10-Q

United States

Securities and Exchange Commission

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2013

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

For the transition period from to 

Commission file number 000-51944

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

(Name of small business issuer in its charter)

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

(412)-489-0006

Issuer’s telephone number, including area code:

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  xNo  ¨

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  xNo  ¨

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

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

       

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

(A Delaware Limited Partnership)

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

PART I.	FINANCIAL INFORMATION	PAGE
Item 1:	Condensed Balance Sheets as of September 30, 2013 and December 31, 2012	3
	Condensed Statements of Operations for the three and nine months ended September 30, 2013 and 2012	4
	Condensed Statements of Comprehensive Loss for the three and nine months ended September 30, 2013 and 2012	5
	Condensed Statement of Changes in Partners’ Capital for the nine months ended September 30, 2013	6
	Condensed Statements of Cash Flows for the nine months ended September 30, 2013 and 2012	7
	Notes to Condensed Financial Statements	8
Item 2:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 4:	Controls and Procedures	21
PART II	OTHER INFORMATION
Item 1:	Legal Proceedings	22
Item 6:	Exhibits	22
SIGNATURES		23
CERTIFICATIONS

 2 

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

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

CONDENSED BALANCE SHEETS

(Unaudited)

	September 30, 2013			December 31, 2012
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	15,200
Accounts receivable trade-affiliate		397,800			256,500
Accounts receivable monetized gains-affiliate		21,500			69,500
Current portion of derivative assets		2,500			3,200
Total current assets		421,800			344,400
Oil and gas properties, net		3,351,200			3,702,900
Long-term derivative assets		8,800			13,000
	$	3,781,800		$	4,060,300
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	13,200		$	1,700
Total current liabilities		13,200			1,700
Asset retirement obligation		3,093,500			2,972,300
Long-term put premiums payable-affiliate		10,400			3,000
Commitments and contingencies		—			—
Partners’ capital:
Managing general partner’s interest		847,500			948,800
Limited partners’ interest (5,227.40 units)		(172,700	)		151,500
Accumulated other comprehensive loss		(10,100	)		(17,000	)
Total partners’ capital		664,700			1,083,300
	$	3,781,800		$	4,060,300

See accompanying notes to condensed financial statements.

 3 

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

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
REVENUES
Natural gas and oil	$	455,500		$	302,700		$	1,307,600		$	911,600
Total revenues		455,500			302,700			1,307,600			911,600
COSTS AND EXPENSES
Production		254,900			232,700			764,600			708,000
Depletion		123,100			87,300			351,600			281,600
Accretion of asset retirement obligation		40,400			37,100			121,200			111,300
General and administrative		47,300			51,300			142,800			150,000
Total costs and expenses		465,700			408,400			1,380,200			1,250,900
Net loss	$	(10,200	)	$	(105,700	)	$	(72,600	)	$	(339,300	)
Allocation of net loss:
Managing general partner	$	(2,600	)	$	(19,700	)	$	(21,800	)	$	(77,300	)
Limited partners	$	(7,600	)	$	(86,000	)	$	(50,800	)	$	(262,000	)
Net loss per limited partnership unit	$	(1	)	$	(16	)	$	(10	)	$	(50	)

See accompanying notes to condensed financial statements.

 4 

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

CONDENSED STATEMENTS OF COMPREHENSIVE LOSS

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Net loss	$	(10,200	)	$	(105,700	)	$	(72,600	)	$	(339,300	)
Other comprehensive income (loss):
Unrealized holding gain (loss) on cash flow hedging contracts		2,200			(9,500	)		(8,300	)		(11,800	)
Difference in estimated hedge gains receivable		16,000			11,900			51,900			85,500
Reclassification adjustment for gains realized in net loss from cash flow hedges		(13,400	)		(13,000	)		(36,700	)		(90,100	)
Total other comprehensive income (loss)		4,800			(10,600	)		6,900			(16,400	)
Comprehensive loss	$	(5,400	)	$	(116,300	)	$	(65,700	)	$	(355,700	)

See accompanying notes to condensed financial statements.

 5 

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

CONDENSED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

FOR THE NINE MONTHS ENDED

September 30, 2013

(Unaudited)

	Managing General Partner			Limited Partners			Accumulated Other Comprehensive (Loss) Income			Total
Balance at January 1, 2013	$	948,800		$	151,500		$	(17,000	)	$	1,083,300
Participation in revenues and expenses:
Net production revenues		176,000			367,000			—			543,000
Depletion		(109,400	)		(242,200	)		—			(351,600	)
Accretion of asset retirement obligation		(40,600	)		(80,600	)		—			(121,200	)
General and administrative		(47,800	)		(95,000	)		—			(142,800	)
Net loss		(21,800	)		(50,800	)		—			(72,600	)
Other comprehensive income		—			—			6,900			6,900
Distributions to partners		(79,500	)		(273,400	)		—			(352,900	)
Balance at September 30, 2013	$	847,500		$	(172,700	)	$	(10,100	)	$	664,700

See accompanying notes to condensed financial statements.

 6 

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

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2013			2012
Cash flows from operating activities:
Net loss	$	(72,600	)	$	(339,300	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion		351,600			281,600
Non-cash loss on derivative value		67,200			122,300
Accretion of asset retirement obligation		121,200			111,300
(Increase) decrease in accounts receivable-affiliate		(141,300	)		156,600
Increase in accrued liabilities		11,500			1,800
Net cash provided by operating activities		337,600			334,300
Cash flows from investing activities:
Proceeds from sale of tangible equipment		100			5,600
Net cash provided by investing activities		100			5,600
Cash flows from financing activities
Distributions to partners		(352,900	)		(420,400	)
Net cash used in financing activities		(352,900	)		(420,400	)
Net decrease in cash and cash equivalents		(15,200	)		(80,500	)
Cash and cash equivalents at beginning of period		15,200			80,500
Cash and cash equivalents at end of period	$	—		$	—

See accompanying notes to condensed financial statements.

 7 

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

NOTES TO CONDENSED FINANCIAL STATEMENTS

September 30, 2013

(Unaudited)

NOTE 1—DESCRIPTION OF BUSINESS

Atlas America Public #15-2005 (A) L.P. (the “Partnership”) is a Delaware limited partnership, formed on July 25, 2005 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP).

In March 2012, the MGP’s ultimate parent, Atlas Energy L.P. (“Atlas Energy”) (NYSE: ATLS), contributed to ARP, a newly-formed exploration and production master limited partnership, substantially all of Atlas Energy’s natural gas and oil development and production assets and its partnership management business, including ownership of the MGP.

On February 17, 2011, Atlas Energy L.P., formerly known as Atlas Pipeline Holdings, L.P. (“Atlas Energy”) (NYSE: ATLS), a then-majority owned subsidiary of Atlas Energy, Inc. and parent of the general partner of Atlas Pipeline Partners, L.P. (“APL”) (NYSE: APL), completed an acquisition of assets from Atlas Energy, Inc., which included its investment partnership business, its oil and gas exploration, development and production activities conducted in Tennessee, Indiana, and Colorado, certain shallow wells and leases in New York and Ohio, certain well interests in Pennsylvania and Michigan and its ownership and management of investments in Lightfoot Capital Partners, L.P. and related entities (the “Transferred Business”).

The Partnership has drilled and currently operates wells located in Pennsylvania and Tennessee. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy, for administrative services.

The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through affiliated and or third-party gas gathering systems. The Partnership does not plan to sell any of its wells and intends to produce them until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. The Partnership expects that no other wells will be drilled and no additional funds will be required for drilling.

The accompanying condensed financial statements, which are unaudited, except that the condensed balance sheet at December 31, 2012 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in the Partnership’s Form 10-K. These interim financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2012. The results of operations for the three and nine months ended September 30, 2013 may not necessarily be indicative of the results of operations for the year ended December 31, 2013.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

In addition to matters discussed further in this note, the Partnership’s significant accounting policies are detailed in its audited financial statements and notes thereto in the Partnership’s annual report on Form 10-K for the year ended December 31, 2012 filed with the Securities and Exchange Commission (“SEC”).

 8 

Use of Estimates

Preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, asset impairments, fair value of derivative instruments and the probability of forecasted transactions. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions as much as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following months’ financial results. Management believes that the operating results presented for the three and nine months ended September 30, 2013 and 2012 represent actual results in all material respects (see “Revenue Recognition” accounting policy for further description).

Accounts Receivable and Allowance for Possible Losses

In evaluating the need for an allowance for possible losses, the MGP performs ongoing credit evaluations of the Partnership’s customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness as determined by review of such customers’ credit information. Credit is extended on an unsecured basis to many of the Partnership’s energy customers. At September 30, 2013 and December 31, 2012, the MGP’s credit evaluation indicated that the Partnership had no need for an allowance for possible losses.

Oil and Gas Properties

Oil and gas properties are stated at cost. Maintenance and repairs that generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized.

The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to six mcf of natural gas.

The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties. The Partnership recorded depletion expense on natural gas and oil properties of $351,600 and $281,600 for the nine months ended September 30, 2013 and 2012, respectively.

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

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

	September 30, 2013			December 31, 2012
Proved properties:
Leasehold interest	$	1,526,600		$	1,526,600
Wells and related equipment		65,092,100			65,092,200
Total natural gas and oil properties		66,618,700			66,618,800
Accumulated depletion and impairment		(63,267,500	)		(62,915,900	)
Oil and gas properties, net	$	3,351,200		$	3,702,900

 9 

Impairment of Long-Lived Assets

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

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

The determination of oil and natural gas reserve estimates is a subjective process and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.

In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. The Partnership may have to pay additional consideration in the future as a well becomes uneconomic under the terms of the Partnership Agreement in order to recover these reserves. There were no impairments recorded during the three and nine months ended September 30, 2013 and 2012. During the year ended December 31, 2012, the Partnership recognized an impairment charge of $162,600.

Working Interest

The Partnership Agreement establishes that revenues and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). The MGP is also provided an additional working interest of 7% as provided in the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expenses until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues and expenses based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.

Revenue Recognition

The Partnership generally sells natural gas and crude oil at prevailing market prices. Generally, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil, in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of working interest and/or overriding royalty.

 10 

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGL’s, crude oil, and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees, which are, in turn, based upon applicable product prices. The Partnership had unbilled revenues at September 30, 2013 and December 31, 2012 of $242,500 and $219,600, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.

Comprehensive loss

Comprehensive loss includes net loss and all other changes in equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States of America, have not been recognized in the calculation of net loss. These changes, other than net loss, are referred to as “other comprehensive loss” and, for the Partnership, include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges.

Recently Adopted Accounting Standards

In July 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-10, Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes (“Update 2013-10”). Currently, Topic 815 provides guidance on the risks that are permitted to be hedged in a fair value or cash flow hedge. In addition, only the interest rates on direct Treasury obligations of the U.S. Government (“UST”) and the London Interbank Offered Rate (“LIBOR”) swap rate are considered benchmark interest rates. Update 2013-10 amends Topic 815 to include the Overnight Index Swap Rate (“OIS”), also referred to as the Fed Funds Effective Swap Rate, as a U.S. benchmark interest rate for hedge accounting purposes. Including the OIS as an acceptable U.S. benchmark interest rate in addition to UST and LIBOR will provide risk managers with a more comprehensive spectrum of interest rate resets to utilize as the designated benchmark interest rate risk component under the hedge accounting guidance in Topic 815. Update 2013-10 is effective for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. The Partnership adopted the requirements of Update 2013-10 upon its effective date of July 17, 2013, and it had no material impact on its financial position, results of operations or related disclosures.

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

Recently Issued Accounting Standards

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

 11 

NOTE 3—ASSET RETIREMENT OBLIGATION

The Partnership recognized an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. It also recognizes a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considered the estimated salvage value in the depletion calculation. The estimated liability is based on the MGP’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in cost estimates, remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for the Partnership’s gas and oil properties, the Partnership determined that there were no other material retirement obligations associated with tangible long-lived assets.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Asset retirement obligation at beginning of period	$	3,053,100	$	2,985,500	$	2,972,300	$	2,911,300
Accretion expense		40,400		37,100		121,200		111,300
Asset retirement obligation at end of period	$	3,093,500	$	3,022,600	$	3,093,500	$	3,022,600

NOTE 4—DERIVATIVE INSTRUMENTS

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

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

 12 

The Partnership enters into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s balance sheets as the initial value of the options. The Partnership reflected net derivative assets on its balance sheet of $11,300 and $16,200 at September 30, 2013 and December 31, 2012, respectively.

The Partnership enters into commodity future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in commodity prices. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. NGL fixed price swaps are priced based on a WTI crude oil index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.

At September 30, 2013, the Partnership had the following commodity derivatives:

Natural Gas Put Options

Production Period Ending December 31,	Volumes (MMBtu) (1)	Average Fixed Price (per MMBtu) (1)		Fair Value Asset (2)
2013	3,200	$	3.45	$	100
2014	10,500		3.80		3,200
2015	8,400		4.00		3,500
2016	8,400		4.15		4,500
				$	11,300

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

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

Effects of Derivative Instruments on Statements of Operations:

The following table summarizes the gain or loss recognized in the statements of operations for effective derivative instruments for the three and nine months ended September 30, 2013 and 2012:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Gains from cash flow hedges reclassified from accumulated other comprehensive loss into natural gas and oil revenues	$	13,400	$	13,000	$	36,700	$	90,100

As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three and nine months ended September 30, 2013 and 2012 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

 13 

Monetized Gains

Prior to February 17, 2011 (date of the Transferred Business), Atlas Energy Inc., (“AEI”) monetized its derivative instruments, including those related to the future natural gas and oil production of the Transferred Business. AEI also monetized derivative instruments that were specifically related to the future natural gas and oil production of the Partnership. At September 30, 2013 and December 31, 2012, remaining hedge monetization cash proceeds of $27,600 and $75,500 related to the amounts hedged on behalf of the Partnership’s limited partners were included within accounts receivable monetized gains-affiliate, respectively, and $3,200 and $15,100 in long-term put premiums payable-affiliate, respectively, on the Partnership’s balance sheets. The Partnership will allocate the monetized net proceeds to the limited partners based on the natural gas and oil production generated over the period of the original derivative contracts.

During June 2012, the MGP used the undistributed monetized funds to purchase natural gas put options on behalf of the limited partners of the Partnership only. A premium (“put premium”) was paid to purchase the contracts and will be allocated to natural gas production revenues generated over the contractual term of the purchased hedging instruments. At September 30, 2013 and December 31, 2012, the put premiums were recorded as short-term payables to affiliate of $6,100 and $6,000, respectively, and long-term payables to affiliate of $13,600 and $18,100, respectively. Furthermore, the current portion of the put premium liability was included in accounts receivable monetized gains-affiliate and the long-term receivable monetized gains-affiliate was included in long term put premiums payable-affiliate in the Partnership’s balance sheets, presenting the impact of offsetting the related party assets and liabilities. The put premiums included on the Partnership’s balance sheets are allocable to the limited partners only.

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

Offsetting Assets	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheets			Net Amount of Assets Presented in the Balance Sheets
As of September 30, 2013
Accounts receivable monetized gains-affiliate	$	27,600	$	(6,100	)	$	21,500
Long-term receivable monetized gains-affiliate		3,200		(3,200	)		—
Total	$	30,800	$	(9,300	)	$	21,500
As of December 31, 2012
Accounts receivable monetized gains-affiliate	$	75,500	$	(6,000	)	$	69,500
Long-term receivable monetized gains-affiliate		15,100		(15,100	)		—
Total	$	90,600	$	(21,100	)	$	69,500

Offsetting Liabilities	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheets		Net Amount of Liabilities Presented in the Balance Sheets
As of September 30, 2013
Put premiums payable-affiliate	$	(6,100	)	$	6,100	$	—
Long-term put premiums payable-affiliate		(13,600	)		3,200		(10,400	)
Total	$	(19,700	)	$	9,300	$	(10,400	)
As of December 31, 2012
Put premiums payable-affiliate	$	(6,000	)	$	6,000	$	—
Long-term put premiums payable-affiliate		(18,100	)		15,100		(3,000	)
Total	$	(24,100	)	$	21,100	$	(3,000	)

 14 

Accumulated Other Comprehensive Loss

As a result of the monetization and the early settlement of natural gas and oil derivative instruments, the put options, and the unrealized gains recognized in earnings in prior periods due to natural gas and oil property impairments, the Partnership recorded a net deferred loss on its balance sheets in accumulated other comprehensive loss of $10,100 as of September 30, 2013. Included in accumulated other comprehensive loss are unrealized gains of $32,500 net of the MGP interest, that were recognized into earnings as a result of oil and gas property impairments during prior periods. During the current year, $17,500 of net gains were recorded by the Partnership and allocated only to the limited partners. Of the remaining $10,100 of net unrealized loss in accumulated other comprehensive loss, the Partnership will reclassify $5,100 of net losses to the Partnership’s statements of operations over the next twelve month period and the remaining losses of $5,000 in later periods.

NOTE 5—FAIR VALUE OF FINANCIAL INSTRUMENTS

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

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

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

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The carrying values of cash, accounts receivable, and accounts payable approximate their respective fair values due to the short term maturities of such financial instruments. The Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 4). The Partnership manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty. The Partnership’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. These derivative instruments are calculated by utilizing commodity indices, quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument.

 15 

Information for assets and liabilities measured at fair value at September 30, 2013 and December 31, 2012 was as follows:

	Level 1		Level 2		Level 3		Total
As of September 30, 2013
Derivative assets, gross
Commodity puts	$	—	$	11,300	$	—	$	11,300
Derivative liabilities, gross
Commodity puts		—		—		—		—
Total derivative, fair value, net	$	—	$	11,300	$	—	$	11,300
As of December 31, 2012
Derivative assets, gross
Commodity puts	$	—	$	16,200	$	—	$	16,200
Derivative liabilities, gross
Commodity puts		—		—		—		—
Total derivative, fair value, net	$	—	$	16,200	$	—	$	16,200

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

The Partnership estimates the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates (see Note 3). There were no additional assets or liabilities that were measured at fair value on a nonrecurring basis for the three and nine months ended September 30, 2013 and 2012.

NOTE 6—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The Partnership has entered into the following significant transactions with the MGP and its affiliates as provided under its Partnership Agreement. Administrative costs, which are included in general and administrative expenses in the Partnership’s statements of operations, are payable at $75 per well per month. Monthly well supervision fees which are included in production expenses in the Partnership’s statements of operations are payable at $296 per well per month for operating and maintaining the wells. Transportation fees, which are included in production expenses in the Partnership’s statements of operations, are generally payable at 13% of the natural gas sales price.

The following table provides information with respect to these costs and the periods incurred.

	Three Months Ended September 30,				Nine Months Ended September 30,
		2013		2012		2013		2012
Administrative	$	29,000	$	30,300	$	92,300	$	95,400
Supervision		114,700		119,900		364,700		377,100
Transportation		54,800		40,000		164,100		126,500
Total	$	198,500	$	190,200	$	621,100	$	599,000

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

 16 

NOTE 7—COMMITMENTS AND CONTINGENCIES

General Commitments

Subject to certain conditions, investor partners may present their interests beginning in 2010 for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. The MGP is not obligated to purchase more than 5% of the units in any calendar year. In the event that the MGP is unable to obtain the necessary funds, it may suspend its purchase obligation.

Beginning one year after each of the Partnership’s wells has been placed into production, the MGP, as operator, may retain $200 per month per well to cover estimated future plugging and abandonment costs. As of September 30, 2013, the MGP has not withheld any such funds. The MGP is currently evaluating its right to exercise this option based on several factors such as commodity prices, the natural decline in well production, and current and future plugging services and costs.

Legal Proceedings

The Partnership is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations.

 17 

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.

General

Atlas America Public #15-2005 (A) L.P. (“we”, “us” or the “Partnership”) is a Delaware limited partnership, formed on July 25, 2005 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP).

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

We do not plan to sell any of our wells and intend to produce them until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. We expect that no other wells will be drilled and no additional funds will be required for drilling.

Overview

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

· well tending, routine maintenance and adjustment;

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

· preparation of reports for us and government agencies.

The well supervision fees, however, do not include costs and expenses related to the purchase of certain equipment, materials, and brine disposal. If these expenses are incurred, we pay cost for third-party services, materials, and a competitive charge for services performed directly by our MGP or its affiliates. Also, beginning one year after each of our wells has been placed into production, our MGP, as operator, may retain $200 per month, per well to cover the estimated future plugging and abandonment costs of the well. As of September 30, 2013, our MGP had not withheld any funds for this purpose.

Markets and Competition

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

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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 September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Production revenues (in thousands):
Gas	$	402		$	253		$	1,184		$	812
Oil		54			50			124			100
Total	$	456		$	303		$	1,308		$	912
Production volumes:
Gas (mcf/day) (1)		1,125			911			1,087			1,022
Oil (bbls/day) (1)		6			7			5			4
Total (mcfe/day) (1)		1,161			953			1,117			1,046
Average sales prices (2)
Gas (per mcf) (1) (3)	$	4.07		$	3.47		$	4.22		$	3.34
Oil (per bbl) (1) (4)	$	97.07		$	82.85		$	90.31		$	88.33
Production costs:
As a percent of revenues		56	%		77	%		58	%		78	%
Per mcfe (1)	$	2.39		$	2.66		$	2.51		$	2.47
Depletion per mcfe	$	1.15		$	1.00		$	1.15		$	0.98

(1)	“Mcf” represents thousand cubic feet, “mcfe” represents thousand cubic feet equivalent, and “bbl” represents barrels. Bbl is converted to mcfe using the ratio of six mcf to one bbl.
(2)	Average sales prices represent accrual basis pricing after adjusting for the effect of previously recognized gains resulting from prior period impairment charges.
(3)	Average gas prices are calculated by including in total revenue derivative gains previously recognized into income in connection with prior period impairment charges and dividing by the total volume for the period. Previously recognized derivative gains were $19,900 and $38,100 for the three months ended September 30, 2013 and 2012, respectively. Previously recognized derivative gains were $67,300 and $123,000 for the nine months ended September 30, 2013 and 2012, respectively.
(4)	Average oil prices are calculated by including in total revenue derivative gains previously recognized into income in connection with prior period impairment charges and dividing by the total volume for the period. Previously recognized derivative gains were $100 for the three months ended September 30, 2013.

Natural Gas Revenues. Our natural gas revenues were $401,400 and $252,900 for the three months ended September 30, 2013 and 2012, respectively, an increase of $148,500 (59%). The $148,500 increase in natural gas revenues for the three months ended September 30, 2013 as compared to the prior year similar period was attributable to a $89,200 increase in our natural gas sales prices after the effect of financial hedges, which was driven by market conditions and a $59,300 increase in production volumes. Our production volumes increased to 1,125 mcf per day for the three months ended September 30, 2013 from 911 mcf per day for the three months ended September 30, 2012, an increase of 214 mcf per day (23%). Production increased due to an increase in available pipeline capacity.

Our natural gas revenues were $1,183,700 and $811,800 for the nine months ended September 30, 2013 and 2012, respectively, an increase of $371,900 (46%). The $371,900 increase in natural gas revenues for the nine months ended September 30, 2013 as compared to the prior year similar period was attributable to a $323,400 increase in our natural gas sales prices after the effect of financial hedges, which was driven by market conditions and an $48,500 increase in production volumes. Our production volumes increased to 1,087 mcf per day for the nine months ended September 30, 2013 from 1,022 mcf per day for the nine months ended September 30, 2012, an increase of 65 mcf per day (6%) Production increased due to an increase in available pipeline capacity.

 19 

Oil Revenues. We drill wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $54,100 and $49,800 for the three months ended September 30, 2013 and 2012, respectively, an increase of $4,300 (9%). The $4,300 increase in oil revenues for the three months ended September 30, 2013 as compared to the prior year similar period was attributable to a $7,800 increase in oil prices after the effect of financial hedges, partially offset by a $3,500 decrease in production volumes. Our production volumes decreased to 6 bbls per day for the three months ended September 30, 2013 from 7 bbls per day for the three months ended September 30, 2012, a decrease of 1 bbl per day (14%).

Our oil revenues were $123,900 and $99,800 for the nine months ended September 30, 2013 and 2012, respectively, an increase of $24,100 (24%). The $24,100 increase in oil revenues for the nine months ended September 30, 2013 as compared to the prior year similar period was attributable to a $21,400 increase in production volumes and a $2,700 increase in oil prices after the effect of financial hedges. Our production volumes increased to 5 bbls per day for the nine months ended September 30, 2013 from 4 bbls per day for the nine months ended September 30, 2012, an increase of 1 bbl per day (25%).

Costs and Expenses. Production expenses were $254,900 and $232,700 for the three months ended September 30, 2013 and 2012, respectively, an increase of $22,200 (10%). Production expenses were $764,600 and $708,000 for the nine months ended September 30, 2013 and 2012, respectively, an increase of $56,600 (8%). The increases for the three and nine months ended September 30, 2013 were mostly due to higher transportation fees.

Depletion of oil and gas properties as a percentage of oil and gas revenues was 27% and 29% for the three months ended September 30, 2013 and 2012, respectively, and 27% and 31% for the nine months ended September 30, 2013 and 2012, respectively. These percentage changes are directly attributable to changes in revenues, oil and gas reserve quantities, product prices and production volumes and changes in the depletable cost basis of oil and gas properties.

General and administrative expenses for the three months ended September 30, 2013 and 2012 were $47,300 and $51,300, respectively, a decrease of $4,000 (8%). For the nine months ended September 30, 2013 and 2012 these expenses were $142,800 and $150,000, respectively, a decrease of $7,200 (5%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP. The decreases for the three and nine months ended September 30, 2013 are primarily due to third-party costs as compared to the prior year similar period.

Liquidity and Capital Resources

Cash provided by operating activities increased $3,300 in the nine months ended September 30, 2013 to $337,600 as compared to $334,300 for the nine months ended September 30, 2012. This increase was due to an increase in the change in net income before depletion and accretion of $346,600 and an increase in the change in accrued liabilities of $9,700. The increase was partially offset by a decrease in the change in accounts receivable trade-affiliate of $297,900 and a decrease in the non-cash loss on hedge instruments of $55,100, for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012.

Cash provided by investing activities was $100 and $5,600 for the nine months ended September 30, 2013 and 2012, respectively, resulting from proceeds received from the sale of tangible equipment.

Cash used in financing activities decreased $67,500 during the nine months ended September 30, 2013 to $352,900 from $420,400 for the nine months ended September 30, 2012. This decrease was due to a decrease in cash distributions to partners.

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

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

 20 

Critical Accounting Policies

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

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Under the supervision of our Chairman of the Board of Directors, Chief Executive Officer, President, and Chief Financial Officer, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, concluded that, at September 30, 2013, our disclosure controls and procedures were effective at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

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

 21 

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of their collective business. The MGP’s management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the MGP’s financial condition or results of operations.

ITEM 6. EXHIBITS

EXHIBIT INDEX

Exhibit No.	Description
4.0	Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #15-2005 L.P. (A) (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

 22 

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 12, 2013	By:	/S/ FREDDIE M. KOTEK
		Freddie M. Kotek, Chairman of the Board of Directors, Chief Executive Officer and President
In accordance with the Exchange Act, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Date: November 12, 2013	By:	/S/ SEAN P. MCGRATH
		Sean P. McGrath, Chief Financial Officer

 23 

EX-31

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, 2013 of Atlas America Public #15-2005 (A) L.P.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have;
	(a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within the entity, particularly during the period in which this report is being prepared;
	(b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	(a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
	By:		/S/ FREDDIE M. KOTEK
	Name:		Freddie M. Kotek
	Title:		Chief Executive Officer of the Managing General Partner
	Date		November 12, 2013

   

EX-31

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, 2013 of Atlas America Public #15-2005 (A) L.P.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have;
	(a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within the entity, particularly during the period in which this report is being prepared;
	(b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	(a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
	By:		/S/ SEAN P. MCGRATH
	Name:		Sean P. McGrath
	Title:		Chief Financial Officer of the Managing General Partner
	Date		November 12, 2013

   

EX-32

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, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Freddie M. Kotek, Chief Executive Officer of the Managing General Partner, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and
(2)	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

By:	/S/ FREDDIE M. KOTEK
Name:	Freddie M. Kotek
Title:	Chief Executive Officer of the Managing General Partner
Date	November 12, 2013

   

EX-32

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, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Sean P. McGrath, Chief Financial Officer of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and
(2)	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

By:	/S/ SEAN P. MCGRATH
Name:	Sean P. McGrath
Title:	Chief Financial Officer of the Managing General Partner
Date	November 12, 2013

   

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Asset Retirement Obligation (Tables)

9 Months Ended

Sep. 30, 2013

Schedule of Asset Retirement Obligation

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

	ThreeMonthsEnded September30,				NineMonthsEnded September30,
	2013		2012		2013		2012
Asset retirement obligation at beginning of period	$	3,053,100	$	2,985,500	$	2,972,300	$	2,911,300
Accretion expense		40,400		37,100		121,200		111,300
Asset retirement obligation at end of period	$	3,093,500	$	3,022,600	$	3,093,500	$	3,022,600

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Asset Retirement Obligation

9 Months Ended

Sep. 30, 2013

ASSET RETIREMENT OBLIGATION

NOTE 3—ASSET RETIREMENT OBLIGATION

The Partnership recognized an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. It also recognizes a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considered the estimated salvage value in the depletion calculation. The estimated liability is based on the MGP’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in cost estimates, remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for the Partnership’s gas and oil properties, the Partnership determined that there were no other material retirement obligations associated with tangible long-lived assets.

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

	ThreeMonthsEnded September30,				NineMonthsEnded September30,
	2013		2012		2013		2012
Asset retirement obligation at beginning of period	$	3,053,100	$	2,985,500	$	2,972,300	$	2,911,300
Accretion expense		40,400		37,100		121,200		111,300
Asset retirement obligation at end of period	$	3,093,500	$	3,022,600	$	3,093,500	$	3,022,600

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Asset Retirement Obligation (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Asset Retirement Obligation [Abstract]
Asset retirement obligation at beginning of period	$ 3,053,100	$ 2,985,500	$ 2,972,300	$ 2,911,300
Accretion expense	40,400	37,100	121,200	111,300
Asset retirement obligation at end of period	$ 3,093,500	$ 3,022,600	$ 3,093,500	$ 3,022,600

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2013

Effects of Derivative Instruments on Statements of Operations

Effects of Derivative Instruments on Statements of Operations:

The following table summarizes the gain or loss recognized in the statements of operations for effective derivative instruments for the three and nine months ended September30, 2013 and 2012:

	ThreeMonthsEnded September30,				NineMonthsEnded September30,
	2013		2012		2013		2012
Gains from cash flow hedges reclassified from accumulated other comprehensive loss into natural gas and oil revenues	$	13,400	$	13,000	$	36,700	$	90,100

Offsetting Derivative Assets

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

Offsetting Assets	GrossAmounts of Recognized Assets		GrossAmounts Offset in the Balance Sheets			NetAmountofAssets PresentedintheBalance Sheets
As of September30, 2013
Accounts receivable monetized gains-affiliate	$	27,600	$	(6,100	)	$	21,500
Long-term receivable monetized gains-affiliate		3,200		(3,200	)		-
Total	$	30,800	$	(9,300	)	$	21,500
As of December31, 2012
Accounts receivable monetized gains-affiliate	$	75,500	$	(6,000	)	$	69,500
Long-term receivable monetized gains-affiliate		15,100		(15,100	)		-
Total	$	90,600	$	(21,100	)	$	69,500

Offsetting Derivative Liabilities

Offsetting Liabilities	GrossAmounts ofRecognized Liabilities			GrossAmounts Offsetinthe BalanceSheets		NetAmountofLiabilities PresentedintheBalance Sheets
As of September30, 2013
Put premiums payable-affiliate	$	(6,100	)	$	6,100	$	-
Long-term put premiums payable-affiliate		(13,600	)		3,200		(10,400	)
Total	$	(19,700	)	$	9,300	$	(10,400	)
As of December31, 2012
Put premiums payable-affiliate	$	(6,000	)	$	6,000	$	-
Long-term put premiums payable-affiliate		(18,100	)		15,100		(3,000	)
Total	$	(24,100	)	$	21,100	$	(3,000	)

Natural Gas Put Options

Commodity Derivatives

The Partnership enters into commodity future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in commodity prices. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. NGL fixed price swaps are priced based on a WTI crude oil index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.

At September30, 2013, the Partnership had the following commodity derivatives:

Natural Gas Put Options

ProductionPeriodEnding December31,	Volumes (MMBtu) (1)	Average FixedPrice (perMMBtu)(1)		FairValue Asset (2)
2013	3,200	$	3.45	$	100
2014	10,500		3.80		3,200
2015	8,400		4.00		3,500
2016	8,400		4.15		4,500
				$	11,300

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

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

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Derivative Instruments (Offsetting Derivative Assets) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	$ 30,800	$ 90,600
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset in the Balance Sheets	(9,300)	(21,100)
Affiliate Balances, Offsetting Derivative Assets, Net Amount of Assets Presented in the Balance Sheets	21,500	69,500
Accounts receivable monetized gains-affiliate
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	27,600	75,500
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset in the Balance Sheets	(6,100)	(6,000)
Affiliate Balances, Offsetting Derivative Assets, Net Amount of Assets Presented in the Balance Sheets	21,500	69,500
Long-term receivable monetized gains-affiliate
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	3,200	15,100
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset in the Balance Sheets	$ (3,200)	$ (15,100)

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Derivative Instruments (Effects of Derivative Instruments on Statements of Operations) (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Gains from cash flow hedges reclassified from accumulated other comprehensive loss into natural gas and oil revenues	$ 13,400	$ 13,000	$ 36,700	$ 90,100

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Certain Relationships and Related Party Transactions (Schedule of Related Party Transactions) (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 198,500	$ 190,200	$ 621,100	$ 599,000
Administrative
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	29,000	30,300	92,300	95,400
Supervision
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	114,700	119,900	364,700	377,100
Transportation
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 54,800	$ 40,000	$ 164,100	$ 126,500

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Derivative Instruments (Commodity Derivatives) (Details) (USD $)					9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013 Natural Gas Put Options		Sep. 30, 2013 Natural Gas Put Options Production Period Ending December 31, 2013 MMBTU		Sep. 30, 2013 Natural Gas Put Options Production Period Ending December 31, 2014 MMBTU		Sep. 30, 2013 Natural Gas Put Options Production Period Ending December 31, 2015 MMBTU		Sep. 30, 2013 Natural Gas Put Options Production Period Ending December 31, 2016 MMBTU
Derivative [Line Items]
Volumes (MMBtu)					3,200	[1]	10,500	[1]	8,400	[1]	8,400	[1]
Average Fixed Price (per MMBtu)					3.45	[1]	3.80	[1]	4.00	[1]	4.15	[1]
Fair Value Asset	$ 11,300	$ 16,200	$ 11,300	[2]	$ 100	[2]	$ 3,200	[2]	$ 3,500	[2]	$ 4,500	[2]

[1] “MMBtu” represents million British Thermal Units.

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

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CONDENSED STATEMENT OF CHANGES IN PARTNERS' CAPITAL (USD $)	Total	Managing General Partner	Limited Partners	Accumulated Other Comprehensive Income (Loss)
Balance at Dec. 31, 2012	$ 1,083,300	$ 948,800	$ 151,500	$ (17,000)
Participation in revenues and expenses:
Net production revenues	543,000	176,000	367,000
Depletion	(351,600)	(109,400)	(242,200)
Accretion of asset retirement obligation	(121,200)	(40,600)	(80,600)
General and administrative	(142,800)	(47,800)	(95,000)
Net loss	(72,600)	(21,800)	(50,800)
Other comprehensive income	6,900			6,900
Distributions to partners	(352,900)	(79,500)	(273,400)
Balance at Sep. 30, 2013	$ 664,700	$ 847,500	$ (172,700)	$ (10,100)

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Description of Business

9 Months Ended

Sep. 30, 2013

DESCRIPTION OF BUSINESS

NOTE 1—DESCRIPTION OF BUSINESS

Atlas America Public #15-2005 (A) L.P. (the “Partnership”) is a Delaware limited partnership, formed on July25, 2005 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP).

In March 2012, the MGP’s ultimate parent, Atlas Energy L.P. (“Atlas Energy”) (NYSE: ATLS), contributed to ARP, a newly-formed exploration and production master limited partnership, substantially all of Atlas Energy’s natural gas and oil development and production assets and its partnership management business, including ownership of the MGP.

On February17, 2011, Atlas Energy L.P., formerly known as Atlas Pipeline Holdings, L.P. (“Atlas Energy”) (NYSE: ATLS), a then-majority owned subsidiary of Atlas Energy, Inc. and parent of the general partner of Atlas Pipeline Partners, L.P. (“APL”) (NYSE: APL), completed an acquisition of assets from Atlas Energy, Inc., which included its investment partnership business, its oil and gas exploration, development and production activities conducted in Tennessee, Indiana, and Colorado, certain shallow wells and leases in New York and Ohio, certain well interests in Pennsylvania and Michigan and its ownership and management of investments in Lightfoot Capital Partners, L.P. and related entities (the “Transferred Business”).

The Partnership has drilled and currently operates wells located in Pennsylvania and Tennessee. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy, for administrative services.

The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through affiliated and or third-party gas gathering systems. The Partnership does not plan to sell any of its wells and intends to produce them until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. The Partnership expects that no other wells will be drilled and no additional funds will be required for drilling.

The accompanying condensed financial statements, which are unaudited, except that the condensed balance sheet at December31, 2012 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in the Partnership’s Form 10-K. These interim financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December31, 2012. The results of operations for the three and nine months ended September30, 2013 may not necessarily be indicative of the results of operations for the year ended December31, 2013.

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Derivative Instruments

9 Months Ended

Sep. 30, 2013

DERIVATIVE INSTRUMENTS

NOTE 4—DERIVATIVE INSTRUMENTS

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

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

The Partnership enters into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s balance sheets as the initial value of the options. The Partnership reflected net derivative assets on its balance sheet of $11,300and $16,200at September30, 2013 and December 31, 2012, respectively.

The Partnership enters into commodity future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in commodity prices. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. NGL fixed price swaps are priced based on a WTI crude oil index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.

At September30, 2013, the Partnership had the following commodity derivatives:

Natural Gas Put Options

ProductionPeriodEnding December31,	Volumes (MMBtu) (1)	Average FixedPrice (perMMBtu)(1)		FairValue Asset (2)
2013	3,200	$	3.45	$	100
2014	10,500		3.80		3,200
2015	8,400		4.00		3,500
2016	8,400		4.15		4,500
				$	11,300

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

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

Effects of Derivative Instruments on Statements of Operations:

The following table summarizes the gain or loss recognized in the statements of operations for effective derivative instruments for the three and nine months ended September30, 2013 and 2012:

	ThreeMonthsEnded September30,				NineMonthsEnded September30,
	2013		2012		2013		2012
Gains from cash flow hedges reclassified from accumulated other comprehensive loss into natural gas and oil revenues	$	13,400	$	13,000	$	36,700	$	90,100

As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three and nine months ended September30, 2013 and 2012 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

Monetized Gains

Prior to February17, 2011 (date of the Transferred Business), Atlas Energy Inc., (“AEI”) monetized its derivative instruments, including those related to the future natural gas and oil production of the Transferred Business. AEI also monetized derivative instruments that were specifically related to the future natural gas and oil production of the Partnership. At September30, 2013 and December31, 2012, remaining hedge monetization cash proceeds of $27,600 and $75,500 related to the amounts hedged on behalf of the Partnership’s limited partners were included within accounts receivable monetized gains-affiliate, respectively, and $3,200 and $15,100 in long-term put premiums payable-affiliate, respectively, on the Partnership’s balance sheets. The Partnership will allocate the monetized net proceeds to the limited partners based on the natural gas and oil production generated over the period of the original derivative contracts.

During June 2012, the MGP used the undistributed monetized funds to purchase natural gas put options on behalf of the limited partners of the Partnership only. A premium (“put premium”) was paid to purchase the contracts and will be allocated to natural gas production revenues generated over the contractual term of the purchased hedging instruments. At September30, 2013 and December31, 2012, the put premiums were recorded as short-term payables to affiliate of $6,100 and $6,000, respectively, and long-term payables to affiliate of $13,600 and $18,100, respectively. Furthermore, the current portion of the put premium liability was included in accounts receivable monetized gains-affiliate and the long-term receivable monetized gains-affiliate was included in long term put premiums payable-affiliate in the Partnership’s balance sheets, presenting the impact of offsetting the related party assets and liabilities. The put premiums included on the Partnership’s balance sheets are allocable to the limited partners only.

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

Offsetting Assets	GrossAmounts of Recognized Assets		GrossAmounts Offset in the Balance Sheets			NetAmountofAssets PresentedintheBalance Sheets
As of September30, 2013
Accounts receivable monetized gains-affiliate	$	27,600	$	(6,100	)	$	21,500
Long-term receivable monetized gains-affiliate		3,200		(3,200	)		-
Total	$	30,800	$	(9,300	)	$	21,500
As of December31, 2012
Accounts receivable monetized gains-affiliate	$	75,500	$	(6,000	)	$	69,500
Long-term receivable monetized gains-affiliate		15,100		(15,100	)		-
Total	$	90,600	$	(21,100	)	$	69,500

Offsetting Liabilities	GrossAmounts ofRecognized Liabilities			GrossAmounts Offsetinthe BalanceSheets		NetAmountofLiabilities PresentedintheBalance Sheets
As of September30, 2013
Put premiums payable-affiliate	$	(6,100	)	$	6,100	$	-
Long-term put premiums payable-affiliate		(13,600	)		3,200		(10,400	)
Total	$	(19,700	)	$	9,300	$	(10,400	)
As of December31, 2012
Put premiums payable-affiliate	$	(6,000	)	$	6,000	$	-
Long-term put premiums payable-affiliate		(18,100	)		15,100		(3,000	)
Total	$	(24,100	)	$	21,100	$	(3,000	)

Accumulated Other Comprehensive Loss

As a result of the monetization and the early settlement of natural gas and oil derivative instruments, the put options, and the unrealized gains recognized in earnings in prior periods due to natural gas and oil property impairments, the Partnership recorded a net deferred loss on its balance sheets in accumulated other comprehensive loss of $10,100 as of September30, 2013. Included in accumulated other comprehensive loss are unrealized gains of $32,500net of the MGP interest, that were recognized into earnings as a result of oil and gas property impairments during prior periods. During the current year, $17,500 of net gains were recorded by the Partnership and allocated only to the limited partners. Of the remaining $10,100 of net unrealized loss in accumulated other comprehensive loss, the Partnership will reclassify $5,100 of net losses to the Partnership’s statements of operations over the next twelve month period and the remaining losses of $5,000 in later periods.

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2013

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

In addition to matters discussed further in this note, the Partnership’s significant accounting policies are detailed in its audited financial statements and notes thereto in the Partnership’s annual report on Form 10-K for the year ended December31, 2012 filed with the Securities and Exchange Commission (“SEC”).

Use of Estimates

Preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, asset impairments, fair value of derivative instruments and the probability of forecasted transactions. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions as much as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following months’ financial results. Management believes that the operating results presented for the three and nine months ended September30, 2013 and 2012 represent actual results in all material respects (see “Revenue Recognition” accounting policy for further description).

Accounts Receivable and Allowance for Possible Losses

In evaluating the need for an allowance for possible losses, the MGP performs ongoing credit evaluations of the Partnership’s customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness as determined by review of such customers’ credit information. Credit is extended on an unsecured basis to many of the Partnership’s energy customers. At September30, 2013 and December31, 2012, the MGP’s credit evaluation indicated that the Partnership had no need for an allowance for possible losses.

Oil and Gas Properties

Oil and gas properties are stated at cost. Maintenance and repairs that generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized.

The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to six mcf of natural gas.

The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties. The Partnership recorded depletion expense on natural gas and oil properties of $351,600 and $281,600 for the nine months ended September30, 2013 and 2012, respectively.

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

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

	September30, 2013			December31, 2012
Proved properties:
Leasehold interest	$	1,526,600		$	1,526,600
Wells and related equipment		65,092,100			65,092,200
Total natural gas and oil properties		66,618,700			66,618,800
Accumulated depletion and impairment		(63,267,500	)		(62,915,900	)
Oil and gas properties, net	$	3,351,200		$	3,702,900

Impairment of Long-Lived Assets

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

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

The determination of oil and natural gas reserve estimates is a subjective process and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.

In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. The Partnership may have to pay additional consideration in the future as a well becomes uneconomic under the terms of the Partnership Agreement in order to recover these reserves. There were no impairments recorded during the three and nine months ended September30, 2013 and 2012. During the year ended December31, 2012, the Partnership recognized an impairment charge of $162,600.

Working Interest

The Partnership Agreement establishes that revenues and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). The MGP is also provided an additional working interest of 7% as provided in the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expenses until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues and expenses based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.

Revenue Recognition

The Partnership generally sells natural gas and crude oil at prevailing market prices. Generally, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil, in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of working interest and/or overriding royalty.

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGL’s, crude oil, and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees, which are, in turn, based upon applicable product prices. The Partnership had unbilled revenues at September30, 2013 and December31, 2012 of $242,500 and $219,600, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.

Comprehensive loss

Comprehensive loss includes net loss and all other changes in equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States of America, have not been recognized in the calculation of net loss. These changes, other than net loss, are referred to as “other comprehensive loss” and, for the Partnership, include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges.

Recently Adopted Accounting Standards

In July 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-10, Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes (“Update 2013-10”). Currently, Topic 815 provides guidance on the risks that are permitted to be hedged in a fair value or cash flow hedge. In addition, only the interest rates on direct Treasury obligations of the U.S. Government (“UST”) and the London Interbank Offered Rate (“LIBOR”) swap rate are considered benchmark interest rates. Update 2013-10 amends Topic 815 to include the Overnight Index Swap Rate (“OIS”), also referred to as the Fed Funds Effective Swap Rate, as a U.S. benchmark interest rate for hedge accounting purposes. Including the OIS as an acceptable U.S. benchmark interest rate in addition to UST and LIBOR will provide risk managers with a more comprehensive spectrum of interest rate resets to utilize as the designated benchmark interest rate risk component under the hedge accounting guidance in Topic 815. Update 2013-10 is effective for qualifying new or redesignated hedging relationships entered into on or after July17, 2013. The Partnership adopted the requirements of Update 2013-10 upon its effective date of July17, 2013, and it had no material impact on its financial position, results of operations or related disclosures.

In February 2013, the FASB issued ASU 2013-02, Comprehensive Income (Topic 220) (“Update 2013-02”). Update 2013-02 requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present significant amounts reclassified out of accumulated other comprehensive income if the amount reclassified to net income in its entirety is in the same reporting period as incurred. For other amounts that are not required to be reclassified in their entirety to net income, an entity is required to reference to other disclosures that provide additional detail about those amounts. Entities are required to implement the amendments prospectively for reporting periods beginning after December15, 2012, with early adoption being permitted. The Partnership adopted the requirements of Update 2013-02 upon its effective date of January1, 2013, and it had no material impact on its financial position, results of operations or related disclosures.

Recently Issued Accounting Standards

In February 2013, the FASB issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements, for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements, for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December15, 2013. The Partnership will apply the requirements of Update 2013-04 upon its effective date of January1, 2014, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

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Derivative Instruments (Offsetting Derivative Liabilities) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities	$ (19,700)	$ (24,100)
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets	9,300	21,100
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount of Liabilities Presented in the Balance Sheets	(10,400)	(3,000)
Put premiums payable-affiliate
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities	(6,100)	(6,000)
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets	6,100	6,000
Long-term put premiums payable-affiliate
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities	(13,600)	(18,100)
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets	3,200	15,100
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount of Liabilities Presented in the Balance Sheets	$ (10,400)	$ (3,000)

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Certain Relationships and Related Party Transactions (Details) (USD $)	9 Months Ended
	Sep. 30, 2013
Administrative
Related Party Transaction [Line Items]
Monthly Administrative Costs Per Well	$ 75
Supervision
Related Party Transaction [Line Items]
Monthly Supervision Fees Per Well	$ 296
Transportation
Related Party Transaction [Line Items]
Transportation Fee Rate As Percentage Of Natural Gas Sales Price	13.00%

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CONDENSED BALANCE SHEETS (PARENTHETICAL)	Sep. 30, 2013
Limited partners' units	5,227.40

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2013

COMMITMENTS AND CONTINGENCIES

NOTE 7—COMMITMENTS AND CONTINGENCIES

General Commitments

Subject to certain conditions, investor partners may present their interests beginning in 2010 for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. The MGP is not obligated to purchase more than 5% of the units in any calendar year. In the event that the MGP is unable to obtain the necessary funds, it may suspend its purchase obligation.

Beginning one year after each of the Partnership’s wells has been placed into production, the MGP, as operator, may retain $200 per month per well to cover estimated future plugging and abandonment costs. As of September30, 2013, the MGP has not withheld any such funds. The MGP is currently evaluating its right to exercise this option based on several factors such as commodity prices, the natural decline in well production, and current and future plugging services and costs.

Legal Proceedings

The Partnership is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations.

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CONDENSED STATEMENTS OF COMPREHENSIVE LOSS (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Net loss	$ (10,200)	$ (105,700)	$ (72,600)	$ (339,300)
Other comprehensive income (loss):
Unrealized holding gain (loss) on cash flow hedging contracts	2,200	(9,500)	(8,300)	(11,800)
Difference in estimated hedge gains receivable	16,000	11,900	51,900	85,500
Reclassification adjustment for gains realized in net loss from cash flow hedges	(13,400)	(13,000)	(36,700)	(90,100)
Total other comprehensive income (loss)	4,800	(10,600)	6,900	(16,400)
Comprehensive loss	$ (5,400)	$ (116,300)	$ (65,700)	$ (355,700)

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CONDENSED BALANCE SHEETS (USD $)	Sep. 30, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 0	$ 15,200
Accounts receivable trade-affiliate	397,800	256,500
Accounts receivable monetized gains-affiliate	21,500	69,500
Current portion of derivative assets	2,500	3,200
Total current assets	421,800	344,400
Oil and gas properties, net	3,351,200	3,702,900
Long-term derivative assets	8,800	13,000
TOTAL ASSETS	3,781,800	4,060,300
Current liabilities:
Accrued liabilities	13,200	1,700
Total current liabilities	13,200	1,700
Asset retirement obligation	3,093,500	2,972,300
Long-term put premiums payable-affiliate	10,400	3,000
Commitments and contingencies
Partners’ capital:
Managing general partner’s interest	847,500	948,800
Limited partners’ interest (5,227.40 units)	(172,700)	151,500
Accumulated other comprehensive loss	(10,100)	(17,000)
Total partners’ capital	664,700	1,083,300
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$ 3,781,800	$ 4,060,300

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Derivative Instruments (Narrative) (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Derivative [Line Items]
Fair Value Asset/(Liability)	$ 11,300		$ 11,300		$ 16,200
Gain Recognized On Settled Commodity Contracts	13,400	13,000	36,700	90,100
Gain (Loss) on Fair Value Hedge Ineffectiveness, Net	0	0	0	0
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	30,800		30,800		90,600
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	19,700		19,700		24,100
Accumulated other comprehensive loss	(10,100)		(10,100)		(17,000)
Unrealized gains (losses) due to natural gas and oil property impairments
Derivative [Line Items]
Accumulated other comprehensive loss	(10,100)		(10,100)
Cash Flow Hedge (Loss) to be Reclassified within Twelve Months			(5,100)
Net Deferred Losses To Be Reclassified Into Net Income In Later Periods			(5,000)
Allocation To Limited Partner Only | Other Comprehensive Income (Loss)
Derivative [Line Items]
Net Derivative Gains Limited Partner			17,500
Allocation To MGP Only | Other Comprehensive Income (Loss)
Derivative [Line Items]
Reclassification Adjustment For Gain Recognized On Property Impairments			32,500
Accounts receivable monetized gains-affiliate
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	27,600		27,600		75,500
Accounts receivable monetized gains-affiliate | Allocation To Limited Partner Only
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	27,600		27,600		75,500
Long-term receivable monetized gains-affiliate
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	3,200		3,200		15,100
Long-term receivable monetized gains-affiliate | Allocation To Limited Partner Only
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	3,200		3,200		15,100
Put premiums payable-affiliate
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	6,100		6,100		6,000
Put premiums payable-affiliate | Allocation To Limited Partner Only
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	6,100		6,100		6,000
Long-term put premiums payable-affiliate
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	13,600		13,600		18,100
Long-term put premiums payable-affiliate | Allocation To Limited Partner Only
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	$ 13,600		$ 13,600		$ 18,100

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Summary of Significant Accounting Policies (Schedule of Oil and Gas Properties) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Natural gas and oil properties	$ 66,618,700	$ 66,618,800
Less - Accumulated depletion and impairment	(63,267,500)	(62,915,900)
Oil and gas properties, net	3,351,200	3,702,900
Leaseholds interests
Natural gas and oil properties	1,526,600	1,526,600
Wells and related equipment
Natural gas and oil properties	$ 65,092,100	$ 65,092,200

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Certain Relationships and Related Party Transactions

9 Months Ended

Sep. 30, 2013

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

NOTE 6—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The Partnership has entered into the following significant transactions with the MGP and its affiliates as provided under its Partnership Agreement. Administrative costs, which are included in general and administrative expenses in the Partnership’s statements of operations, are payable at $75 per well per month. Monthly well supervision fees which are included in production expenses in the Partnership’s statements of operations are payable at $296 per well per month for operating and maintaining the wells. Transportation fees, which are included in production expenses in the Partnership’s statements of operations, are generally payable at 13% of the natural gas sales price.

The following table provides information with respect to these costs and the periods incurred.

	ThreeMonthsEnded September30,					NineMonthsEnded September30,
		2013		2012			2013		2012
Administrative	$	29,000	$	30,300	$		92,300	$	95,400
Supervision		114,700		119,900			364,700		377,100
Transportation		54,800		40,000			164,100		126,500
Total	$	198,500	$	190,200	$		621,100	$	599,000

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

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Fair Value of Financial Instruments (Assets Measured at Fair Value on a Recurring Basis) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total derivative, fair value, net	$ 11,300	$ 16,200
Commodity Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross	11,300	16,200
Derivative liabilities, gross
Fair Value, Inputs, Level 1
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total derivative, fair value, net
Fair Value, Inputs, Level 1 | Commodity Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross
Derivative liabilities, gross
Fair Value, Inputs, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total derivative, fair value, net	11,300	16,200
Fair Value, Inputs, Level 2 | Commodity Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross	11,300	16,200
Derivative liabilities, gross
Fair Value, Inputs, Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total derivative, fair value, net
Fair Value, Inputs, Level 3 | Commodity Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross
Derivative liabilities, gross

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

9 Months Ended

Sep. 30, 2013

Oil and Gas Properties

Schedule of Oil and Gas Properties

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

	September30, 2013			December31, 2012
Proved properties:
Leasehold interest	$	1,526,600		$	1,526,600
Wells and related equipment		65,092,100			65,092,200
Total natural gas and oil properties		66,618,700			66,618,800
Accumulated depletion and impairment		(63,267,500	)		(62,915,900	)
Oil and gas properties, net	$	3,351,200		$	3,702,900

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Fair Value of Financial Instruments

9 Months Ended

Sep. 30, 2013

FAIR VALUE OF FINANCIAL INSTRUMENTS

NOTE 5—FAIR VALUE OF FINANCIAL INSTRUMENTS

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

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

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

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The carrying values of cash, accounts receivable, and accounts payable approximate their respective fair values due to the short term maturities of such financial instruments. The Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 4). The Partnership manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty. The Partnership’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. These derivative instruments are calculated by utilizing commodity indices, quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument.

Information for assets and liabilities measured at fair value at September30, 2013 and December31, 2012 was as follows:

	Level1		Level2		Level3		Total
As of September30, 2013
Derivative assets, gross
Commodity puts	$	-	$	11,300	$	-	$	11,300
Derivative liabilities, gross
Commodity puts		-		-		-		-
Total derivative, fair value, net	$	-	$	11,300	$	-	$	11,300
As of December31, 2012
Derivative assets, gross
Commodity puts	$	-	$	16,200	$	-	$	16,200
Derivative liabilities, gross
Commodity puts		-		-		-		—
Total derivative, fair value, net	$	-	$	16,200	$	-	$	16,200

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

The Partnership estimates the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates (see Note3). There were no additional assets or liabilities that were measured at fair value on a nonrecurring basis for the three and nine months ended September30, 2013 and 2012.

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CONDENSED STATEMENTS OF CASH FLOWS (USD $)	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Cash flows from operating activities:
Net loss	$ (72,600)	$ (339,300)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion	351,600	281,600
Non-cash loss on derivative value	67,200	122,300
Accretion of asset retirement obligation	121,200	111,300
(Increase) decrease in accounts receivable-affiliate	(141,300)	156,600
Increase in accrued liabilities	11,500	1,800
Net cash provided by operating activities	337,600	334,300
Cash flows from investing activities:
Proceeds from sale of tangible equipment	100	5,600
Net cash provided by investing activities	100	5,600
Cash flows from financing activities
Distributions to partners	(352,900)	(420,400)
Net cash used in financing activities	(352,900)	(420,400)
Net decrease in cash and cash equivalents	(15,200)	(80,500)
Cash and cash equivalents at beginning of period	15,200	80,500
Cash and cash equivalents at end of period	$ 0

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Commitments and Contingencies (Details) (USD $)	9 Months Ended
	Sep. 30, 2013
Disclosure - Commitments and Contingencies (Details) [Line Items]
Investor Partners Ownership Interest Presented For Purchase By The MGP, Maximum Percentage	5.00%
Operator Fee Per Well To Cover Estimated Future Plugging And Abandonment Costs, Monthly	$ 200

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Fair Value of Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2013

Schedule of Fair Value Derivative Instruments

Information for assets and liabilities measured at fair value at September30, 2013 and December31, 2012 was as follows:

	Level1		Level2		Level3		Total
As of September30, 2013
Derivative assets, gross
Commodity puts	$	-	$	11,300	$	-	$	11,300
Derivative liabilities, gross
Commodity puts		-		-		-		-
Total derivative, fair value, net	$	-	$	11,300	$	-	$	11,300
As of December31, 2012
Derivative assets, gross
Commodity puts	$	-	$	16,200	$	-	$	16,200
Derivative liabilities, gross
Commodity puts		-		-		-		—
Total derivative, fair value, net	$	-	$	16,200	$	-	$	16,200

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2013

Use of Estimates

Use of Estimates

Preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, asset impairments, fair value of derivative instruments and the probability of forecasted transactions. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions as much as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following months’ financial results. Management believes that the operating results presented for the three and nine months ended September30, 2013 and 2012 represent actual results in all material respects (see “Revenue Recognition” accounting policy for further description).

Accounts Receivable and Allowance for Possible Losses

Accounts Receivable and Allowance for Possible Losses

In evaluating the need for an allowance for possible losses, the MGP performs ongoing credit evaluations of the Partnership’s customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness as determined by review of such customers’ credit information. Credit is extended on an unsecured basis to many of the Partnership’s energy customers. At September30, 2013 and December31, 2012, the MGP’s credit evaluation indicated that the Partnership had no need for an allowance for possible losses.

Oil and Gas Properties

Oil and Gas Properties

Oil and gas properties are stated at cost. Maintenance and repairs that generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized.

The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to six mcf of natural gas.

The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties. The Partnership recorded depletion expense on natural gas and oil properties of $351,600 and $281,600 for the nine months ended September30, 2013 and 2012, respectively.

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

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

	September30, 2013			December31, 2012
Proved properties:
Leasehold interest	$	1,526,600		$	1,526,600
Wells and related equipment		65,092,100			65,092,200
Total natural gas and oil properties		66,618,700			66,618,800
Accumulated depletion and impairment		(63,267,500	)		(62,915,900	)
Oil and gas properties, net	$	3,351,200		$	3,702,900

Impairment of Long-Lived Assets

Impairment of Long-Lived Assets

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

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

The determination of oil and natural gas reserve estimates is a subjective process and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.

In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. The Partnership may have to pay additional consideration in the future as a well becomes uneconomic under the terms of the Partnership Agreement in order to recover these reserves. There were no impairments recorded during the three and nine months ended September30, 2013 and 2012. During the year ended December31, 2012, the Partnership recognized an impairment charge of $162,600.

Working Interest

Working Interest

The Partnership Agreement establishes that revenues and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). The MGP is also provided an additional working interest of 7% as provided in the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expenses until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues and expenses based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.

Revenue Recognition

Revenue Recognition

The Partnership generally sells natural gas and crude oil at prevailing market prices. Generally, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil, in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of working interest and/or overriding royalty.

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGL’s, crude oil, and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees, which are, in turn, based upon applicable product prices. The Partnership had unbilled revenues at September30, 2013 and December31, 2012 of $242,500 and $219,600, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.

Comprehensive Loss

Comprehensive loss

Comprehensive loss includes net loss and all other changes in equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States of America, have not been recognized in the calculation of net loss. These changes, other than net loss, are referred to as “other comprehensive loss” and, for the Partnership, include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges.

Recently Adopted Accounting Standards

Recently Adopted Accounting Standards

In July 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-10, Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes (“Update 2013-10”). Currently, Topic 815 provides guidance on the risks that are permitted to be hedged in a fair value or cash flow hedge. In addition, only the interest rates on direct Treasury obligations of the U.S. Government (“UST”) and the London Interbank Offered Rate (“LIBOR”) swap rate are considered benchmark interest rates. Update 2013-10 amends Topic 815 to include the Overnight Index Swap Rate (“OIS”), also referred to as the Fed Funds Effective Swap Rate, as a U.S. benchmark interest rate for hedge accounting purposes. Including the OIS as an acceptable U.S. benchmark interest rate in addition to UST and LIBOR will provide risk managers with a more comprehensive spectrum of interest rate resets to utilize as the designated benchmark interest rate risk component under the hedge accounting guidance in Topic 815. Update 2013-10 is effective for qualifying new or redesignated hedging relationships entered into on or after July17, 2013. The Partnership adopted the requirements of Update 2013-10 upon its effective date of July17, 2013, and it had no material impact on its financial position, results of operations or related disclosures.

In February 2013, the FASB issued ASU 2013-02, Comprehensive Income (Topic 220) (“Update 2013-02”). Update 2013-02 requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present significant amounts reclassified out of accumulated other comprehensive income if the amount reclassified to net income in its entirety is in the same reporting period as incurred. For other amounts that are not required to be reclassified in their entirety to net income, an entity is required to reference to other disclosures that provide additional detail about those amounts. Entities are required to implement the amendments prospectively for reporting periods beginning after December15, 2012, with early adoption being permitted. The Partnership adopted the requirements of Update 2013-02 upon its effective date of January1, 2013, and it had no material impact on its financial position, results of operations or related disclosures.

Recently Issued Accounting Standards

Recently Issued Accounting Standards

In February 2013, the FASB issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements, for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements, for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December15, 2013. The Partnership will apply the requirements of Update 2013-04 upon its effective date of January1, 2014, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

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Summary of Significant Accounting Policies (Narrative) (Details) (USD $)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Allowance for Uncollectible Accounts Receivable		$ 0		$ 0	$ 0
Depletion of Oil and Gas Properties	123,100	87,300	351,600	281,600
Asset Impairment Charges	0	0	0	0	162,600
Additional working interest			7.00%
Unbilled Revenues	$ 242,500		$ 242,500		$ 219,600

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Certain Relationships and Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2013

Costs Incurred From Related Party Transactions

The following table provides information with respect to these costs and the periods incurred.

	ThreeMonthsEnded September30,					NineMonthsEnded September30,
		2013		2012			2013		2012
Administrative	$	29,000	$	30,300	$		92,300	$	95,400
Supervision		114,700		119,900			364,700		377,100
Transportation		54,800		40,000			164,100		126,500
Total	$	198,500	$	190,200	$		621,100	$	599,000

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Document and Entity Information	9 Months Ended
	Sep. 30, 2013
Document - Document and Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
Entity Registrant Name	Atlas America Public #15-2005 (A) L.P.
Entity Central Index Key	0001335236
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding	5,227.40

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Description of Business (Details)	9 Months Ended
	Sep. 30, 2013
Atlas Resources Public #18-2009 (B) L.P. Formation Date	Jul. 25, 2005