10-Q

United States

Securities and Exchange Commission

Washington, D.C. 20549

Form 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2013

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission file number 000-51944

ATLAS AMERICA PUBLIC #15-2005 (A) L.P.

(Name of small business issuer in its charter)

Delaware	20-3208344
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
Park Place Corporate Center One 1000 Commerce Drive, 4th Floor Pittsburgh, PA	15275
(Address of principal executive offices)	(zip code)

Issuer’s telephone number, including area code: (412)-489-0006

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No   ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” “non accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one):

Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	¨	Smaller reporting company	x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

ATLAS AMERICA PUBLIC 15-2005 (A) L.P.

(A Delaware Limited Partnership)

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

		PAGE
PART I.	FINANCIAL INFORMATION
Item 1:	Financial Statements (Unaudited)
	Balance Sheets as of March 31, 2013 and December 31, 2012		3
	Statements of Operations for the Three Months ended March 31, 2013 and 2012		4
	Statements of Comprehensive Loss for the Three Months ended March 31, 2013 and 2012		5
	Statement of Changes in Partners’ Capital for the Three Months ended March 31, 2013		6
	Statements of Cash Flows for the Three Months ended March 31, 2013 and 2012		7
	Notes to Financial Statements		8
Item 2:	Management’s Discussion and Analysis of Financial Condition and Results of Operations		17
Item 4:	Controls and Procedures		19
PART II.	OTHER INFORMATION
Item 1:	Legal Proceedings		20
Item 6:	Exhibits		20
SIGNATURES			21
CERTIFICATIONS			22

2

ATLAS AMERICA PUBLIC #15-2005 (A) L.P.

BALANCE SHEETS

(Unaudited)

	March 31,			December 31,
	2013			2012
ASSETS
Current assets:
Cash and cash equivalents	$	36,000		$	15,200
Accounts receivable trade–affiliate		297,900			256,500
Accounts receivable monetized gains-affiliate		51,900			69,500
Current portion of derivative assets		900			3,200
Total current assets		386,700			344,400
Oil and gas properties, net		3,587,000			3,702,900
Long-term derivative assets		10,400			13,000
	$	3,984,100		$	4,060,300
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	4,300		$	1,700
Total current liabilities		4,300			1,700
Long-term put premiums payable-affiliate		5,200			3,000
Asset retirement obligation		3,012,700			2,972,300
Commitments and contingencies		—			—
Partners’ capital:
Managing general partner’s interest		927,700			948,800
Limited partners’ interest (5,227.40 units)		54,000			151,500
Accumulated other comprehensive loss		(19,800	)		(17,000	)
Total partners’ capital		961,900			1,083,300
	$	3,984,100		$	4,060,300

See accompanying notes to financial statements.

3

ATLAS AMERICA PUBLIC #15-2005 (A) L.P.

STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended
	March 31,
	2013			2012
REVENUES
Natural gas and oil	$	397,300		$	358,500
Total revenues		397,300			358,500
COSTS AND EXPENSES
Production		251,100			254,900
Depletion		115,900			101,100
Accretion of asset retirement obligation		40,400			37,100
General and administrative		52,100			55,900
Total expenses		459,500			449,000
Net loss	$	(62,200	)	$	(90,500	)
Allocation of net loss:
Managing general partner	$	(20,600	)	$	(24,200	)
Limited partners	$	(41,600	)	$	(66,300	)
Net loss per limited partnership unit	$	(8	)	$	(13	)

See accompanying notes to financial statements.

4

ATLAS AMERICA PUBLIC #15-2005 (A) L.P.

STATEMENTS OF COMPREHENSIVE LOSS

(Unaudited)

	Three Months Ended
	March 31,
	2013			2012
Net loss	$	(62,200	)	$	(90,500	)
Other comprehensive loss:
Unrealized holding loss on cash flow hedging contracts		(11,400	)		—
Difference in estimated hedge gains receivable		24,600			51,900
Less: reclassification adjustment for gains realized in net loss from cash flow hedges		(16,000	)		(54,600	)
Total other comprehensive loss		(2,800	)		(2,700	)
Comprehensive loss	$	(65,000	)	$	(93,200	)

See accompanying notes to financial statements.

5

ATLAS AMERICA PUBLIC #15-2005 (A) L.P.

STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

FOR THE THREE MONTHS ENDED

March 31, 2013

(Unaudited)

	Managing General Partner			Limited Partners			Accumulated Other Comprehensive Loss (Cash Flow Hedges)			Total
Balance at December 31, 2012	$	948,800		$	151,500		$	(17,000	)	$	1,083,300
Participation in revenues and expenses:
Net production revenues		46,400			99,800			—			146,200
Depletion		(36,100	)		(79,800	)		—			(115,900	)
Accretion of asset retirement obligation		(13,500	)		(26,900	)		—			(40,400	)
General and administrative		(17,400	)		(34,700	)		—			(52,100	)
Net loss		(20,600	)		(41,600	)		—			(62,200	)
Other comprehensive loss		—			—			(2,800	)		(2,800	)
Distributions to partners		(500	)		(55,900	)		—			(56,400	)
Balance at March 31, 2013	$	927,700		$	54,000		$	(19,800	)	$	961,900

See accompanying notes to financial statements.

6

ATLAS AMERICA PUBLIC #15-2005 (A) L.P.

STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended
	March 31,
	2013			2012
Cash flows from operating activities:
Net loss	$	(62,200	)	$	(90,500	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion		115,900			101,100
Non cash loss on derivative value		21,900			41,400
Accretion of asset retirement obligation		40,400			37,100
(Increase) decrease in accounts receivable-affiliate		(41,400	)		120,600
Increase in accrued liabilities		2,600			14,600
Net cash provided by operating activities		77,200			224,300
Cash flows from financing activities:
Distributions to partners		(56,400	)		(236,200	)
Net cash used in financing activities		(56,400	)		(236,200	)
Net increase (decrease) in cash and cash equivalents		20,800			(11,900	)
Cash and cash equivalents at beginning of period		15,200			80,500
Cash and cash equivalents at end of period	$	36,000		$	68,600

See accompanying notes to financial statements.

7

ATLAS AMERICA PUBLIC #15-2005 (A) L.P.

NOTES TO FINANCIAL STATEMENTS

March 31, 2013

(Unaudited)

NOTE 1—DESCRIPTION OF BUSINESS

Atlas America Public #15-2005 (A) L.P. (the “Partnership”) is a Delaware limited partnership, formed on July 25, 2005 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. (“Atlas Energy”) (NYSE: ATLS), a then-majority owned subsidiary of Atlas Energy, Inc. and parent of the general partner of Atlas Pipeline Partners, L.P. (“APL”) (NYSE: APL), completed an acquisition of assets from Atlas Energy, Inc., which included its investment partnership business, its oil and gas exploration, development and production activities conducted in Tennessee, Indiana, and Colorado, certain shallow wells and leases in New York and Ohio, certain well interests in Pennsylvania and Michigan and its ownership and management of investments in Lightfoot Capital Partners, L.P. and related entities (the “Transferred Business”).

The Partnership has drilled and currently operates wells located in Pennsylvania and Tennessee. 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 financial statements, which are unaudited, except that the balance sheet at December 31, 2012 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, 2012. The results of operations for the three months ended March 31, 2013 may not necessarily be indicative of the results of operations for the year ended December 31, 2013.

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, 2012 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.

8

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 months ended March 31, 2013 and 2012 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 March 31, 2013 and December 31, 2012, 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 $115,900 and $101,100 for the three months ended March 31, 2013 and 2012, 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.

The following is a summary of oil and gas properties at the dates indicated:

	March 31,			December 31,
	2013			2012
Proved properties:
Leasehold interests	$	1,526,600		$	1,526,600
Wells and related equipment		65,092,200			65,092,200
Total natural gas and oil properties		66,618,800			66,618,800
Accumulated depletion and impairment		(63,031,800	)		(62,915,900	)
Oil and gas properties, net	$	3,587,000		$	3,702,900

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.

9

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 months ended March 31, 2013 and 2012. During the year ended December 31, 2012, the Partnership recognized an impairment charge of $162,600.

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 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 March 31, 2013 and December 31, 2012 of $224,100 and $219,600, 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 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 loss. These changes, other than net loss, are referred to as “other comprehensive loss” and, for the Partnership, include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges.

10

Recently Adopted Accounting Standards

In February 2013, the FASB issued ASU No. 2013-02, Comprehensive Income (Topic 220) (“Update 2013-02”). Update 2013-02 requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present significant amounts reclassified out of accumulated other comprehensive income if the amount reclassified to net income in its entirety is in the same reporting period as incurred. For other amounts that are not required to be reclassified in their entirety to net income, an entity is required to reference to other disclosures that provide additional detail about those amounts. Entities are required to implement the amendments prospectively for reporting periods beginning after December 15, 2012, with early adoption being permitted. The Partnership adopted the requirements of Update 2013-02 upon its effective date of January 1, 2013, and it had no material impact on its financial position, results of operations or related disclosures as other comprehensive income (loss) of the Partnership includes only cash flow hedges (see Note 4).

Recently Issued Accounting Standards

In February 2013, the FASB issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement, and disclosure, of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership will apply the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

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.

A reconciliation of the Partnership’s liability for plugging and abandonment costs for the periods indicated is as follows:

	Three Months Ended
	March 31,
	2013		2012
Asset retirement obligation at beginning of period	$	2,972,300	$	2,911,300
Accretion expense		40,400		37,100
Asset retirement obligation at end of period	$	3,012,700	$	2,948,400

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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 sheet of $11,300 at March 31, 2013.

At March 31, 2013, the Partnership had the following commodity derivatives:

Natural Gas Put Options

Production Period Ending December 31,	Volumes		Average Strike		Fair Value Asset  (2)
	(mmbtu) (1)		(per mmbtu) (1)
2013		9,500	$	3.450	$	400
2014		10,500		3.800		2,800
2015		8,400		4.000		3,500
2016		8,400		4.150		4,600
					$	11,300

(1) “Mmbtu” represents million British Thermal Units.

(2) Fair value based on forward New York Mercantile Exchange (“NYMEX”) natural gas prices, as applicable.

12

The following table summarizes the gain or loss recognized in the statements of operations for the three months ended March 31, 2013 and 2012:

Effects of Derivative Instruments on statements of operations:

	Three Months Ended
	March 31,
	2013			2012
Loss from cash flow hedges recognized in accumulated other comprehensive income	$	(11,400	)	$	—
Gains from cash flow hedges reclassified from accumulated other comprehensive income into natural gas and oil revenues	$	16,000		$	54,600

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.

The Partnership recognized gains of $16,000 and $54,600 for the three months ended March 31, 2013 and 2012, respectively, on settled contracts covering commodity production. These gains were included within gas and oil production revenue in the Partnership’s statements of operations. As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three months ended March 31, 2013 and 2012 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

Monetized Gains

Prior to February 17, 2011 (date of the Transferred Business), 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 March 31, 2013 and December 31, 2012, remaining hedge monetization cash proceeds of $57,900 and $75,500 related to the amounts hedged on behalf of the Partnerships’ limited partners were included within accounts receivable monetized gains-affiliate, respectively, and $11,400 and $15,100 in long-term put premiums payable-affiliate, respectively, on the Partnership’s balance sheets. The Partnership will allocate the monetized net proceeds to the limited partners based on the natural gas and oil production generated over the period of the original derivative contracts.

During June 2012, the MGP used the undistributed monetized funds to purchase natural gas put options on behalf of the limited partners of the Partnership only. A premium (“put premium”) was paid to purchase the contracts and will be allocated to natural gas production revenues generated over the contractual term of the purchased hedging instruments. At March 31, 2013 and December 31, 2012, the put premiums recorded as short-term payables to affiliate were $6,000 and long-term payables to affiliate of $16,600 and $18,100, respectively. Furthermore, the current portion of the put premium liabilities was included in accounts receivable monetized gains-affiliate and the long-term receivable monetized gains-affiliate were included in long term put premiums payable-affiliate in the Partnership’s balance sheets, presenting the impact of offsetting the related party assets and liabilities. The put premiums included on the Partnership’s balance sheets are allocable to the limited partners only.

13

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 of Recognized Assets			Gross Amounts Offset in the Balance Sheets			Net Amount of Assets Presented in the Balance Sheets
Offsetting Assets
As of March 31, 2013
Accounts receivable monetized gains-affiliate	$	57,900		$	(6,000	)	$	51,900
Long-term accounts receivable monetized gains-affiliate		11,400			(11,400	)		—
Total	$	69,300		$	(17,400	)	$	51,900
As of December 31, 2012
Accounts receivable monetized gains-affiliate	$	75,500		$	(6,000	)	$	69,500
Long-term accounts receivable monetized gains-affiliate		15,100			(15,100	)		—
Total	$	90,600		$	(21,100	)	$	69,500
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheets			Net Amount of Liabilities Presented in the Balance Sheets
Offsetting Liabilities
As of March 31, 2013
Put premiums payable-affiliate	$	(6,000	)	$	6,000		$	—
Long-term put premiums payable-affiliate		(16,600	)		11,400			(5,200	)
Total	$	(22,600	)	$	17,400		$	(5,200	)
As of December 31, 2012
Put premiums payable-affiliate	$	(6,000	)	$	6,000		$	—
Long-term put premiums payable-affiliate		(18,100	)		15,100			(3,000	)
Total	$	(24,100	)	$	21,100		$	(3,000	)

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 gains recognized in earnings in prior periods due to natural gas and oil property impairments, the Partnership recorded a net deferred loss on its balance sheets in accumulated other comprehensive loss of $19,800 as of March 31, 2013. Included in other comprehensive income are unrealized gains of $77,800, 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, $7,700 of net gains were recorded by the Partnership and allocated only to the limited partners. Of the remaining $19,800 of net unrealized loss in accumulated other comprehensive loss, the Partnership will reclassify $12,300 of net losses to the Partnership’s statements of operations over the next twelve month period and the remaining losses of $7,500 in later periods.

14

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 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 March 31, 2013 and December 31, 2012 was as follows:

	Level 1		Level 2		Level 3		Total
As of March 31, 2013
Derivative assets, gross
Commodity puts	$	—	$	11,300	$	—	$	11,300
Derivative liabilities, gross
Commodity puts	$	—	$	—	$	—	$	—
Total derivatives, fair value, net	$	—	$	11,300	$	—	$	11,300
	Level 1		Level 2		Level 3		Total
As of December 31, 2012
Derivative assets, gross
Commodity puts	$	—	$	16,200	$	—	$	16,200
Derivative liabilities, gross
Commodity puts	$	—	$	—	$	—	$	—
Total derivatives, fair value, net	$	—	$	16,200	$	—	$	16,200

15

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

The Partnership estimates the fair value of 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 months ended March 31, 2013 and 2012.

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. Administrative costs incurred for the three months ended March 31, 2013 and 2012 were $33,400 and $34,600, respectively.

• Monthly well supervision fees, which are included in production expenses in the Partnership’s statements of operations, are payable at $296 per well per month for operating and maintaining the wells. Well supervision fees incurred for the three months ended March 31, 2013 and 2012 were $132,100 and $136,600, respectively.

• 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. Transportation fees incurred for the three months ended March 31, 2013 and 2012 were $49,800 and $50,100, respectively.

• The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP.

Subordination by Managing General Partner

Under the terms of the Partnership Agreement, the MGP may be required to subordinate up to 50% of its share of net production revenues so that the limited partners receive a return of at least 10% of their net subscriptions, determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution to the limited partners (August 2006) and expiring 60 months from that date.

NOTE 7—COMMITMENTS AND CONTINGENCIES

General Commitments

Subject to certain conditions, investor partners may present their interests beginning in 2010 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 March 31, 2013, the MGP has not withheld any such funds.

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.

16

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (UNAUDITED)

Forward-Looking Statements

When used in this Form 10-Q, the words “believes”, “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements. These risks and uncertainties could cause actual results to differ materially from the results stated or implied in this document. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.

This Management’s Discussion and Analysis should be read in conjunction with our Financial Statements and the Notes to our Financial Statements.

General

Atlas America Public #15-2005 (A) L.P. (“we”, “us” or the “Partnership”) is a Delaware limited partnership, formed on July 25, 2005 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).

We have drilled and currently operate wells located in Pennsylvania and Tennessee. We have no employees and rely on our MGP for management, which in turn, relies on its parent company, Atlas Energy L.P. (“Atlas Energy”), for administrative services.

Our operating cash flows are generated from our wells, which produce natural gas and oil. Our produced natural gas and oil is then delivered to market through third-party gas gathering systems. We do not plan to sell any of our wells and intend to produce them until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. We expect that no other wells will be drilled and no additional funds will be required for drilling.

Overview

The following discussion provides information to assist in understanding our financial condition and results of operations. Our operating cash flows are generated from our wells, which produce primarily natural gas, but also some oil. Our produced natural gas and oil is then delivered to market through affiliated or third-party gas gathering systems. Our ongoing operating and maintenance costs have been and are expected to be fulfilled through revenues from the sale of our natural gas and oil production. We pay our MGP, as operator, a monthly well supervision fee, which covers all normal and regularly recurring operating expenses for the production and sale of natural gas and oil such as:

• well tending, routine maintenance and adjustment;

• reading meters, recording production, pumping, maintaining appropriate books and records; and

• preparation of reports for us and government agencies.

The well supervision fees, however, do not include costs and expenses related to the purchase of certain equipment, materials, and brine disposal. If these expenses are incurred, we pay cost for third-party services, materials, and a competitive charge for services performed directly by our MGP or its affiliates. Also, beginning one year after each of our wells has been placed into production, our MGP, as operator, may retain $200 per month, per well to cover the estimated future plugging and abandonment costs of the well. As of March 31, 2013, our MGP had not withheld any funds for this purpose.

Markets and Competition

The availability of a ready market for natural gas and oil produced by us, and the price obtained, depends on numerous factors beyond our control, including the extent of domestic production, imports of foreign natural gas and oil, political instability or terrorist acts in oil and gas producing countries and regions, market demand, competition from other energy sources, the effect of federal regulation on the sale of natural gas and oil in interstate commerce, other governmental regulation of the production and transportation of natural gas and oil and the proximity, availability and capacity of pipelines and other required facilities. Our MGP is responsible for selling our production. During 2013 and 2012, we experienced no problems in selling our natural gas and oil. Product availability and price are the principal means of competition in selling natural gas and oil production. While it is impossible to accurately determine our comparative position in the industry, we do not consider our operations to be a significant factor in the industry.

17

Results of Operations

The following table sets forth information relating to our production revenues, volumes, sales prices, production costs and depletion during the periods indicated:

	Three Months Ended
	March 31,
	2013			2012
Production revenues (in thousands):
Gas	$	354		$	339
Oil		43			19
Total	$	397		$	358
Production volumes:
Gas (mcf/day) (1)		1,071			1,126
Oil (bbl/day) (1)		6			2
Total (mcfe/day) (1)		1,107			1,138
Average sales prices: (2)
Gas (per mcf) (1) (3)	$	3.91		$	3.72
Oil (per bbl) (1)	$	86.14		$	92.17
Production costs:
As a percent of revenues		63	%		71	%
Per mcfe (1)	$	2.53		$	2.46
Depletion per mcfe	$	1.17		$	.97

(1) “Mcf” represents thousand cubic feet, “mcfe” represents thousand cubic feet equivalent, and “bbl” represents barrels. Bbl is converted to mcfe using the ratio of six mcfs to one bbl.

(2) Average sales prices represent accrual basis pricing after adjusting for the effect of previously recognized gains resulting from prior period impairment charges.

(3) Average gas prices are calculated by including in total revenue derivative gains previously recognized into income in connection with prior period impairment charges and dividing by the total volume for the period. Previously recognized derivative gains were $22,600 and $41,600 for the three months ended March 31, 2013 and 2012, respectively.

Natural Gas Revenues. Our natural gas revenues were $354,500 and $339,200 for the three months ended March 31, 2013 and 2012, respectively, an increase of $15,300 (5%). The $15,300 increase in natural gas revenues for the three months ended March 31, 2013 as compared to the prior year similar period was attributable to a $35,400 increase in our natural gas sales prices after the effect of financial hedges, which was driven by market conditions, partially offset by a $20,100 decrease in production volumes. Our production volumes decreased to 1,071 mcf per day for the three months ended March 31, 2013 from 1,126 mcf per day for the three months ended March 31, 2012, a decrease of 55 mcf per day (5%).

Oil Revenues. We drill wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $42,800 and $19,300 for the three months ended March 31, 2013 and 2012, respectively, an increase of $23,500 (122%). The $23,500 increase in oil revenues for the three months ended March 31, 2013 as compared to the prior year similar period was attributable to a $26,500 increase in production volumes, partially offset by a $3,000 decrease in oil prices after the effect of financial hedges. Our production volumes increased to 6 bbls per day for the three months ended March 31, 2013 from 2 bbls per day for the three months ended March 31, 2012, an increase of 4 bbls per day (200%).

Costs and Expenses. Production expenses were $251,100 and $254,900 for the three months ended March 31, 2013 and 2012, respectively, a decrease of $3,800 (1%). This decrease was mostly due to a decrease in monthly supervision fees due to wells being temporarily shut-in for repairs and maintenance.

Depletion of oil and gas properties as a percentage of oil and gas revenues was 29% and 28% for the three months ended March 31, 2013 and 2012, respectively. These percentage changes are directly attributable to changes in revenues, oil and gas reserve quantities, product prices and production volumes and changes in the depletable cost basis of oil and gas properties.

18

General and administrative expenses for the three months ended March 31, 2013 and 2012 were $52,100 and $55,900, respectively, a decrease of $3,800 (7%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP. The decrease for the three months ended March 31, 2013 is primarily due to a decrease in third-party costs as compared to the prior year similar period.

Liquidity and Capital Resources

Cash provided by operating activities decreased $147,100 in the three months ended March 31, 2013 to $77,200 as compared to $224,300 for the three months ended March 31, 2012. This decrease was due to a decrease in the change in accounts receivable trade-affiliate of $162,000, a decrease in net non-cash loss on hedge instruments of $19,500 and the change in accrued liabilities which decreased operating cash flows by $12,000. In addition, net loss before depletion and accretion increased operating cash flows by $46,400 for the three months ended March 31, 2013 compared to the three months ended March 31, 2012.

Cash used in financing activities decreased $179,800 during the three months ended March 31, 2013 to $56,400 from $236,200 for the three months ended March 31, 2012. This decrease was due to a decrease in cash distributions to partners.

Our MGP may withhold funds for future plugging and abandonment costs. Any additional funds, if required, will be obtained from production revenues or borrowings from our MGP or its affiliates, which are not contractually committed to make loans to us. The amount that we may borrow may not at any time exceed 5% of our total subscriptions and we will not borrow from third-parties.

The Partnership is generally limited to the amount of funds generated by the cash flows from our operations, which we believe is adequate to fund future operations and distributions to our partners. Historically, there has been no need to borrow funds from our MGP to fund operations.

Subordination by Managing General Partner

Under the terms of the Partnership Agreement, the MGP may be required to subordinate up to 50% of its share of net production revenues so that the limited partners receive a return of at least 10% of their net subscriptions, determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution to the limited partners (August 2006) and expiring 60 months from that date.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. On an on-going basis, we evaluate our estimates, including those related to our asset retirement obligations, depletion and certain accrued receivables and liabilities. We base our estimates on historical experience and on various other assumptions that we believe reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. A discussion of significant accounting policies we have adopted and followed in the preparation of our financial statements is included within “Notes to Financial Statements” in Part I, Item 1, “Financial Statements” in this quarterly report and in our Annual Report on Form 10-K for the year ended December 31, 2012.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

19

Under the supervision of our Chairman of the Board of Directors, Chief Executive Officer, President, and Chief Financial Officer, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, concluded that, at March 31, 2013, our disclosure controls and procedures were effective at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There have been no changes in the Partnership’s internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The MGP is not aware of any legal proceedings filed against the Partnership.

Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of their collective business. 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.

ITEM 6. EXHIBITS

EXHIBIT INDEX

Exhibit No.	Description
4.0	Amended and Restated Certificate and Agreement of Limited Partnership for Public #15-2005 (A) L.P. (1)
31.1	Certification Pursuant to Rule 13a-14/15(d)-14
31.2	Certification Pursuant to Rule 13a-14/15(d)-14
32.1	Section 1350 Certification
32.2	Section 1350 Certification
101	Interactive Data File

(1) Filed on August 9, 2005 in the Form S-1A Registration Statement dated August 9, 2005, File No. 000-51944

20

SIGNATURES

Pursuant to the requirements of the Securities of the Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Atlas America Public #15-2005 (A) L.P.

	ATLAS RESOURCES, LLC, Managing General Partner
Date: May 14, 2013	By:	/s/ FREDDIE M. KOTEK
		Freddie M. Kotek, Chairman of the Board of Directors, Chief Executive Officer and President

In accordance with the Exchange Act, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date: May 14, 2013	By:	/s/ SEAN P. MCGRATH
		Sean P. McGrath, Chief Financial Officer

21

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Freddie M. Kotek, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended March 31, 2013 of Atlas America Public #15-2005 (A) L.P.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have;

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within the entity, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

By:	/s/ FREDDIE M. KOTEK
Name:	Freddie M. Kotek
Title:	Chief Executive Officer of the Managing General Partner
Date:	May 14, 2013

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Sean P. McGrath, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended March 31, 2013 of Atlas America Public #15-2005 (A) L.P.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have;

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within the entity, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) valuated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

By:	/s/ SEAN P. MCGRATH
Name:	Sean P. McGrath
Title:	Chief Financial Officer of the Managing General Partner
Date:	May 14, 2013

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Atlas America Public #15-2005 (A) L.P. (the “Partnership”) on Form 10-Q for the period ended March 31, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Freddie M. Kotek, Chief Executive Officer of the Managing General Partner, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

By:	/s/ FREDDIE M. KOTEK
Name:	Freddie M. Kotek
Title:	Chief Executive Officer of the Managing General Partner
Date:	May 14, 2013

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Atlas America Public #15-2005 (A) L.P. (the “Partnership”) on Form 10-Q for the period ended March 31, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Sean P. McGrath, Chief Financial Officer of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

By:	/s/ SEAN P. MCGRATH
Name:	Sean P. McGrath
Title:	Chief Financial Officer of the Managing General Partner
Date:	May 14, 2013

XML

Derivative Instruments (Narrative) (Details) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012
Derivative [Line Items]
Fair Value Asset/(Liability)	$ 11,300		$ 16,200
Gain Recognized On Settled Commodity Contracts	16,000	54,600
Gain (Loss) on Fair Value Hedge Ineffectiveness, Net	7,700
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Of Recognized Assets	69,300		90,600
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	22,600		24,100
Accumulated Other Comprehensive Loss, Net of Tax	(19,800)		(17,000)
Accumulated Other Comprehensive Income (Loss), Prior Periods, Net Of Tax	19,800
Net Deferred Gain To Be Reclassified Into Net Income Over The Next Twelve Months	12,300
Net Deferred Loss To Be Reclassified Into Net Income In Later Periods	7,500
Net Deferred Loss [Member] | Net Amount of Cash Received for Monetized Gains and Reversal of Prior Period Gains Recognized [Member]
Derivative [Line Items]
Accumulated Other Comprehensive Loss, Net of Tax	(19,800)
Unrealized Gain [Member]
Derivative [Line Items]
Accumulated Other Comprehensive Loss, Net of Tax		(77,800)
Accounts Receivable Monetized Gains Affiliate [Member]
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Of Recognized Assets	57,900	75,500	75,500
Long Term Accounts Receivable Monetized [Member]
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Of Recognized Assets	11,400	15,100	(15,100)
Put Premiums Payable Affiliate [Member]
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	6,000		6,000
Long Term Put Premiums Payable Affiliate [Member]
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	$ 16,600		$ 18,100

XML

Summary Of Significant Accounting Policies

3 Months Ended

Mar. 31, 2013

Summary of Significant Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

In management's opinion, all adjustments necessary for a fair presentation of the Partnership's financial position, results of operations and cash flows for the periods disclosed have been made. Management has considered for disclosure any material subsequent events through the date the financial statements were issued.

In addition to matters discussed further in this note, the Partnership's significant accounting policies are detailed in its audited financial statements and notes thereto in the Partnership's annual report on Form 10-K for the year ended December 31, 2012 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 months ended March 31, 2013 and 2012 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 March 31, 2013 and December 31, 2012, 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 $115,900 and $101,100 for the three months ended March 31, 2013 and 2012, 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.

The following is a summary of oil and gas properties at the dates indicated:

	March 31,	December 31,
	2013	2012
Proved properties:
Leasehold interests	$        1,526,600	$          1,526,600
Wells and related equipment	65,092,200	65,092,200
Total natural gas and oil properties	66,618,800	66,618,800
Accumulated depletion and impairment	(63,031,800)	(62,915,900)
Oil and gas properties, net	$         3,587,000	$          3,702,900

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 months ended March 31, 2013 and 2012. During the year ended December 31, 2012, the Partnership recognized an impairment charge of $162,600.

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 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 March 31, 2013 and December 31, 2012 of $224,100 and $219,600, 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 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 loss. These changes, other than net loss, are referred to as "other comprehensive 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 No. 2013-02, Comprehensive Income (Topic 220) ("Update 2013-02"). Update 2013-02 requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present significant amounts reclassified out of accumulated other comprehensive income if the amount reclassified to net income in its entirety is in the same reporting period as incurred. For other amounts that are not required to be reclassified in their entirety to net income, an entity is required to reference to other disclosures that provide additional detail about those amounts. Entities are required to implement the amendments prospectively for reporting periods beginning after December 15, 2012, with early adoption being permitted. The Partnership adopted the requirements of Update 2013-02 upon its effective date of January 1, 2013, and it had no material impact on its financial position, results of operations or related disclosures as other comprehensive income (loss) of the Partnership includes only cash flow hedges (see Note 4).

Recently Issued Accounting Standards

In February 2013, the FASB issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date ("Update 2013-04"). Update 2013-04 provides guidance for the recognition, measurement, and disclosure, of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership will apply the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

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Fair Value of Financial Instruments (Assets Measured at Fair Value on a Non-Recurring Basis) (Details) (USD $)	Mar. 31, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Total	$ 11,300	$ 16,200
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Total	11,300	16,200
Commodity Puts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Asset	11,300	16,200
Commodity Puts [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Asset	$ 11,300	$ 16,200

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Derivative Instruments (Gross Fair Values of Receivable and Payable Affiliate Balances) (Details) (USD $)	Mar. 31, 2013	Dec. 31, 2012	Mar. 31, 2012
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Of Recognized Assets	$ 69,300	$ 90,600
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset In The Balance Sheets	(17,400)	(21,100)
Affiliate Balances, Offsetting Derivative Assets, Net Amount Of Assets Presented In The Balance Sheets	51,900	69,500
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	(22,600)	(24,100)
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset In The Balance Sheets	17,400	21,100
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount Of Liabilities Presented In The Balance Sheets	(5,200)	(3,000)
Accounts Receivable Monetized Gains Affiliate [Member]
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Of Recognized Assets	57,900	75,500	75,500
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset In The Balance Sheets	(6,000)	(6,000)
Affiliate Balances, Offsetting Derivative Assets, Net Amount Of Assets Presented In The Balance Sheets	51,900	69,500
Long Term Accounts Receivable Monetized [Member]
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Of Recognized Assets	11,400	(15,100)	15,100
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset In The Balance Sheets	(11,400)	(15,100)
Put Premiums Payable Affiliate [Member]
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	(6,000)	(6,000)
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset In The Balance Sheets	6,000	6,000
Long Term Put Premiums Payable Affiliate [Member]
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	(16,600)	(18,100)
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset In The Balance Sheets	11,400	15,100
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount Of Liabilities Presented In The Balance Sheets	$ (5,200)	$ (3,000)

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Certain Relationships and Related Party Transactions (Details) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Related Party Transaction [Line Items]
Monthly Administrative Costs Per Well	$ 75
Administrative Costs Included in General and Administrative Expenses	33,400	34,600
Monthly Supervision Fees Per Well	296
Subordination, Expiration From The First Distribution To The Limited Partners	60 years
Date Of First Distribution To Limited Partners	Aug. 01, 2006
Well Supervision Fees Included In Production Expenses [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	132,100	136,600
Transportation Fees Inclcuded In Production Expenses [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	49,800
Direct Costs Included in General And Administrative Expense [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party		$ 50,100
Managing General Partner [Member]
Related Party Transaction [Line Items]
Managing General Partner Maximum Subordination Percentage Of Share Of Net Production Revenues	50.00%
Limited Partners [Member]
Related Party Transaction [Line Items]
Subordination Target Return Rate For Limited Partner Subscriptions	10.00%

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Commitments and Contingencies (Details) (USD $)	3 Months Ended
	Mar. 31, 2013
Commitments and Contingencies [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
Operator Fee To Cover Estimated Future Plugging And Abandonment Costs	$ 0

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Description of Business

3 Months Ended

Mar. 31, 2013

Description of Business [Abstract]

DESCRIPTION OF BUSINESS

NOTE 1 - DESCRIPTION OF BUSINESS

Atlas America Public #15-2005 (A) L.P. (the "Partnership") is a Delaware limited partnership, formed on July 25, 2005 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. ("Atlas Energy") (NYSE: ATLS), a then-majority owned subsidiary of Atlas Energy, Inc. and parent of the general partner of Atlas Pipeline Partners, L.P. ("APL") (NYSE: APL), completed an acquisition of assets from Atlas Energy, Inc., which included its investment partnership business, its oil and gas exploration, development and production activities conducted in Tennessee, Indiana, and Colorado, certain shallow wells and leases in New York and Ohio, certain well interests in Pennsylvania and Michigan and its ownership and management of investments in Lightfoot Capital Partners, L.P. and related entities (the "Transferred Business").

The Partnership has drilled and currently operates wells located in Pennsylvania and Tennessee. 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 financial statements, which are unaudited, except that the balance sheet at December 31, 2012 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, 2012. The results of operations for the three months ended March 31, 2013 may not necessarily be indicative of the results of operations for the year ended December 31, 2013.

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Balance Sheets (USD $)	Mar. 31, 2013	Dec. 31, 2012
ASSETS
Cash and cash equivalents	$ 36,000	$ 15,200
Accounts receivable trade-affiliate	297,900	256,500
Accounts receivable monetized gains-affiliate	51,900	69,500
Current portion of derivative assets	900	3,200
Total current assets	386,700	344,400
Oil and gas properties, net	3,587,000	3,702,900
Long-term derivative asset	10,400	13,000
TOTAL ASSETS	3,984,100	4,060,300
LIABILITIES AND PARTNERS' CAPITAL
Accrued liabilities	4,300	1,700
Total current liabilities	4,300	1,700
Long term put premiums payable-affiliate	5,200	3,000
Asset retirement obligations	3,012,700	2,972,300
Commitments and Contingencies
Partners' capital:
Managing general partner's interest	927,700	948,800
Limited partners' interest (5,227.40 units)	54,000	151,500
Accumulated other comprehensive loss	(19,800)	(17,000)
Total partners' capital	961,900	1,083,300
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$ 3,984,100	$ 4,060,300

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Statement Of Changes In Partners' Capital (USD $)	Managing General Partner [Member]	Limited Partners [Member]	Accumulated Other Comprehensive (Loss) Income [Member]	Total
Balance at Dec. 31, 2012	$ 948,800	$ 151,500	$ (17,000)	$ 1,083,300
Participation in revenue and expenses:
Net production revenues	46,400	99,800	0	146,200
Depletion	(36,100)	(79,800)	0	(115,900)
Accretion of asset retirement obligation	(13,500)	(26,900)	0	(40,400)
General and administrative	(17,400)	(34,700)	0	(52,100)
Net loss	(20,600)	(41,600)	0	(62,200)
Other comprehensive loss	0	0	(2,800)	(2,800)
Distributions to partners	(500)	(55,900)	0	(56,400)
Balance at Mar. 31, 2013	$ 927,700	$ 54,000	$ (19,800)	$ 961,900

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Summary of Significant Accounting Policies (Narrative) (Details) (USD $)	3 Months Ended				12 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2012 Oil and Gas Properties [Member]
Allowance for Uncollectible Accounts Receivable	$ 0			$ 0
Depletion of Oil and Gas Properties	115,900	101,100
Asset Impairment Charges					162,600
Unbilled Revenues	$ 224,100		$ 219,600
Additional working interest	7.00%

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Asset Retirement Obligation (Details) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Asset Retirement Obligation [Abstract]
Asset retirement obligation at beginning of period	$ 2,972,300	$ 2,911,300
Accretion expense	40,400	37,100
Asset retirement obligation at end of period	$ 3,012,700	$ 2,948,400

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Statements Of Cash Flows (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Cash flows from operating activities:
Net loss	$ (62,200)	$ (90,500)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion	115,900	101,100
Non-cash loss on derivative value	21,900	41,400
Accretion of asset retirement obligation	40,400	37,100
(Increase) decrease in accounts receivable trade-affiliate	(41,400)	120,600
Decrease in accrued liabilities	2,600	14,600
Net cash provided by operating activities	77,200	224,300
Cash flows from financing activities:
Distributions to partners	(56,400)	(236,200)
Net cash used in financing activities	(56,400)	(236,200)
Net increase (decrease) in cash and cash equivalents	20,800	(11,900)
Cash and cash equivalents at beginning of period	15,200	80,500
Cash and cash equivalents at end of period	$ 36,000	$ 68,600

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Balance Sheets (Parenthetical)	Mar. 31, 2013	Dec. 31, 2012
Balance Sheets [Abstract]
Limited Partners' Units	5,227.40	5,227.40

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Asset Retirement Obligation (Tables)

3 Months Ended

Mar. 31, 2013

Asset Retirement Obligation [Abstract]

Schedule of Asset Retirement Obligation [Table Text Block]

	Three Months Ended
	March 31,
	2013	2012
Asset retirement obligation at beginning of period	$         2,972,300	$       2,911,300
Accretion expense	40,400	37,100
Asset retirement obligation at end of period	$         3,012,700	$       2,948,400

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Document and Entity Information	3 Months Ended
	Mar. 31, 2013
Document and Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q1
Entity Registrant Name	Atlas America Public #15-2005 (A) L.P.
Entity Central Index Key	0001335236
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding	5,277.40

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Fair Value of Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2013

Fair Value of Financial Instruments [Abstract]

Assets Measured at Fair Value on a Non-Recurring Basis [Table Text Block]

Information for assets and liabilities measured at fair value at March 31, 2013 and December 31, 2012 was as follows:

	Level 1	Level 2	Level 3	Total
As of March 31, 2013
Derivative assets, gross
Commodity puts	$             —	$          11,300	$             —	$          11,300
Derivative liabilities, gross
Commodity puts	$             —	$                   —	$             —	$                   —
Total derivatives, fair value, net	$             —	$          11,300	$             —	$          11,300

	Level 1	Level 2	Level 3	Total
As of December 31, 2012
Derivative assets, gross
Commodity puts	$             —	$           16,200	$             —	$           16,200
Derivative liabilities, gross
Commodity puts	$             —	$                   —	$             —	$                   —
Total derivatives, fair value, net	$             —	$           16,200	$             —	$           16,200

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Statements Of Operations (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
REVENUES
Natural gas and oil	$ 397,300	$ 358,500
Total revenues	397,300	358,500
COSTS AND EXPENSES
Production	251,100	254,900
Depletion	115,900	101,100
Accretion of asset retirement obligation	40,400	37,100
General and administrative	52,100	55,900
Total expenses	459,500	449,000
Net loss	(62,200)	(90,500)
Allocation of net loss:
Managing general partner	(20,600)	(24,200)
Limited partners	$ (41,600)	$ (66,300)
Net loss per limited partnership unit	(8)	(13)

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Fair Value Of Financial Instruments

3 Months Ended

Mar. 31, 2013

Fair Value of Financial Instruments [Abstract]

FAIR VALUE OF FINANCIAL INSTRUMENTS

NOTE 5 - FAIR VALUE OF FINANCIAL INSTRUMENTS

The Partnership has established a hierarchy to measure its financial instruments at fair value, which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect the Partnership's own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1– Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

Level 3 – Unobservable inputs that reflect the entity's own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The 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 March 31, 2013 and December 31, 2012 was as follows:

	Level 1	Level 2	Level 3	Total
As of March 31, 2013
Derivative assets, gross
Commodity puts	$             —	$          11,300	$             —	$          11,300
Derivative liabilities, gross
Commodity puts	$             —	$                   —	$             —	$                   —
Total derivatives, fair value, net	$             —	$          11,300	$             —	$          11,300

	Level 1	Level 2	Level 3	Total
As of December 31, 2012
Derivative assets, gross
Commodity puts	$             —	$           16,200	$             —	$           16,200
Derivative liabilities, gross
Commodity puts	$             —	$                   —	$             —	$                   —
Total derivatives, fair value, net	$             —	$           16,200	$             —	$           16,200

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

The Partnership estimates the fair value of 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 months ended March 31, 2013 and 2012.

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Derivative Instruments

3 Months Ended

Mar. 31, 2013

Derivative Instruments [Abstract]

DERIVATIVE INSTRUMENTS

NOTE 4 - DERIVATIVE INSTRUMENTS

The MGP, on behalf of the Partnership, uses a number of different derivative instruments, principally swaps, collars and options, in connection with the Partnership's commodity price risk management activities. Management enters into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under commodity-based swap agreements, the Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike, price and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged.

The MGP formally documents all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity derivative contracts to the forecasted transactions. The MGP assesses, both at the inception of the derivative and on an ongoing basis, whether the derivative was effective in offsetting changes in the forecasted cash flow of the hedged item. If the MGP determines that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the MGP will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which are determined by management of the MGP through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership's statements of operations. For derivatives qualifying as hedges, the Partnership recognizes the effective portion of changes in fair value of derivative instruments as accumulated other comprehensive income and reclassifies the portion relating to the Partnership's commodity derivatives to gas and oil production revenues within the Partnership's statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership recognizes changes in fair value within gain (loss) on mark-to-market derivatives in the Partnership's statements of operations as they occur.

The Partnership enters into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership's balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership's balance sheets as the initial value of the options. The Partnership reflected net derivative assets on its balance sheet of $11,300 at March 31, 2013.

At March 31, 2013, the Partnership had the following commodity derivatives:

Natural Gas Put Options

Production
Period Ending		Average	Fair Value
December 31,	Volumes	Strike	Asset (2)
	(mmbtu) (1)	(per mmbtu) (1)
2013	9,500	$             3.450	$                     400
2014	10,500	3.800	2,800
2015	8,400	4.000	3,500
2016	8,400	4.150	4,600
			$                11,300

__________

(1)"Mmbtu" represents million British Thermal Units.

(2)Fair value based on forward New York Mercantile Exchange ("NYMEX") natural gas prices, as applicable.

The following table summarizes the gain or loss recognized in the statements of operations for the three months ended March 31, 2013 and 2012:

Effects of Derivative Instruments on statements of operations:

	Three Months Ended
	March 31,
	2013	2012
Loss from cash flow hedges recognized in accumulated other comprehensive income	$        (11,400)	$                 —
Gains from cash flow hedges reclassified from accumulated other comprehensive income into natural gas and oil revenues	$         16,000	$         54,600

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.

The Partnership recognized gains of $16,000 and $54,600 for the three months ended March 31, 2013 and 2012, respectively, on settled contracts covering commodity production. These gains were included within gas and oil production revenue in the Partnership's statements of operations. As the underlying prices and terms in the Partnership's derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three months ended March 31, 2013 and 2012 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

Monetized Gains

Prior to February 17, 2011 (date of the Transferred Business), 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 March 31, 2013 and December 31, 2012, remaining hedge monetization cash proceeds of $57,900 and $75,500 related to the amounts hedged on behalf of the Partnerships' limited partners were included within accounts receivable monetized gains-affiliate, respectively, and $11,400 and $15,100 in long-term put premiums payable-affiliate, respectively, on the Partnership's balance sheets. The Partnership will allocate the monetized net proceeds to the limited partners based on the natural gas and oil production generated over the period of the original derivative contracts.

During June 2012, the MGP used the undistributed monetized funds to purchase natural gas put options on behalf of the limited partners of the Partnership only. A premium ("put premium") was paid to purchase the contracts and will be allocated to natural gas production revenues generated over the contractual term of the purchased hedging instruments. At March 31, 2013 and December 31, 2012, the put premiums recorded as short-term payables to affiliate were $6,000 and long-term payables to affiliate of $16,600 and $18,100, respectively. Furthermore, the current portion of the put premium liabilities was included in accounts receivable monetized gains-affiliate and the long-term receivable monetized gains-affiliate were included in long term put premiums payable-affiliate in the Partnership's balance sheets, presenting the impact of offsetting the related party assets and liabilities. The put premiums included on the Partnership's balance sheets are allocable to the limited partners only

The following table summarizes the gross and net fair values of the Partnership's affiliate balances on the Partnership's balance sheets for the periods indicated:

	Gross Amounts	Gross Amounts	Net Amount of Assets
	of Recognized	Offset in the	Presented in the
	Assets	Balance Sheets	Balance Sheets
Offsetting Assets
As of March 31, 2013
Accounts receivable monetized gains-affiliate	$              57,900	$               (6,000)	$                        51,900
Long-term accounts receivable monetized gains-affiliate	11,400	(11,400)	—
Total	$              69,300	$             (17,400)	$                        51,900
As of December 31, 2012
Accounts receivable monetized gains-affiliate	$              75,500	$               (6,000)	$                        69,500
Long-term accounts receivable monetized gains-affiliate	15,100	(15,100)	—
Total	$              90,600	$             (21,100)	$                        69,500
	Gross Amounts	Gross Amounts	Net Amount of Liabilities
	of Recognized	Offset in the	Presented in the
	Liabilities	Balance Sheets	Balance Sheets
Offsetting Liabilities
As of March 31, 2013
Put premiums payable-affiliate	$               (6,000)	$                6,000	$                               —
Long-term put premiums payable-affiliate	(16,600)	11,400	(5,200)
Total	$             (22,600)	$              17,400	$                         (5,200)
As of December 31, 2012
Put premiums payable-affiliate	$               (6,000)	$                6,000	$                               —
Long-term put premiums payable-affiliate	(18,100)	15,100	(3,000)
Total	$             (24,100)	$              21,100	$                         (3,000)

.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 sheets in accumulated other comprehensive loss of $19,800 as of March 31, 2013. Included in other comprehensive income are unrealized gains of $77,800, net of the MGP, interest that were recognized into income as a result of oil and gas property impairments during prior periods. During the current year, $7,700 of net gains were recorded by the Partnership and allocated only to the limited partners. Of the remaining $19,800 of net unrealized loss in accumulated other comprehensive loss, the Partnership will reclassify $12,300 of net losses to the Partnership's statements of operations over the next twelve month period and the remaining losses of $7,500 in later periods.

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Summary of Significant Accounting Policies (Schedule of Oil and Gas Properties) (Details) (USD $)	Mar. 31, 2013	Dec. 31, 2012
Accumulated depletion and impairment	$ (63,031,800)	$ (62,915,900)
Oil and gas properties, net	3,587,000	3,702,900
Leasehold interests [Member]
Proved Oil and Gas Property, Successful Effort Method	1,526,600	1,526,600
Wells and related equipment[Member]
Proved Oil and Gas Property, Successful Effort Method	65,092,200	65,092,200
Total natural gas and oil properties [Member]
Proved Oil and Gas Property, Successful Effort Method	$ 66,618,800	$ 66,618,800

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Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 2013

Derivative [Line Items]

Effects of Derivative Instruments on Statements of Operations [Table Text Block]

	Three Months Ended
	March 31,
	2013	2012
Loss from cash flow hedges recognized in accumulated other comprehensive income	$        (11,400)	$                 —
Gains from cash flow hedges reclassified from accumulated other comprehensive income into natural gas and oil revenues	$         16,000	$         54,600

Gross Fair Values of Receivable and Payable Affiliate Balances [Table Text Block]

	Gross Amounts	Gross Amounts	Net Amount of Assets
	of Recognized	Offset in the	Presented in the
	Assets	Balance Sheets	Balance Sheets
Offsetting Assets
As of March 31, 2013
Accounts receivable monetized gains-affiliate	$              57,900	$               (6,000)	$                        51,900
Long-term accounts receivable monetized gains-affiliate	11,400	(11,400)	—
Total	$              69,300	$             (17,400)	$                        51,900
As of December 31, 2012
Accounts receivable monetized gains-affiliate	$              75,500	$               (6,000)	$                        69,500
Long-term accounts receivable monetized gains-affiliate	15,100	(15,100)	—
Total	$              90,600	$             (21,100)	$                        69,500
	Gross Amounts	Gross Amounts	Net Amount of Liabilities
	of Recognized	Offset in the	Presented in the
	Liabilities	Balance Sheets	Balance Sheets
Offsetting Liabilities
As of March 31, 2013
Put premiums payable-affiliate	$               (6,000)	$                6,000	$                               —
Long-term put premiums payable-affiliate	(16,600)	11,400	(5,200)
Total	$             (22,600)	$              17,400	$                         (5,200)
As of December 31, 2012
Put premiums payable-affiliate	$               (6,000)	$                6,000	$                               —
Long-term put premiums payable-affiliate	(18,100)	15,100	(3,000)
Total	$             (24,100)	$              21,100	$                         (3,000)

Commodity Puts [Member]

Derivative [Line Items]

Commodity Derivatives [Table Text Block]

Natural Gas Put Options

Production
Period Ending		Average	Fair Value
December 31,	Volumes	Strike	Asset (2)
	(mmbtu) (1)	(per mmbtu) (1)
2013	9,500	$             3.450	$                     400
2014	10,500	3.800	2,800
2015	8,400	4.000	3,500
2016	8,400	4.150	4,600
			$                11,300

__________

(1)"Mmbtu" represents million British Thermal Units.

(2)Fair value based on forward New York Mercantile Exchange ("NYMEX") natural gas prices, as applicable.

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Summary of Significant Accounting Policies (Policy)

3 Months Ended

Mar. 31, 2013

Summary of Significant Accounting Policies [Abstract]

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 months ended March 31, 2013 and 2012 represent actual results in all material respects (see "Revenue Recognition" accounting policy for further description).

Receivables [Policy Text Block]

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 March 31, 2013 and December 31, 2012, the MGP's credit evaluation indicated that the Partnership had no need for an allowance for possible losses.

Natural Gas and Oil Properties [Policy Text Block]

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 $115,900 and $101,100 for the three months ended March 31, 2013 and 2012, 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.

Impairment of Long-Lived Assets [Policy Text Block]

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 months ended March 31, 2013 and 2012. During the year ended December 31, 2012, the Partnership recognized an impairment charge of $162,600.

Comprehensive Loss [Policy Text Block]

Comprehensive loss

Comprehensive loss includes net 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 loss. These changes, other than net loss, are referred to as "other comprehensive loss" and, for the Partnership, include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges.

Working Interest [Policy Text Block]

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 [Policy Text Block]

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 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 March 31, 2013 and December 31, 2012 of $224,100 and $219,600, respectively, which were included in accounts receivable trade-affiliate within the Partnership's balance sheets.

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Certain Relationships And Related Party Transactions

3 Months Ended

Mar. 31, 2013

Certain Relationships And Related Party Transactions [Abstract]

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

NOTE 6 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The Partnership has entered into the following significant transactions with the MGP and its affiliates as provided under its Partnership Agreement:

·Administrative costs, which are included in general and administrative expenses in the Partnership's statements of operations, are payable at $75 per well per month. Administrative costs incurred for the three months ended March 31, 2013 and 2012 were $33,400 and $34,600, respectively.

·Monthly well supervision fees, which are included in production expenses in the Partnership's statements of operations, are payable at $296 per well per month for operating and maintaining the wells. Well supervision fees incurred for the three months ended March 31, 2013 and 2012 were $132,100 and $136,600, respectively.

·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. Transportation fees incurred for the three months ended March 31, 2013 and 2012 were $49,800 and $50,100, respectively.

·The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership's balance sheets includes the net production revenues due from the MGP.

Subordination by Managing General Partner

Under the terms of the Partnership Agreement, the MGP may be required to subordinate up to 50% of its share of net production revenues so that the limited partners receive a return of at least 10% of their net subscriptions, determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution to the limited partners (August 2006) and expiring 60 months from that date.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2013

Commitments and Contingencies [Abstract]

COMMITMENTS AND CONTINGENCIES

NOTE 7 — COMMITMENTS AND CONTINGENCIES

General Commitments

Subject to certain conditions, investor partners may present their interests beginning in 2010 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 March 31, 2013, the MGP has not withheld any such funds.

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.

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Summary of Significant Accounting Policies (Tables) (Oil and Gas Properties [Member])

3 Months Ended

Mar. 31, 2013

Oil and Gas Properties [Member]

Property, Plant and Equipment [Line Items]

Property, Plant and Equipment [Table Text Block]

	March 31,	December 31,
	2013	2012
Proved properties:
Leasehold interests	$        1,526,600	$          1,526,600
Wells and related equipment	65,092,200	65,092,200
Total natural gas and oil properties	66,618,800	66,618,800
Accumulated depletion and impairment	(63,031,800)	(62,915,900)
Oil and gas properties, net	$         3,587,000	$          3,702,900

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Basis Of Presentation (Details)	3 Months Ended
	Mar. 31, 2013
Atlas America Public #15-2005 (A) L.P. Formation Date	Jul. 25, 2005
Parent Company [Member]
Date Acquired by Atlas Energy L.P.	Feb. 17, 2011

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Derivative Instruments (Commodity Derivatives) (Details) (USD $)			3 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	Mar. 31, 2013 Production Period Ending December 31, 2013 [Member] MMBTU	Mar. 31, 2013 Production Period Ending December 31, 2014 [Member] MMBTU	Mar. 31, 2013 Production Period Ending December 31, 2015 [Member] MMBTU	Mar. 31, 2013 Production Period Ending December 31, 2016 [Member] MMBTU
Derivative [Line Items]
Volumes (mmbtu)			9,500	10,500	8,400	8,400
Average Fixed Price (per mmbtu)			3.45	3.80	4.00	4.15
Fair Value Asset/(Liability)	$ 11,300	$ 16,200	$ 400	$ 2,800	$ 3,500	$ 4,600

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Statements of Comprehensive Loss (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Statements of Comprehensive (Loss) Income [Abstract]
Net loss	$ (62,200)	$ (90,500)
Other comprehensive loss:
Unrealized holding loss on cash flow hedging contracts	(11,400)
Difference in estimated hedge gains receivable	24,600	51,900
Less: reclassification adjustment for gains realized in net loss from cash flow hedges	(16,000)	(54,600)
Total other comprehensive loss	(2,800)	(2,700)
Comprehensive loss	$ (65,000)	$ (93,200)

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Asset Retirement Obligation

3 Months Ended

Mar. 31, 2013

Asset Retirement Obligation [Abstract]

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.

A reconciliation of the Partnership's liability for plugging and abandonment costs for the periods indicated is as follows:

	Three Months Ended
	March 31,
	2013	2012
Asset retirement obligation at beginning of period	$         2,972,300	$       2,911,300
Accretion expense	40,400	37,100
Asset retirement obligation at end of period	$         3,012,700	$       2,948,400

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Derivative Instruments (Effects of Derivative Instruments on Statements of Operations) (Details) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Derivative Instruments [Abstract]
(Loss) Gain recognized in accumulated OCI	$ (11,400)
Gain reclassified from accumulated OCI into (loss) income	$ 16,000	$ 54,600

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Fair Value of Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2013

Fair Value of Financial Instruments [Abstract]

Assets Measured at Fair Value on a Non-Recurring Basis [Table Text Block]

Information for assets and liabilities measured at fair value at March 31, 2013 and December 31, 2012 was as follows:

	Level 1	Level 2	Level 3	Total
As of March 31, 2013
Derivative assets, gross
Commodity puts	$             —	$          11,300	$             —	$          11,300
Derivative liabilities, gross
Commodity puts	$             —	$                   —	$             —	$                   —
Total derivatives, fair value, net	$             —	$          11,300	$             —	$          11,300

	Level 1	Level 2	Level 3	Total
As of December 31, 2012
Derivative assets, gross
Commodity puts	$             —	$           16,200	$             —	$           16,200
Derivative liabilities, gross
Commodity puts	$             —	$                   —	$             —	$                   —
Total derivatives, fair value, net	$             —	$           16,200	$             —	$           16,200