Atlas America Public #12-2003 Limited Partnership 10-Q 2012 Q2 Quarterly report

United States

Securities and Exchange Commission

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2012

¨ 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  x    No  ¨

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

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

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

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

ATLAS AMERICA PUBLIC #12-2003 Limited Partnership

(A DELAWARE LIMITED PARTNERSHIP)

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

		PAGE
PART I.	FINANCIAL INFORMATION
Item 1:	Financial Statements
	Balance Sheets as of June 30, 2012 and December 31, 2011		3
	Statements of Operations for the three and six months ended June 30, 2012 and 2011		4
	Statements of Comprehensive (Loss) Income for the three and six months ended June 30, 2012 and 2011		5
	Statement of Changes in Partners’ Capital for the six months ended June 30, 2012		6
	Statements of Cash Flows for the six months ended June 30, 2012 and 2011		7
	Notes to Financial Statements		8
Item 2:	Management’s Discussion and Analysis of Financial Condition and Results of Operations		17
Item 4:	Controls and Procedures		20
PART II.	OTHER INFORMATION
Item 1:	Legal Proceedings		20
Item 6:	Exhibits		21
SIGNATURES			22
CERTIFICATIONS			23

2

ATLAS AMERICA PUBLIC #12-2003 Limited Partnership

BALANCE SHEETS

	June 30, 2012		December 31, 2011
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	57,100
Accounts receivable trade-affiliate		152,900		264,500
Accounts receivable monetized gains-affiliate		113,800		156,600
Short-term hedge receivable due from affiliate		4,200		—
Total current assets		270,900		478,200
Oil and gas properties, net		5,483,500		5,755,500
Long-term receivable monetized gains-affiliate		31,500		102,300
Long-term hedge receivable due from affiliate		22,400		—
	$	5,808,300	$	6,336,000
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	20,500	$	8,600
Total current liabilities		20,500		8,600
Asset retirement obligation		3,451,000		3,365,300
Partners’ capital:
Managing general partner		1,731,000		1,871,500
Limited partners (4,024 units)		557,700		1,017,900
Accumulated other comprehensive income		48,100		72,700
Total partners’ capital		2,336,800		2,962,100
	$	5,808,300	$	6,336,000

See accompanying notes to financial statements.

3

ATLAS AMERICA PUBLIC #12-2003 Limited Partnership

STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
REVENUES
Natural gas, oil and liquid gas	$	257,000		$	529,500		$	580,500		$	883,400
Interest income		—			—			—			100
Total revenues		257,000			529,500			580,500			883,500
COSTS AND EXPENSES
Production		272,800			300,700			538,200			573,400
Depletion		142,500			154,200			272,000			265,300
Accretion of asset retirement obligation		42,800			46,500			85,700			93,000
General and administrative		49,300			52,600			111,500			110,900
Total costs and expenses		507,400			554,000			1,007,400			1,042,600
Net loss	$	(250,400	)	$	(24,500	)	$	(426,900	)	$	(159,100	)
Allocation of net loss:
Managing general partner	$	(72,200	)	$	(23,600	)	$	(125,200	)	$	(58,000	)
Limited partners	$	(178,200	)	$	(900	)	$	(301,700	)	$	(101,100	)
Net loss per limited partnership unit	$	(44	)	$	—		$	(75	)	$	(25	)

See accompanying notes to financial statements.

4

ATLAS AMERICA PUBLIC #12-2003 Limited Partnership

STATEMENTS OF COMPREHENSIVE LOSS

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Net loss	$	(250,400	)	$	(24,500	)	$	(426,900	)	$	(159,100	)
Other comprehensive (loss) income:
Unrealized holding (loss) gain on hedging contracts		(2,300	)		—			(2,300	)		35,600
MGP portion of non-cash loss on hedge instruments		—			—			—			184,200
Difference in estimated monetized gains receivable		17,700			37,000			48,300			58,900
Less: reclassification adjustment for gains realized in net loss		(26,900	)		(56,300	)		(70,600	)		(125,400	)
Total other comprehensive (loss) income		(11,500	)		(19,300	)		(24,600	)		153,300
Comprehensive loss	$	(261,900	)	$	(43,800	)	$	(451,500	)	$	(5,800	)

See accompanying notes to financial statements.

5

ATLAS AMERICA PUBLIC #12-2003 Limited Partnership

STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

FOR THE SIX MONTHS ENDED

June 30, 2012

(Unaudited)

	Managing General Partner			Limited Partners			Accumulated Other Comprehensive Income (Loss)			Total
Balance at January 1, 2012	$	1,871,500		$	1,017,900		$	72,700		$	2,962,100
Participation in revenues and expenses:
Net production revenues		700			41,600			—			42,300
Depletion		(56,900	)		(215,100	)		—			(272,000	)
Accretion of asset retirement obligation		(30,000	)		(55,700	)		—			(85,700	)
General and administrative		(39,000	)		(72,500	)		—			(111,500	)
Net loss		(125,200	)		(301,700	)		—			(426,900	)
Other comprehensive loss		—			—			(24,600	)		(24,600	)
Distributions to partners		(15,300	)		(158,500	)		—			(173,800	)
Balance at June 30, 2012	$	1,731,000		$	557,700		$	48,100		$	2,336,800

See accompanying notes to financial statements.

6

ATLAS AMERICA PUBLIC #12-2003 Limited Partnership

STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	2012			2011
Cash flows from operating activities:
Net loss	$	(426,900	)	$	(159,100	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion		272,000			265,300
Non-cash loss on hedge instruments		62,400			182,500
Accretion of asset retirement obligation		85,700			93,000
Decrease in accounts receivable trade-affiliate		111,600			24,500
Increase in accrued liabilities		11,900			4,600
Net cash provided by operating activities		116,700			410,800
Cash flows from financing activities:
Distributions to partners		(173,800	)		(433,600	)
Net cash used in financing activities		(173,800	)		(433,600	)
Net decrease in cash and cash equivalents		(57,100	)		(22,800	)
Cash and cash equivalents at beginning of period		57,100			152,500
Cash and cash equivalents at end of period	$	—		$	129,700
Supplemental Schedule of non-cash investing and financing activities:
Distribution to Managing General Partner	$	—		$	184,200

See accompanying notes to financial statements.

7

ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

NOTE 1—DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

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 “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP).

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

In March 2012, Atlas Energy contributed to ARP, a newly formed exploration and production master limited partnership, substantially all of Atlas Energy’s natural gas and oil development and production assets and its partnership management business, including ownership of our MGP. Atlas Energy also distributed an approximate 19.6% limited partner interest in ARP to its unitholders, retaining a 78.4% limited partner interest. Atlas Energy also owns ARP’s general partner, which owns a 2% general partner interest and all of the incentive distribution rights in ARP.

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, for administrative services.

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

The accompanying financial statements, which are unaudited except that the balance sheet at December 31, 2011 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in the Form 10-K. These interim financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2011. Certain amounts in the prior period financial statements have been reclassified to conform to the current year presentation. The results of operations for the three and six months ended June 30, 2012 may not necessarily be indicative of the results of operations for the year ended December 31, 2012.

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, 2011 filed with the Securities and Exchange Commission (“SEC”).

Use of Estimates

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

8

ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2012

(Unaudited)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Use of Estimates (Continued)

The natural gas industry principally conducts its business by processing actual transactions as much as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following months’ financial results. Management believes that the operating results presented for the three and six months ended June 30, 2012 and 2011 represent actual results in all material respects (see “Revenue Recognition” accounting policy for further description).

Accounts Receivable and Allowance for Possible Losses

In evaluating the need for an allowance for possible losses, the MGP performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness as determined by review of its customers’ credit information. Credit is extended on an unsecured basis to many of its energy customers. At June 30, 2012 and December 31, 2011, the MGP’s credit evaluation indicated that the Partnership had no need for an allowance for possible losses.

Oil and Gas Properties

Oil and gas properties are stated at cost. Maintenance and repairs 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 which generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized.

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

The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties. The Partnership recorded depletion expense on natural gas and oil properties of $272,000 and $265,300 for the six months ended June 30, 2012 and 2011, respectively.

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

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

	June 30, 2012			December 31, 2011
Proved properties:
Leasehold interests	$	1,131,600		$	1,131,600
Wells and related equipment		52,224,500			52,224,500
		53,356,100			53,356,100
Accumulated depletion and impairment		(47,872,600	)		(47,600,600	)
Oil and gas properties, net	$	5,483,500		$	5,755,500

9

ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2012

(Unaudited)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Impairment of Long-Lived Assets

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

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

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

In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. The Partnership may have to pay additional consideration in the future as a well becomes uneconomic under the terms of the Partnership Agreement in order to recover these reserves. There was no impairment charge recognized during the three and six months ended June 30, 2012 and year ended December 31, 2011.

Working Interest

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

Revenue Recognition

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

10

ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2012

(Unaudited)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue Recognition (Continued)

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGL’s, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “Use of Estimates” accounting policy for further description). The Partnership had unbilled revenues at June 30, 2012 and December 31, 2011 of $162,000 and $218,600, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.

Comprehensive Loss

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

Recently Adopted Accounting Standards

In December 2011, the FASB issued Accounting Standards Update (“ASU”) 2011-12,Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05(“Update 2011-12”). The amendments in this update effectively defer implementation of changes made in Update 2011-05,Comprehensive Income (Topic 220): Presentation of Comprehensive Income(“Update 2011-05”), related to the presentation of reclassification adjustments out of accumulated other comprehensive income. Under Update 2011-05 which was issued by the FASB in June 2011, entities are provided the option to present the total of comprehensive income, the components of net income and the components of other comprehensive income in either a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with a total net income, each component of other comprehensive income and a total amount for comprehensive income. Update 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. As a result of Update 2011-12, entities are required to disclose reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect prior to Update 2011-05. All other requirements in Update 2011-05 are not affected by Update 2011-12. These requirements are effective for interim and annual reporting periods beginning after December 15, 2011. Accordingly, entities are not required to comply with presentation requirements of Update 2011-05 related to the disclosure of reclassifications out of accumulated other comprehensive income. The Partnership included separate but consecutive statements of income and comprehensive income within its Form 10-Qs upon the adoption of these ASUs on January 1, 2012. The adoption had no material impact on the Partnership’s financial condition or results of operations.

In December 2011, the FASB issued ASU 2011-11,Balance Sheet (Topic 210): Disclosure about Offsetting Assets and Liabilities(“Update 2011-11”). The amendments in this update require an entity to disclose both gross and net information about both financial and derivative instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the statement of financial position. An entity shall disclose at the end of a reporting period certain quantitative information separately for assets and liabilities that are within the scope of Update 2011-11, as well as provide a description of the rights of setoff associated with an entity’s recognized assets and recognized liabilities subject to an enforceable master netting arrangement or similar agreement. Entities are required to implement the amendments for interim and annual reporting periods beginning after January 1, 2013 and shall be applied retrospectively for any period presented that begins before the date of initial application. The Partnership has elected to early adopt these requirements and updated its disclosures to meet these requirements effective January 1, 2012. The adoption had no material impact on the Partnership’s financial position or results of operations.

11

ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2012

(Unaudited)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Recently Adopted Accounting Standards (Continued)

In May 2011, the FASB issued ASU 2011-04,Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“Update 2011-04”). The amendments in Update 2011-04 revise the wording used to describe many of the requirements for measuring fair value and for disclosing information about fair value measurements in U.S. GAAP. For many of the amendments, the guidance is not necessarily intended to result in a change in the application of the requirements in Topic 820; rather it is intended to clarify the intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. As a result, Update 2011-04 aims to provide common fair value measurement and disclosure requirements in U.S. GAAP and International Financial Reporting Standards. These requirements are effective for interim and annual reporting periods beginning after December 15, 2011. The Partnership updated its disclosures to meet these requirements upon the adoption of Update 2011-04 on January 1, 2012 (See Note 5). The adoption had no material impact on the Partnership’s financial position or results of operations.

NOTE 3—ASSET RETIREMENT OBLIGATION

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

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Asset retirement obligation at beginning of period	$	3,408,200	$	3,146,900	$	3,365,300	$	3,100,400
Accretion expense		42,800		46,500		85,700		93,000
Asset retirement obligation at end of period	$	3,451,000	$	3,193,400	$	3,451,000	$	3,193,400

12

ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2012

(Unaudited)

NOTE 4—DERIVATIVE INSTRUMENTS

Outstanding Contracts

The MGP, on behalf of the Partnership, uses a number of different derivative instruments, principally swaps, collars and options, in connection with its commodity price risk management activities. The MGP enters into financial instruments to hedge forecasted natural gas, NGL’s, crude oil and condensate 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 natural gas, NGLs, crude oil and condensate are sold. Under commodity-based swap agreements, the MGP receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not the obligation, to receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged.

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

At June 30, 2012, the Partnership had the following commodity derivatives:

Natural Gas Put Options

Production Period Ending December 31,	Volumes		Average Strike		Fair Value Asset(2)
	(mmbtu) (1)		(per mmbtu) (1)
2012		9,100	$	2.80	$	1,600
2013		13,700		3.45		5,500
2014		11,400		3.80		5,900
2015		9,100		4.00		6,200
2016		9,100		4.15		7,400
					$	26,600

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

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

13

ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2012

(Unaudited)

NOTE 4—DERIVATIVE INSTRUMENTS (Continued)

The following tables summarize the fair value of the Partnership’s derivative instruments as of June 30, 2012, as well as the gain or loss recognized in the statements of operations for the three and six months ended June 30, 2012 and 2011:

Fair Value of Derivative Instruments:

		Fair Value
Derivatives in Cash Flow Hedging Relationships	Balance Sheet Location	June 30, 2012
Derivative Commodity Contracts	Current Assets	$	4,200
	Long-Term Assets		22,400
	Current liabilities		—
	Long-term liabilities		—
	Total	$	26,600

Effects of Derivative Instruments on Statements of Operations:

	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012			2011
(Loss) gain recognized in accumulated OCI	$	(2,300	)	$	—	$	(2,300	)	$	35,600
Gain reclassified from accumulated OCI into loss	$	26,900		$	56,300	$	70,600		$	125,400

Historically, the MGP has entered into natural gas and crude oil future option contracts and collar contracts on behalf of the Partnership to achieve more predictable cash flows by hedging its exposure to changes in natural gas and oil prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. These contracts qualified and were designated as cash flow hedges and recorded at their fair values.

The Partnership recognized a gain of $129,000 for the six months ended June 30, 2011 on settled contracts covering natural gas and oil production for historical periods prior to the acquisition of the Transferred Business. These gains are included within gas and oil production revenue in the Partnership’s statements of operations. As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the six months ended June 30, 2011 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

Monetized Gains

Prior to the sale on February 17, 2011 of the Transferred Business, Atlas Energy, Inc. monetized its derivative instruments related to the Transferred Business. The monetized proceeds related to instruments that were originally put into place to hedge future natural gas and oil production of the Transferred Business, including production generated through its drilling partnerships. In addition, a portion of the monetized proceeds were used to fund the premiums paid in connection with the purchase of the June 2012 put options. As of June 30, 2012 and December 31, 2011, the Partnership recorded a receivable from the monetized derivative instruments of $119,700 and $156,600 in accounts receivable monetized gains-affiliate, respectively, and $54,500 and $102,300 in long-term receivable monetized gains-affiliate, respectively, with the corresponding net unrealized gains in accumulated other comprehensive income on the Partnership’s balance sheets, which will be allocated to natural gas and oil production revenue generated over the period of the original instruments’ term.

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ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2012

(Unaudited)

NOTE 4—DERIVATIVE INSTRUMENTS (Continued)

During June 2012, the MGP used the undistributed monetized funds to purchase natural gas put options on behalf of the limited partners of the Partnership only. A premium (“put premium”) was paid to purchase the contracts and at June 30, 2012, the put premiums were recorded as short-term and long-term payables to affiliate of $5,900 and $23,000, respectively. Furthermore, the put premium liabilities were included in accounts receivable monetized gains-affiliate and long-term receivable monetized gains-affiliate, respectively, in the Partnership’s balance sheets. The put premiums will be allocated to natural gas production revenues generated over the contractual term of the purchased hedging instruments.

The following table summarizes the gross fair values of the Partnership’s receivable and payable affiliate balances, presenting the impact of offsetting the related party assets and liabilities on the Partnership’s balance sheets for the periods indicated:

	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Balance Sheets			Net Amount of Assets Presented in the Balance Sheets
Offsetting Derivative Assets
As of June 30, 2012
Accounts receivable monetized gains-affiliate	$	119,700		$	(5,900	)	$	113,800
Long-term accounts receivable monetized gains-affiliate		54,500			(23,000	)		31,500
Total	$	174,200		$	(28,900	)	$	145,300
As of December 31, 2011
Accounts receivable monetized gains-affiliate	$	156,600		$	—		$	156,600
Long-term accounts receivable monetized gains-affiliate		102,300			—			102,300
Total	$	258,900		$	—		$	258,900
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheets			Net Amount of Liabilities Presented in the Balance Sheets
Offsetting Derivative Liabilities
As of June 30, 2012
Put premiums payable-affiliate	$	(5,900	)	$	5,900		$	—
Long-term put premiums payable-affiliate		(23,000	)		23,000			—
Total	$	(28,900	)	$	28,900		$	—
As of December 31, 2011
Put premiums payable-affiliate	$	—		$	—		$	—
Long-term put premiums payable-affiliate		—			—			—
Total	$	—		$	—		$	—

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ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2012

(Unaudited)

NOTE 4—DERIVATIVE INSTRUMENTS (Continued)

Accumulated Other Comprehensive Income (Loss)

As a result of the monetization and the early settlement of natural gas and oil derivative instruments, the put options and the unrealized gains recognized in income in prior periods due to natural gas and oil property impairments, the Partnership recorded a net deferred gain on its balance sheet in accumulated other comprehensive income of $48,100 as of June 30, 2012. For the year ended and prior periods, unrealized gains of 123,800 net of the MGP interest, respectively, were recognized into income as a result of oil and gas property impairments. In 2011, the MGP’s portion of the unrealized gains, $184,200, was written-off as part of the terms of the acquisition of the Transferred Business as a non-cash distribution to the MGP. During the current year, $40,400 of monetized proceeds were recorded by the Partnership and allocated only to the limited partners. Of the remaining $48,100 of net unrealized gain in accumulated other comprehensive income, the Partnership will reclassify $30,300 of net gains to the Partnership’s statements of operations over the next twelve month period and the remaining $17,800 in later periods.

NOTE 5—FAIR VALUE OF FINANCIAL INSTRUMENTS

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

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

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

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Partnership uses a fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 4). The Partnership’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements.

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

The Partnership estimates the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates (see Note 3). There were no additional assets or liabilities that were measured at fair value on a nonrecurring basis for the three and six months ended June 30, 2012 and 2011.

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ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2012

(Unaudited)

NOTE 6—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

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

• Administrative costs, which are included in general and administrative expenses in the Partnership’s statements of operations, are payable at $75 per well per month. Administrative costs incurred for the three and six months ended June 30, 2012 were $38,300 and $78,600, respectively. Administrative costs incurred for the three and six months ended June 30, 2011 were $43,900 and $84,600, respectively.

• Monthly well supervision fees, which are included in production expenses in the Partnership’s statements of operations, are payable at $313 per well per month, for operating and maintaining the wells. Well supervision fees incurred for the three months and six months ended June 30, 2012 were $160,000 and $328,500, respectively. Well supervision fees incurred for the three and six months ended June 30, 2011 were $183,500 and $353,600, respectively.

• Transportation fees, which are included in production expenses in the Partnership’s statements of operations, are generally payable at 13% of the natural gas sales price. Transportation fees incurred for the three and six months ended June 30, 2012 were $30,400 and $66,200, respectively. Transportation fees incurred for the three and six months ended June 30, 2011 were $65,800 and $115,500, respectively.

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

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

General

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 “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP).

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

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

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Results of Operations

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Production revenues (in thousands):
Gas	$	230		$	503		$	506		$	839
Oil		24			27			66			44
Liquid		3			—			8			—
Total	$	257		$	530		$	580		$	883
Production volumes:
Gas (mcf/day) (1)		1,054			1,131			994			966
Oil (bbls/day)(1)		3			3			4			3
Liquid (bbl/day) (1)		1			—			1			—
Total (mcfe/day) (1)		1,078			1,149			1,024			984
Average sales prices:(2)
Gas (per mcf)(1) (3)	$	2.74		$	5.57		$	3.14		$	5.84
Oil (per bbl)(1)	$	91.99		$	102.48		$	94.79		$	96.38
Liquid per (bbl/day) (1)	$	33.93		$	—		$	38.26		$	—
Average production costs:
As a percent of revenues		106	%		57	%		93	%		65	%
Per mcfe	$	2.78		$	2.88		$	2.89		$	3.23
Depletion per mcfe	$	1.45		$	1.48		$	1.46		$	1.49

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

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

(3) Average gas prices are calculated by including in total revenue derivative gains previously recognized into income and dividing by the total volume for the period. Previously recognized derivative gains were $33,200 and $70,200 for the three months ended June 30, 2012 and 2011, respectively. Previously recognized derivative gains were $62,500 and $182,600 for the six months ended June 30, 2012 and 2011, respectively. The derivative gains are included in other comprehensive income and resulted from prior period impairment charges.

Natural Gas Revenues. Our natural gas revenues were $229,600 and $502,700 for the three months ended June 30, 2012 and 2011, respectively, a decrease of $273,100 (54%). The $273,100 decrease in natural gas revenues for the three months ended June 30, 2012 as compared to the prior year similar period was attributable to a $238,800 decrease in our natural gas sales prices after the effect of financial hedges, which was driven by market conditions and a $34,300 decrease in production volumes. Our production volumes decreased to 1,054 mcf per day for the three months ended June 30, 2012 from 1,131 mcf per day for the three months ended June 30, 2011, a decrease of 77 mcf per day (7%). The overall decrease in natural gas production volumes for the three months ended June 30, 2012 as compared to the prior year similar period resulted primarily from the normal decline inherent in the life of a well.

Our natural gas revenues were $505,700 and $839,000 for the six months ended June 30, 2012 and 2011, respectively, a decrease of $333,300 (40%). The $333,300 decrease in natural gas revenues for the six months ended June 30, 2012 as compared to the prior year similar period was attributable to a $362,700 decrease in our natural gas sales prices after the effect of financial hedges, which was driven by market conditions, partially offset by a $29,400 increase in production volumes. Our production volumes increased to 994 mcf per day for the six months ended June 30, 2012 from 966 mcf per day for the six months ended June 30, 2011, an increase of 28 mcf per day (3%). Production increased for the six months ended June 30, 2012 due to an increase in available pipeline capacity.

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Oil Revenues.We drill wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $24,400 and $26,800 for the three months ended June 30, 2012 and 2011, respectively, a decrease of $2,400 (9%). The $2,400 decrease in oil revenues for the three months ended June 30, 2012 as compared to the prior year similar period was attributable to $2,800 decrease in oil prices after the effect of financial hedges, partially offset by a $400 increase in production volumes. Our production volumes increased to 2.91 bbls per day for the three months ended June 30, 2012 from 2.87 bbls per day for the three months ended June 30, 2011, an increase of 0.4 bbls per day (1%).

Our oil revenues were $66,300 and $44,400 for the six months ended June 30, 2012 and 2011, respectively, an increase of $21,900 (49%). The $21,900 increase in oil revenues for the six months ended June 30, 2012 as compared to the prior year similar period was attributable to a $23,000 increase in production volumes, partially offset by a $1,100 decrease in oil prices after the effect of financial hedges. Our production volumes increased to 4 bbls per day for the six months ended June 30, 2012 from 3 bbls per day for the six months ended June 30, 2011, an increase of 1 bbl per day (33%).

Natural 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. Some wells, 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 revenue were $3,000 and $8,500, respectively, for the three and six months ended June 30, 2012.

Costs and Expenses.Production expenses were $272,800 and $300,700 for the three months ended June 30, 2012 and 2011, respectively, a decrease of $27,900 (9%). Production expenses were $538,200 and $573,400 for the six months ended June 30, 2012 and 2011, respectively, a decrease of $35,200 (6%). The decrease for the three and six months ended June 30, 2012 as compared to the prior year similar periods were primarily attributable to a decrease in transportation fees.

Depletion of oil and gas properties as a percentage of oil and gas revenues were 55% and 29% for the three months ended June 30, 2012 and 2011, respectively; and 47% and 30% for the six months ended June 30, 2012 and 2011, 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 June 30, 2012 and 2011 were $49,300 and $52,600, respectively, a decrease of $3,300 (6%). For the six months ended June 30, 2012 and 2011, these expenses were $111,500 and $110,900, respectively, an increase of $600 (.5%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP. The decrease for the three-month period ended June 30, 2012 and the increase for the six month period ended June 30, 2012 are primarily due to changes in third-party costs as compared to the prior year similar period.

Liquidity and Capital Resources

Cash provided by operating activities decreased $294,100 in the six months ended June 30, 2012 to $116,700 as compared to $410,800 for the six months ended June 30, 2011. This decrease was due to a decrease in net loss before depletion and accretion of $268,400 and the change in the net non-cash loss on hedge instruments of $120,100. In addition, the change in accrued liabilities increased operating cash flows by $7,300 and the change in accounts receivable trade-affiliate increased operating cash flows by $87,100 for the six months ended June 30, 2012 compared to the six months ended June 30, 2011.

Cash used in financing activities decreased $259,800 for the six months ended June 30, 2012 to $173,800 from $433,600 for the six months ended June 30, 2011. This decrease was due to a decrease in cash distributions to partners.

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

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

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Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. On an on-going basis, we evaluate our estimates, including those related to our asset retirement obligations, depletion and certain accrued receivables and liabilities. We base our estimates on historical experience and on various other assumptions that we believe reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. A discussion of our significant accounting policies we have adopted and followed in the preparation of our financial statements is included within “Notes to Financial Statements” in Part I, Item 1, “Financial Statements” in this quarterly report and in our Annual Report on Form 10-K for the year ended December 31, 2011.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Under the supervision of our Chairman of the Board of Directors, Chief Executive Officer, President, and Chief Financial Officer, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, concluded that, at June 30, 2012, our disclosure controls and procedures were effective at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

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

PART II OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The Managing General Partner is not aware of any legal proceedings filed against the Partnership.

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

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ITEM 6. EXHIBITS

EXHIBIT INDEX

Exhibit No.	Description
4.0	Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #12-2003(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 3, 2003 in the Form S-1 Registration Statement dated September 3, 2003, File No. 333-105811

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SIGNATURES

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

Atlas America Public #12-2003 Limited Partnership

	ATLAS RESOURCES, LLC, Managing General Partner
Date: August 14, 2012	By:/s/ FREDDIE M. KOTEK
	Freddie M. Kotek, Chairman of the Board of Directors, Chief Executive Officer and President

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

Date: August 14, 2012	By:/s/ SEAN P. MCGRATH
	Sean P. McGrath, Chief Financial Officer

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