United States

Securities and Exchange Commission

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended ~~September~~March 3031, ~~2015~~2016

¨	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 000-50700

ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP

(Name of small business issuer in its charter)

Delaware		54-2113989
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

Park Place Corporate Center One 1000 Commerce Drive, 4th Floor Pittsburgh, PA		15275
(Address of principal executive offices)		(zip code)

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

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

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

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

Large accelerated filer	¨	Accelerated filer	¨

Non-accelerated filer	¨	Smaller reporting company	þ

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

ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP

(A Delaware Limited Partnership)

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

		PAGE
PART I.	FINANCIAL INFORMATION (Unaudited)
Item 1:
	Condensed Balance Sheets as of September 30, 2015 and December 31, 2014	3
	Condensed Balance Sheets as of March 31, 2016 and December 31, 2015	3
	Condensed Statements of Operations for the Three and Nine Months ended September 30, 2015 and 2014	4
	Condensed Statements of Operations for the Three Months ended March 31, 2016 and 2015	4
	Condensed Statements of Comprehensive Loss for the Three and Nine Months ended September 30, 2015 and 2014	5
	Condensed Statements of Comprehensive Loss for the Three Months ended March 31, 2016 and 2015	5
	Condensed Statement of Changes in Partners’ Deficit for the Nine Months ended September 30, 2015	6
	Condensed Statement of Changes in Partners’ Deficit for the Three Months ended March 31, 2016	6
	Condensed Statements of Cash Flows for the Nine Months ended September 30, 2015 and 2014	7
	Condensed Statements of Cash Flows for the Three Months ended March 31, 2016 and 2015	7
	Notes to Condensed Financial Statements	8
Item 2:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	1713
Item 4:	Controls and Procedures	2216
PART II.	OTHER INFORMATION
Item 1:	Legal Proceedings	2217
Item 6:	Exhibits	2318
Signatures		24
SIGNATURES		19
CERTIFICATIONS

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP

CONDENSED BALANCE SHEETS

(Unaudited)

	September 30,2015			December 31,2014
	March 31,2016			December 31,2015
ASSETS
Current assets:
Cash	$	-		$	-
Accounts receivable trade-affiliate		3746,~~700~~400			-50,900
Asset retirement receivable-affiliate		589,200			324,200
Current portion of derivative assets		21,800			25,600
Current portion of derivative assets		12,400			9,300
Total current assets		68,200			76,500
Total current assets		639,300			333,500
Gas and oil properties, net		1,815,400			1,815,400
Gas and oil properties, net		1,815,400			2,593,100
Long-term asset retirement receivable-affiliate		852,500			721,200
Long-term derivative assets		2,800			7,700
Total assets	$	2,736,100		$	2,613,100
	$	2,457,500		$	2,934,300
LIABILITIES AND PARTNERS’ DEFICIT
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable trade-affiliate	$	~~734~~1,~~500~~209,800		$	~~108~~996,~~100~~600
Accrued liabilities		1416,~~500~~700			911,~~100~~300
Current portion of put premiums payable-affiliate		6,600			5,900
Put premiums payable-affiliate		8,700			11,800
Total current liabilities		~~755~~1,~~600~~235,200			~~123~~1,~~100~~019,700
Asset retirement obligations		5,~~492~~613,~~500~~900			5,~~266~~567,~~600~~900
Long-term put premiums payable-affiliate		1,700			6,800
Commitments and contingencies (Note 6)
Commitments and contingencies
Partners’ deficit:
Managing general partner’s deficit		(1,~~449~~566,~~700~~900	)		(~~856~~1,~~500~~517,100	)
Limited partners’ deficit (4,024 units)		(2,~~344~~546,~~200~~800	)		(12,~~610~~458,~~000~~400	)
Accumulated other comprehensive income		~~1,600~~700			41,~~300~~000
Total partners’ deficit		(34,~~792~~113,~~300~~000	)		(23,~~462~~974,~~200~~500	)
	$	2,457,500		$	2,934,300
Total liabilities and partners’ deficit	$	2,736,100		$	2,613,100

See accompanying notes to condensed financial statements.

ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months EndedSeptember 30,						Nine Months EndedSeptember 30,
	Three Months EndedMarch 31,
	2015			2014			2015			2014
	2016			2015
REVENUES
Natural gas, oil and liquids	$	5078,~~100~~500		$	~~164~~162,~~900~~200		$	~~312,300~~		$	~~881,200~~
Gain on mark-to-market derivatives		74,~~200~~300			-2,700			~~7,400~~			-
Total revenues		5782,~~300~~800			164,900			~~319,700~~			~~881,200~~
COSTS AND EXPENSES
Production		~~135~~136,~~700~~900			~~213~~211,~~600~~200			~~516,900~~			~~679,200~~
Depletion		~~16,400~~-			4223,~~800~~000			~~61,600~~			~~118,900~~
Impairment		716,100			-			716,100			-
Accretion of asset retirement obligations		46,000			75,300
Accretion of asset retirement obligation		75,300			49,800			225,900			149,300
General and administrative		38,100			49,100
General and administrative		36,700			46,100			126,600			133,700
Total costs and expenses		221,000			358,600
Total costs and expenses		980,200			352,300			1,647,100			1,081,100
Net loss	$	(138,200	)	$	(193,700	)
Net loss	$	(922,900	)	$	(187,400	)	$	(1,327,400	)	$	(199,900	)
Allocation of net loss:
Allocation of net loss:
Managing general partner	$	(49,800	)	$	(73,200	)
Managing general partner	$	(442,500	)	$	(78,400	)	$	(593,200	)	$	(106,400	)
Limited partners	$	(88,400	)	$	(120,500	)
Limited partners	$	(480,400	)	$	(109,000	)	$	(734,200	)	$	(93,500	)
Net loss per limited partnership unit	$	(22	)	$	(30	)
Net loss per limited partnership unit	$	(119	)	$	(27	)	$	(182	)	$	(23	)

See accompanying notes to condensed financial statements.

ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP

CONDENSED STATEMENTS OF COMPREHENSIVE LOSS

(Unaudited)

	Three Months EndedSeptember 30,						Nine Months EndedSeptember 30,
	Three Months EndedMarch 31,
	2015			2014			2015			2014
	2016			2015
Net loss	$	(~~922~~138,~~900~~200	)	$	(~~187~~193,~~400~~700	)	$	~~(1,327,400~~	)	$	~~(199,900~~	)
Other comprehensive loss:
Unrealized holding gain (loss) on cash flow hedging contracts		-			3,500			-			(6,300	)
Difference in estimated hedge receivable		-			1,800
Difference in estimated hedge gains receivable		(3,000	)		(100	)		400			19,900
Reclassification adjustment to net loss of mark-to-market gains on cash flow hedges		(300	)		(2,700	)
Reclassification adjustment for losses (gains) realized in net loss from cash flow hedges		2,200			(1,600	)		(3,100	)		(15,500	)
Total other comprehensive loss		(300	)		(900	)
Total other comprehensive (loss) income		(800	)		1,800			(2,700	)		(1,900	)
Comprehensive loss	$	(138,500	)	$	(194,600	)
Comprehensive loss	$	(923,700	)	$	(185,600	)	$	(1,330,100	)	$	(201,800	)

See accompanying notes to condensed financial statements.

ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP

CONDENSED STATEMENT OF CHANGES IN PARTNERS’ DEFICIT

FOR THE ~~NINE~~THREE MONTHS ENDED

~~September~~March 3031, ~~2015~~2016

(Unaudited)

	ManagingGeneralPartner			LimitedPartners			Accumulated OtherComprehensiveIncome (Loss)			Total
Balance at December 31, 2014	$	(856,500	)	$	(1,610,000	)	$	4,300		$	(2,462,200	)
Balance at December 31, 2015	$	(1,517,100	)	$	(2,458,400	)	$	1,000		$	(3,974,500	)
Participation in revenues, costs and expenses:
Net production expenses		(7220,400	)		(~~132~~38,~~200~~000	)		-			(~~204~~58,~~600~~400	)
Gain on mark-to-market derivatives		-			74,~~400~~300			-			74,~~400~~300
Depletion		(31,500	)		(30,100	)		-			(61,600	)
Accretion of asset retirement obligations		(16,100	)		(29,900	)		-			(46,000	)
Impairment		(366,000	)		(350,100	)		-			(716,100	)
General and administrative		(13,300	)		(24,800	)		-			(38,100	)
Accretion of asset retirement obligation		(79,000	)		(146,900	)		-			(225,900	)
Net loss		(49,800	)		(88,400	)		-			(138,200	)
General and administrative		(44,300	)		(82,300	)		-			(126,600	)
Other comprehensive loss		-			-			(300	)		(300	)
Net loss		(593,200	)		(734,200	)		-			(1,327,400	)
Balance at March 31, 2016	$	(1,566,900	)	$	(2,546,800	)	$	700		$	(4,113,000	)
Other comprehensive loss		-			-			(2,700	)		(2,700	)
Balance at September 30, 2015	$	(1,449,700	)	$	(2,344,200	)	$	1,600		$	(3,792,300	)

See accompanying notes to condensed financial statements.

ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months EndedSeptember 30,
	Three Months EndedMarch 31,
	2015			2014
	2016			2015
Cash flows from operating activities:
Net loss	$	(1138,~~327,400~~200	)	$	(~~199~~193,~~900~~700	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion		~~61,600~~-			~~118~~23,~~900~~000
Impairment		716,100			-
Non-cash loss (gain) on derivative value		400			(3,500	)
Non-cash (gain) loss on derivative value		(5,300	)		7,900
Accretion of asset retirement obligations		46,000			75,300
Accretion of asset retirement obligation		225,900			149,300
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable trade-affiliate		(37,700	)		191,200
Decrease in accounts receivable trade-affiliate		4,500			-
Increase in asset retirement receivable-affiliate		(~~265~~131,~~000~~300	)		~~(191,500~~-	)
Increase in accounts payable trade-affiliate		~~626~~213,~~400~~200			-96,100
Increase (decrease) in accrued liabilities		5,400			(600	)
Increase in accrued liabilities		5,400			2,800
Net cash provided by operating activities		-			~~75,300~~-
Net change in cash and cash equivalents		-			75,300
Cash flows from investing activities:
Cash and cash equivalents at beginning of period		-			5,600
Net cash provided by investing activities		-			-
Cash and cash equivalents at end of period	$	-		$	80,900
Cash flows from financing activities:
Net cash provided by financing activities		-			-
Net change in cash		-			-
Cash at beginning of period		-			-
Cash at end of period	$	-		$	-

See accompanying notes to condensed financial statements.

ATLAS AMERICA PUBLIC #12-2003 Limited Partnership

NOTES TO CONDENSED FINANCIAL STATEMENTS

~~September~~March 3031, ~~2015~~2016

(Unaudited)

NOTE 1 - DESCRIPTION OF BUSINESS

Atlas America Public #12-2003 Limited Partnership (the “Partnership”) is a Delaware limited partnership formed on July 15, 2003 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or the “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP). Unless the context otherwise requires, references to “the Partnership,” “we,” “us” and “our”, refer to Atlas America Public #12-2003 Limited Partnership.

On February 27, 2015, the MGP’s ultimate parent, Atlas Energy, L.P. (“Atlas Energy”), which was a publicly traded master-limited partnership, was acquired by Targa Resources Corp. and distributed to Atlas Energy’s unitholders 100% of the limited liability company interests in ARP’s general partner, Atlas Energy Group, LLC (“Atlas Energy Group”; NYSE: ATLS). Atlas Energy Group became a separate, publicly traded company and the ultimate parent of the MGP as a result of the distribution. Following the distribution, Atlas Energy Group continues to manage ARP’s operations and activities through its ownership of the ARP’s general partner interest.

~~The~~Atlas ~~Partnership~~Energy ~~has~~Group, ~~drilled~~LLC ~~and~~(“Atlas ~~currently~~Energy ~~operates~~Group”; ~~wells~~OTCQX: ~~located~~ATLS) inmanages ~~Pennsylvania.~~ARP’s ~~The~~operations ~~Partnership has no employees~~ and ~~relies~~activities onthrough ~~the MGP for management, which in turn, relies on~~ its ~~parent~~ownership ~~company,~~of ~~Atlas~~ARP’s ~~Energy~~general ~~Group~~partner ~~(February 27, 2015 and prior, Atlas Energy), for administrative services~~interest.

The Partnership’s ~~operating~~has ~~cash~~drilled ~~flows~~and ~~are~~currently ~~generated~~operates ~~from its~~ wells, ~~which~~located ~~produce~~in ~~natural gas and oil~~Pennsylvania. ~~Produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems.~~ The Partnership ~~intends~~has tono ~~produce~~employees ~~its~~and ~~wells~~relies ~~until~~on ~~they~~the ~~are~~MGP ~~depleted~~for ~~or become uneconomical to produce~~management, at which ~~time~~in ~~they~~turn, ~~will~~relies beon ~~plugged~~its ~~and~~parent ~~abandoned~~company, orAtlas ~~sold.~~Energy ~~The~~Group, ~~Partnership does not expect to drill additional wells and expects no additional funds will be required~~ for ~~drilling~~administrative services.

The ~~accompanying~~Partnership’s ~~condensed~~operating ~~financial~~cash ~~statements,~~flows ~~which~~ are ~~unaudited,~~generated ~~except~~from ~~that~~its ~~for the balance sheet at December 31~~wells, ~~2014,~~ which isproduce ~~derived~~natural ~~from audited financial statements~~gas, ~~are~~oil ~~presented~~and inNGL. ~~accordance~~Produced ~~with~~natural ~~the~~gas, ~~requirements~~oil ~~of Form 10-Q~~ and ~~accounting~~NGL ~~principles~~is ~~generally~~then ~~accepted~~delivered into ~~the~~market ~~United~~through ~~States~~affiliated ofand/or ~~America~~third-party ~~(“U.S.~~gas ~~GAAP”)~~gathering ~~for interim reporting~~systems. ~~They~~The doPartnership ~~not~~intends ~~include~~to ~~all~~produce ~~disclosures~~its ~~normally~~wells ~~made~~until inthey ~~financial~~are ~~statements~~depleted ~~contained~~or inbecome ~~the~~uneconomical ~~Partnership’s~~to ~~Form~~produce, ~~10-K.~~at ~~These~~which ~~interim~~time ~~financial~~they ~~statements~~will ~~should~~ be ~~read~~plugged ~~in conjunction with the audited financial statements~~ and ~~notes~~abandoned ~~thereto~~or ~~presented~~sold. inThe ~~the~~ Partnership’s ~~Annual~~does ~~Report~~not onexpect ~~Form~~to ~~10-K~~drill ~~for~~additional ~~the~~wells ~~year ended December 31, 2014. The results of operations for the three~~ and ~~nine~~expects ~~months~~no ~~ended~~additional ~~September~~funds ~~30,~~will ~~2015 may not necessarily~~ be ~~indicative~~required ~~of the results of operations~~ for ~~the full year ended December 31, 2015~~drilling.

The economic viability of the Partnership’s production is based on a variety of factors including proved developed reserves that it can expect to recover through existing wells with existing equipment and operating methods or in which the cost of additional required extraction equipment is relatively minor compared to the cost of a new well; and through currently installed extraction equipment and related infrastructure which is operational at the time of the reserves estimate (if the extraction is by means not involving drilling, completing or reworking a well). There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues.

The prices at which the Partnership’s natural gas, oil and ~~oil~~NGL will be sold are uncertain and the Partnership is not guaranteed a specific ~~natural gas~~ price for the sale of its ~~natural gas~~ production. Changes in natural gas, oil and ~~oil~~NGL prices have a significant impact on the Partnership’s cash flow and the value of its reserves. Lower natural gas, oil and ~~oil~~NGL prices may not only decrease the Partnership’s revenues, but also may reduce the amount of natural gas, oil and ~~oil~~NGL that the Partnership can produce economically.

~~Historically,~~Liquidity ~~there has been no need to borrow funds from the MGP to fund operations as the amount of funds generated by the Partnership’s operations has been adequate to fund future operations~~ and ~~distributions~~Capital toResources the partners. However, recent declines in commodity prices may challenge the Partnership’s ability to pay its obligations as they become due and its intention to produce its wells until they are depleted, as they may become uneconomical to produce. Accordingly, the MGP determined that there is substantial doubt about the Partnership’s ability to continue as a going concern. The MGP has planned, as necessary, to continue the Partnership’s operations and to fund the Partnership’s operations for at least the next 12 months. The MGP has concluded that such undertaking is sufficient to alleviate the doubt as to the Partnership’s ability to continue as a going concern.

The Partnership is generally limited to the amount of funds generated by the cash flow from its operations to fund its obligations and make distributions, if any, to its partners.

The natural gas, oil and natural gas liquids commodity price markets have suffered significant declines throughout 2015 and have continued to decline and remain low in 2016. The extreme ongoing volatility in the energy industry and commodity prices will likely continue to impact the Partnership’s outlook. The Partnership has experienced downward revisions of its natural gas and oil reserves volumes and values due to the significant declines in commodity prices. The MGP continues to implement various cost saving measures to reduce the Partnership’s operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. The MGP will continue to be opportunistic and aggressive in managing the Partnership’s cost structure and, in turn, liquidity to meet its operating needs. To the extent commodity prices remain low or decline further, or the Partnership experiences other disruptions in the industry, the Partnership’s ability to fund its operations and make distributions may be further impacted, and could result in the MGP’s decision to liquidate the Partnership’s operations.

Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from the Partnership’s operations have been adequate to fund its obligations and distributions to its partners. However, the recent significant declines in commodity prices have challenged the Partnership’s ability to fund its operations and may make it uneconomical for the Partnership to produce its wells until they are depleted as the Partnership originally intended. Accordingly, the MGP determined that there is substantial doubt about the Partnership’s ability to continue as a going concern. The MGP intends, as necessary, to continue the Partnership’s operations and to fund the Partnership’s obligations for at least the next twelve months. The MGP has concluded that such undertaking is sufficient to alleviate the doubt as to the Partnership’s ability to continue as a going concern. To the extent commodity prices remain low or decline further, ARP experiences disruptions in the financial markets impacting its respective longer-term access to or cost of capital, or ARP experiences any of the other impacts to its liquidity discussed below, the MGP’s ability to continue the Partnership’s operations and to fund the Partnership’s obligations for at least the next twelve months, as necessary, may be impacted.

ARP’s revolving credit facility is currently in the process of its semi-annual redetermination. Based on projected market conditions, continued declines in commodity prices and recent conversations with its administrative agent, ARP expects that its borrowing base will be redetermined to a level below its outstanding borrowings as of March 31, 2016. If ARP’s borrowing base is redetermined below its current outstanding borrowings and ARP is unable to repay the deficiency or deposit additional collateral to eliminate such deficiency, or if ARP experiences any other event of default on its debt obligations, or if other debt agreements cross-default, and the lenders accelerate the maturity of any other outstanding debts, the MGP, may not have sufficient liquidity to continue the Partnership’s operations and to fund the Partnership’s obligations, and as a result, there would be substantial doubt regarding the Partnership’s ability to continue as a going concern.

If, however, the MGP were to decide to liquidate our operations, the liquidation valuation of the Partnership’s assets and liabilities would be determined by an independent expert. It is possible that based on such determination, we would not be able to make any liquidation distributions to our limited partners. A liquidation could result in the transfer of the post-liquidation assets and liabilities of the Partnership to the MGP and would occur without any further contributions from or distributions to the limited partners.

The condensed financial statements, which are unaudited, except for the balance sheet at December 31, 2015, which is derived from audited financial statements, have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission and accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim reporting. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. GAAP have been condensed or omitted pursuant to those rules and regulations, although we believe that the disclosures made are adequate to make the information not misleading. 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, 2015. The results of operations for the three months ended March 31, 2016 may not necessarily be indicative of the results of operations for the year ended December 31, 2016.

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, 2014 filed with the Securities and Exchange Commission (“SEC”).

Use of Estimates

The preparation of the Partnership’s 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 many 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, 2015 and 2014 represent actual results in all material respects (See “-Revenue Recognition”).

Accounts Receivable

Accounts receivable on the balance sheets consist solely of the trade account receivable associated with the Partnership’s operations. In evaluating the realizability of the Partnership’s accounts receivable, 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, 2015 and December 31, 2014, the MGP’s credit evaluation indicated that the Partnership had no need for an allowance for uncollectible accounts receivable.

Gas and Oil Properties

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

The Partnership follows the successful efforts method of accounting for gas and oil producing activities. Oil and natural gas liquids (“NGLs”) are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to six Mcf of natural gas. Mcf is defined as one thousand cubic feet.

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 $61,600 and $118,900 for the nine months ended September 30, 2015 and 2014, respectively.

~~Upon~~The ~~the~~natural ~~sale~~gas orindustry ~~retirement~~principally ofconducts aits ~~complete~~business ~~field~~by ofprocessing aactual ~~proved~~transactions ~~property,~~many as 60 days after the ~~cost~~month isof ~~eliminated~~delivery. ~~from~~Consequently, the ~~property~~most ~~accounts~~recent two months’ financial results were recorded using estimated volumes and ~~the~~contract ~~resultant~~market ~~gain~~prices. orDifferences ~~loss~~between isestimated ~~reclassified~~and toactual amounts are recorded in the ~~Partnership~~following months’s ~~statements~~financial ~~of operations~~results. ~~Upon~~Management ~~the~~believes ~~sale~~that ofthe anoperating ~~individual~~results ~~well,~~presented for the ~~Partnership~~three ~~credits~~months ~~the~~ended ~~proceeds~~March to31, ~~accumulated~~2016 ~~depletion~~and ~~within~~2015 ~~its~~represent ~~balance~~actual ~~sheets~~results in all material respects.

Gas and Oil Properties

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

	September 30,2015			December 31,2014
	March 31,2016			December 31,2015
Proved properties:
Leasehold interests	$	1,~~131~~126,~~600~~100		$	1,~~131~~126,~~600~~100
Wells and related equipment		53,~~566~~253,300			53,~~566~~253,300
Total natural gas and oil properties		54,~~697~~379,~~900~~400			54,~~697~~379,~~900~~400
Accumulated depletion and impairment		(52,~~882~~564,~~500~~000	)		(52,~~104~~564,~~800~~000	)
Gas and oil properties, net	$	1,815,400		$	21,~~593~~815,~~100~~400

~~Impairment~~As a result of ~~Long-Lived~~the ~~Assets~~recent significant declines in commodity prices and associated recorded impairment charges, remaining net book value of gas and oil properties on our balance sheet at March 31, 2016 and December 31, 2015 was primarily related to the estimated salvage value of such properties. The estimated salvage values were based on the MGP’s historical experience in determining such values.

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

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

During the three and nine months ended September 30, 2015, the Partnership recognized $716,100 of impairment related to gas and oil properties. There was no gas and oil properties impairment recorded for the three and nine months ended September 30, 2014. The impairment relates to the carrying amount of these gas and oil properties being in excess of the Partnership’s estimate of their fair value at September 30, 2015. The estimate of the fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil prices at the date of measurement.

Derivative Instruments

The Partnership’s MGP enters into certain financial contracts to manage the Partnership’s exposure to movement in commodity prices (See Note 4). The derivative instruments recorded on the balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Partnership’s statements of operations unless specific hedge accounting criteria are met. On January 1, 2015, the Partnership discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, subsequent changes in fair value after December 31, 2014 of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations, while the fair values of the instruments recorded in accumulated other comprehensive income as of December 31, 2014 will be reclassified to the statements of operations in the periods in which those respective derivative contracts settle. Prior to discontinuance of hedge accounting, the fair value of these commodity derivative instruments was recognized in accumulated other comprehensive income (loss) within partners’ capital on the Partnership’s balance sheets and reclassified to the Partnership’s statements of operations at the time the originally hedged physical transactions affected earnings.

Asset Retirement Obligations

The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells (See Note 3). The Partnership recognizes a liability for its future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depletion.

Income Taxes

The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income reported in the accompanying financial statements. The federal and state income taxes related to the Partnership were immaterial to the financial statements and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for in the accompanying financial statements.

The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s MGP does not believe it has any tax positions taken within its financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. The Partnership has not recognized any potential interest or penalties in its financial statements for the three and nine months ended September 30, 2015 and 2014.

The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2011. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of September 30, 2015.

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, crude oil and natural gas liquids (“NGLs”) at prevailing market prices. Typically, 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, crude oil and NGLs, in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty.

The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP. The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees, which are, in turn, based upon applicable product prices (See Note 2: “-Use of Estimates”). During the quarter ended September 30, 2014, the Partnership identified an error in its revenue recognition process. As a result, the Partnership overstated its June 30, 2014 unbilled revenues by $34,600. As a result, revenue and net income was overstated by $34,600 for the three and six months ended June 30, 2014. In adjusting for the overstatement of revenue and net income that existed at June 30, 2014, the third quarter revenue is understated by $34,600 and net loss is overstated for the three month period ended September 30, 2014. In addition, there was no impact on Partnership distributions. Refer to the Partnership’s Form 10-Q for the quarter ended September 30, 2014 for further explanation of this error. The Partnership had unbilled revenues at September 30, 2015 of $37,700, which was included in accounts receivable trade-affiliate within the Partnership’s balance sheets. The Partnership had unbilled revenues at December 31, 2014 of $116,900, which was offset by $225,000 of amounts due to the MGP, which was included in accounts payable trade-affiliate within the Partnership’s balance sheets.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on the Partnership’s financial statements and, at September 30, 2015, only include changes in the fair value of unsettled derivative contracts which, prior to January 1, 2015, were accounted for as cash flow hedges (See Note 4). The Partnership does not have any other type of transaction which would be included within other comprehensive income (loss).

Recently Issued Accounting Standards

In ~~January~~August ~~2015~~2014, the ~~Financial Accounting Standards Board (“~~FASB”) ~~issued~~updated ~~Accounting~~the ~~Standards~~accounting ~~Update~~guidance ~~(“ASU”)~~related ~~2015-01,~~to ~~Income~~the ~~Statement~~evaluation –of ~~Extraordinary~~whether ~~and~~there ~~Unusual~~is ~~Items~~substantial ~~(Subtopic~~doubt ~~225-20):~~about ~~Simplifying~~an ~~Income~~entity’s ~~Statement~~ability ~~Presentation~~to bycontinue ~~Eliminating~~as ~~the~~a ~~Concept~~going ~~of Extraordinary Items (“Update 2015-01”)~~concern. The ~~amendments~~updated inaccounting ~~Update~~guidance ~~2015-01~~requires ~~simplify~~an ~~the~~entity’s ~~income~~management ~~statement~~to ~~presentation~~evaluate ~~requirements~~whether inthere ~~Subtopic~~are ~~225-20~~conditions byor ~~eliminating~~events ~~the~~that ~~concept~~raise ofsubstantial ~~extraordinary~~doubt ~~items.~~about ~~Extraordinary~~its ~~items~~ability ~~are~~to ~~events~~continue ~~and~~as ~~transactions~~a ~~that~~going ~~are~~concern ~~distinguished~~within byone ~~their~~year ~~unusual~~from ~~nature~~the ~~and~~date by the ~~infrequency~~financial ofstatements ~~their occurrence. The amendments in Update 2015-01~~ are ~~effective~~issued ~~for fiscal years,~~ and ~~interim~~provide ~~periods~~footnote ~~within those fiscal years~~disclosures, ~~beginning~~if ~~after December 15, 2015~~necessary. AThe ~~reporting~~updated ~~entity~~guidance ~~may~~is ~~apply~~effective ~~the~~as ~~amendments~~of ~~prospectively.~~January A1, ~~reporting~~2017 ~~entity~~and ~~may also apply~~ the ~~amendments~~Partnership ~~retrospectively~~is tocurrently ~~all prior periods presented~~ in the ~~financial~~process ~~statements.~~of ~~Early~~determining ~~adoption is permitted provided that~~ the ~~guidance~~impact ~~is applied from the beginning~~ of ~~the~~providing ~~fiscal year of adoption. The Partnership will adopt~~ the ~~requirements~~enhanced ofdisclosures, ~~Update~~as ~~2015-01 upon its effective date of January 1~~applicable, ~~2016,~~within ~~and it does not anticipate it having a material impact on~~ its financial ~~position, results of operations or related disclosures~~statements.

In ~~August~~May 2014, the FASB ~~issued~~updated ~~ASU~~the ~~2014-15,~~accounting ~~Presentation~~guidance ofrelated ~~Financial~~to ~~Statements~~revenue ~~– Going Concern (Subtopic 205-40) (“Update 2014-15”)~~recognition. The ~~amendments~~updated inaccounting ~~Update~~guidance ~~2014-15~~provides ~~provide~~a ~~U.S.~~single, ~~GAAP~~contract-based ~~guidance~~revenue onrecognition ~~the~~model ~~responsibility~~to ofhelp animprove ~~entity’s~~financial ~~management~~reporting inby ~~evaluating~~providing ~~whether~~clearer ~~there~~guidance ison ~~substantial~~when ~~doubt~~an ~~about the~~ entity’s ~~ability~~should torecognize ~~continue~~revenue, ~~as a going concern~~ and ~~about~~by ~~related~~reducing ~~footnote~~the ~~disclosures.~~number ~~For~~of ~~each~~standards ~~reporting~~to ~~period,~~which an entity’s ~~management~~has ~~will be required~~ to ~~evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued~~refer. In ~~doing~~July so2015, the ~~amendments~~FASB invoted ~~Update~~to ~~2014-15~~defer ~~should reduce diversity in~~ the ~~timing~~effective ~~and~~date ~~content~~by ofone ~~footnote~~year ~~disclosures.~~to ~~The amendments in Update 2014-~~December 15, ~~are~~2017 ~~effective~~ for ~~the~~ annual ~~period~~reporting ~~ending~~periods beginning after ~~December~~that ~~15,~~date. ~~2016,~~The ~~and~~updated ~~for~~accounting ~~annual~~guidance ~~and~~provides ~~interim~~companies ~~periods~~with ~~thereafter.~~alternative ~~Early~~methods ~~adoption~~of ~~is permitted~~adoption. The Partnership ~~will~~is ~~adopt~~currently in the ~~requirements~~process of ~~Update~~determining ~~2014-15~~the ~~upon~~impact ~~its~~that ~~effective~~the ~~date~~updated inaccounting ~~2016,~~guidance ~~and~~will ithave ~~does not anticipate it having a material impact~~ on its financial ~~position,~~statements ~~results~~and ofits ~~operations~~method orof ~~related disclosures~~adoption.

12NOTE 3 - DERIVATIVE INSTRUMENTS

InThe ~~May 2014~~MGP, ~~the~~on ~~FASB~~behalf issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the ~~Accounting Standards Codification. In addition~~Partnership, ~~the~~uses ~~existing requirements for the recognition of~~ a ~~gain~~number ~~or loss on the transfer~~ of ~~nonfinancial~~different ~~assets~~derivative ~~that are not in a contract with a customer (for example~~instruments, ~~assets~~principally ~~within~~put ~~the scope of Topic 360~~contracts, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles – Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in ~~Update~~connection 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with ~~a customer, identify~~ the ~~performance~~partnership’s ~~obligations~~commodity ~~in the contract, determine the transaction~~ price, ~~allocate~~risk ~~the~~management ~~transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations~~activities. ~~These~~The ~~requirements~~Partnership ~~are~~does ~~effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is~~ not ~~permitted.~~apply Onhedge ~~July~~accounting ~~9, 2015, the FASB decided~~ to ~~defer~~any ~~the effective date~~ of ~~ASU~~its ~~2014-09~~derivative ~~by one year~~instruments. As a result, ~~public~~gains ~~entities would apply the new revenue standard to annual reporting periods beginning after December 15, 2017,~~ and tolosses ~~interim~~associated ~~periods within that reporting period,~~ with ~~the~~derivative ~~option~~instruments toare ~~adopt~~recognized ~~the~~in ~~standard as of the original effective date~~earnings. The Partnership will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2018, and is evaluating the impact of the adoption on its financial position, results of operations and related disclosures.

~~NOTE~~The ~~3—ASSET~~Partnership ~~RETIREMENT~~enters ~~OBLIGATIONS~~into commodity put contracts to achieve more predictable cash flows by hedging the Partnership’s 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. These contracts have been recorded at their fair values.

The estimated liability for asset retirement obligations was based on the MGP’s historical experience in plugging and abandoning wells, the 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 was discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its gas and oil properties, the Partnership determined that there were no other material retirement obligations associated with tangible long-lived assets. 10

The ~~MGP’s~~Partnership ~~historical~~reflected ~~practice~~net ~~and~~derivative ~~continued~~assets ~~intention~~on isits tobalance ~~retain~~sheets ~~distributions from the limited partners as the wells within the Partnership near the end~~ of ~~their useful life. On a partnership-by-partnership basis~~$21,800 ~~the MGP assesses its right to withhold amounts related to plugging~~ and ~~abandonment costs based on several factors including commodity price trends~~$25,600 ~~the~~at ~~natural~~March ~~decline in the production of the wells and current and future costs. Generally~~31, ~~the~~2016 ~~MGP’s intention is to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approaches the fair value of the future plugging~~ and ~~abandonment~~December ~~cost. Upon the MGP’s decision to retain all future distributions to the limited partners of the Partnership~~31, ~~the MGP will assume the related asset retirement obligations of the limited partners. As of September 30,~~ 2015, ~~the MGP withheld $589,200 of net production revenue for future plugging and abandonment costs~~respectively.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2015		2014		2015		2014
Asset retirement obligation at beginning of period	$	5,417,200	$	3,452,600	$	5,266,600	$	3,353,100
Accretion expense		75,300		49,800		225,900		149,300
Asset retirement obligation at end of period	$	5,492,500	$	3,502,400	$	5,492,500	$	3,502,400

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 Partnership enters into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s balance sheets as the initial value of the options. The Partnership reflected net derivative assets on its balance sheets of $15,200 and $17,000 at September 30, 2015 and December 31, 2014, respectively. As a result of the put options, the Partnership recorded a net deferred gain on its balance sheet in accumulated other comprehensive income of $1,600 as of September 30, 2015. During the nine months ended September 30, 2015, $2,200 of net gains were recorded by the Partnership and allocated only to the limited partners. Of the $1,600 of deferred gains in accumulated other comprehensive income on the Partnership’s balance sheet at September 30, 2015, the Partnership will reclassify $1,400 of gains to its statement of operations over the next twelve month period as these contracts expire with the remaining gains of $200 being reclassified to the Partnership’s statements of operations in later periods as the remaining contracts expire.

The following table summarizes the gains or losses recognized within the statements of operations for derivative instruments previously designated as cash flow hedges for the periods indicated:

	Three Months EndedSeptember 30,						Nine Months EndedSeptember 30,
		Three Months Ended
	2015			2014			2015		2014
		March 31,
(Loss) gain reclassified from accumulated other comprehensive income into natural gas and oil revenues	$	(2,200	)	$	1,600		$	3,100	$	15,500
		2016			2015
Gain subsequent to December 31, 2014 recognized in gain on mark-to-market derivatives	$	7,200		$	-		$	7,400	$	-
Gains reclassified from accumulated other comprehensive loss into natural gas, oil and liquids revenues		$	300		$	2,700
Gains subsequent to hedge accounting recognized in gain on mark-to-market derivatives		$	4,300		$	2,700

14At March 31, 2016, the Partnership had the following 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.

At September 30, 2015, the Partnership had the following commodity derivatives:

Natural Gas Put Options

ProductionPeriod EndingDecember 31,	Volumes		Average Fixed Price		Fair ValueAsset (2)
	(MMBtu) (1)		(per MMBtu) (1)
2015		2,200	$	4.00	$	3,100
2016		11,300	$	4.15	$	21,800
2016		8,900	$	4.15		12,100
				Total net assets	$	15,200

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

(2)	Fair value based on forward NYMEX natural gas prices, as applicable.

~~Put~~As ~~Premiums~~the ~~Payable~~underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three months ended March 31, 2016 and 2015 for hedge ineffectiveness.

~~During~~NOTE ~~June~~4 2012, 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, 2015 and December 31, 2014, $6,600 and $5,900, respectively, of the put premiums were recorded as short-~~term~~ ~~payables~~FAIR toVALUE ~~affiliate~~OF ~~and~~FINANCIAL ~~$1,700~~INSTRUMENTS ~~and $6,800, respectively, were recorded as long-term payables to affiliate.~~

NOTE 5 - FAIR VALUE OF FINANCIAL INSTRUMENTS

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

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

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

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts ~~(See Note 4)~~. The ~~Partnership~~fair ~~manages~~value ~~and~~of ~~reports~~a ~~the~~financial ~~derivative~~instrument ~~assets~~depends ~~and liabilities~~ on ~~the~~a ~~basis~~number of ~~its~~factors, ~~net~~including ~~exposure~~the toavailability ~~market~~of ~~risks and credit risks by counterparty. The Partnership’s commodity derivative contracts are valued based on~~ observable market data ~~related~~over to the ~~change~~contractual interm ~~price~~ of the underlying ~~commodity~~instrument. ~~and~~The ~~are~~Partnership ~~therefore~~separates ~~defined~~the asfair ~~Level~~value 2of ~~assets~~its ~~and~~financial ~~liabilities~~instruments ~~within~~into ~~the~~three ~~same~~levels ~~class~~(Levels of1, ~~nature~~2 and ~~risk.~~3) ~~The~~based ~~fair~~on ~~values~~its assessment of ~~these~~the ~~derivative~~availability ~~instruments~~of ~~are~~observable ~~calculated~~market bydata ~~utilizing~~and ~~commodity~~the ~~indices,~~significance ~~quoted~~of ~~prices~~non-observable ~~for~~data ~~futures~~used ~~and~~to ~~options~~determine ~~contracts~~fair ~~traded~~value. As onof ~~open~~March ~~markets~~31, ~~that~~2016 ~~coincide~~and ~~with the underlying commodity~~December 31, ~~expiration period~~2015, ~~strike~~all ~~price~~derivative ~~(if~~financial ~~applicable)~~instruments ~~and~~were ~~the~~classified ~~pricing~~as ~~formula~~Level ~~utilized in the derivative instrument~~2.

1511

Information for assets measured at fair value at ~~September~~March 3031, ~~2015~~2016 and December 31, ~~2014~~2015 was as follows:

Level 1

Level 2

Level 3

Total

As of September 30, 2015

As of March 31, 2016

Derivative assets, gross

Commodity puts

1521,~~200~~800

Level 1

Level 2

Level 3

Total

As of December 31, 2014

As of December 31, 2015

Derivative assets, gross

Commodity puts

1725,~~000~~600

~~Other~~NOTE ~~Financial~~5 ~~Instruments~~- CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The ~~estimated~~Partnership ~~fair~~has ~~value~~entered ofinto the ~~Partnership’s~~following ~~other~~significant ~~financial~~transactions ~~instruments~~with ~~has~~the ~~been~~MGP ~~determined~~and ~~based~~its ~~upon~~affiliates as provided under its ~~assessment~~Partnership ofAgreement. ~~available~~Administrative ~~market~~costs, ~~information~~which are included in general and ~~valuation~~production ~~methodologies~~expense in the Partnership’s statements of operations, are payable at $75 per well per month. ~~However~~Monthly well supervision fees, ~~these~~which ~~estimates~~are ~~may~~included ~~not~~in ~~necessarily~~general beand ~~indicative~~administrative expenses in the Partnership’s statement of operations, are payable at $313 per well per month for operating and maintaining the ~~amounts~~wells. ~~that~~Well supervision fees are proportionately reduced to the extent the Partnership ~~could~~does ~~realize~~not ~~upon~~acquire 100% of the ~~sale~~working ofinterest ~~such~~in ~~financial~~a ~~instruments~~well. ~~The~~Transportation fees are included in production expenses in the Partnership’s ~~other~~statements ~~current~~of ~~assets~~operations and ~~liabilities~~are ongenerally ~~its~~payable ~~balance~~at ~~sheets~~13% ~~are~~of ~~considered~~the tonatural begas ~~financial~~sales ~~instruments~~price. ~~The~~Direct ~~estimated~~costs, ~~fair~~which ~~values~~are ofincluded ~~these~~in ~~instruments~~production ~~approximate~~and ~~their~~general ~~carrying~~administrative ~~amounts~~expenses ~~due~~in tothe ~~their~~Partnership’s ~~short-term~~statements ~~nature~~of ~~and~~operations, ~~thus~~ are ~~categorized~~payable to the MGP and its affiliates as ~~Level~~reimbursement 1for all costs expended on the Partnership’s behalf.

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

The Partnership estimates the fair value of its asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates (See Note 3). There were no additional assets or liabilities that were measured at fair value on a nonrecurring basis for the three and nine months ended September 30, 2015 and 2014.

Management estimates the fair value of the Partnership’s long-lived assets in connection with reviewing these assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions and judgments regarding such events or circumstances. During the three and nine months ended September 30, 2015, the Partnership recognized $716,100 of impairment related to gas and oil properties. These estimates of fair value are Level 3 measurements as they are based upon unobservable inputs. No impairments were recognized during the three and nine months ended September 30, 2014.

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 expense 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 statement of operations, are payable at $313 per well per month for operating and maintaining the wells. Well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of the working interest in a well. Transportation fees are included in production expenses in the Partnership’s statements of operations and are generally payable at 13% of the natural gas sales price. Direct costs, which are included in production and general administrative expenses in the Partnership’s statements of operations, are payable to the MGP and its affiliates as reimbursement for all costs expended on the Partnership’s behalf.

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

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

Three Months Ended March 31,

2015

2014

2015

2014

2016

2015

Administrative fees

2224,~~700~~400

3334,~~000~~800

~~83,800~~

~~98,300~~

Supervision fees

94102,~~900~~100

~~137~~145,~~800~~300

~~350,100~~

~~410,500~~

Transportation fees

59,~~200~~500

1619,300

~~34,600~~

~~98,300~~

Direct costs

4939,~~600~~000

7260,~~600~~900

~~175,000~~

~~205,800~~

Total

~~172~~175,~~400~~000

~~259~~260,~~700~~300

~~643,500~~

~~812,900~~

The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts payable trade-affiliate on the Partnership’s balance sheets includes the net production ~~revenues~~expense due to the MGP ~~as of September 30, 2015 and December 31, 2014~~.

NOTE 76 - COMMITMENTS AND CONTINGENCIES

General Commitments

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

Beginning one year after each of the Partnership’s wells has been placed into production, the MGP, as operator, may retain $200 per month per well to cover estimated future plugging and abandonment costs. As of ~~September~~March 3031, ~~2015~~2016, the MGP withheld $~~589~~852,~~200~~500 of net production revenue for future plugging and abandonment costs.

Legal Proceedings

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

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

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. Such statements are subject to certain risks and uncertainties, which 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 #12-2003 Limited Partnership ~~(“we”, “us” or the “Partnership”)~~ is a Delaware limited partnership, formed on July 15, 2003 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or the “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP). Unless the context otherwise requires, references to “the Partnership,” “we,” “us” and “our”, refer to Atlas America Public #12-2003 Limited Partnership.

17Atlas Energy Group, LLC manages ARP’s operations and activities through its ownership of the ARP’s general partner interest.

OnWe ~~February~~have ~~27,~~drilled ~~2015,~~and ~~the~~currently ~~MGP’s~~operate ~~ultimate~~wells ~~parent,~~located ~~Atlas~~in ~~Energy, L~~Pennsylvania.P. ~~(“Atlas~~We ~~Energy”),~~have ~~which~~no ~~was~~employees ~~a publicly traded master-limited partnership, was acquired by Targa Resources Corp.~~ and ~~distributed~~rely toon ~~Atlas~~our ~~Energy’s~~MGP ~~unitholders~~for ~~100%~~management, ofwhich ~~the limited liability company interests~~ in ~~ARP’s general partner~~turn, ~~Atlas~~relies ~~Energy~~on ~~Group,~~its ~~LLC (“Atlas Energy Group”; NYSE: ATLS). Atlas Energy Group became a separate, publicly traded company and the ultimate~~ parent ~~of the MGP as a result of the distribution. Following the distribution~~company, Atlas Energy Group, ~~continues~~for toadministrative ~~manage ARP’s operations and activities through its ownership of ARP’s general partner interest~~services.

We have drilled and currently operate wells located in Pennsylvania. We have no employees and rely on our MGP for management, which in turn, relies on its parent company, Atlas Energy Group (February 27, 2015 and prior, Atlas Energy), for administrative services.

We intend to continue to produce our wells 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~~March 3031, ~~2015~~2016, our MGP withheld $~~589~~852,~~200~~500 of net production revenues 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 gas and oil 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 ~~2014~~2016 and ~~the first nine months of~~ 2015, we experienced no problems in selling our natural gas and oil. Product availability and price are the principal means of competing 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.

Results of Operations

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

	Three Months Ended						~~Nine Months Ended~~
	September 30,						September 30,
	March 31,
	2015			2014			2015			2014
	2016			2015
Production revenues (in thousands):
Gas	$	4471		$	~~149~~152		$	~~284~~		$	~~822~~
Oil		56			117			23			43
Liquid		1			5			5			16
Liquids		1			3
Total	$	5078		$	~~165~~162		$	~~312~~		$	~~881~~
Production volumes:
Gas (Mcf/day) (1)		489			803			635			779
Gas (mcf/day) (1)		575			728
Oil (bbl/day) (1)		2			12			2			2
Liquid (bbl/day) (1)		1			1			1			1
Liquids (bbl/day) (1)		1			1
Total (Mcfe/day) (1)		507			815			653			797
Total (mcfe/day) (1)		593			746
Average sales prices: (2)
Gas (per Mcf) (1) (3) (4)	$	.96		$	2.53		$	1.64		$	3.90
Gas (per mcf) (1)	$	1.36		$	2.48
Oil (per bbl) (1)	$	5930.2863		$	~~100~~46.11		$	~~49.85~~		$	~~94.96~~
Liquid per (bbl/day) (1)	$	16.00		$	50.46		$	25.28		$	53.63
Liquids (per bbl) (1)	$	18.70		$	36.54
Production costs:
As a percent of revenues (4)		271	%		107	%		166	%		77	%
As a percent of revenues		175	%		130	%
Per Mcfe (1)		2.95		$	2.85		$	2.91		$	3.13
Per mcfe (1)	$	2.54		$	3.16
Depletion per Mcfe	$	0.35		$	0.57		$	0.35		$	0.55
Depletion per mcfe	$	-		$	0.34

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

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

~~(3)~~Natural ~~Average~~Gas Revenues. Our natural gas ~~prices~~revenues ~~are~~were ~~calculated~~$71,100 byand ~~including~~$152,500 infor ~~total~~the ~~revenue~~three ~~derivative~~months ~~gains~~ended ~~previously~~March ~~recognized~~31, ~~into~~2016 ~~income~~and 2015, respectively, a decrease of $81,400 (53%). The $81,400 decrease in ~~connection~~natural ~~with~~gas revenues for the three months ended March 31, 2016 as compared to the prior year similar period ~~impairment~~was ~~charges~~attributable ~~and~~to ~~dividing~~a by$50,900 ~~the~~decrease ~~total~~in ~~volume~~our ~~for~~natural gas sales prices after the ~~period.~~effect ~~Previously~~of ~~recognized~~financial ~~derivative~~hedges, ~~gains~~which were $3driven by market conditions,~~100~~ and a $730,~~900~~500 decrease in production volumes. Our production volumes decreased to 575 mcf per day for the three ~~and~~months ~~nine~~ended March 31, 2016 from 728 mcf per day for the three months ended ~~September~~March 31, 302015, ~~2014~~a decrease of 153 mcf per day (21%). The overall decrease in natural gas production volumes for the three months ended March 31, ~~respectively~~2016 as compared to the prior year similar period resulted primarily from the normal decline inherent in the life of a well in addition to wells shut-in due to it being uneconomical to produce in the current pricing environment.

~~(4) The average sales price and production costs as a percentage of revenues for natural gas for the three months ended September 30,2014 has been adjusted to reflect $34,600 of additional revenue.~~14

Oil Revenues. We drill wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $6,100 and $7,200 for the three months ended March 31, 2016 and 2015, respectively, a decrease of $1,100 (15%). The decrease in oil revenues was attributable to a $3,100 decrease in oil prices, partially offset by a $2,000 increase in production volumes. Our production volumes were 2.19 bbls per day for the three months ended March 31, 2016 and 1.73 bbls per day for the three months ended March 31, 2015, an increase of 0.46 bbls per day (26%).

Natural Gas ~~Revenues~~Liquids Revenue. ~~During~~The ~~the~~majority ~~quarter~~of ~~ended~~our ~~September~~wells ~~30,~~produce ~~2014~~“dry gas”, ~~management~~which ~~identified~~is ancomposed ~~error~~primarily inof ~~the~~methane ~~process~~and ~~used~~requires tono ~~estimate~~additional ~~our~~processing ~~unbilled~~before ~~revenue.~~being Astransported aand ~~result,~~sold ~~natural~~to ~~gas revenue for~~ the ~~three~~purchaser. ~~months~~Some ~~ended~~wells, ~~September 30~~however, ~~2014~~produce ~~includes~~“wet ~~an adjustment to reduce natural~~ gas ~~revenue by $34~~”,~~600.~~ ~~The~~which ~~adjustment~~contains islarger ~~the~~amounts ~~result~~ of ~~overestimating~~ethane ~~our~~and ~~unbilled~~other ~~revenues~~associated ashydrocarbons of(i.e. ~~June~~“natural ~~30,~~gas ~~2014.~~liquids”) ~~Refer~~that tomust ~~the~~be ~~Partnership’s~~removed ~~Form~~prior ~~10-Q~~to ~~for~~transporting the ~~quarter~~gas. ~~ended~~Once ~~September 30~~removed, ~~2014~~these ~~for~~natural ~~further~~gas ~~explanation~~liquids ofare ~~this~~sold ~~error~~to various purchasers. Our ~~unadjusted~~ natural gas liquids revenues were $431,~~200~~300 and $~~183~~2,~~400~~500 for the three months ended ~~September~~March 3031, ~~2015~~2016 and ~~2014~~2015, respectively, a decrease of $~~140~~1,200 (7648%). ~~The~~Our ~~$140,200 decrease in natural gas revenues for the three months ended September 30, 2015 as compared to the prior year similar period was attributable to a $71,600 decrease in~~ production volumes ~~and a $68,600 decrease in our natural gas sales prices after the effect of financial hedges, which were driven by market conditions~~0.76 ~~Our~~bbls ~~production volumes decreased to 489 Mcf~~ per day for ~~the~~both ~~three months ended September 30, 2015 from 803 Mcf per day for the three months ended September 30, 2014, a decrease~~ of ~~314 Mcf per day (39%). The overall decrease in natural gas production volumes for~~ the three months ended ~~September~~March 3031, ~~2015~~2016 ~~as compared to the prior year similar period resulted primarily from the normal decline inherent in the life of a well~~ and ~~a decrease in the number of producing wells due to wells being shut-in as a result of the decline in natural gas prices~~2015.

~~Our~~Gain ~~natural~~on ~~gas~~Mark-to-Market ~~revenues~~Derivatives. ~~were~~On ~~$283,600~~January ~~and $822~~1,~~300~~ ~~for the nine months ended September 30,~~ 2015 ~~and 2014~~, ~~respectively,~~we adiscontinued ~~decrease~~hedge ofaccounting ~~$538,700 (66%). The $538,700 decrease in natural gas revenues~~ for ~~the nine months ended September 30, 2015 as compared to the prior year similar period was attributable to a $387,000 decrease in~~ our ~~natural~~qualified ~~gas~~commodity ~~sales prices after the effect of financial hedges, which were driven by market conditions, and a $151,700 decrease in production volumes~~derivatives. ~~Our~~As ~~production volumes decreased to 635 Mcf per day for the nine months ended September 30~~such, ~~2015~~subsequent ~~from~~changes ~~779 Mcf per day for the nine months ended September 30, 2014, a decrease of 144 Mcf per day (18%). The overall decrease~~ in ~~natural~~fair ~~gas~~value ~~production volumes for the nine months ended September 30, 2015 as compared to the prior year similar period resulted primarily from the normal decline inherent in the life~~ of athese ~~well~~derivatives ~~and~~are arecognized ~~decrease~~immediately inwithin ~~the~~gain ~~number~~on ~~of producing wells due~~ mark-to ~~wells being shut~~-~~in as a result of the decline in natural gas prices.~~ market

~~Oil~~derivatives ~~Revenues.~~on Weour ~~drill~~statements ~~wells~~of ~~primarily to produce natural gas, rather than oil, but some wells have limited oil production~~operations. ~~Our~~The ~~oil~~fair ~~revenues~~values ~~were~~of ~~$5,800~~these ~~and~~commodity ~~$11,200~~derivative ~~for~~instruments ~~the~~as ~~three~~of ~~months~~December ~~ended September 30~~31, ~~2015 and~~ 2014, ~~respectively,~~which awere ~~decrease~~recognized ofin ~~$5,400~~accumulated ~~(48%).~~other ~~The~~comprehensive ~~$5,400~~income ~~decrease~~within inpartners’ ~~oil~~capital ~~revenues~~on ~~for~~our ~~the~~balance ~~three months ended September 30~~sheet, ~~2015~~will asbe ~~compared~~reclassified to ~~the~~our ~~prior~~statements ~~year~~of ~~similar~~operations ~~period was attributable to a $4,000 decrease~~ in ~~oil~~the ~~prices~~future ~~and~~at ~~a $1,400 decrease in production volumes. Our production volumes decreased to 1.06 bbls per day for~~ the ~~three~~time ~~months ended September 30, 2015 from 1.22 bbls per day for~~ the ~~three~~originally ~~months~~hedged ~~ended~~physical ~~September~~transactions ~~30, 2014, a decrease of~~ settle.~~16 bbls per day (13%).~~

~~Our~~We ~~oil~~recognized ~~revenues~~gains ~~were~~on mark-to-market derivatives of $234,~~900~~300 and $432,~~100~~700 for the ~~nine~~three months ended ~~September~~March 3031, ~~2015~~2016 and ~~2014~~2015, respectively~~, a decrease of $19,200 (45%)~~. ~~The~~This ~~$19,200~~gain ~~decrease~~was indue ~~oil~~primarily ~~revenues for the nine months ended September 30, 2015 as compared~~ to ~~the prior year similar period was attributable~~ mark-to-market agains ~~$21,600 decrease~~ in ~~oil~~the ~~prices,~~current ~~partially~~year ~~offset~~primarily byrelated ~~a $2,400 increase in production volumes. Our production volumes increased~~ to ~~1.75 bbls per day for~~ the ~~nine~~change ~~months~~in ~~ended~~natural ~~September~~gas ~~30,~~prices ~~2015~~during ~~from 1.66 bbls per day for~~ the ~~nine months ended September 30, 2014, an increase of~~ year.~~09 bbls per day (6%).~~

~~Natural~~Costs ~~Gas Liquids Revenue. The majority of our wells produce “dry gas”, which is composed primarily of methane~~ and ~~requires no additional processing before being transported and sold to the purchaser~~Expenses. ~~Some~~Production ~~wells,~~expenses however, produce “wet gas”, which contains larger amounts of ethane and other associated hydrocarbons (i.e. “natural gas liquids”) that must be removed prior to transporting the gas. Once removed, these natural gas liquids are sold to various purchasers. Our natural gas liquids revenues were $1136,~~100~~900 and $4211,~~900~~200 for the three months ended ~~September~~March 3031, ~~2015~~2016 and ~~2014~~2015, respectively, a decrease of $74,300 (35%). ~~Our~~This ~~natural~~decrease ~~gas~~was ~~liquids~~mostly ~~revenues~~attributable ~~were~~to ~~$4,800~~a ~~and~~decrease ~~$15,800~~in ~~for~~transportation ~~the~~expenses ~~nine~~and ~~months~~well ~~ended~~supervision ~~September~~fees ~~30,~~due ~~2015~~to ~~and~~additional ~~2014,~~wells ~~respectively~~being shut-in.

~~Gain~~For ~~(Loss)~~the onthree ~~Mark-to-Market~~months ~~Derivatives.~~ended OnMarch ~~January 1~~31, ~~2015~~2016, wethere ~~discontinued~~was ~~hedge~~no ~~accounting~~depletion ~~for~~recorded ~~our~~due ~~qualified~~to ~~commodity~~the ~~derivatives.~~recent Assignificant ~~such,~~declines ~~subsequent changes~~ in ~~fair~~commodity ~~value~~prices ofand ~~these~~associated ~~derivatives~~recorded ~~are~~impairment ~~recognized~~charges. Therefore, ~~immediately~~the ~~within~~remaining ~~gain~~net onbook ~~mark-to-market~~value ~~derivatives on our statements~~ of ~~operations.~~gas ~~The~~and ~~fair~~oil ~~values~~properties ofon ~~these~~our ~~commodity~~balance ~~derivative~~sheet ~~instruments~~at as December 31, ~~2014,~~2015 ~~which~~was ~~were~~primarily ~~recognized~~related into ~~accumulated~~the ~~other~~estimated ~~comprehensive~~salvage ~~income~~value ~~within~~of ~~partners’~~such ~~capital~~properties. onFor ~~our~~the ~~balance~~three ~~sheet,~~months ~~will~~ended beMarch ~~reclassified~~31, to2015, ~~our~~depletion ~~statements~~ of ~~operations~~gas inand ~~the~~oil ~~future~~properties atas ~~the~~a ~~time~~percentage ~~the~~of ~~originally~~gas ~~hedged~~and ~~physical~~oil ~~transactions~~revenues ~~settle~~was 14%.

WeGeneral ~~recognized~~and aadministrative ~~gain~~expenses ~~on mark-to-market derivatives of $7,200~~ for the three months ended ~~September~~March 3031, ~~2015.~~2016 ~~This~~and ~~gain~~2015 ~~was~~were ~~due~~$38,100 ~~primarily~~and to$49,100, ~~mark-to-market~~respectively, ~~gains~~a indecrease ~~the~~of ~~current~~$11,000 ~~quarter~~(22%). ~~primarily~~These ~~related~~expenses toinclude ~~the~~third-party ~~change~~costs infor ~~natural~~services ~~gas~~as ~~prices~~well ~~during~~as the ~~year.~~monthly ~~There~~administrative ~~were~~fees nocharged ~~gains~~by orour ~~losses~~MGP onand ~~mark-~~vary from period to~~-market~~ ~~derivatives~~period ~~during~~due to the ~~three~~costs ~~months~~charged ~~ended~~to ~~September~~us ~~30,~~and ~~2014~~services provided to us.

We recognized a gain on mark-to-market derivatives of $7,400 for the nine months ended September 30, 2015. This gain was due primarily to mark-to-market gains in the current quarter primarily related to the change in natural gas prices during the year. There were no gains or losses on mark-to-market derivatives during the nine months ended September 30, 2014.

Costs and Expenses. Production expenses were $135,700 and $213,600 for the three months ended September 30, 2015 and 2014, respectively, a decrease of $77,900 (36%). Production expenses were $516,900 and $679,200 for the nine months ended September 30, 2015 and 2014, respectively, a decrease of $162,300 (24%). The decreases for the three and nine months ended September 30, 2015 as compared to the prior year similar period were mostly due to decreases in transportation fees due to a decrease in revenue.

Depletion of oil and gas properties as a percentage of oil and gas revenues was 33% and 26% for the three months ended September 30, 2015 and 2014, respectively, and 20% and 13% for the nine months ended September 30, 2015 and 2014, 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, 2015 and 2014 were $36,700 and $46,100, respectively, a decrease of $9,400 (20%). For the nine months ended September 30, 2015 and 2014, these expenses were $126,600 and $133,700, respectively, a decrease of $7,100 (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, 2015 as compared to the prior year similar period are primarily due to third-party costs as compared to the prior year similar period.

Impairment of gas and oil properties for the three and nine months ended September 30, 2015 was $716,100. There were no impairments of gas and oil properties for the three and nine months ended September 30, 2014. Periodically, we compare the carrying value of our proved developed gas and oil properties to their estimated fair market value. To the extent our carrying value exceeds the estimated fair market value, an impairment charge is recognized. As a result of this assessment, an impairment charge was recognized for the three and nine months ended September 30, 2015. This charge is based on reserve quantities, future market prices and our carrying value. We cannot provide any assurance that similar charges may or may not be taken in future periods.

Liquidity and Capital Resources

~~Cash~~We ~~provided~~are bygenerally ~~operating~~limited ~~activities decreased $75,300~~ to ~~$0 in~~ the ~~nine~~amount ~~months~~of ~~ended~~funds ~~September~~generated ~~30,~~by ~~2015 as compared to $75,300 for~~ the ~~nine~~cash ~~months~~flows ~~ended~~from ~~September~~our 30operations, ~~2014.~~which ~~This~~we ~~decrease~~believe ~~was~~is ~~mostly~~adequate ~~due~~ to afund ~~decrease~~future inoperations ~~net loss before depletion, accretion, impairment~~ and adistributions ~~non-cash~~to ~~loss~~our ~~on derivative value of $405,300, a decrease in the change in accounts receivable trade-affiliate of $228,900, and a decrease in the change in asset retirement receivable affiliate of $73,500~~partners. ~~The decrease was partially offset by an increase in the change in accounts payable trade-affiliate of $626~~Historically,~~400~~ ~~and~~there anhas ~~increase~~been inno ~~accrued~~need ~~liabilities~~to ofborrow ~~$6,000~~funds ~~for~~from ~~the~~our ~~nine~~MGP ~~months ended September 30, 2015 compared~~ to ~~the~~fund ~~nine months ended September 30, 2014~~operations.

~~Our~~The ~~MGP~~natural ~~may~~gas, ~~withhold~~oil ~~funds~~and ~~for~~natural ~~future~~gas ~~plugging~~liquids commodity price markets have suffered significant declines throughout 2015 and ~~abandonment~~have ~~costs~~continued to decline and remain low in 2016. ~~Through~~The ~~September~~extreme ~~30,~~ongoing ~~2015,~~volatility ~~our~~in ~~MGP~~the ~~has~~energy ~~withheld~~industry ~~$589,200~~and commodity prices will likely continue to impact the Partnership’s outlook. We have experienced downward revisions of ~~funds~~its ~~for~~natural ~~this~~gas ~~purpose~~and oil reserves volumes and values due to the significant declines in commodity prices. ~~Any~~Our ~~additional~~MGP ~~funds~~continues to implement various cost saving measures to reduce our operating and general and administrative costs, ifincluding ~~required~~renegotiating contracts with contractors, ~~will~~suppliers beand ~~obtained~~service ~~from~~providers, ~~production~~reducing ~~revenues~~the ornumber ~~borrowings~~of ~~from~~staff ~~our~~and ~~MGP~~contractors orand ~~its~~deferring ~~affiliates,~~and ~~which~~eliminating ~~are~~discretionary ~~not~~costs. ~~contractually~~Our ~~committed~~MGP will continue to ~~make~~be ~~loans~~opportunistic and aggressive in managing our cost structure and, in turn, liquidity to usmeet our operating needs. ~~The~~To ~~amount~~the ~~that~~extent wecommodity ~~may~~prices ~~borrow~~remain atlow ~~any~~or ~~one~~decline ~~time~~further, ~~may~~or ~~not~~we atexperience ~~any~~other ~~time~~disruptions ~~exceed~~in 5%the ofindustry, our ~~total~~ability ~~subscriptions~~to fund our operations and make distributions may be further impacted, and wecould ~~will~~result ~~not~~in ~~borrow~~the ~~from~~MGP’s ~~third-parties.~~decision to liquidate our operations.

We are 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. However, recent declines in commodity prices may challenge the Partnership’s ability to pay its obligations as they become due and its intention to produce its wells until they are depleted, as they may become uneconomical to produce. Accordingly, the MGP determined that there is substantial doubt about the Partnership’s ability to continue as a going concern. The MGP has planned, as necessary, to continue the Partnership’s operations and to fund the Partnership’s operations for at least the next 12 months. The MGP has concluded that such undertaking is sufficient to alleviate the doubt as to the Partnership’s ability to continue as a going concern.15

Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from our operations have been adequate to fund our obligations and distributions to our partners. However, the recent significant declines in commodity prices have challenged our ability to fund its operations and may make it uneconomical for to produce our wells until they are depleted as we originally intended. Accordingly, the MGP determined that there is substantial doubt about our ability to continue as a going concern. The MGP intends, as necessary, to continue our operations and to fund our obligations for at least the next twelve months. The MGP has concluded that such undertaking is sufficient to alleviate the doubt as to our ability to continue as a going concern.

To the extent commodity prices remain low or decline further, ARP experiences disruptions in the financial markets impacting its respective longer-term access to or cost of capital, or ARP experiences any of the other impacts to its liquidity discussed below, the MGP’s ability to continue the Partnership’s operations and to fund the Partnership’s obligations for at least the next twelve months, as necessary, may be impacted.

There was no cash provided by operating activities for the three months ended March 31, 2016 and 2015. This was primarily due to a decrease in the change in asset retirement receivable of $131,300. The decrease was offset by an increase in the change in accounts payable trade-affiliate of $117,100, an increase in accounts receivable trade-affiliate of $4,500, an increase in the change in the non-cash loss on hedge instruments of $3,900, an increase in net earnings before depletion and accretion of $3,200, and an increase in the change in accrued liabilities of $2,600 for the three months ended March 31, 2016 compared to the three months ended March 31, 2015.

Our MGP may withhold funds for future plugging and abandonment costs. Through March 31, 2016, our MGP has withheld $852,500 of funds for this purpose. Any additional funds, if required, will be obtained from production revenues or borrowings from our MGP or its affiliates, which are not contractually committed to make loans to us. The amount that we may borrow at any one time may not at any time exceed 5% of our total subscriptions, and we will not borrow from third-parties.

Critical Accounting Policies

~~The~~For ~~discussion~~a ~~and~~more ~~analysis~~complete ofdiscussion ~~our financial condition and results~~ of ~~operations~~the isaccounting ~~based~~policies upon our financial statements, which have been prepared in accordance with 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~~identified ~~and~~as ~~followed~~critical in the preparation of our condensed consolidated financial statements, isplease ~~included~~refer ~~within “Notes~~ to ~~Financial~~our ~~Statements”~~Management’s inDiscussion ~~Part~~and I,Analysis ~~Item 1,~~of “Financial ~~Statements”~~Condition inand ~~this~~Results ~~quarterly~~of ~~report~~Operations ~~and~~ in our Annual Report on Form 10-K for the fiscal year ended December 31, ~~2014~~2015.

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 general partner’s Chief Executive Officer 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 general partner’s Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, 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 general partner’s Chief Executive Officer and Chief Financial Officer concluded that, as of September 30, 2015, our disclosure controls and procedures were effective at the reasonable assurance level. 16

Under the supervision of our general partner’s Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, 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 general partner’s Chief Executive Officer and Chief Financial Officer concluded that, as of March 31, 2016, our disclosure controls and procedures were effective at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

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

PART II OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

2217

ITEM 6.

EXHIBITS

EXHIBIT INDEX

Exhibit No.		Description
4(a)		Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #12-2003 Limited Partnership (1)
4.0		Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #12-2003 Limited Partnership (1)
10.1		Drilling and Operating Agreement for Atlas America Public #12-2003 Limited Partnership (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 September 5, 2003 in the Form S-1/A Registration Statement dated September 5, 2003, File No. 333-105811

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SIGNATURES

Pursuant to the requirements of the Securities of the Exchange Act of 1934, ~~this~~the ~~report~~registrant has ~~been~~duly ~~signed~~caused ~~below~~this byreport ~~the~~to ~~following~~be ~~person~~signed on its behalf ofby the ~~registrant~~undersigned, ~~and~~thereunto induly ~~the capacities and on the dates indicated~~authorized.

	ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP
	By: ATLAS RESOURCES, LLC, General Partner
	By: Atlas Resources, LLC, its Managing General Partner
Date: November 23, 2015	By:/s/ FREDDIE M. KOTEK
Date: May 23, 2016	By:	/s/ FREDDIE M. KOTEK
	Freddie M. Kotek, Chairman of the Board of Directors, Chief Executive Officer and President
		Freddie M. Kotek,Chief Executive Officer and President of the Managing General Partner
Date: November 23, 2015	By:/s/ JEFFREY M. SLOTTERBACK
	Jeffrey M. Slotterback, Chief Financial Officer

Date: May 23, 2016

By:

/s/ JEFFREY M. SLOTTERBACK

Jeffrey M. Slotterback

Chief Financial Officer of the

Managing General Partner

Filing Compare · ATLAS AMERICA PUBLIC #12-2003 Limited Partnership