10-Q

United States
Securities and Exchange Commission

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2011

o 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.)
Westpointe Corporate Center One 1550 Coraopolis Heights Rd. 2nd Floor
Moon Township, PA	15108
(Address of principal executive offices)	(zip code)

Issuer’s telephone number, including area code: (412) 262-2830

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 þ No o

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 þ No o

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 o Accelerated filer o Non-accelerated filer o Smaller reporting company þ

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

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
Balance Sheets as of September 30, 2011 and December 31, 2010		3
Statements of Operations for the Three Months and Nine Months ended September 30, 2011 and 2010		4
Statement of Changes in Partners’ Capital for the Nine Months ended September 30, 2011		5
Statements of Cash Flows for the Nine Months ended September 30, 2011 and 2010		6
Notes to Financial Statements		7-15
Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations		16-19
Item 4: Controls and Procedures		19-20
PART II. OTHER INFORMATION
Item 1: Legal Proceedings		20
Item 6: Exhibits		20
SIGNATURES		21
CERTIFICATIONS
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

2

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

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

BALANCE SHEETS

	September 30,		December 31,
	2011		2010
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	76,200	$	115,500
Accounts receivable-affiliate		705,900		471,400
Short-term hedge receivable due from affiliate		—		466,800
Total current assets		782,100		1,053,700
Oil and gas properties, net		6,427,400		6,913,400
Long-term hedge receivable due from affiliate		—		456,300
Long-term receivable-affiliate		209,400		—
	$	7,418,900	$	8,423,400
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	11,800	$	13,500
Short-term hedge liability due to affiliate		—		4,600
Total current liabilities		11,800		18,100
Asset retirement obligation		2,754,500		2,635,900
Long-term hedge liability due to affiliate		—		80,800
Partners’ capital:
Managing general partner		1,938,000		2,392,500
Limited partners (5,227.40 units)		2,502,000		3,207,800
Accumulated other comprehensive income		212,600		88,300
Total partners’ capital		4,652,600		5,688,600
	$	7,418,900	$	8,423,400

See accompanying notes to financial statements.

3

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

STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
REVENUES
Natural gas and oil	$	531,100		$	531,900		$	1,415,000		$	2,033,000
Interest income		—			—			—			100
Total revenues		531,100			531,900			1,415,000			2,033,100
COSTS AND EXPENSES
Production		279,400			329,500			827,700			1,008,800
Depletion		170,500			453,200			486,000			1,628,300
Accretion of asset retirement obligation		39,500			29,400			118,600			88,200
General and administrative		52,200			36,300			153,200			152,400
Total expenses		541,600			848,400			1,585,500			2,877,700
Net loss	$	(10,500	)	$	(316,500	)	$	(170,500	)	$	(844,600	)
Allocation of net loss:
Managing general partner	$	(8,000	)	$	(32,600	)	$	(58,400	)	$	(19,000	)
Limited partners	$	(2,500	)	$	(283,900	)	$	(112,100	)	$	(825,600	)
Net loss per limited partnership unit	$	0		$	(54	)	$	(21	)	$	(158	)

See accompanying notes to financial statements.

4

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

STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

FOR THE NINE MONTHS ENDED

September 30, 2011

(Unaudited)

							Accumulated
	Managing						Other
	General			Limited			Comprehensive
	Partner			Partners			Income		Total
Balance at January 1, 2011	$	2,392,500		$	3,207,800		$	88,300	$	5,688,600
Participation in revenues and expenses:
Net production revenues		118,400			468,900			—		587,300
Depletion		(85,800	)		(400,200	)		—		(486,000	)
Accretion of asset retirement obligation		(39,700	)		(78,900	)		—		(118,600	)
General and administrative		(51,300	)		(101,900	)		—		(153,200	)
Net loss		(58,400	)		(112,100	)		—		(170,500	)
Other comprehensive income		—			—			124,300		124,300
Subordination		(39,400	)		39,400			—		—
Distributions to partners		(356,700	)		(633,100	)		—		(989,800	)
Balance at September 30, 2011	$	1,938,000		$	2,502,000		$	212,600	$	4,652,600

See accompanying notes to financial statements.

5

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

STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended
	September 30,
	2011			2010
Cash flows from operating activities:
Net loss	$	(170,500	)	$	(844,600	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion		486,000			1,628,300
Non-cash loss on hedge instruments		269,800			404,400
Accretion of asset retirement obligation		118,600			88,200
Decrease in accounts receivable-affiliate		40,800			75,100
Decrease in accrued liabilities		(1,700	)		(13,700	)
Net cash provided by operating activities		743,000			1,337,700
Cash flows from financing activities:
Distributions to partners		(782,300	)		(1,487,300	)
Net cash used in financing activities		(782,300	)		(1,487,300	)
Net decrease in cash and cash equivalents		(39,300	)		(149,600	)
Cash and cash equivalents at beginning of period		115,500			161,500
Cash and cash equivalents at end of period	$	76,200		$	11,900
Supplemental schedule of non-cash operating and financing activities:
Distribution to managing general partner	$	207,500		$	—

See accompanying notes to financial statements.

6

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

NOTES TO FINANCIAL STATEMENTS

September 30, 2011

(Unaudited)

NOTE 1 — BASIS OF PRESENTATION

Atlas America Public #15-2005 (A) L.P. (the “Partnership”) is a Delaware limited partnership and 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 Energy, L.P., formerly Atlas Pipeline Holdings, L.P. (“Atlas Energy”) (NYSE: ATLS). On February 17, 2011, Atlas Energy, 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, and certain well interests in Pennsylvania and Michigan; and its ownership and management of investments in Lightfoot Capital Partners, L.P. and related entities (the “Transferred Business”).

Atlas Energy recently announced that it intends to create a newly formed exploration and production master limited partnership named Atlas Resource Partners, L.P. (“Atlas Resource Partners”), which will hold substantially all of ATLS’ current natural gas and oil development and production assets and the partnership management business.

Atlas Resources’ focus is on the development and/or production of natural gas and oil in the Appalachian, Michigan, Indiana, and/or Colorado basin regions of the United States of America. Atlas Resources is also a leading sponsor of and manages tax-advantaged direct investment partnerships, in which it co-invests to finance the exploitation and development of its acreage. Atlas Energy Resource Services, Inc. provides Atlas Resources with the personnel necessary to manage its assets and raise capital.

The accompanying financial statements, which are unaudited except that the balance sheet at December 31, 2010 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 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, 2010. The results of operations for the three and nine months ended September 30, 2011 may not necessarily be indicative of the results of operations for the year ended December 31, 2011.

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.

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, 2010 filed with the Securities and Exchange Commission (“SEC”).

Use of Estimates

Preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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 revenue 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.

7

ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2011
(Unaudited)

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Use of Estimates (Continued)

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 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 the Partnership’s customers’ credit information. Credit is extended on an unsecured basis to many of its energy customers. As of September 30, 2011 and December 31, 2010, 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 are expensed as incurred. Major renewals and improvements that extend the useful lives of property 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 equals six Mcf.

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 costs of developed producing properties. Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the cost from the property accounts and the resultant gain or loss is reclassified to the Partnership’s statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its balance sheets.

	September 30,			December 31,
	2011			2010
Proved properties:
Leasehold interests	$	1,526,600		$	1,526,600
Wells and related equipment		65,069,800			65,069,800
		66,596,400			66,596,400
Accumulated depletion		(60,169,000	)		(59,683,000	)
	$	6,427,400		$	6,913,400

8

ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2011
(Unaudited)

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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 for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review of the Partnership’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties, less the applicable accumulated depletion, and 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 production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. There was no impairment charge recognized during the three and nine months ended September 30, 2011. During the year ended December 31, 2010, the Partnership recognized an impairment charge of $8,286,900, net of an offsetting gain in accumulated other comprehensive income of $291,400.

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.

9

ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2011
(Unaudited)

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue Recognition

The Partnership generally sells natural gas and crude oil at prevailing market prices. Revenue is 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 the Partnership’s percentage ownership of the working interest. Generally, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index with certain adjustments based on proximity to gathering and transmission lines and the quality of its natural gas.

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas and crude oil 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 fees which are, in turn, based upon applicable product prices (see “Use of Estimates” accounting policy for further description). The Partnership had unbilled revenues at September 30, 2011 and December 31, 2010 of $300,300 and $312,500 respectively, which are included in accounts receivable — affiliate within the Partnership’s balance sheets.

Recently Issued Accounting Standards

In June 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. Update 2011-05 amends the FASB Accounting Standards Codification to provide an entity with the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income in either a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with a total net income, each component of other comprehensive income, and a total amount for comprehensive income. Update 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of changes in partners’ capital. These changes apply to both annual and interim financial statements. Update 2011-05 will be effective for public entities’ fiscal years, and interim periods within those years, beginning after December 15, 2011. The Partnership will apply the requirements of Update 2011-05 upon its effective date of January 1, 2012, 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 associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depletion.

The estimated liability is based on the MGP’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its oil and gas properties, the Partnership has determined that there are no other material retirement obligations associated with tangible long-lived assets.

10

ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2011
(Unaudited)

NOTE 3 — ASSET RETIREMENT OBLIGATION (Continued)

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
Asset retirement obligation at beginning of period	$	2,715,000	$	2,019,800	$	2,635,900	$	1,961,000
Accretion expense		39,500		29,400		118,600		88,200
Asset retirement obligation at end of period	$	2,754,500	$	2,049,200	$	2,754,500	$	2,049,200

NOTE 4 — DERIVATIVE INSTRUMENTS

The MGP, on behalf of the Partnership, historically used a number of different derivative instruments, principally swaps and collars, in connection with its commodity price risk management activities. The MGP entered into financial instruments to hedge the Partnership’s forecasted natural gas and crude oil 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 natural gas and crude oil is sold. Under swap agreements, the Partnership received or paid a fixed price and received or remitted a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not obligation, to purchase or sell natural gas and crude oil at a fixed price for the relevant contract period.

Historically, the MGP has entered into natural gas and crude oil future option contracts and collar contracts on behalf of the Partnership to achieve more predictable cash flows by hedging its exposure to changes in natural gas and oil prices. At any point in time, such contracts included regulated New York Mercantile Exchange (“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 delivery of natural gas. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. These contracts qualified and were designated as cash flow hedges and recorded at their fair values.

The MGP formally documented all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This included matching the commodity derivative contracts to the forecasted transactions. The MGP assessed, 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 it determined that a derivative was not effective as a hedge or that it had 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 discontinued hedge accounting for the derivative and subsequent changes in the derivative fair value, which was determined by the MGP through the utilization of market data, were recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations. For derivatives qualifying as hedges, the Partnership recognized the effective portion of changes in fair value in partners’ capital as accumulated other comprehensive income and reclassified the portion relating to commodity derivatives to gas and oil production revenues for the Partnership’s derivatives within the Partnership’s statements of operations as the underlying transactions were settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership recognized changes in fair value within gain (loss) on mark-to-market derivatives in its statements of operations as they occurred.

11

ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2011
(Unaudited)

NOTE 4 — DERIVATIVE INSTRUMENTS (Continued)

Prior to the sale on February 17, 2011 of the Transferred Business, Atlas Energy, Inc. monetized its derivative instruments related to the Transferred Business. The monetized proceeds related to instruments that were originally put into place to hedge future natural gas and oil production of the Transferred Business, including production generated through its drilling partnerships. At September 30, 2011, the Partnership recorded a net receivable from the monetized derivative instruments of $275,300 in accounts receivable-affiliate and $209,400 in long-term receivable-affiliate with the corresponding net unrealized gains in accumulated other comprehensive income on the Partnership’s balance sheets, which will be allocated to natural gas and oil production revenue generated over the period of the original instruments’ term. As a result of the monetization and the early settlement of natural gas and oil derivative instruments and the unrealized gains recognized in income in prior periods due to natural gas and oil property impairments, the Partnership recorded a net deferred gain on its balance sheets in other comprehensive income of $212,600 as of September 30, 2011. Unrealized gains, net of the MGP’s interest, previously recognized into income as a result of prior period impairments included in accumulated other comprehensive income were $90,600 and $181,500 for the year ended December 31, 2010 and prior periods, respectively. The MGP’s portion of the unrealized gains was written-off as part of the terms related to the acquisition of the Transferred Business. For the nine months ended September 30, 2011, the Partnership reclassified $207,500 of unrealized gains previously recognized into income from prior period impairments related to the MGP from a hedge receivable due from affiliate to a non-cash distribution to the MGP. As such, $207,500 was recorded as a distribution to partners on the statement of changes in partners’ capital. During the nine months ended September 30, 2011, $233,900 of monetized proceeds were recorded by the Partnership and allocated only to the limited partners. Of the remaining $212,600 of net unrealized gain in accumulated other comprehensive income, the Partnership will reclassify $117,100 of net gains to the Partnership’s statements of operations over the next twelve month period and the remaining $95,500 in later periods.

The following tables summarize the fair value of the Partnership’s derivative instruments as of December 31, 2010, as well as the gain or loss recognized in the statements of operations for the three and nine months ended September 30, 2011 and 2010:

Fair Value of Derivative Instruments:

	Balance Sheet	Fair Value
Derivatives in Cash Flow Hedging Relationships	Location	December 31, 2010
Commodity Contracts	Current assets	$	466,800
	Long-term assets		456,300
			923,100
	Current liabilities		(4,600	)
	Long-term liabilities		(80,800	)
			(85,400	)
	Total	$	837,700

12

ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2011
(Unaudited)

NOTE 4 — DERIVATIVE INSTRUMENTS (Continued)

Effects of Derivative Instruments on Statements of Operations:

		Three Months Ended				Nine Months Ended
		September 30,		September 30,		September 30,		September 30,
		2011		2010		2011		2010
Derivative in Cash Flow Hedging Relationships	Gain Recognized in OCI on Derivatives
	Commodity Contracts	$	—	$	511,400	$	9,800	$	1,227,500

		Three Months Ended				Nine Months Ended
		September 30,		September 30,		September 30,		September 30,
		2011		2010		2011		2010
Location of Gain Reclassified from Accumulated OCI into Income	Gain Reclassified from OCI into Net Income (Loss)
	Gas and Oil Revenue	$	56,000	$	68,000	$	146,900	$	243,000

NOTE 5 — COMPREHENSIVE INCOME (LOSS)

Comprehensive income (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 income (loss)” and, for the Partnership, include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges. , and changes in the estimated amount of future monetized proceeds to be received (See Note 4). The monetized proceeds included in accounts receivable affiliate have been allocated to the Partnership based on estimated future production in relation to all other partnerships’ future production eligible to receive monetized hedge proceeds. As actual production is realized, there may be a corresponding difference in the Partnership’s actual share of monetized hedge proceeds received than what was previously estimated. This component is shown as “Difference in estimated monetized gains receivable.” A reconciliation of the Partnership’s comprehensive income (loss) for the periods indicated is as follows:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Net loss	$	(10,500	)	$	(316,500	)	$	(170,500	)	$	(844,600	)
Other comprehensive income (loss):
Unrealized holding gain on hedging contracts		—			511,400			9,800			1,227,500
MGP portion of non-cash loss on hedge instruments		—			—			207,500			—
Difference in estimated monetized gains receivable		16,900			—			53,900			—
Less: reclassification adjustment for gains realized in net loss		(56,000	)		(68,000	)		(146,900	)		(243,000	)
Total other comprehensive income (loss)		(39,100	)		443,400			124,300			984,500
Comprehensive income (loss)	$	(49,600	)	$	126,900		$	(46,200	)	$	139,900

13

ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2011
(Unaudited)

NOTE 6 — 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. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1— Quoted prices in active markets for identical 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 entities own assumptions about the assumptions that 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 used a fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 4). The Partnership’s commodity derivative contracts were valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements.

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

The Partnership estimates the fair value of asset retirement obligations using Level 3 inputs 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).

NOTE 7 — 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 and nine months ended September 30, 2011 were $37,100 and $110,500 respectively. Administrative costs incurred for the three and nine months ended September 30, 2010 were $38,200 and $113,600 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 in 2011 and 2010, respectively, for operating and maintaining the wells. Well supervision fees incurred for the three and nine months ended September 30, 2011 were $146,700 and $436,600 respectively. Well supervision fees incurred for the three and nine months ended September 30, 2010 were $151,000 and $448,800, respectively.

14

ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2011
(Unaudited)

NOTE 7 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS (Continued)

• 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 and nine months ended September 30, 2011 were $69,200 and $203,000, respectively. Transportation fees incurred for the three and nine months ended September 30, 2010 were $80,500 and $296,000, respectively.

The MGP and its affiliates perform all administrative and management functions for the Partnership including billing revenues and paying expenses. “Accounts receivable-affiliate” on the Partnership’s balance sheets represents 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 production revenues of the Partnership to the benefit of the limited partners for an amount equal to 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). The MGP subordinated $39,400 and $236,000 of its net production revenue to the limited partners for the nine months ended September 30, 2011 and 2010, respectively.

NOTE 8 — SUBSEQUENT EVENTS

Management has considered for disclosure any material subsequent events through the date the financial statements were issued.

Formation of Atlas Resource Partners, L.P. On October 17, 2011, Atlas Energy announced that its board of directors has approved a plan to create a newly formed exploration and production master limited partnership named Atlas Resource Partners, L.P. (“Atlas Resource Partners”), which will hold substantially all of Atlas Energy’s current natural gas and oil development, and production assets and the partnership management business, including the MGP. Upon consummation of the transaction, Atlas Energy will retain a 78.4% limited partner interest in Atlas Resource Partners and intends to distribute a 19.6% limited partner interest in Atlas Resource Partners to Atlas Energy unit holders. Atlas Energy will also own the newly created general partner of Atlas Resource Partners, which will own a 2% general partner interest and all of the incentive distribution rights in the newly formed partnership. Completion of the transaction is subject to a number of conditions, including final approval by the Atlas Energy’s board of directors, as well as the effectiveness of a Form 10 registration statement that Atlas Resource Partners filed with the SEC on October 17, 2011. The transaction is expected to close in the first quarter of 2012. The MGP anticipates that this transaction will have no impact on the Partnership’s operations.

15

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.

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

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 managing general partner (“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 September 30, 2011, our MGP had not withheld any funds for this purpose. Our MGP intends to produce our wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. No other wells will be drilled and no additional funds will be required for drilling.

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 2011 and 2010, 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.

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 Holdings Operating Company, LLC, for administrative services.

16

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						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Production revenues (in thousands):
Gas	$	487		$	500		$	1,316		$	1,955
Oil		44			32			99			78
Total	$	531		$	532		$	1,415		$	2,033
Production volumes:
Gas (mcf/day) (1)		1,058			1,026			1,023			1,244
Oil (bbls/day) (1)		6			5			4			5
Total (mcfe/day) (1)		1,094			1,056			1,047			1,274
Average sales prices: (2)
Gas (per mcf) (1) (3)	$	5.58		$	6.75		$	5.68		$	6.91
Oil (per bbl) (1) (4)	$	84.45		$	75.55		$	87.91		$	74.26
Average production costs:
As a percent of revenues		53	%		62	%		58	%		50	%
Per mcfe (1)	$	2.78		$	3.38		$	2.90		$	2.91
Depletion per mcfe	$	1.70		$	4.65		$	1.70		$	4.69

(1)	“Mcf” represents thousand cubic feet, “mcfe” represents thousand cubic feet equivalent, and “bbls” represents barrels. Bbls are converted to mcfe using the ratio of six mcfs to one bbl.
(2)	Average sales prices represent accrual basis pricing after reversing the effect of previously recognized gains resulting from prior period impairment charges.
(3)	Average gas prices are calculated by including in total revenue derivative and gains previously recognized into income and dividing by the total volume for the period. Previously recognized derivative gains were $55,500 and $137,800 for the three months ended September 30, 2011 and 2010, respectively. Previously recognized derivative gains were $270,500 and $390,400 for the nine months ended September 30, 2011 and 2010, respectively. The derivative gains are included in other comprehensive income and resulted from prior period impairment charges.
(4)	Average oil prices are calculated by including in total revenue derivative gains and losses previously recognized into income and dividing by the total volume for the period. Previously recognized derivative losses of $300 and gains of $5,000 for the three months ended September 30, 2011 and 2010, respectively. Previously recognized derivative losses of $600 and gains of $14,000 for the nine months ended September 30, 2011 and 2010, respectively. The derivative gains are included in other comprehensive income and resulted from prior period impairment charges.

Natural Gas Revenues. Our natural gas revenues were $487,400 and $499,600 for the three months ended September 30, 2011 and 2010, respectively, a decrease of $12,200 (2%). The $12,200 decrease in natural gas revenues for the three months ended September 30, 2011 as compared to the prior year similar period was attributable to a $989,900 decrease in natural gas sales prices after the effect financial hedges, which are driven by market conditions, partially offset by a $977,700 increase in production volumes. Our production volumes increased to 1,058 mcf per day for the three months ended September 30, 2011 from 1,026 mcf per day for the three months ended September 30, 2010, an increase of 32 mcf per day (3%). Production increased due to certain wells being moved to new gathering system.

17

Our natural gas revenues were $1,316,200 and $1,954,900 for the nine months ended September 30, 2011 and 2010, respectively, a decrease of $638,700 (33%). The $638,700 decrease in natural gas revenues for the nine months ended September 30, 2011 as compared to the prior year similar period was attributable to a $347,600 decrease in production volumes and a $291,100 decrease in natural gas sales prices after the effect of financial hedges, which are driven by market conditions. Our production volumes decreased to 1,023 mcf per day for the nine months ended September 30, 2011 from 1,244 mcf per day for the nine months ended September 30, 2010, a decrease of 221 mcf per day (18%). The overall decrease in natural gas production volumes for the nine months ended September 30, 2011 resulted primarily from the normal decline inherent in the life of a well.

Oil Revenues. We drill wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $43,700 and $32,300 for the three months ended September 30, 2011 and 2010, respectively, an increase of $11,400 (35%). The $11,400 increase in oil revenues for the three months ended September 30, 2011 as compared to the prior year similar period was attributable to a $40,700 increase in production volumes, partially offset by a $29,300 decrease in oil prices after the effect of financial hedges which are driven by market conditions. Our production volumes increased to 6 bbls per day for the three months ended September 30, 2011 from 5 bbls per day for the three months ended September 30, 2010, an increase of 1 bbl per day (20%).

Our oil revenues were $98,800 and $78,100 for the nine months ended September 30, 2011 and 2010, respectively, an increase of $20,700 (27%). The $20,700 increase in oil revenues for the nine months ended September 30, 2011 as compared to the prior year similar period was attributable to an $28,500 increase in oil prices after the effect of financial hedges, partially offset by a $7,800 decrease in production volumes. Our production volumes decreased to 4 bbls per day for the nine months ended September 30, 2011 from 5 bbls per day for the nine months ended September 30, 2011, a decrease of 1 bbl per day (20%).

Costs and Expenses. Production expenses were $279,400 and $329,500 for the three months ended September 30, 2011 and 2010, respectively, a decrease of $50,100 (15%). Production expenses were $827,700 and $1,008,800 for the nine months ended September 30, 2011 and 2010, respectively a decrease of $181,100 (18%). These decreases for the three and nine months ended September 30, 2011 was primarily due to a decrease in transportation fees, which are affected by a decrease in production volumes.

Depletion of oil and gas properties as a percentage of oil and gas revenues were 32% and 85% for the three months ended September 30, 2011 and 2010; respectively; and 34% and 80% for the nine months ended September 30, 2011 and 2010, respectively. These percentage changes were directly attributable to changes in revenues, oil and gas reserve quantities, product prices, production volumes and changes in the depletable cost basis of our oil and gas properties.

General and administrative expenses for the three months ended September 30, 2011 and 2010 were $52,200 and $36,300 respectively, an increase of $15,900 (44%). For the nine months ended September 30, 2011 and 2010, these expenses were $153,200 and $152,400, respectively, an increase of $800 (1%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP, and vary from year to year due to the timing and billing of the costs and services provided to us.

Liquidity and Capital Resources

Cash provided by operating activities decreased $594,700 in the nine months ended September 30, 2011 to $743,000 as compared to $1,337,700 for the nine months ended September 30, 2010. This decrease was due to a decrease in net earnings before depletion and accretion of $437,800 and the change in a net non-cash loss on hedge instruments of $134,600. The change in accounts receivable-affiliate decreased operating cash flows by $34,300. In addition, the change in accrued liabilities affiliate increased operating cash flows by $12,000 for the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010.

18

Cash used in financing activities decreased $705,000 during the nine months ended September 30, 2011 to $782,300 from $1,487,300 for the nine months ended September 30, 2010. This decrease was due to a decrease in cash distributions.

Our MGP may withhold funds for future plugging and abandonment costs. Through September 30, 2011, our MGP had not withheld any funds for this purpose. 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 production revenues of the Partnership to the benefit of the limited partners for an amount equal to 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). The MGP subordinated $39,400 and $236,000 of its net production revenue to the limited partners for the nine months ended September 30, 2011 and 2010, respectively.

Critical Accounting Policies and Estimates

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 our 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, 2010.

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 MGP’s 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 MGP’s 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 MGP’s Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, concluded that, at September 30, 2011, 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 effect, our internal control over financial reporting.

PART II OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The Managing General Partner 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-1 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: November 10, 2011	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 person on behalf of the registrant and in the capacities and on the dates indicated.

Date: November 10, 2011	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 September 30, 2011 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: Name:	/s/ FREDDIE M. KOTEK Freddie M. Kotek
Title:	Chief Executive Officer of the Managing General Partner

Date: November 10, 2011

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 September 30, 2011 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: Name:	/s/ SEAN P. MCGRATH Sean P. McGrath
Title:	Chief Financial Officer of the Managing General Partner

Date: November 10, 2011

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 September 30, 2011 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: November 10, 2011

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 September 30, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Sean P. McGrath, Chief Financial 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: Name:	/s/ SEAN P. MCGRATH Sean P. McGrath
Title:	Chief Financial Officer of the Managing General Partner

Date: November 10, 2011

XML

Balance Sheets (Parenthetical)	Sep. 30, 2011	Dec. 31, 2010
Balance Sheets
Limited Partners' Units	5,227.4	5,227.4

XML

Statements Of Operations (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
REVENUES
Natural gas and oil	$ 531,100	$ 531,900	$ 1,415,000	$ 2,033,000
Interest income				100
Total revenues	531,100	531,900	1,415,000	2,033,100
COSTS AND EXPENSES
Production	279,400	329,500	827,700	1,008,800
Depletion	170,500	453,200	486,000	1,628,300
Accretion of asset retirement obligation	39,500	29,400	118,600	88,200
General and administrative	52,200	36,300	153,200	152,400
Total expenses	541,600	848,400	1,585,500	2,877,700
Net loss	(10,500)	(316,500)	(170,500)	(844,600)
Allocation of net loss:
Managing general partner	(8,000)	(32,600)	(58,400)	(19,000)
Limited partners	$ (2,500)	$ (283,900)	$ (112,100)	$ (825,600)
Net loss per limited partnership unit	0	(54)	(21)	(158)

XML

Document and Entity Information	9 Months Ended
	Sep. 30, 2011
Document and Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Entity Registrant Name	Atlas America Public #15-2005 (A) Program
Entity Central Index Key	0001335236
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding	5,227.4

XML

Fair Value Of Financial Instruments

9 Months Ended

Sep. 30, 2011

Fair Value of Financial Instruments

FAIR VALUE OF FINANCIAL INSTRUMENTS

NOTE 6 — 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. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1— Quoted prices in active markets for identical 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 entities own assumptions about the assumptions that 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 used a fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 4). The Partnership's commodity derivative contracts were valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements.

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

The Partnership estimates the fair value of asset retirement obligations using Level 3 inputs 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).

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Summary Of Significant Accounting Policies

9 Months Ended

Sep. 30, 2011

Summary of Significant Accounting Policies

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.

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, 2010 filed with the Securities and Exchange Commission ("SEC").

Use of Estimates

Preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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 revenue 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 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 the Partnership's customers' credit information. Credit is extended on an unsecured basis to many of its energy customers. As of September 30, 2011 and December 31, 2010, 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 are expensed as incurred. Major renewals and improvements that extend the useful lives of property 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 equals six Mcf.

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 costs of developed producing properties. Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the cost from the property accounts and the resultant gain or loss is reclassified to the Partnership's statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its balance sheets.

	September 30,			December 31,
	2011			2010
Proved properties:
Leasehold interests	$	1,526,600		$	1,526,600
Wells and related equipment		65,069,800			65,069,800
		66,596,400			66,596,400
Accumulated depletion		(60,169,000	)		(59,683,000	)
	$	6,427,400		$	6,913,400

Impairment of Long-Lived Assets

The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset's estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review of the Partnership's oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties, less the applicable accumulated depletion, and 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 production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. There was no impairment charge recognized during the three and nine months ended September 30, 2011. During the year ended December 31, 2010, the Partnership recognized an impairment charge of $8,286,900, net of an offsetting gain in accumulated other comprehensive income of $291,400.

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. Revenue is 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 the Partnership's percentage ownership of the working interest. Generally, the Partnership's sales contracts are based on pricing provisions that are tied to a market index with certain adjustments based on proximity to gathering and transmission lines and the quality of its natural gas.

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas and crude oil 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 fees which are, in turn, based upon applicable product prices (see "Use of Estimates" accounting policy for further description). The Partnership had unbilled revenues at September 30, 2011 and December 31, 2010 of $300,300 and $312,500 respectively, which are included in accounts receivable — affiliate within the Partnership's balance sheets.

Recently Issued Accounting Standards

In June 2011, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. Update 2011-05 amends the FASB Accounting Standards Codification to provide an entity with the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income in either a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with a total net income, each component of other comprehensive income, and a total amount for comprehensive income. Update 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of changes in partners' capital. These changes apply to both annual and interim financial statements. Update 2011-05 will be effective for public entities' fiscal years, and interim periods within those years, beginning after December 15, 2011. The Partnership will apply the requirements of Update 2011-05 upon its effective date of January 1, 2012, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

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Subsequent Events

9 Months Ended

Sep. 30, 2011

Subsequent Events

SUBSEQUENT EVENTS

NOTE 8 — SUBSEQUENT EVENTS

Management has considered for disclosure any material subsequent events through the date the financial statements were issued.

Formation of Atlas Resource Partners, L.P. On October 17, 2011, Atlas Energy announced that its board of directors has approved a plan to create a newly formed exploration and production master limited partnership named Atlas Resource Partners, L.P. ("Atlas Resource Partners"), which will hold substantially all of Atlas Energy's current natural gas and oil development, and production assets and the partnership management business, including the MGP. Upon consummation of the transaction, Atlas Energy will retain a 78.4% limited partner interest in Atlas Resource Partners and intends to distribute a 19.6% limited partner interest in Atlas Resource Partners to Atlas Energy unit holders. Atlas Energy will also own the newly created general partner of Atlas Resource Partners, which will own a 2% general partner interest and all of the incentive distribution rights in the newly formed partnership. Completion of the transaction is subject to a number of conditions, including final approval by the Atlas Energy's board of directors, as well as the effectiveness of a Form 10 registration statement that Atlas Resource Partners filed with the SEC on October 17, 2011. The transaction is expected to close in the first quarter of 2012. The MGP anticipates that this transaction will have no impact on the Partnership's operations.

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Certain Relationships And Related Party Transactions

9 Months Ended

Sep. 30, 2011

Certain Relationships And Related Party Transactions

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

NOTE 7 — 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 and nine months ended September 30, 2011 were $37,100 and $110,500 respectively. Administrative costs incurred for the three and nine months ended September 30, 2010 were $38,200 and $113,600 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 in 2011 and 2010, respectively, for operating and maintaining the wells. Well supervision fees incurred for the three and nine months ended September 30, 2011 were $146,700 and $436,600 respectively. Well supervision fees incurred for the three and nine months ended September 30, 2010 were $151,000 and $448,800, 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 and nine months ended September 30, 2011 were $69,200 and $203,000, respectively. Transportation fees incurred for the three and nine months ended September 30, 2010 were $80,500 and $296,000, respectively.

The MGP and its affiliates perform all administrative and management functions for the Partnership including billing revenues and paying expenses. "Accounts receivable-affiliate" on the Partnership's balance sheets represents 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 production revenues of the Partnership to the benefit of the limited partners for an amount equal to 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). The MGP subordinated $39,400 and $236,000 of its net production revenue to the limited partners for the nine months ended September 30, 2011 and 2010, respectively.

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Statements Of Cash Flows (USD $)	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Cash flows from operating activities:
Net loss	$ (170,500)	$ (844,600)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion	486,000	1,628,300
Non-cash loss on hedge instruments	269,800	404,400
Accretion of asset retirement obligation	118,600	88,200
Decrease in accounts receivable-affiliate	40,800	75,100
Decrease in accrued liabilities	(1,700)	(13,700)
Net cash provided by operating activities	743,000	1,337,700
Cash flows from financing activities:
Distributions to partners	(782,300)	(1,487,300)
Net cash used in financing activities	(782,300)	(1,487,300)
Net decrease in cash and cash equivalents	(39,300)	(149,600)
Cash and cash equivalents at beginning of period	115,500	161,500
Cash and cash equivalents at end of period	76,200	11,900
Supplemental schedule of non-cash operating and financing activities:
Distribution to Managing General Partner	$ 207,500

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Asset Retirement Obligation

9 Months Ended

Sep. 30, 2011

Asset Retirement Obligation

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 associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depletion.

The estimated liability is based on the MGP's historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for 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 well plugging and abandonment costs for the periods indicated is as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
Asset retirement obligation at beginning of period	$	2,715,000	$	2,019,800	$	2,635,900	$	1,961,000
Accretion expense		39,500		29,400		118,600		88,200
Asset retirement obligation at end of period	$	2,754,500	$	2,049,200	$	2,754,500	$	2,049,200

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Derivative Instruments

9 Months Ended

Sep. 30, 2011

Derivative Instruments

DERIVATIVE INSTRUMENTS

NOTE 4 — DERIVATIVE INSTRUMENTS

The MGP, on behalf of the Partnership, historically used a number of different derivative instruments, principally swaps and collars, in connection with its commodity price risk management activities. The MGP entered into financial instruments to hedge the Partnership's forecasted natural gas and crude oil 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 natural gas and crude oil is sold. Under swap agreements, the Partnership received or paid a fixed price and received or remitted a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not obligation, to purchase or sell natural gas and crude oil at a fixed price for the relevant contract period.

Historically, the MGP has entered into natural gas and crude oil future option contracts and collar contracts on behalf of the Partnership to achieve more predictable cash flows by hedging its exposure to changes in natural gas and oil prices. At any point in time, such contracts included regulated New York Mercantile Exchange ("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 delivery of natural gas. Crude oil contracts are based on a West Texas Intermediate ("WTI") index. These contracts qualified and were designated as cash flow hedges and recorded at their fair values.

The MGP formally documented all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This included matching the commodity derivative contracts to the forecasted transactions. The MGP assessed, 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 it determined that a derivative was not effective as a hedge or that it had 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 discontinued hedge accounting for the derivative and subsequent changes in the derivative fair value, which was determined by the MGP through the utilization of market data, were recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership's statements of operations. For derivatives qualifying as hedges, the Partnership recognized the effective portion of changes in fair value in partners' capital as accumulated other comprehensive income and reclassified the portion relating to commodity derivatives to gas and oil production revenues for the Partnership's derivatives within the Partnership's statements of operations as the underlying transactions were settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership recognized changes in fair value within gain (loss) on mark-to-market derivatives in its statements of operations as they occurred.

Prior to the sale on February 17, 2011 of the Transferred Business, Atlas Energy, Inc. monetized its derivative instruments related to the Transferred Business. The monetized proceeds related to instruments that were originally put into place to hedge future natural gas and oil production of the Transferred Business, including production generated through its drilling partnerships. At September 30, 2011, the Partnership recorded a net receivable from the monetized derivative instruments of $275,300 in accounts receivable-affiliate and $209,400 in long-term receivable-affiliate with the corresponding net unrealized gains in accumulated other comprehensive income on the Partnership's balance sheets, which will be allocated to natural gas and oil production revenue generated over the period of the original instruments' term. As a result of the monetization and the early settlement of natural gas and oil derivative instruments and the unrealized gains recognized in income in prior periods due to natural gas and oil property impairments, the Partnership recorded a net deferred gain on its balance sheets in other comprehensive income of $212,600 as of September 30, 2011. Unrealized gains, net of the MGP's interest, previously recognized into income as a result of prior period impairments included in accumulated other comprehensive income were $90,600 and $181,500 for the year ended December 31, 2010 and prior periods, respectively. The MGP's portion of the unrealized gains was written-off as part of the terms related to the acquisition of the Transferred Business. For the nine months ended September 30, 2011, the Partnership reclassified $207,500 of unrealized gains previously recognized into income from prior period impairments related to the MGP from a hedge receivable due from affiliate to a non-cash distribution to the MGP. As such, $207,500 was recorded as a distribution to partners on the statement of changes in partners' capital. During the nine months ended September 30, 2011, $233,900 of monetized proceeds were recorded by the Partnership and allocated only to the limited partners. Of the remaining $212,600 of net unrealized gain in accumulated other comprehensive income, the Partnership will reclassify $117,100 of net gains to the Partnership's statements of operations over the next twelve month period and the remaining $95,500 in later periods.

The following tables summarize the fair value of the Partnership's derivative instruments as of December 31, 2010, as well as the gain or loss recognized in the statements of operations for the three and nine months ended September 30, 2011 and 2010:

Fair Value of Derivative Instruments:

	Balance Sheet	Fair Value
Derivatives in Cash Flow Hedging Relationships	Location	December 31, 2010
Commodity Contracts	Current assets	$	466,800
	Long-term assets		456,300
			923,100
	Current liabilities		(4,600	)
	Long-term liabilities		(80,800	)
			(85,400	)
	Total	$	837,700

Effects of Derivative Instruments on Statements of Operations:

		Three Months Ended				Nine Months Ended
		September 30,		September 30,		September 30,		September 30,
		2011		2010		2011		2010
Derivative in Cash Flow Hedging Relationships	Gain Recognized in OCI on Derivatives
	Commodity Contracts	$	—	$	511,400	$	9,800	$	1,227,500

		Three Months Ended				Nine Months Ended
		September 30,		September 30,		September 30,		September 30,
		2011		2010		2011		2010
Location of Gain Reclassified from Accumulated OCI into Income	Gain Reclassified from OCI into Net Income (Loss)
	Gas and Oil Revenue	$	56,000	$	68,000	$	146,900	$	243,000

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Comprehensive Income (Loss)

9 Months Ended

Sep. 30, 2011

Comprehensive Income (Loss)

COMPREHENSIVE INCOME (LOSS)

NOTE 5 — COMPREHENSIVE INCOME (LOSS)

Comprehensive income (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 income (loss)" and, for the Partnership, include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges. , and changes in the estimated amount of future monetized proceeds to be received (See Note 4). The monetized proceeds included in accounts receivable affiliate have been allocated to the Partnership based on estimated future production in relation to all other partnerships' future production eligible to receive monetized hedge proceeds. As actual production is realized, there may be a corresponding difference in the Partnership's actual share of monetized hedge proceeds received than what was previously estimated. This component is shown as "Difference in estimated monetized gains receivable." A reconciliation of the Partnership's comprehensive income (loss) for the periods indicated is as follows:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Net loss	$	(10,500	)	$	(316,500	)	$	(170,500	)	$	(844,600	)
Other comprehensive income (loss):
Unrealized holding gain on hedging contracts		—			511,400			9,800			1,227,500
MGP portion of non-cash loss on hedge instruments		—			—			207,500			—
Difference in estimated monetized gains receivable		16,900			—			53,900			—
Less: reclassification adjustment for gains realized in net loss		(56,000	)		(68,000	)		(146,900	)		(243,000	)
Total other comprehensive income (loss)		(39,100	)		443,400			124,300			984,500
Comprehensive income (loss)	$	(49,600	)	$	126,900		$	(46,200	)	$	139,900

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Statement Of Changes In Partners' Capital (USD $)	Managing General Partner [Member]	Limited Partners [Member]	Accumulated Other Comprehensive Income [Member]	Total
Balance at Dec. 31, 2010	$ 2,392,500	$ 3,207,800	$ 88,300	$ 5,688,600
Participation in revenues and expenses:
Net production revenues	118,400	468,900		587,300
Depletion	(85,800)	(400,200)		(486,000)
Accretion of asset retirement obligation	(39,700)	(78,900)		(118,600)
General and administrative	(51,300)	(101,900)		(153,200)
Net loss	(58,400)	(112,100)		(170,500)
Other comprehensive income			124,300	124,300
Subordination	(39,400)	39,400		0
Distributions to partners	(356,700)	(633,100)		(989,800)
Balance at Sep. 30, 2011	$ 1,938,000	$ 2,502,000	$ 212,600	$ 4,652,600

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Basis Of Presentation

9 Months Ended

Sep. 30, 2011

Basis Of Presentation

BASIS OF PRESENTATION

NOTE 1 — BASIS OF PRESENTATION

Atlas America Public #15-2005 (A) L.P. (the "Partnership") is a Delaware limited partnership and 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 Energy, L.P., formerly Atlas Pipeline Holdings, L.P. ("Atlas Energy") (NYSE: ATLS). On February 17, 2011, Atlas Energy, 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, and certain well interests in Pennsylvania and Michigan; and its ownership and management of investments in Lightfoot Capital Partners, L.P. and related entities (the "Transferred Business").

Atlas Energy recently announced that it intends to create a newly formed exploration and production master limited partnership named Atlas Resource Partners, L.P. ("Atlas Resource Partners"), which will hold substantially all of ATLS' current natural gas and oil development and production assets and the partnership management business.

Atlas Resources' focus is on the development and/or production of natural gas and oil in the Appalachian, Michigan, Indiana, and/or Colorado basin regions of the United States of America. Atlas Resources is also a leading sponsor of and manages tax-advantaged direct investment partnerships, in which it co-invests to finance the exploitation and development of its acreage. Atlas Energy Resource Services, Inc. provides Atlas Resources with the personnel necessary to manage its assets and raise capital.

The accompanying financial statements, which are unaudited except that the balance sheet at December 31, 2010 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 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, 2010. The results of operations for the three and nine months ended September 30, 2011 may not necessarily be indicative of the results of operations for the year ended December 31, 2011.

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Balance Sheets (USD $)	Sep. 30, 2011	Dec. 31, 2010
ASSETS
Cash and cash equivalents	$ 76,200	$ 115,500
Accounts receivable-affiliate	705,900	471,400
Short-term hedge receivable due from affiliate		466,800
Total current assets	782,100	1,053,700
Oil and gas properties, net	6,427,400	6,913,400
Long-term hedge receivable due from affiliate		456,300
Long-term receivable-affiliate	209,400
TOTAL ASSETS	7,418,900	8,423,400
LIABILITIES AND PARTNERS' CAPITAL
Accrued liabilities	11,800	13,500
Short-term hedge liability due to affiliate		4,600
Total current liabilities	11,800	18,100
Asset retirement obligation	2,754,500	2,635,900
Long-term hedge liability due to affiliate		80,800
Partners' capital:
Managing general partner	1,938,000	2,392,500
Limited partners (5,227.40 units)	2,502,000	3,207,800
Accumulated other comprehensive income	212,600	88,300
Total partners' capital	4,652,600	5,688,600
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$ 7,418,900	$ 8,423,400