	($192,000)	$637,100	($604,600)
Other comprehensive income (loss):	'	'	'	'
Unrealized holding gain (loss) on cash flow hedging contracts	3,300	4,100	-49,100	-47,200
Difference in estimated hedge gains receivable	-7,800	17,300	85,300	96,100
Reclassification adjustment for losses (gains) realized in net loss from cash flow hedges	5,200	5,600	-38,300	-17,200
Total other comprehensive income (loss)	700	27,000	-2,100	31,700
Comprehensive income (loss)	$294,500	($165,000)	$635,000	($572,900)

CONDENSED_STATEMENTS_OF_CHANGE

CONDENSED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL (USD $)	Total	Managing General Partner	Limited Partners	Accumulated Other Comprehensive Loss
Balance at Dec. 31, 2013	$6,776,300	$3,278,400	$3,542,800	($44,900)
Participation in revenues and expenses:	'	'	'	'
Net production revenues	1,433,700	479,800	953,900	'
Depletion	-365,500	-74,700	-290,800	'
Accretion of asset retirement obligation	-228,300	-75,900	-152,400	'
General and administrative	-202,800	-67,400	-135,400	'
Net income (loss)	637,100	261,800	375,300	'
Other comprehensive loss	-2,100	'	'	-2,100
Distributions to partners	-1,080,800	-320,100	-760,700	'
Balance at Jun. 30, 2014	$6,330,500	$3,220,100	$3,157,400	($47,000)

CONDENSED_STATEMENTS_OF_CASH_F

CONDENSED STATEMENTS OF CASH FLOWS (USD $)	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Cash flows from operating activities:	'	'
Net income (loss)	$637,100	($604,600)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	'	'
Depletion	365,500	1,207,600
Non cash loss on derivative value	40,400	224,700
Accretion of asset retirement obligation	228,300	220,700
Changes in operating assets and liabilities:	'	'
Increase in accounts receivable trade-affiliate	-309,400	-105,600
Asset retirement receivable-affiliate	-47,500	'
Decrease in accrued liabilities	-700	-5,000
Asset retirement obligation liabilities settled	-300	-21,600
Net cash provided by (used in) operating activities	913,400	916,200
Cash flows from investing activities:	'	'
Proceeds from sale of tangible equipment	300	300
Purchase of tangible equipment	'	-1,100
Net cash used in operating activities	300	-800
Cash flows from financing activities:	'	'
Distributions to partners	-1,080,800	-902,000
Net cash used in financing activities	-1,080,800	-902,000
Net (decrease) increase in cash and cash equivalents	-167,100	13,400
Cash and cash equivalents at beginning of period	167,100	102,500
Cash and cash equivalents at end of period	'	$115,900

Description_of_Business

Description of Business	6 Months Ended
	Jun. 30, 2014
DESCRIPTION OF BUSINESS	'
	NOTE 1 - DESCRIPTION OF BUSINESS
	Atlas America Public #15-2006 (B) L.P. (the “Partnership”) is a Delaware limited partnership, formed on May 9, 2006 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP).
	In March 2012, the MGP’s ultimate parent, Atlas Energy L.P. (“Atlas Energy”) (NYSE: ATLS), contributed to ARP, a newly-formed exploration and production master limited partnership, substantially all of Atlas Energy’s natural gas and oil development and production assets and its partnership management business, including ownership of the MGP.
	On February 17, 2011, Atlas Energy L.P., formerly known as Atlas Pipeline Holdings, L.P., a then-majority owned subsidiary of Atlas Energy, Inc. and parent of the general partner of Atlas Pipeline Partners, L.P. (“APL”) (NYSE: APL), completed an acquisition of assets from Atlas Energy, Inc., which included its investment partnership business, its oil and gas exploration, development and production activities conducted in Tennessee, Indiana, and Colorado, certain shallow wells and leases in New York and Ohio, certain well interests in Pennsylvania and its ownership and management of investments in Lightfoot Capital Partners, L.P. and related entities (the “Transferred Business”).
	The Partnership has drilled and currently operates wells located in Pennsylvania, Tennessee, and Ohio. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy, for administrative services.
	The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through third-party gas gathering systems. The Partnership does not plan to sell any of its wells and intends to produce them until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. The Partnership expects that no other wells will be drilled and no additional funds will be required for drilling.
	The accompanying condensed financial statements, which are unaudited, except that the balance sheet at December 31, 2013 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in the Partnership’s Form 10-K. These interim financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2013. The results of operations for the three and six months ended June 30, 2014 may not necessarily be indicative of the results of operations for the year ended December 31, 2014.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2014
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	'
	NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	In management's opinion, all adjustments necessary for a fair presentation of the Partnership's financial position, results of operations and cash flows for the periods disclosed have been made. Management has considered for disclosure any material subsequent events through the date the financial statements were issued.
	In addition to matters discussed further in this note, the Partnership’s significant accounting policies are detailed in its audited financial statements and notes thereto in the Partnership’s annual report on Form 10-K for the year ended December 31, 2013 filed with the Securities and Exchange Commission (“SEC”).
	Use of Estimates
	Preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, asset impairments, fair value of derivative instruments and the probability of forecasted transactions. Actual results could differ from those estimates.
	The natural gas industry principally conducts its business by processing actual transactions as much as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following months’ financial results. Management believes that the operating results presented for the three and six months ended June 30, 2014 and 2013 represent actual results in all material respects (see “Revenue Recognition” accounting policy for further description).
	Accounts Receivable and Allowance for Possible Losses
	In evaluating the need for an allowance for possible losses, the MGP performs ongoing credit evaluations of the Partnership’s customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness as determined by review of such customers’ credit information. Credit is extended on an unsecured basis to many of the Partnership’s energy customers. At June 30, 2014 and December 31, 2013, the MGP’s credit evaluation indicated that the Partnership had no need for an allowance for possible losses.
	Oil and Gas Properties
	Oil and gas properties are stated at cost. Maintenance and repairs that generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized.
	The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Oil is 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. The Partnership recorded depletion expense on natural gas and oil properties of $365,500 and $1,207,600 for the six months ended June 30, 2014 and 2013, respectively.
	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. Upon the sale of an entire interest, a gain or loss is recorded in the statements of operations. As a result of retirements the Partnership reclassified $389,200 from oil and gas properties to accumulated depletion for the six months ended June 30, 2013.
	The following is a summary of oil and gas properties at the dates indicated:
		June 30,			December 31,
		2014			2013
	Proved properties:
	Leasehold interests	$	4,179,600		$	4,179,600
	Wells and related equipment		183,397,200			183,397,500
	Total natural gas and oil properties		187,576,800			187,577,100
	Accumulated depletion and impairment		(174,606,600	)		(174,241,100	)
	Oil and gas properties, net	$	12,970,200		$	13,336,000
	Impairment of Long-Lived Assets
	The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset's estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount of that asset to its estimated fair value if such carrying amount exceeds the fair value.
	The review of the Partnership’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of the production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.
	The determination of oil and natural gas reserve estimates is a subjective process and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.
	In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. The Partnership may have to pay additional consideration in the future as a well becomes uneconomic under the terms of the Partnership Agreement in order to recover these reserves. There were no impairments recorded during the three and six months ended June 30, 2014 and 2013, or during the year ended December 31, 2013.
	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 expenses until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues and expenses based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.
	Revenue Recognition
	The Partnership generally sells natural gas 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 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, NGL's, 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. The Partnership had unbilled revenues at June 30, 2014 and December 31, 2013 of $828,600 and $738,300, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.
	Comprehensive Income (Loss)
	Comprehensive income (loss) includes net income (loss) and all other changes in equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States of America, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as "other comprehensive income (loss)" and, for the Partnership, include changes in the fair value of 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 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 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 using the full retrospective method 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.

Asset_Retirement_Obligation

Asset Retirement Obligation	6 Months Ended
	Jun. 30, 2014
ASSET RETIREMENT OBLIGATION	'
	NOTE 3 - ASSET RETIREMENT OBLIGATION
	The Partnership recognizes an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. It also recognizes a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The 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 associated asset retirement costs from revisions are capitalized as part of the carrying amount of the long-lived asset. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its oil and gas properties, the Partnership has determined that there are 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 June 30, 2014 the MGP withheld $47,500 of net production revenue for future plugging and abandonment costs.
	A reconciliation of the Partnership’s liability for plugging and abandonment costs for the periods indicated is as follows:
		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2014			2013			2014			2013
	Asset retirement obligation at beginning of period	$	7,806,400		$	8,228,200		$	7,692,200		$	8,117,800
	Accretion expense		114,100			110,300			228,300			220,700
	Liabilities settled		(300	)		(21,600	)		(300	)		(21,600	)
	Asset retirement obligation at end of period	$	7,920,200		$	8,316,900		$	7,920,200		$	8,316,900

Derivative_Instruments

Derivative Instruments	6 Months Ended
	Jun. 30, 2014
DERIVATIVE INSTRUMENTS	'
	NOTE 4 - DERIVATIVE INSTRUMENTS
	The MGP, on behalf of the Partnership, uses a number of different derivative instruments, principally swaps, collars and options, in connection with the Partnership’s commodity price risk management activities. Management enters into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under commodity-based swap agreements, the Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. 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 $30,500 and $42,100 at June 30, 2014 and December 31, 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 June 30, 2014, the Partnership had the following commodity derivatives:
	Natural Gas Put Options
	Production		Volumes				Average				Fair Value
	Period Ending						Fixed Price				Asset (2)
	December 31,
			(MMBtu) (1)				(per MMBtu) (1)
	2014			27,600			$	3.8			$	800
	2015			44,200				4				11,800
	2016			44,200				4.15				17,900
											$	30,500
	-1	“MMBtu” represents million British Thermal Units.
	-2	Fair value based on forward New York Mercantile Exchange (“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 the three and six months ended June 30, 2014 and 2013:
		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2014				2013				2014				2013
	(Loss) gain from cash flow hedges reclassified from accumulated other comprehensive income (loss) into natural gas and oil revenues	$		)		$	(5,600	)		$	38,300			$	17,200
			(5,200
	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 three and six months ended June 30, 2014 and 2013 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.
	Monetized Gains
	Prior to February 17, 2011  Atlas Energy Inc. (“AEI”), monetized its derivative instruments, including those related to the future natural gas and oil production of the Transferred Business. AEI also monetized derivative instruments that were specifically related to the future natural gas and oil production of the Partnership. At June 30, 2014 and December 31, 2013, remaining hedge monetization cash proceeds of $41,300 and $88,100, respectively, related to the amounts hedged on behalf of the Partnership’s limited partners were included within accounts receivable monetized gains-affiliate. The Partnership will allocate the monetized net proceeds to the limited partners based on the natural gas and oil production generated over the period of the original derivative contracts.
	During June 2012, the MGP used the undistributed monetized funds to purchase natural gas put options on behalf of the limited partners of the Partnership only. A premium (“put premium”) was paid to purchase the contracts and will be allocated to natural gas production revenues generated over the contractual term of the purchased hedging instruments. At June 30, 2014 and December 31, 2013, the put premiums were recorded as short-term payables to affiliate of $30,800 and $31,900, respectively, and long-term payables to affiliate of $48,800 and $63,600, respectively. Furthermore, the current portion of the put premium liability is included in accounts receivable monetized gains-affiliate in the Partnership’s balance sheets.
	The following table summarizes the gross and net fair values of the Partnership’s affiliate balances on the Partnership’s balance sheets for the periods indicated:
			Gross Amounts				Gross Amounts				Net Amount of
			of Recognized				Offset in the				Assets
			Assets				Balance Sheets				Presented in the
											Balance Sheets
	Offsetting Assets
	As of June 30, 2014
			$	41,300			$	(30,800	)		$	10,500
	Accounts receivable monetized gains-affiliate
	As of December 31, 2013
	Accounts receivable monetized gains-affiliate		$	88,100			$	(31,900	)		$	56,200
			Gross Amounts				Gross Amounts				Net Amount of
			of Recognized				Offset in the				Liabilities
			Liabilities				Balance Sheets				Presented in the
											Balance Sheets
	Offsetting Liabilities
	As of June 30, 2014
			$	(30,800	)		$	30,800			$	-
	Put premiums payable-affiliate
	Long-term put premiums payable-affiliate			(48,800	)			-				(48,800	)
			$	(79,600	)		$	30,800			$	(48,800	)
	Total
	As of December 31, 2013
	Put premiums payable-affiliate		$	(31,900	)		$	31,900			$	-
	Long-term put premiums payable-affiliate			(63,600	)			-				(63,600	)
			$	(95,500	)		$	31,900			$	(63,600	)
	Total
	Accumulated Other Comprehensive Loss
	As a result of the monetization and the early settlement of natural gas and oil derivative instruments, the put options, and the unrealized losses recognized in income in prior periods due to natural gas and oil property impairments, the Partnership recorded a net deferred loss on its balance sheet in accumulated other comprehensive loss of $47,000 as of June 30, 2014. Included in accumulated other comprehensive loss are unrealized gains of $39,200, net of the MGP interest, that were recognized into earnings as a result of oil and gas property impairments during prior periods. During the current year, $9,200 of net losses were recorded by the Partnership and allocated only to the limited partners. Of the remaining $47,000 of net unrealized loss in accumulated other comprehensive loss, the Partnership will reclassify $22,800 of net losses to the Partnership’s statements of operations over the next twelve month period and the remaining losses of $24,200 in later periods.

Fair_Value_of_Financial_Instru

Fair Value of Financial Instruments	6 Months Ended
	Jun. 30, 2014
FAIR VALUE OF FINANCIAL INSTRUMENTS	'
	NOTE 5 - FAIR VALUE OF FINANCIAL INSTRUMENTS
	The Partnership has established a hierarchy to measure its financial instruments at fair value, which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect the Partnership’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value:
	Level 1 – Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.
	Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.
	Level 3 – Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	The carrying values of cash, accounts receivable, and accounts payable approximate their respective fair values due to the short term maturities of such financial instruments. The Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 4). The Partnership manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty. The Partnership’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. These derivative instruments are calculated by utilizing commodity indices, quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument.
	Information for assets and liabilities measured at fair value at June 30, 2014 and December 31, 2013 is as follows:
		Level 1		Level 2		Level 3		Total
	As of June 30, 2014
	Derivative assets, gross
	Commodity puts	$	-	$	30,500	$	-	$	30,500
	Derivative liabilities, gross
	Commodity puts	$	-	$	-	$	-	$	-
		$	-	$	30,500	$	-	$	30,500
	Total derivatives, fair value, net
		Level 1		Level 2		Level 3		Total
	As of December 31, 2013
	Derivative assets, gross
	Commodity puts	$	-	$	42,100	$	-	$	42,100
	Derivative liabilities, gross
	Commodity puts	$	-	$	-	$	-	$	-
		$	-	$	42,100	$	-	$	42,100
	Total derivatives, fair value, net
	Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
	The Partnership estimates the fair value of its asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates (see Note 3). There were no additional assets or liabilities that were measured at fair value on a nonrecurring basis for the three and six months ended June 30, 2014 and 2013.

Certain_Relationships_and_Rela

Certain Relationships and Related Party Transactions	6 Months Ended
	Jun. 30, 2014
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS	'
	NOTE 6 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
	The Partnership has entered into the following significant transactions with the MGP and its affiliates as provided under its Partnership Agreement. Administrative costs, which are included in general and administrative expenses in the Partnership’s statements of operations, are payable at $75 per well per month. Monthly well supervision fees, which are included in production expense in the Partnership’s statement of operations, are payable at $296 per well per month for operating and maintaining the wells. Transportation fees, which are included in production expenses in the Partnership’s statements of operations, are generally payable at 13% of the natural gas sales price.
	The following table provides information with respect to these costs and the periods incurred:
		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2014		2013		2014		2013
	Administrative	$	90,600	$	90,500	$	176,900	$	186,700
	Supervision		358,200		357,900		699,100		737,700
	Transportation		173,200		204,700		356,300		358,900
	Total	$	622,000	$	653,100	$	1,232,300	$	1,283,300
	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	6 Months Ended
	Jun. 30, 2014
COMMITMENTS AND CONTINGENCIES	'
	NOTE 7 - COMMITMENTS AND CONTINGENCIES
	General Commitments
	Subject to certain conditions, investor partners may present their interests for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. The MGP is not obligated to purchase more than 5% of the 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 June 30, 2014 the MGP withheld $47,500 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.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2014
Use of Estimates	'
	Use of Estimates
	Preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, asset impairments, fair value of derivative instruments and the probability of forecasted transactions. Actual results could differ from those estimates.
	The natural gas industry principally conducts its business by processing actual transactions as much as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following months’ financial results. Management believes that the operating results presented for the three and six months ended June 30, 2014 and 2013 represent actual results in all material respects (see “Revenue Recognition” accounting policy for further description).
Accounts Receivable and Allowance for Possible Losses	'
	Accounts Receivable and Allowance for Possible Losses
	In evaluating the need for an allowance for possible losses, the MGP performs ongoing credit evaluations of the Partnership’s customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness as determined by review of such customers’ credit information. Credit is extended on an unsecured basis to many of the Partnership’s energy customers. At June 30, 2014 and December 31, 2013, the MGP’s credit evaluation indicated that the Partnership had no need for an allowance for possible losses.
Oil and Gas Properties	'
	Oil and Gas Properties
	Oil and gas properties are stated at cost. Maintenance and repairs that generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized.
	The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Oil is 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. The Partnership recorded depletion expense on natural gas and oil properties of $365,500 and $1,207,600 for the six months ended June 30, 2014 and 2013, respectively.
	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. Upon the sale of an entire interest, a gain or loss is recorded in the statements of operations. As a result of retirements the Partnership reclassified $389,200 from oil and gas properties to accumulated depletion for the six months ended June 30, 2013.
	The following is a summary of oil and gas properties at the dates indicated:
		June 30,			December 31,
		2014			2013
	Proved properties:
	Leasehold interests	$	4,179,600		$	4,179,600
	Wells and related equipment		183,397,200			183,397,500
	Total natural gas and oil properties		187,576,800			187,577,100
	Accumulated depletion and impairment		(174,606,600	)		(174,241,100	)
	Oil and gas properties, net	$	12,970,200		$	13,336,000
Impairment of Long-Lived Assets	'
	Impairment of Long-Lived Assets
	The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset's estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount of that asset to its estimated fair value if such carrying amount exceeds the fair value.
	The review of the Partnership’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of the production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.
	The determination of oil and natural gas reserve estimates is a subjective process and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.
	In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. The Partnership may have to pay additional consideration in the future as a well becomes uneconomic under the terms of the Partnership Agreement in order to recover these reserves. There were no impairments recorded during the three and six months ended June 30, 2014 and 2013, or during the year ended December 31, 2013.
Working Interest	'
	Working Interest
	The Partnership Agreement establishes that revenues and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). The MGP is also provided an additional working interest of 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 expenses until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues and expenses based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.
Revenue Recognition	'
	Revenue Recognition
	The Partnership generally sells natural gas 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 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, NGL's, 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. The Partnership had unbilled revenues at June 30, 2014 and December 31, 2013 of $828,600 and $738,300, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.
Comprehensive Income (loss)	'
	Comprehensive Income (Loss)
	Comprehensive income (loss) includes net income (loss) and all other changes in equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States of America, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as "other comprehensive income (loss)" and, for the Partnership, include changes in the fair value of 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 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 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 using the full retrospective method 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.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2014
Schedule of Oil and Gas Properties	'
	The following is a summary of oil and gas properties at the dates indicated:
		June 30,			December 31,
		2014			2013
	Proved properties:
	Leasehold interests	$	4,179,600		$	4,179,600
	Wells and related equipment		183,397,200			183,397,500
	Total natural gas and oil properties		187,576,800			187,577,100
	Accumulated depletion and impairment		(174,606,600	)		(174,241,100	)
	Oil and gas properties, net	$	12,970,200		$	13,336,000

Asset_Retirement_Obligation_Ta

Asset Retirement Obligation (Tables)	6 Months Ended
	Jun. 30, 2014
Schedule of Asset Retirement Obligation	'
	A reconciliation of the Partnership’s liability for plugging and abandonment costs for the periods indicated is as follows:
		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2014			2013			2014			2013
	Asset retirement obligation at beginning of period	$	7,806,400		$	8,228,200		$	7,692,200		$	8,117,800
	Accretion expense		114,100			110,300			228,300			220,700
	Liabilities settled		(300	)		(21,600	)		(300	)		(21,600	)
	Asset retirement obligation at end of period	$	7,920,200		$	8,316,900		$	7,920,200		$	8,316,900

Derivative_Instruments_Tables

Derivative Instruments (Tables)	6 Months Ended
	Jun. 30, 2014
Commodity Derivatives Natural Gas Put Options	'
	At June 30, 2014, the Partnership had the following commodity derivatives:
	Natural Gas Put Options
	Production		Volumes				Average				Fair Value
	Period Ending						Fixed Price				Asset (2)
	December 31,
			(MMBtu) (1)				(per MMBtu) (1)
	2014			27,600			$	3.8			$	800
	2015			44,200				4				11,800
	2016			44,200				4.15				17,900
											$	30,500
	-1	“MMBtu” represents million British Thermal Units.
	-2	Fair value based on forward New York Mercantile Exchange (“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 the three and six months ended June 30, 2014 and 2013:
		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2014				2013				2014				2013
	(Loss) gain from cash flow hedges reclassified from accumulated other comprehensive income (loss) into natural gas and oil revenues	$		)		$	(5,600	)		$	38,300			$	17,200
			(5,200
Offsetting Assets	'
	The following table summarizes the gross and net fair values of the Partnership’s affiliate balances on the Partnership’s balance sheets for the periods indicated:
			Gross Amounts				Gross Amounts				Net Amount of
			of Recognized				Offset in the				Assets
			Assets				Balance Sheets				Presented in the
											Balance Sheets
	Offsetting Assets
	As of June 30, 2014
			$	41,300			$	(30,800	)		$	10,500
	Accounts receivable monetized gains-affiliate
	As of December 31, 2013
	Accounts receivable monetized gains-affiliate		$	88,100			$	(31,900	)		$	56,200
Offsetting Liabilities	'
			Gross Amounts				Gross Amounts				Net Amount of
			of Recognized				Offset in the				Liabilities
			Liabilities				Balance Sheets				Presented in the
											Balance Sheets
	Offsetting Liabilities
	As of June 30, 2014
			$	(30,800	)		$	30,800			$	-
	Put premiums payable-affiliate
	Long-term put premiums payable-affiliate			(48,800	)			-				(48,800	)
			$	(79,600	)		$	30,800			$	(48,800	)
	Total
	As of December 31, 2013
	Put premiums payable-affiliate		$	(31,900	)		$	31,900			$	-
	Long-term put premiums payable-affiliate			(63,600	)			-				(63,600	)
			$	(95,500	)		$	31,900			$	(63,600	)
	Total

Fair_Value_of_Financial_Instru1

Fair Value of Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2014
Schedule of Fair Value Derivative Instruments	'
	Information for assets and liabilities measured at fair value at June 30, 2014 and December 31, 2013 is as follows:
		Level 1		Level 2		Level 3		Total
	As of June 30, 2014
	Derivative assets, gross
	Commodity puts	$	-	$	30,500	$	-	$	30,500
	Derivative liabilities, gross
	Commodity puts	$	-	$	-	$	-	$	-
		$	-	$	30,500	$	-	$	30,500
	Total derivatives, fair value, net
		Level 1		Level 2		Level 3		Total
	As of December 31, 2013
	Derivative assets, gross
	Commodity puts	$	-	$	42,100	$	-	$	42,100
	Derivative liabilities, gross
	Commodity puts	$	-	$	-	$	-	$	-
		$	-	$	42,100	$	-	$	42,100
	Total derivatives, fair value, net

Certain_Relationships_and_Rela1

Certain Relationships and Related Party Transactions (Tables)	6 Months Ended
	Jun. 30, 2014
Costs Incurred From Related Party Transactions	'
	The following table provides information with respect to these costs and the periods incurred:
		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2014		2013		2014		2013
	Administrative	$	90,600	$	90,500	$	176,900	$	186,700
	Supervision		358,200		357,900		699,100		737,700
	Transportation		173,200		204,700		356,300		358,900
	Total	$	622,000	$	653,100	$	1,232,300	$	1,283,300

Description_of_Business_Detail

Description of Business (Details)	6 Months Ended
	Jun. 30, 2014
Description Of Business [Line Items]	'
Atlas America Public #15-2006 (B) L.P. Formation Date	9-May-06

Summary_of_Significant_Account3

Summary of Significant Accounting Policies (Narrative) (Details) (USD $)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013
Summary Of Significant Accounting Policies [Line Items]	'	'	'	'	'
Allowance for Uncollectible Accounts Receivable	$0	'	$0	'	$0
Depletion of Oil and Gas Properties	191,700	637,400	365,500	1,207,600	'
Reclassification from Oil and Gas Properties to Accumulated Depletion due to Asset Retirements	'	'	'	389,200	'
Asset Impairment Charges	0	0	0	0	0
Additional Working Interest	'	'	7.00%	'	'
Unbilled Revenues	$828,600	'	$828,600	'	$738,300

Summary_of_Significant_Account4

Summary of Significant Accounting Policies (Summary of Oil and Gas Properties) (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013
Property Plant And Equipment [Line Items]	'	'
Total natural gas and oil properties	$187,576,800	$187,577,100
Accumulated depletion and impairment	-174,606,600	-174,241,100
Oil and gas properties, net	12,970,200	13,336,000
Leasehold Interests	'	'
Property Plant And Equipment [Line Items]	'	'
Total natural gas and oil properties	4,179,600	4,179,600
Wells and related equipment	'	'
Property Plant And Equipment [Line Items]	'	'
Total natural gas and oil properties	$183,397,200	$183,397,500

Asset_Retirement_Obligation_Na

Asset Retirement Obligation (Narrative) (Details) (USD $)	6 Months Ended
	Jun. 30, 2014
Asset Retirement Obligations [Line Items]	'
Net production revenue for future plugging and abandonment costs	$47,500

Asset_Retirement_Obligation_Sc

Asset Retirement Obligation (Schedule of Asset Retirement Obligation) (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'	'	'	'
Asset retirement obligation at beginning of period	$7,806,400	$8,228,200	$7,692,200	$8,117,800
Accretion expense	114,100	110,300	228,300	220,700
Liabilities settled	-300	-21,600	-300	-21,600
Asset retirement obligation at end of period	$7,920,200	$8,316,900	$7,920,200	$8,316,900

Derivative_Instruments_Narrati

Derivative Instruments (Narrative) (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013
Derivative [Line Items]	'	'	'	'	'
Fair Value Asset/(Liability)	$30,500	'	$30,500	'	$42,100
Gain (Loss) On Fair Value Hedge Ineffectiveness Net	0	0	0	0	'
Affiliate Balances Offsetting Derivative Liabilities Gross Amounts Of Recognized Liabilities	79,600	'	79,600	'	95,500
Accumulated other comprehensive loss	-47,000	'	-47,000	'	-44,900
Accumulated other comprehensive (loss) income	'	'	'	'	'
Derivative [Line Items]	'	'	'	'	'
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	'	'	-22,800	'	'
Net Deferred Gain (Loss) To Be Reclassified Into Net Income In Later Periods	'	'	-24,200	'	'
Other Comprehensive Income (Loss)	'	'	'	'	'
Derivative [Line Items]	'	'	'	'	'
Unrealized gains (losses) due to natural gas and oil property impairments	'	'	39,200	'	'
Allocation To Limited Partner Only | Other Comprehensive Income (Loss)	'	'	'	'	'
Derivative [Line Items]	'	'	'	'	'
Net Derivative Gains (Losses) Limited Partner	'	'	9,200	'	'
Accounts receivable monetized gains-affiliate	'	'	'	'	'
Derivative [Line Items]	'	'	'	'	'
Affiliate Balances Offsetting Derivative Assets Gross Amounts Of Recognized Assets	41,300	'	41,300	'	88,100
Put premiums payable-affiliate	'	'	'	'	'
Derivative [Line Items]	'	'	'	'	'
Affiliate Balances Offsetting Derivative Liabilities Gross Amounts Of Recognized Liabilities	30,800	'	30,800	'	31,900
Long-term put premiums payable-affiliate	'	'	'	'	'
Derivative [Line Items]	'	'	'	'	'
Affiliate Balances Offsetting Derivative Liabilities Gross Amounts Of Recognized Liabilities	$48,800	'	$48,800	'	$63,600

Derivative_Instruments_Commodi

Derivative Instruments (Commodity Derivatives) (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2014		Jun. 30, 2014		Jun. 30, 2014		Jun. 30, 2014
			Natural Gas Put Options		Production Period Ending December 31, 2014		Production Period Ending December 31, 2015		Production Period Ending December 31, 2016
					Natural Gas Put Options		Natural Gas Put Options		Natural Gas Put Options
					MMBTU		MMBTU		MMBTU
Derivative [Line Items]	'	'	'		'		'		'
Volumes (MMBtu)	'	'	'		27,600	[1]	44,200	[1]	44,200	[1]
Average Fixed Price (per MMBtu)	'	'	'		3.8	[1]	4	[1]	4.15	[1]
Fair Value Asset	$30,500	$42,100	$30,500	[2]	$800	[2]	$11,800	[2]	$17,900	[2]
[1]	bMMBtub represents million British Thermal Units.
[2]	Fair value based on forward New York Mercantile Exchange (bNYMEXb) natural gas prices, as applicable.

Derivative_Instruments_Offsett

Derivative Instruments (Offsetting Assets) (Details) (Accounts receivable monetized gains-affiliate, USD $)	Jun. 30, 2014	Dec. 31, 2013
Accounts receivable monetized gains-affiliate	'	'
Derivative [Line Items]	'	'
Affiliate Balances Offsetting Derivative Assets Gross Amounts Of Recognized Assets	$41,300	$88,100
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset in the Balance Sheets	-30,800	-31,900
Affiliate Balances, Offsetting Derivative Assets, Net Amount of Assets Presented in the Balance Sheets	$10,500	$56,200

Derivative_Instruments_Offsett1

Derivative Instruments (Offsetting Liabilities) (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities	($79,600)	($95,500)
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets	30,800	31,900
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount of Liabilities Presented in the Balance Sheets	-48,800	-63,600
Put premiums payable-affiliate	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities	-30,800	-31,900
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets	30,800	31,900
Long-term put premiums payable-affiliate	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities	-48,800	-63,600
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount of Liabilities Presented in the Balance Sheets	($48,800)	($63,600)

Fair_Value_of_Financial_Instru2

Fair Value of Financial Instruments (Assets Measured at Fair Value on a Recurring Basis) (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative, Fair Value, Total	$30,500	$42,100
Fair Value, Inputs, Level 2	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative, Fair Value, Total	30,500	42,100
Commodity Puts	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative assets, gross	30,500	42,100
Derivative liabilities, gross	'	'
Commodity Puts | Fair Value, Inputs, Level 1	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative liabilities, gross	'	'
Commodity Puts | Fair Value, Inputs, Level 2	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative assets, gross	30,500	42,100
Derivative liabilities, gross	'	'
Commodity Puts | Fair Value, Inputs, Level 3	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative liabilities, gross	'	'

Fair_Value_of_Financial_Instru3

Fair Value of Financial Instruments (Narrative) (Details) (USD $)	Jun. 30, 2014	Jun. 30, 2013
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Additional assets that were measured at fair value on a nonrecurring basis	$0	$0
Additional liabilities that were measured at fair value on a nonrecurring basis	$0	$0

Certain_Relationships_and_Rela2

Certain Relationships and Related Party Transactions (Narrative) (Details) (USD $)	6 Months Ended
	Jun. 30, 2014
Administrative	'
Related Party Transaction [Line Items]	'
Monthly Administrative Costs Per Well	$75
Supervision	'
Related Party Transaction [Line Items]	'
Monthly Supervision Fees Per Well	$296
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) (USD $)	3 Months Ended		6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Related Party Transaction [Line Items]	'	'	'	'
Related Party Transaction, Expenses from Transactions with Related Party	$622,000	$653,100	$1,232,300	$1,283,300
Administrative	'	'	'	'
Related Party Transaction [Line Items]	'	'	'	'
Related Party Transaction, Expenses from Transactions with Related Party	90,600	90,500	176,900	186,700
Supervision	'	'	'	'
Related Party Transaction [Line Items]	'	'	'	'
Related Party Transaction, Expenses from Transactions with Related Party	358,200	357,900	699,100	737,700
Transportation	'	'	'	'
Related Party Transaction [Line Items]	'	'	'	'
Related Party Transaction, Expenses from Transactions with Related Party	$173,200	$204,700	$356,300	$358,900

Commitments_and_Contingencies_

Commitments and Contingencies (Narrative) (Details) (USD $)	6 Months Ended
	Jun. 30, 2014
Disclosure Commitments And Contingencies Details [Line Items]	'
Investor Partners Ownership Interest Presented For Purchase By The MGP, Maximum Percentage	5.00%
Operator Fee Per Well To Cover Estimated Future Plugging And Abandonment Costs, Monthly	$200
Net production revenue for future plugging and abandonment costs	$47,500