10-Q

United States

Securities and Exchange Commission

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended 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 000-51275

ATLAS AMERICA PUBLIC #14-2004 L.P.

(Name of small business issuer in its charter)

Delaware	86-1111314
(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 #14-2004 L.P.

(A DELAWARE LIMITED PARTNERSHIP)

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

PART I.	FINANCIAL INFORMATION	PAGE
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 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		18
Item 4:	Controls and Procedures		21
PART II.	OTHER INFORMATION
Item 1:	Legal Proceedings		21
Item 6:	Exhibits		22
SIGNATURES			23
CERTIFICATIONS

2

ATLAS AMERICA PUBLIC #14-2004 L.P.

BALANCE SHEETS

	June 30,		December 31,
	2012		2011
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	51,600	$	241,700
Accounts receivable trade-affiliate		237,200		445,100
Accounts receivable monetized gains-affiliate		139,200		191,600
Short-term hedge receivable		5,200		—
Total current assets		433,200		878,400
Oil and gas properties, net		6,975,000		7,376,600
Long-term receivable monetized gains-affiliate		38,800		125,500
Long-term hedge receivable		27,500		—
	$	7,474,500	$	8,380,500
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	4,700	$	10,300
Total current liabilities		4,700		10,300
Asset retirement obligation		3,782,000		3,711,900
Partners’ capital:
Managing general partner		2,707,900		2,932,700
Limited partners (5,256.95 units)		974,300		1,714,800
Accumulated other comprehensive income		5,600		10,800
Total partners’ capital		3,687,800		4,658,300
	$	7,474,500	$	8,380,500

See accompanying notes to financial statements.

3

ATLAS AMERICA PUBLIC #14-2004 L.P.

STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
REVENUES
Natural gas, oil and liquid gas	$	318,500		$	582,100		$	749,000		$	1,027,400
Interest income		—			100			100			200
Total revenues		318,500			582,200			749,100			1,027,600
COSTS AND EXPENSES
Production		315,100			367,500			652,200			704,000
Depletion		194,000			189,700			389,400			345,000
Accretion of asset retirement obligation		47,300			50,700			94,600			101,400
General and administrative		55,700			54,900			119,600			118,100
Total cost and expenses		612,100			662,800			1,255,800			1,268,500
Net loss	$	(293,600	)	$	(80,600	)	$	(506,700	)	$	(240,900	)
Allocation of net loss:
Managing general partner	$	(74,800	)	$	(35,000	)	$	(129,900	)	$	(78,900	)
Limited partners	$	(218,800	)	$	(45,600	)	$	(376,800	)	$	(162,000	)
Net loss per limited partnership unit	$	(42	)	$	(9	)	$	(72	)	$	(31	)

See accompanying notes to financial statements.

4

ATLAS AMERICA PUBLIC #14-2004 L.P.

STATEMENTS OF COMPREHENSIVE LOSS

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
Net loss	$	(293,600	)	$	(80,600	)	$	(506,700	)	$	(240,900	)
Other comprehensive loss:
Unrealized holding gain (loss) on hedging contracts		(2,800	)		—			(2,800	)		20,200
MGP portion of non-cash loss on hedge instruments		—			—			—			212,400
Difference in estimated monetized gains receivable		23,500			10,300			70,000			27,000
Less: reclassification adjustment for gains realized in net loss		(23,400	)		(52,000	)		(72,400	)		(137,600	)
Total other comprehensive (loss) income		(2,700	)		(41,700	)		(5,200	)		122,000
Comprehensive loss	$	(296,300	)	$	(122,300	)	$	(511,900	)	$	(118,900	)

See accompanying notes to financial statements.

5

ATLAS AMERICA PUBLIC #14-2004 L.P.

STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

FOR THE SIX MONTHS ENDED

June 30, 2012

(Unaudited)

							Accumulated
	Managing						Other
	General			Limited			Comprehensive
	Partner			Partners			Income (Loss)			Total
Balance at January 1, 2012	$	2,932,700		$	1,714,800		$	10,800		$	4,658,300
Participation in revenues and expenses:
Net production revenues		23,900			72,900			—			96,800
Interest income		—			100			—			100
Depletion		(78,800	)		(310,600	)		—			(389,400	)
Accretion of asset retirement obligation		(33,100	)		(61,500	)		—			(94,600	)
General and administrative		(41,900	)		(77,700	)		—			(119,600	)
Net loss		(129,900	)		(376,800	)		—			(506,700	)
Other comprehensive loss		—			—			(5,200	)		(5,200	)
Distributions to partners		(94,900	)		(363,700	)		—			(458,600	)
Balance at June 30, 2012	$	2,707,900		$	974,300		$	5,600		$	3,687,800

See accompanying notes to financial statements.

6

ATLAS AMERICA PUBLIC #14-2004 L.P.

STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended
	June 30,
	2012			2011
Cash flows from operating activities:
Net loss	$	(506,700	)	$	(240,900	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion		389,400			345,000
Non-cash loss on hedge instruments		101,200			200,600
Accretion of asset retirement obligation		94,600			101,400
Decrease in accounts receivable trade-affiliate		207,900			83,900
(Decrease) increase in accrued liabilities		(5,600	)		5,000
Asset retirement obligation settled		(24,500	)		—
Net cash provided by operating activities		256,300			495,000
Cash flows from investing activities:
Proceeds from sale of tangible equipment		12,200			—
Net cash provided by investing activities		12,200			—
Cash flows from financing activities:
Distributions to partners		(458,600	)		(629,200	)
Net cash used in financing activities		(458,600	)		(629,200	)
Net decrease in cash and cash equivalents		(190,100	)		(134,200	)
Cash and cash equivalents at beginning of period		241,700			346,800
Cash and cash equivalents at end of period	$	51,600		$	212,600
Supplemental schedule of non-cash investing and financing activities:
Distribution to Managing General Partner	$	—		$	212,400

See accompanying notes to financial statements.

7

ATLAS AMERICA PUBLIC #14-2004 L.P.

NOTES TO FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

NOTE 1 - DESCRIPTION OF BUSINESS

Atlas America Public #14-2004 L.P. (the “Partnership”) is a Delaware limited partnership, formed on May 3, 2004 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 and Tennessee. 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 #14-2004 L.P.

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 Partnership’s 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 $389,400 and $345,000 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. As a result of retirements, the Partnership reclassified $335,100 from oil and gas properties to accumulated depletion for the six months ended June 30, 2012.

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

	June 30,			December 31,
	2012			2011
Proved properties:
Leasehold interest	$	1,412,700		$	1,417,900
Wells and related equipment		66,762,100			67,104,200
		68,174,800			68,522,100
Accumulated depletion and impairment		(61,199,800	)		(61,145,500	)
Oil and gas properties, net	$	6,975,000		$	7,376,600

9

ATLAS AMERICA PUBLIC #14-2004 L.P.

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. During the year ended December 31, 2011, the Partnership recognized an impairment charge of $1,398,000, net of an offsetting gain in accumulated other comprehensive income of $94,300.

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.

10

ATLAS AMERICA PUBLIC #14-2004 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2012

(Unaudited)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue Recognition

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

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGL’s, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “Use of Estimates” accounting policy for further description). The Partnership had unbilled revenues at June 30, 2012 and December 31, 2011 of $206,100 and $325,400, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.

Comprehensive (Loss) Income

Comprehensive (loss) income 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.

11

ATLAS AMERICA PUBLIC #14-2004 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2012

(Unaudited)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Recently Adopted Accounting Standards (Continued)

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.

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				Six Months Ended
	June 30,				June 30,
	2012		2011		2012			2011
Asset retirement obligation at beginning of period	$	3,734,700	$	3,432,600	$	3,711,900		$	3,381,900
Liabilities settled		—		—		(24,500	)		—
Accretion expense		47,300		50,700		94,600			101,400
Asset retirement obligation at end of period	$	3,782,000	$	3,483,300	$	3,782,000		$	3,483,300

12

ATLAS AMERICA PUBLIC #14-2004 L.P.

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 entered 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 received or paid a fixed price and received or remitted a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not 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		11,204	$	2.80	$	1,940
2013		16,806		3.45		6,726
2014		14,005		3.80		7,259
2015		11,204		4.00		7,608
2016		11,204		4.15		9,167
					$	32,700

13

ATLAS AMERICA PUBLIC #14-2004 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2012

(Unaudited)

NOTE 4 – DERIVATIVE INSTRUMENTS (Continued)

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

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

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	$	5,200
	Long-Term Assets		27,500
	Current liabilities		—
	Long-term liabilities		—
	Total	$	32,700

Effects of Derivative Instruments on Statements of Operations:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2012			2011		2012			2011
(Loss) gain recognized in accumulated OCI	$	(2,800	)	$	—	$	(2,800	)	$	20,200
Gain reclassified from accumulated OCI into income	$	23,400		$	52,000	$	72,400		$	137,600

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 $144,900 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.

14

ATLAS AMERICA PUBLIC #14-2004 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2012

(Unaudited)

NOTE 4 – DERIVATIVE INSTRUMENTS (Continued)

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 $146,500 and $191,600 in accounts receivable monetized gains-affiliate, respectively, and $67,000 and $125,500 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.

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 $7,300 and $28,200, 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 premium will be allocated to natural gas production revenues generated over the contractual term of the purchased hedging instruments.

15

ATLAS AMERICA PUBLIC #14-2004 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2012

(Unaudited)

NOTE 4 – DERIVATIVE INSTRUMENTS (Continued)

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:

Offsetting Derivative Assets	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Balance Sheets			Net Amount of Assets Presented in the Balance Sheets
As of June 30, 2012
Accounts receivable monetized gains-affiliate	$	146,500		$	(7,300	)	$	139,200
Long-term accounts receivable monetized gains-affiliate		67,000			(28,200	)		38,800
Total	$	213,500		$	(35,500	)	$	178,000
As of December 31, 2011
Accounts receivable monetized gains-affiliate	$	191,600		$	—		$	191,600
Long-term accounts receivable monetized gains-affiliate		125,500			—			125,500
Total	$	317,100		$	—		$	317,100
Offsetting Derivative Liabilities	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheets			Net Amount of Liabilities Presented in the Balance Sheets
As of June 30, 2012
Put premiums payable-affiliate	$	(7,300	)	$	7,300		$	—
Long-term put premiums payable-affiliate		(28,200	)		28,200			—
Total	$	(35,500	)	$	35,500		$	—
As of December 31, 2011
Put premiums payable-affiliate	$	—		$	—		$	—
Long-term put premiums payable-affiliate		—			—			—
Total	$	—		$	—		$	—

16

ATLAS AMERICA PUBLIC #14-2004 L.P.

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 $5,600 as of June 30, 2012. For the year ended December 31, 2011 and prior periods, unrealized gains of $65,600 and $139,500 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, $212,400, 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, $28,500 of monetized proceeds were recorded by the Partnership and allocated only to the limited partners. Of the remaining $5,600 of net unrealized gain in accumulated other comprehensive income, the Partnership will reclassify $1,800 of net gains to the Partnership’s statements of operations over the next twelve month period and the remaining $3,800 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.

17

ATLAS AMERICA PUBLIC #14-2004 L.P.

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, $41,900 and $85,700, respectively. Administrative costs incurred for the three and six months ended June 30, 2011 were $46,100 and $91,400, respectively.

• Monthly well supervision fees, which are included in production expenses in the Partnership’s statements of operations, are payable at $318 per well per month, for operating and maintaining the wells. Well supervision fees incurred for the three and six months June 30, 2012 were $177,500 and $363,300, respectively. Well supervision fees incurred for the three and six months ended June 30, 2011 were $195,200 and $387,200, 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 $41,300 and $94,500, respectively. Transportation fees incurred for the three and six months ended June 30, 2011 were $66,100 and $122,100, respectively.

• The MGP and its affiliates perform all administrative and management functions for the Partnership including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets represents 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 #14-2004 L.P. (the “Partnership”) is a Delaware limited partnership, formed on May 3, 2004 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP).

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

18

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	$	264		$	494		$	625		$	890
Oil		51			88			113			137
Liquid		4			—			11			—
Total	$	319		$	582		$	749		$	1,027
Production volumes:
Gas (mcf/day) (1)		1,206			1,117			1,211			1,013
Oil (bbls/day) (1)		6			10			7			8
Liquid (bbl/day) (1)		1			—			2			—
Total (mcfe/day) (1)		1,248			1,177			1,265			1,061
Average sales prices: (2)
Gas (per mcf) (1) (3)	$	2.88		$	5.67		$	3.30		$	5.95
Oil (per bbl) (1)	$	86.88		$	97.82		$	93.58		$	92.07
Liquid per (bbl/day) (1)	$	33.80		$	—		$	38.08		$	—
Average production costs:
As a percent of revenues		99	%		63	%		87	%		69	%
Per mcfe	$	2.77		$	3.43		$	2.84		$	3.66
Depletion per mcfe	$	1.70		$	1.77		$	1.70		$	1.79

(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 loss and dividing by the total volume for the period. Previously recognized derivative gains were $52,200 and $82,400 for the three months ended June 30, 2012 and 2011, respectively. Previously recognized derivative gains were $102,000 and $200,900 for the six months ended June 30, 2012 and 2011, respectively. The derivative gains are included in other comprehensive loss and resulted from prior period impairment charges.

Natural Gas Revenues. Our natural gas revenues were $263,800 and $494,500 for the three months ended June 30, 2012 and 2011, respectively, a decrease of $230,700 (47%). The $230,700 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 $270,000 decrease in our natural gas sales prices after the effect of financial hedges, which was driven by market conditions, partially offset by a $39,300 increase in production volumes. Our production volumes increased to 1,206 mcf per day for the three months ended June 30, 2012 from 1,117 mcf per day for the three months ended June 30, 2011, an increase of 89 mcf per day (8%).

Our natural gas revenues were $624,600 and $890,100 for the six months ended June 30, 2012 and 2011, respectively, a decrease of $265,500 (30%). The $265,500 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 $445,700 decrease in our natural gas sales prices after the effect of financial hedges, which was driven by market conditions, partially offset by an $180,200 increase in production volumes. Our production volumes increased to 1,211 mcf per day for the six months ended June 30, 2012 from 1,013 mcf per day for the six months ended June 30, 2011, an increase of 198 mcf per day (20%).

19

Oil Revenues. We drill wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $51,200 and $87,600 for the three months ended June 30, 2012 and 2011, respectively, a decrease of $36,400 (42%). The $36,400 decrease in oil revenues for the three months ended June 30, 2012 as compared to the prior year similar period was attributable to a $30,000 decrease in production volumes and a $6,400 decrease in oil prices after the effect of financial hedges. Our production volumes decreased to 6 bbls per day for the three months ended June 30, 2012 from 10 bbls per day for the three months ended June 30, 2011, a decrease of 4 bbls per day (40%).

Our oil revenues were $113,500 and $137,300 for the six months ended June 30, 2012 and 2011, respectively, a decrease of $23,800 (17%). The $23,800 decrease in oil revenues for the six months ended June 30, 2012 as compared to the prior year similar period was attributable to a $25,600 decrease in production volumes, partially offset by a $1,800 increase in oil prices after the effect of financial hedges. Our production volumes decreased to 7 bbls per day for the six months ended June 30, 2012 from 8 bbls per day for the six months ended June 30, 2011, a decrease of 1 bbl per day (13%).

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 revenues were $3,500 and $10,900 for the three and six months ended June 30, 2012.

Costs and Expenses. Production expenses were $315,100 and $367,500 for the three months ended June 30, 2012 and 2011, respectively, a decrease of $52,400 (14%). Production expenses were $652,200 and $704,000 for the six months ended June 30, 2012 and 2011, respectively, a decrease of $51,800 (7%). The decrease for the three and six months ended June 30, 2012 as compared to the prior year similar period was mainly due to lower transportation fees.

Depletion of oil and gas properties as a percentage of oil and gas revenues were 61% and 33% for the three months ended June 30, 2012 and 2011, respectively; and 52% and 34% 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 $55,700 and $54,900, respectively, an increase of $800 (1.5%). For the six months ended June 30, 2012 and 2011, these expenses were $119,600 and $118,100, respectively, an increase of $1,500 (1.3%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP. The increase for the three and six month and period ended June 30, 2012 are primarily due to third-party costs as compared to the prior year similar period.

Liquidity and Capital Resources

Cash provided by operating activities decreased $238,700 in the six months ended June 30, 2012 to $256,300 as compared to $495,000 for the six months ended June 30, 2011. This decrease was due to a decrease in net earnings before depletion, a net non-cash loss on hedge instruments and accretion of $327,600, a decrease in the change in accrued liabilities of $10,600 and the settlement of asset retirement obligations of $24,500. In addition, the change in accounts receivable trade-affiliate increased operating cash flows by $124,000 for the six months ended June 30, 2012 compared to the six months ended June 30, 2011.

Cash provided by investing activities was $12,200 for the six months ended June 30, 2012 due to the sale of tangible equipment.

Cash used in financing activities decreased $170,600 during the six months ended June 30, 2012 to $458,600 from $629,200 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. Through June 30, 2012, our MGP had not withheld any funds for this purpose. Any additional funds, if required, will be obtained from production revenues or borrowings from our MGP or its affiliates, which are not contractually committed to make loans to us. The amount that we may borrow may not at any time exceed 5% of our total subscriptions, and we will not borrow from third-parties.

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

20

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with 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.

21

ITEM 6. EXHIBITS

EXHIBIT INDEX

Exhibit No.	Description
4.0	Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #14-2004 L.P. (1)
31.1	Certification Pursuant to Rule 13a-14/15(d)-14
31.2	Certification Pursuant to Rule 13a-14/15(d)-14
32.1	Section 1350 Certification
32.2	Section 1350 Certification
101	Interactive Data File

(1) Filed on June 30, 2004 in the Form S-1 Registration Statement dated June 30, 2004, File No. 000-51275

22

SIGNATURES

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

Atlas America Public #14-2004 L.P.
	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

23

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Freddie M. Kotek, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2012 of Atlas America Public #14-2004 L.P.;

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

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

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

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

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

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

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

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

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

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

By:	/s/ FREDDIE M. KOTEK
Name:	Freddie M. Kotek
Title:	Chief Executive Officer of the Managing General Partner
Date:	August 14, 2012

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Sean P. McGrath, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2012 of Atlas America Public #14-2004 L.P.;

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

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

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

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

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

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

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

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

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

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

By:	/s/ SEAN P. MCGRATH
Name:	Sean P. McGrath
Title:	Chief Financial Officer of the Managing General Partner
Date:	August 14, 2012

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Atlas America Public #14-2004 L.P. (the “Partnership”) on Form 10-Q for the period ended June 30, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Freddie M. Kotek, Chief Executive Officer of the Managing General Partner, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

By:	/S/ FREDDIE M. KOTEK
Name:	Freddie M. Kotek
Title:	Chief Executive Officer of the Managing General Partner
Date:	August 14, 2012

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Atlas America Public #14-2004 L.P. (the “Partnership”) on Form 10-Q for the period ended June 30, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Sean P. McGrath, Chief Financial Officer of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

By:	/S/ SEAN P. MCGRATH
Name:	Sean P. McGrath
Title:	Chief Financial Officer of the Managing General Partner
Date:	August 14, 2012

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Derivative Instruments (Effects of Derivative Instruments on Statements of Operations) (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Derivative Instruments [Abstract]
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Net of Tax	$ (2,800)		$ (2,800)	$ 20,200
Unrealized holding gain (loss) on hedging contracts	(2,800)		(2,800)	20,200
(Loss) Gain recognized in accumulated OCI	(2,800)		(2,800)	20,200
Gain reclassified from accumulated OCI into (loss) income	23,400	52,000	72,400	137,600
Less: reclassification adjustment for gains realized in net loss	$ (23,400)	$ (52,000)	$ (72,400)	$ (137,600)

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2012

Summary of Significant Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

In addition to matters discussed further in this note, the Partnership's significant accounting policies are detailed in its audited financial statements and notes thereto in the Partnership's annual report on Form 10-K for the year ended December 31, 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.

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 $389,400 and $345,000 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. As a result of retirements, the Partnership reclassified $335,100 from oil and gas properties to accumulated depletion for the six months ended June 30, 2012.

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

	June 30,	December 31,
	2012	2011
Proved properties:
Leasehold interest	$                              1,412,700	$                              1,417,900
Wells and related equipment	66,762,100	67,104,200
	68,174,800	68,522,100
Accumulated depletion and impairment	(61,199,800)	(61,145,500)
Oil and gas properties, net	$                              6,975,000	$                              7,376,600

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. During the year ended December 31, 2011, the Partnership recognized an impairment charge of $1,398,000, net of an offsetting gain in accumulated other comprehensive income of $94,300.

Working Interest

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

Revenue Recognition

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

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGL's, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership's records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see "Use of Estimates" accounting policy for further description). The Partnership had unbilled revenues at June 30, 2012 and December 31, 2011 of $206,100 and $325,400, respectively, which were included in accounts receivable trade-affiliate within the Partnership's balance sheets.

Comprehensive (Loss) Income

Comprehensive (loss) income 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.

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.

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Certain Relationships and Related Party Transactions (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Related Party Transaction [Line Items]
Monthly Administrative Costs Per Well			$ 75
Administrative Costs Included in General and Administrative Expenses	41,900	46,100	85,700	91,400
Monthly Supervision Fees Per Well			318
Transportation Fee Rate As A Percentage Of The Natural Gas Sales Price			13.00%
Well Supervision Fees Included In Production Expenses [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	177,500	195,200	363,300	387,200
Production And Distribution Costs [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 41,300	$ 66,100	$ 94,500	$ 122,100

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Description of Business

6 Months Ended

Jun. 30, 2012

Description of Business [Abstract]

DESCRIPTION OF BUSINESS

NOTE 1 - DESCRIPTION OF BUSINESS

Atlas America Public #14-2004 L.P. (the "Partnership") is a Delaware limited partnership, formed on May 3, 2004 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 and Tennessee. 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.

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Balance Sheets (USD $)	Jun. 30, 2012	Dec. 31, 2011
ASSETS
Cash and cash equivalents	$ 51,600	$ 241,700
Accounts receivable trade-affiliate	237,200	445,100
Accounts receivable monetized gains-affiliate	139,200	191,600
Short-term hedge receivable	5,200
Total current assets	433,200	878,400
Oil and gas properties, net	6,975,000	7,376,600
Long-term receivable monetized gains-affiliate	38,800	125,500
Long-term hedge receivable	27,500
TOTAL ASSETS	7,474,500	8,380,500
LIABILITIES AND PARTNERS' CAPITAL
Accrued liabilities	4,700	10,300
Total current liabilities	4,700	10,300
Asset retirement obligation	3,782,000	3,711,900
Partners' capital:
Managing general partner	2,707,900	2,932,700
Limited partners (5,256.95 units)	974,300	1,714,800
Accumulated other comprehensive income	5,600	10,800
Total partners' capital	3,687,800	4,658,300
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$ 7,474,500	$ 8,380,500

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Statement of Changes in Partners' Capital (USD $)	Managing General Partner [Member]	Limited Partners [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Total
Balance at Dec. 31, 2011	$ 2,932,700	$ 1,714,800	$ 10,800	$ 4,658,300
Participation in revenues and expenses
Net production revenues	23,900	72,900		96,800
Interest income		100		100
Depletion	(78,800)	(310,600)		(389,400)
Accretion of asset retirement obligation	(33,100)	(61,500)		(94,600)
General and administrative	(41,900)	(77,700)		(119,600)
Net loss	(129,900)	(376,800)		(506,700)
Other comprehensive loss			(5,200)	(5,200)
Distributions to partners	(94,900)	(363,700)		(458,600)
Balance at Jun. 30, 2012	$ 2,707,900	$ 974,300	$ 5,600	$ 3,687,800

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Derivative Instruments (Narrative) (Details) (USD $)	6 Months Ended				12 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Jun. 30, 2012 Net Deferred Gain [Member] Net Amount of Cash Received for Monetized Gains and Reversal of Prior Period Gains Recognized [Member]	Dec. 31, 2011 Unrealized Gains [Member] Net Amount of Cash Received for Monetized Gains and Reversal of Prior Period Gains Recognized [Member]	Dec. 31, 2011 Noncash Distribution [Member] Net Amount of Cash Received for Monetized Gains and Reversal of Prior Period Gains Recognized [Member]	Jun. 30, 2012 Allocation To Limited Partner Only [Member]	Jun. 30, 2011 Allocation To Limited Partner And Managing General Partner [Member]	Jun. 30, 2012 Accounts Receivable Monetized Gains Affiliate [Member]	Dec. 31, 2011 Accounts Receivable Monetized Gains Affiliate [Member]	Jun. 30, 2012 Long Term Accounts Receivable Monetized [Member]	Dec. 31, 2011 Long Term Accounts Receivable Monetized [Member]	Jun. 30, 2012 Put Premiums Payable Affiliate [Member]	Dec. 31, 2011 Put Premiums Payable Affiliate [Member]	Jun. 30, 2012 Long Term Put Premiums Payable Affiliate [Member]	Dec. 31, 2011 Long Term Put Premiums Payable Affiliate [Member]
Derivative [Line Items]
Gain Recognized On Settled Commodity Contracts								$ 144,900
Gain (Loss) on Fair Value Hedge Ineffectiveness, Net		0
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Of Recognized Assets	213,500		317,100						146,500	191,600	67,000	125,500
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	35,500												7,300		28,200
Accumulated Other Comprehensive Income (Loss), Net of Tax	5,600		10,800	5,600	65,600
Accumulated Other Comprehensive Income (Loss), Prior Periods, Net Of Tax					139,500
Distribution to Managing General Partner		(212,400)				(212,400)
Net production revenues	96,800						28,500
Net Deferred Gain To Be Reclassified Into Net Income Over The Next Twelve Months	1,800
Net Deferred Gain To Be Reclassified Into Net Income In Later Periods	$ 3,800

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Derivative Instruments (Fair Value of Derivative Instruments) (Details) (USD $)	Jun. 30, 2012
Derivative [Line Items]
Total Derivatives in Cash Flow Hedging Relationships	$ 32,700
Current Assets [Member]
Derivative [Line Items]
Derivatives in Cash Flow Hedging Relationships, Asset	5,200
Long Term Assets [Member]
Derivative [Line Items]
Derivatives in Cash Flow Hedging Relationships, Asset	$ 27,500

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Statements of Cash Flows (USD $)	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
Cash flows from operating activities:
Net loss	$ (506,700)	$ (240,900)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion	389,400	345,000
Non-cash loss on hedge instruments	101,200	200,600
Accretion expense	94,600	101,400
Decrease in accounts receivable trade-affiliate	207,900	83,900
(Decrease) increase in accrued liabilities	(5,600)	5,000
Asset retirement obligation settled	(24,500)
Net cash provided by operating activities	256,300	495,000
Cash flows from investing activities:
Proceeds from sale of tangible equipment	12,200
Net cash provided by investing activities	12,200
Cash flows from financing activities:
Distributions to partners	(458,600)	(629,200)
Net cash used in financing activities	(458,600)	(629,200)
Net decrease in cash and cash equivalents	(190,100)	(134,200)
Cash and cash equivalents at beginning of period	241,700	346,800
Cash and cash equivalents at end of period	51,600	212,600
Supplemental schedule of non-cash investing and financing activities:
Distribution to Managing General Partner		$ 212,400

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Balance Sheets (Parenthetical)	Jun. 30, 2012	Dec. 31, 2011
Balance Sheets
Limited Partners' Units	5,256.95	5,256.95

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Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2012

Derivative [Line Items]

Fair Value of Derivative Instruments [Table Text Block]

		Fair Value
Derivatives in Cash Flow Hedging Relationships	Balance Sheet Location	June 30, 2012
Derivative Commodity Contracts	Current Assets	$        5,200
	Long-Term Assets	27,500
	Current liabilities	—
	Long-term liabilities	—
	Total	$      32,700

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

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2012	2011	2012	2011
(Loss) gain recognized in accumulated OCI	$     (2,800)	$              —	$    (2,800)	$         20,200
Gain reclassified from accumulated OCI into income	$    23,400	$      52,000	$   72,400	$       137,600

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

	Gross Amounts	Gross Amounts	Net Amount of Assets
	of Recognized	Offset in the	Presented in the
	Assets	Balance Sheets	Balance Sheets
Offsetting Derivative Assets
As of June 30, 2012
Accounts receivable monetized gains-affiliate	$         146,500	$            (7,300)	$                      139,200
Long-term accounts receivable monetized gains-affiliate	67,000	(28,200)	38,800
Total	$         213,500	$           (35,500)	$                      178,000
As of December 31, 2011
Accounts receivable monetized gains-affiliate	$         191,600	$                    —	$                      191,600
Long-term accounts receivable monetized gains-affiliate	125,500	—	125,500
Total	$         317,100	$                    —	$                      317,100
	Gross Amounts	Gross Amounts	Net Amount of Liabilities
	of Recognized	Offset in the	Presented in the
	Liabilities	Balance Sheets	Balance Sheets
Offsetting Derivative Liabilities
As of June 30, 2012
Put premiums payable-affiliate	$                           (7,300)	$                           7,300	$                                          —
Long-term put premiums payable-affiliate	(28,200)	28,200	—
Total	$                           (35,500)	$                           35,500	$                                          —
As of December 31, 2011
Put premiums payable-affiliate	$                           —	$                           —	$                                          —
Long-term put premiums payable-affiliate	—	—	—
Total	$                           —	$                           —	$                                          —

Purchased Put Option [Member]

Derivative [Line Items]

Commodity Derivatives [Table Text Block]

Natural Gas Put Options

Production
Period Ending		Average	Fair Value
December 31,	Volumes	Strike	Asset (2)
	(mmbtu) (1)	(per mmbtu) (1)
2012	11,204	$                        2.80	$                     1,940
2013	16,806	3.45	6,726
2014	14,005	3.80	7,259
2015	11,204	4.00	7,608
2016	11,204	4.15	9,167
			$                  32,700

____________

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

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

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Document and Entity Information	6 Months Ended
	Jun. 30, 2012
Document and Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q2
Entity Registrant Name	Atlas America Public #14-2004 L.P.
Entity Central Index Key	0001294476
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding	5,256.95

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Description of Business And Basis Of Presentation (Details)	6 Months Ended
	Jun. 30, 2012
Description of Business [Abstract]
Atlas America Public #14-2004 L.P. Formation Date	May 03, 2004

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Statements of Operations (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
REVENUES
Natural gas, oil and liquid gas	$ 318,500	$ 582,100	$ 749,000	$ 1,027,400
Interest income		100	100	200
Total revenues	318,500	582,200	749,100	1,027,600
COSTS AND EXPENSES
Production	315,100	367,500	652,200	704,000
Depletion	194,000	189,700	389,400	345,000
Accretion of asset retirement obligation	47,300	50,700	94,600	101,400
General and administrative	55,700	54,900	119,600	118,100
Total costs and expenses	612,100	662,800	1,255,800	1,268,500
Net loss	(293,600)	(80,600)	(506,700)	(240,900)
Allocation of net loss:
Managing general partner	(74,800)	(35,000)	(129,900)	(78,900)
Limited partners	$ (218,800)	$ (45,600)	$ (376,800)	$ (162,000)
Net loss per limited partnership unit	(42)	(9)	(72)	(31)

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Fair Value of Financial Instruments

6 Months Ended

Jun. 30, 2012

Fair Value of Financial Instruments [Abstract]

FAIR VALUE OF FINANCIAL INSTRUMENTS

NOTE 5 - FAIR VALUE OF FINANCIAL INSTRUMENTS

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

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

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

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Partnership uses a 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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Derivative Instruments

6 Months Ended

Jun. 30, 2012

Derivative Instruments [Abstract]

DERIVATIVE INSTRUMENTS

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 entered 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 received or paid a fixed price and received or remitted a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not 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		Average	Fair Value
December 31,	Volumes	Strike	Asset (2)
	(mmbtu) (1)	(per mmbtu) (1)
2012	11,204	$                        2.80	$                     1,940
2013	16,806	3.45	6,726
2014	14,005	3.80	7,259
2015	11,204	4.00	7,608
2016	11,204	4.15	9,167
			$                  32,700

____________

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

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

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	$        5,200
	Long-Term Assets	27,500
	Current liabilities	—
	Long-term liabilities	—
	Total	$      32,700

Effects of Derivative Instruments on Statements of Operations:

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2012	2011	2012	2011
(Loss) gain recognized in accumulated OCI	$     (2,800)	$              —	$    (2,800)	$         20,200
Gain reclassified from accumulated OCI into income	$    23,400	$      52,000	$   72,400	$       137,600

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 $144,900 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 $146,500 and $191,600 in accounts receivable monetized gains-affiliate, respectively, and $67,000 and $125,500 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.

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 $7,300 and $28,200, 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 premium 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	Gross Amounts	Net Amount of Assets
	of Recognized	Offset in the	Presented in the
	Assets	Balance Sheets	Balance Sheets
Offsetting Derivative Assets
As of June 30, 2012
Accounts receivable monetized gains-affiliate	$         146,500	$            (7,300)	$                      139,200
Long-term accounts receivable monetized gains-affiliate	67,000	(28,200)	38,800
Total	$         213,500	$           (35,500)	$                      178,000
As of December 31, 2011
Accounts receivable monetized gains-affiliate	$         191,600	$                    —	$                      191,600
Long-term accounts receivable monetized gains-affiliate	125,500	—	125,500
Total	$         317,100	$                    —	$                      317,100
	Gross Amounts	Gross Amounts	Net Amount of Liabilities
	of Recognized	Offset in the	Presented in the
	Liabilities	Balance Sheets	Balance Sheets
Offsetting Derivative Liabilities
As of June 30, 2012
Put premiums payable-affiliate	$                           (7,300)	$                           7,300	$                                          —
Long-term put premiums payable-affiliate	(28,200)	28,200	—
Total	$                           (35,500)	$                           35,500	$                                          —
As of December 31, 2011
Put premiums payable-affiliate	$                           —	$                           —	$                                          —
Long-term put premiums payable-affiliate	—	—	—
Total	$                           —	$                           —	$                                          —

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 $5,600 as of June 30, 2012. For the year ended December 31, 2011 and prior periods, unrealized gains of $65,600 and $139,500 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, $212,400, 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, $28,500 of monetized proceeds were recorded by the Partnership and allocated only to the limited partners. Of the remaining $5,600 of net unrealized gain in accumulated other comprehensive income, the Partnership will reclassify $1,800 of net gains to the Partnership's statements of operations over the next twelve month period and the remaining $3,800 in later periods.

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Derivative Instruments (Commodity Derivatives) (Details) (USD $)	6 Months Ended
	Jun. 30, 2012 MMBTU USDPerMmbtu
Derivative [Line Items]
Fair Value Asset	$ 32,700
Production Period Ending December 31, 2012 [Member] | Purchased Put Option [Member]
Derivative [Line Items]
Volumes (mmbtu)	11,204	[1]
Average Strike (per mmbtu)	2.80	[1]
Fair Value Asset	1,940	[2]
Production Period Ending December 31, 2013 [Member] | Purchased Put Option [Member]
Derivative [Line Items]
Volumes (mmbtu)	16,806	[1]
Average Strike (per mmbtu)	3.45	[1]
Fair Value Asset	6,726	[2]
Production Period Ending December 31, 2014 [Member] | Purchased Put Option [Member]
Derivative [Line Items]
Volumes (mmbtu)	14,005	[1]
Average Strike (per mmbtu)	3.80	[1]
Fair Value Asset	7,259	[2]
Production Period Ending December 31, 2015 [Member] | Purchased Put Option [Member]
Derivative [Line Items]
Volumes (mmbtu)	11,204	[1]
Average Strike (per mmbtu)	4.00	[1]
Fair Value Asset	7,608	[2]
Production Period Ending December 31, 2016 [Member] | Purchased Put Option [Member]
Derivative [Line Items]
Volumes (mmbtu)	11,204	[1]
Average Strike (per mmbtu)	4.15	[1]
Fair Value Asset	$ 9,167	[2]

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

[2]

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Summary of Significant Accounting Policies (Narrative) (Details) (USD $)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011
Summary of Significant Accounting Policies [Abstract]
Additional working interest			7.00%
Unbilled Revenues	$ 206,100		$ 206,100		$ 325,400
Depletion of Oil and Gas Properties	194,000	189,700	389,400	345,000
Asset Impairment Charges, Net of an Offsetting Gain	0		0		1,398,000
Asset Impairment Charges, Offsetting Gain					94,300
Reclassification From Oil And Gas Properties To Accumulated Depletion Due To Asset Retirements			$ 335,100

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

6 Months Ended

Jun. 30, 2012

Oil And Gas Properties [Member]

Schedule of Oil and Gas Properties [Table Text Block]

	June 30,	December 31,
	2012	2011
Proved properties:
Leasehold interest	$                              1,412,700	$                              1,417,900
Wells and related equipment	66,762,100	67,104,200
	68,174,800	68,522,100
Accumulated depletion and impairment	(61,199,800)	(61,145,500)
Oil and gas properties, net	$                              6,975,000	$                              7,376,600

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Certain Relationships And Related Party Transactions

6 Months Ended

Jun. 30, 2012

Certain Relationships And Related Party Transactions [Abstract]

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

NOTE 6 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The Partnership has entered into the following significant transactions with 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, $41,900 and $85,700, respectively. Administrative costs incurred for the three and six months ended June 30, 2011 were $46,100 and $91,400, respectively.

·Monthly well supervision fees, which are included in production expenses in the Partnership's statements of operations, are payable at $318 per well per month, for operating and maintaining the wells. Well supervision fees incurred for the three and six months June 30, 2012 were $177,500 and $363,300, respectively. Well supervision fees incurred for the three and six months ended June 30, 2011 were $195,200 and $387,200, 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 $41,300 and $94,500, respectively. Transportation fees incurred for the three and six months ended June 30, 2011 were $66,100 and $122,100, respectively.

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

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Summary of Significant Accounting Policies (Policy)

6 Months Ended

Jun. 30, 2012

Summary of Significant Accounting Policies [Abstract]

Use of Estimates [Policy Text Block]

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.

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 [Policy Text Block]

Accounts Receivable and Allowance for Possible Losses

In evaluating the need for an allowance for possible losses, the MGP performs ongoing credit evaluations of 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 [Policy Text Block]

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 $389,400 and $345,000 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. As a result of retirements, the Partnership reclassified $335,100 from oil and gas properties to accumulated depletion for the six months ended June 30, 2012.

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

	June 30,	December 31,
	2012	2011
Proved properties:
Leasehold interest	$                              1,412,700	$                              1,417,900
Wells and related equipment	66,762,100	67,104,200
	68,174,800	68,522,100
Accumulated depletion and impairment	(61,199,800)	(61,145,500)
Oil and gas properties, net	$                              6,975,000	$                              7,376,600

Impairment of Long-Lived Assets [Policy Text Block]

Impairment of Long-Lived Assets

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

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

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

In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. The Partnership may have to pay additional consideration in the future as a well becomes uneconomic under the terms of the Partnership Agreement in order to recover these reserves. There was no impairment charge recognized during the three and six months ended June 30, 2012. During the year ended December 31, 2011, the Partnership recognized an impairment charge of $1,398,000, net of an offsetting gain in accumulated other comprehensive income of $94,300.

Working Interest [Policy Text Block]

Working Interest

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

Revenue Recognition [Policy Text Block]

Revenue Recognition

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

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGL's, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership's records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see "Use of Estimates" accounting policy for further description). The Partnership had unbilled revenues at June 30, 2012 and December 31, 2011 of $206,100 and $325,400, respectively, which were included in accounts receivable trade-affiliate within the Partnership's balance sheets.

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Asset Retirement Obligation (Tables)

6 Months Ended

Jun. 30, 2012

Asset Retirement Obligation [Abstract]

Schedule of Asset Retirement Obligation [Table Text Block]

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2012	2011	2012	2011
Asset retirement obligation at beginning of period	$ 3,734,700	$     3,432,600	$                      3,711,900	$                      3,381,900
Liabilities settled	—	—	(24,500)	—
Accretion expense	47,300	50,700	94,600	101,400
Asset retirement obligation at end of period	$ 3,782,000	$     3,483,300	$                      3,782,000	$                      3,483,300

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Asset Retirement Obligation (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Asset Retirement Obligation [Abstract]
Asset retirement obligation at beginning of period	$ 3,734,700	$ 3,432,600	$ 3,711,900	$ 3,381,900
Liabilities settled			(24,500)
Accretion expense	47,300	50,700	94,600	101,400
Asset retirement obligation at end of period	$ 3,782,000	$ 3,483,300	$ 3,782,000	$ 3,483,300

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Derivative Instruments (Gross Fair Values of Receivable and Payable Affiliate Balances) (Details) (USD $)	Jun. 30, 2012	Dec. 31, 2011
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Of Recognized Assets	$ 213,500	$ 317,100
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset In The Balance Sheets	(35,500)
Affiliate Balances, Offsetting Derivative Assets, Net Amount Of Assets Presented In The Balance Sheets	178,000	317,100
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	(35,500)
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset In The Balance Sheets	35,500
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount Of Liabilities Presented In The Balance Sheets
Accounts Receivable Monetized Gains Affiliate [Member]
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Of Recognized Assets	146,500	191,600
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset In The Balance Sheets	(7,300)
Affiliate Balances, Offsetting Derivative Assets, Net Amount Of Assets Presented In The Balance Sheets	139,200	191,600
Long Term Accounts Receivable Monetized [Member]
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Of Recognized Assets	67,000	125,500
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset In The Balance Sheets	(28,200)
Affiliate Balances, Offsetting Derivative Assets, Net Amount Of Assets Presented In The Balance Sheets	38,800	125,500
Put Premiums Payable Affiliate [Member]
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	(7,300)
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset In The Balance Sheets	7,300
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount Of Liabilities Presented In The Balance Sheets
Long Term Put Premiums Payable Affiliate [Member]
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	(28,200)
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset In The Balance Sheets	28,200
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount Of Liabilities Presented In The Balance Sheets

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Statements of Comprehensive (Loss) Income (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Statements of Comprehensive (Loss) Income
Net loss	$ (293,600)	$ (80,600)	$ (506,700)	$ (240,900)
Other comprehensive (loss) income:
Unrealized holding gain (loss) on hedging contracts	(2,800)		(2,800)	20,200
MGP portion of non- cash loss on hedge instruments				212,400
Difference in estimated monetized gains receivable	23,500	10,300	70,000	27,000
Less: reclassification adjustment for gains realized in net loss	(23,400)	(52,000)	(72,400)	(137,600)
Total other comprehensive (loss) income	(2,700)	(41,700)	(5,200)	122,000
Comprehensive loss	$ (296,300)	$ (122,300)	$ (511,900)	$ (118,900)

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Asset Retirement Obligation

6 Months Ended

Jun. 30, 2012

Asset Retirement Obligation [Abstract]

ASSET RETIREMENT OBLIGATION

NOTE 3 - ASSET RETIREMENT OBLIGATION

The Partnership recognizes an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. 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		Six Months Ended
	June 30,		June 30,
	2012	2011	2012	2011
Asset retirement obligation at beginning of period	$ 3,734,700	$     3,432,600	$                      3,711,900	$                      3,381,900
Liabilities settled	—	—	(24,500)	—
Accretion expense	47,300	50,700	94,600	101,400
Asset retirement obligation at end of period	$ 3,782,000	$     3,483,300	$                      3,782,000	$                      3,483,300

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Fair Value of Financial Instruments (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Fair Value of Financial Instruments [Abstract]
Asset retirement obligations, additional amount measured during the period	$ 0	$ 0	$ 0	$ 0

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Summary of Significant Accounting Policies (Schedule of Oil and Gas Properties) (Details) (USD $)	Jun. 30, 2012	Dec. 31, 2011
Proved Oil and Gas Property, Successful Effort Method	$ 68,174,800	$ 68,522,100
Accumulated depletion and impairment	(61,199,800)	(61,145,500)
Property, Plant and Equipment, Net, Total	6,975,000	7,376,600
Leaseholds interests [Member]
Proved Oil and Gas Property, Successful Effort Method	1,412,700	1,417,900
Wells and related equipment [Member]
Proved Oil and Gas Property, Successful Effort Method	$ 66,762,100	$ 67,104,200