United States
	Securities and Exchange Commission
	Washington, D.C. 20549
	Form 10-Q
(Mark One)
R	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended June 30, 2009
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from _____ to _____
	Commission file number 0-52168
	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.)
Westpointe Corporate Center One
1550 Coraopolis Heights Rd. 2nd Floor
Moon Township, PA		15108
(Address of principal executive offices)		(zip code)
Issuer’s telephone number, including area code: (412) 262-2830
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports),
and (2) has been subject to such filing requirements for the past 90 days. YesR No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive
Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12
months (or for such shorter period that the registrant was required to submit and post such files). Yes o No R
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", 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 R
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No R
Transitional Small Business Disclosure Format (check one): Yes o No R

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, 2009 and December 31, 2008	3
	Statements of Net Earnings for the Three Months and Six Months ended June 30, 2009 and 2008	4
	Statement of Changes in Partners’ Capital for the Six Months ended June 30, 2009	5
	Statements of Cash Flows for the Six Months ended June 30, 2009 and 2008	6
	Notes to Financial Statements	7-16
Item 2:	Management’s Discussion and Analysis of Financial Condition or Plan of Operations	16-21
Item 4:	Controls and Procedures	21-22
PART II.	OTHER INFORMATION
Item 6:	Exhibits	22
SIGNATURES		23
CERTIFICATIONS		24-27

2

ATLAS AMERICA PUBLIC #14-2004 L.P.

BALANCE SHEETS

	June 30,		December 31,
	2009		2008
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	514,800	$	1,242,100
Accounts receivable – affiliate		1,052,100		1,228,700
Short-term hedge receivable due from affiliate		828,300		1,288,800
Total current assets		2,395,200		3,759,600
Oil and gas properties, net		22,676,000		23,553,800
Long-term hedge receivable due from affiliate		498,000		842,000
	$	25,569,200	$	28,155,400
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	9,900	$	22,200
Short-term hedge liability due to affiliate		2,700		110,400
Total current liabilities		12,600		132,600
Asset retirement obligation		2,351,000		2,282,500
Long-term hedge liability due to affiliate		125,100		99,400
Partners’ capital:
Managing general partner		6,796,000		7,512,000
Limited partners (5,256.95 units)		15,365,000		16,609,700
Accumulated other comprehensive income		919,500		1,519,200
Total partners' capital		23,080,500		25,640,900
	$	25,569,200	$	28,155,400

The accompanying notes are an integral part of these financial statements.

3

ATLAS AMERICA PUBLIC #14-2004 L.P.

STATEMENTS OF NET EARNINGS

(Unaudited)

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2009			2008		2009		2008
REVENUES
Natural gas and oil	$	897,100		$	1,888,300	$	2,244,500	$	3,997,200
Interest income		300			1,800		900		6,200
Total revenues		897,400			1,890,100		2,245,400		4,003,400
COSTS AND EXPENSES
Production		447,700			606,300		898,900		1,202,400
Depletion		427,700			649,800		875,800		1,337,400
Accretion of asset retirement obligation		34,300			34,900		68,500		69,700
General and administrative		71,100			79,000		134,100		140,100
Total expenses		980,800			1,370,000		1,977,300		2,749,600
Net (loss) earnings	$	(83,400	)	$	520,100	$	268,100	$	1,253,800
Allocation of net earnings (loss):
Managing general partner	$	37,300		$	297,800	$	229,900	$	677,900
Limited partners	$	(120,700	)	$	222,300	$	38,200	$	575,900
Net (loss) earnings per limited partnership unit	$	(23	)	$	43	$	7	$	110

The accompanying notes are an integral part of these financial statements.

4

ATLAS AMERICA PUBLIC #14-2004 L.P.

STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

FOR THE SIX MONTHS ENDED

June 30, 2009

(Unaudited)

							Accumulated
	Managing						Other
	General			Limited			Comprehensive
	Partner			Partners			Income (Loss)			Total
Balance at January 1, 2009	$	7,512,000		$	16,609,700		$	1,519,200		$	25,640,900
Participation in revenues and expenses:
Net production revenues		471,000			874,600			—			1,345,600
Interest income		300			600			—			900
Depletion		(170,500	)		(705,300	)		—			(875,800	)
Accretion of asset retirement obligation		(24,000	)		(44,500	)		—			(68,500	)
General and administrative		(46,900	)		(87,200	)		—			(134,100	)
Net earnings		229,900			38,200			—			268,100
Other comprehensive loss		—			—			(599,700	)		(599,700	)
Subordination		(338,200	)		338,200			—			—
Distributions to partners		(607,700	)		(1,621,100	)		—			(2,228,800	)
Balance at June 30, 2009	$	6,796,000		$	15,365,000		$	919,500		$	23,080,500

The accompanying notes are an integral part of these financial statements.

5

ATLAS AMERICA PUBLIC #14-2004 L.P.

STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended
	June 30,
	2009			2008
Cash flows from operating activities:
Net earnings	$	268,100		$	1,253,800
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depletion		875,800			1,337,400
Non-cash loss on derivative value		122,800			246,500
Accretion of asset retirement obligation		68,500			69,700
Decrease (increase) in accounts receivable – affiliate		176,600			(69,500	)
Decrease in accrued liabilities		(12,300	)		(4,400	)
Net cash provided by operating activities		1,499,500			2,833,500
Cash flows from investing activities:
Proceeds from sale of tangible equipment		2,000			—
Net cash provided by investing activities		2,000			—
Cash flows from financing activities:
Distribution to partners		(2,228,800	)		(3,026,500	)
Net cash used in financing activities		(2,228,800	)		(3,026,500	)
Net decrease in cash and cash equivalents		(727,300	)		(193,000	)
Cash and cash equivalents at beginning of period		1,242,100			1,590,200
Cash and cash equivalents at end of period	$	514,800		$	1,397,200

The accompanying notes are an integral part of these financial statements.

6

ATLAS AMERICA PUBLIC #14-2004 L.P.

NOTES TO FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

NOTE 1 - DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

Atlas America Public #14-2004 L.P. (the “Partnership”) is a Delaware Limited Partnership which includes Atlas Resources, LLC of Pittsburgh, Pennsylvania, as Managing General Partner ("MGP") and Operator, and 1,518 Limited Partners. The Partnership was formed on May 3, 2004 to drill and operate gas wells located primarily in western Pennsylvania and Tennessee. The Partnership has no employees and relies on its MGP for management which, in turn, relies on its parent company, Atlas Energy Resources, LLC (NYSE:ATN), ("Atlas Energy"), for administrative services.

The financial statements as of June 30, 2009 and for the three months and six months ended June 30, 2009 and 2008 are unaudited except that the balance sheet at December 31, 2008 is derived from audited financial statements. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (”U.S. GAAP”) have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission. However, in the opinion of management, these interim financial statements include all the necessary adjustments to fairly present the results of the interim periods presented. Management has evaluated subsequent events through August 13, 2009, the date the financial statements were issued. The unaudited interim financial statements should be read in conjunction with the audited financial statements included in the Partnership’s Form 10-K for the year ended December 31, 2008. The results of operations for the three months and six months ended June 30, 2009 may not necessarily be indicative of the results of operations for the year ended December 31, 2009.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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, 2008 filed with the Securities and Exchange Commission.

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 as of the date of the financial statements and the reported amounts of revenues, costs and expenses during the reporting period. The Partnership’s financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, fair value of derivative instruments and the probability of forecasted transactions. Actual results could differ from these estimates.

Accounts Receivable and Allowance for Possible Losses

In evaluating the need for an allowance for possible losses, the Partnership's MGP performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s 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, 2009 and December 31, 2008, the Partnership's MGP’s credit evaluation indicated that the Partnership has no need for an allowance for possible losses.

7

ATLAS AMERICA PUBLIC #14-2004 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2009

(Unaudited)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue Recognition

Because there are timing differences between the delivery of the Partnership’s natural gas and oil and the receipt of a delivery statement, the Partnership has unbilled revenues. These revenues are accrued based upon volumetric data from the Partnership’s records and estimates of the related transportation and compression fees which are, in turn, based upon applicable product prices. The Partnership had unbilled trade receivables of $666,200 at June 30, 2009 and $932,400 at December 31, 2008, which are included in Accounts receivable-affiliate on the Partnership's Balance Sheets.

Oil and Gas Properties

The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Oil and gas properties are recorded at cost. Depletion is based on cost less estimated salvage value primarily using the unit-of-production method over the assets’ estimated useful lives. In addition, accumulated depletion includes impairment adjustments to reflect the write-down to fair market value of the oil and gas properties. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized.

Oil and gas properties consist of the following at the dates indicated:
	June 30,			December 31,
	2009			2008
Natural gas and oil properties:
Proved properties:
Leasehold interest	$	1,417,900		$	1,417,900
Wells and related equipment		66,170,400			66,172,400
		67,588,300			67,590,300
Accumulated depletion		(44,912,300	)		(44,036,500	)
	$	22,676,000		$	23,553,800

Recently Adopted and Issued Financial Accounting Standards

In June 2009, the FASB issued Statement No. 165, Subsequent Events (“SFAS No. 165”). SFAS No. 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS No. 165 requires management of a reporting entity to evaluate events or transactions that may occur after the balance sheet date for potential recognition or disclosure in the financial statements and provides guidance for disclosures that an entity should make about those events. SFAS No. 165 is effective for interim or annual financial periods ending after June 15, 2009 and shall be applied prospectively. The Partnership adopted the requirements of SFAS No. 165 on April 1, 2009 and its adoption did not have a material impact on its financial position or results of operations.

8

ATLAS AMERICA PUBLIC #14-2004 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2009

(Unaudited)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Recently Adopted and Issued Financial Accounting Standards (Continued)

In June 2009, the FASB issued Statement No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – A Replacement of FASB Statement No. 162 (“SFAS No. 168”). SFAS No. 168 establishes the FASB Accounting Standards Codification (“Codification”) as the single source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. The Codification supersedes all existing non-Securities and Exchange Commission accounting and reporting standards. Following SFAS No. 168, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead, the FASB will issue Accounting Standards Updates, which will serve only to update the Codification. SFAS No. 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Partnership will apply the requirements of SFAS No. 168 to its financial statements and will update its disclosure references to the new FASB codification for the interim period ended September 30, 2009 and does not expect it to have a material impact on its financial position or results of operations.

In April 2009, the Financial Accounting Standards Board, (“FASB”) issued Staff Position 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (“FSP FAS 157-4”). FSP FAS 157-4 applies to all fair value measurements and provides additional clarification on estimating fair value when the market activity for an asset has declined significantly. FSP FAS 157-4 also requires an entity to disclose a change in valuation technique and related inputs to the valuation calculation and to quantify its effects, if practicable. FSP FAS 157-4 is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Partnership adopted the requirements of FSP FAS 157-4 on April 1, 2009 and its adoption did not have a material impact on its financial position or results of operations.

In April 2009, the FASB issued Staff Position 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments (“FSP FAS 107-1 and APB 28-1”). FSP FAS 107-1 and APB 28-1 require an entity to provide disclosures about fair value of financial instruments in interim financial information. In addition, an entity shall disclose in the body or in the accompanying notes of its summarized financial information for interim reporting periods and in its financial statements for annual reporting periods the fair value of all financial instruments for which it is practicable to estimate that value, whether recognized or not recognized in the statement of financial position. FSP FAS 107-1 APB 28-1 is effective for interim periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Partnership adopted the requirements of FSP FAS 107-1 APB 28-1 on April 1, 2009 and its adoption did not have a material impact on its financial position or results of operations.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, - an amendment of FASB Statement No. 133 (“SFAS No. 161”). SFAS No. 161 amends the requirement of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”), to require enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedge items are accounted for under SFAS No. 133 and its related interpretations and how derivative instruments and related hedge items affect an entity’s financial position, financial performance and cash flows. The Partnership adopted the requirements of SFAS No. 161 on January 1, 2009 and it did not have a material impact on its financial position or results of operations (See Note 5).

9

ATLAS AMERICA PUBLIC #14-2004 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2009

(Unaudited)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Modernization of Oil and Gas Reporting

In December 2008, the Securities and Exchange Commission (“SEC”) announced that it had approved revisions to its oil and gas reporting disclosures by adopting amendments to Rule 4-10 of Regulation S-X and Items 201, 801, and 802 of Regulation S-K. These new disclosure requirements are referred to as “Modernization of Oil and Gas Reporting” and include provisions that:

·   Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.

·   Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end pricing. This should maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date.

·   Permit companies to disclose their probable and possible reserves on a voluntary basis. Current rules limit disclosure to only proved reserves.

·   Update and revise reserve definitions to reflect changes in the oil and gas industry and new technologies. New updated definitions include “by geographic area” and “reasonable certainty.”

·   Permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.

·   Require additional disclosures regarding the qualifications of the chief technical person who oversees the Partnership’s overall reserve estimation process. Additionally, disclosures are required related to internal controls over reserve estimation, as well as a report addressing the independence and qualifications of a Partnership’s  reserves preparer or auditor based on Society of Petroleum Engineers criteria.

The Partnership will begin complying with the disclosure requirements in its annual report on Form 10-K for the year ending December 31, 2009. The new rules may not be applied to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required. The Partnership is currently in the process of evaluating the new requirements.

NOTE 3 - TRANSACTIONS WITH ATLAS RESOURCES, LLC AND ITS AFFILIATES

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

·   Administrative costs which are included in general and administrative expenses in the Partnership’s Statements of Net Earnings are payable at $75 per well per month. Administrative costs incurred for the three months and six months ended June 30, 2009 were $49,100 and $98,700, respectively. Administrative costs incurred for the three months and six months ended June 30, 2008 were $49,600 and $98,800, respectively.

10

ATLAS AMERICA PUBLIC #14-2004 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2009

(Unaudited)

NOTE 3 - TRANSACTIONS WITH ATLAS RESOURCES, LLC AND ITS AFFILIATES (Continued)

·   Monthly well supervision fees which are included in production expenses in the Partnership’s Statements of Net Earnings are payable at $318 per well per month in 2009 and 2008, for operating and maintaining the wells. Well supervision fees incurred for the three months and six months June 30, 2009 were $208,100 and $418,400, respectively. Well supervision fees incurred for the three months and six months ended June 30, 2008 were $210,400 and $418,800, respectively.

·   Transportation fees which are included in production expenses in the Partnership’s Statements of Net Earnings are generally payable at 13% of the natural gas sales price. Transportation fees incurred for the three months and six months ended June 30, 2009 were $101,400 and $232,100, respectively. Transportation fees incurred for the three months and six months ended June 30, 2008 were $245,000 and $511,000, respectively.

The MGP and its affiliates perform all administrative and management functions for the Partnership including billing revenues and paying expenses. “Accounts receivable-affiliate” on the Partnership's Balance Sheets represents the net production revenues due from the MGP.

Subordination by Managing General Partner

Under the terms of the Partnership agreement, the MGP may be required to subordinate up to 50% of its share of net production revenues of the Partnership to provide a distribution to the limited partners equal to at least 10% of their agreed subscriptions. Subordination is determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution of net revenues to the investor partners (July 2005) and expiring 60 months from that date. For the six months ended June 30, 2009, the MGP was required to subordinate $338,200 of its net revenues of $676,400. Therefore MGP distributions were decreased and the limited partners were increased by $338,200 as shown on the Statement of Changes in Partners’ Capital for the six months ended June 30, 2009.

NOTE 4 - COMPREHENSIVE LOSS

Comprehensive loss includes net income (loss) and all other changes in equity of a business during a period from transactions and other events and circumstances from non-owner sources. These changes, other than net income, are referred to as "other comprehensive income (loss)" and, for the Partnership, include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges. A reconciliation of the Partnership’s comprehensive loss for the periods indicated is as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Net (loss) earnings	$	(83,400	)	$	520,100		$	268,100		$	1,253,800
Other comprehensive loss:
Unrealized holding loss on hedging contracts		(9,900	)		(3,734,500	)		(51,100	)		(5,622,600	)
Less: reclassification adjustment for (gains) losses realized in net earnings		(221,400	)		280,500			(548,600	)		72,100
Total other comprehensive loss		(231,300	)		(3,454,000	)		(599,700	)		(5,550,500	)
Comprehensive loss	$	(314,700	)	$	(2,933,900	)	$	(331,600	)	$	(4,296,700	)

11

ATLAS AMERICA PUBLIC #14-2004 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2009

(Unaudited)

NOTE 5 - DERIVATIVE INSTRUMENTS

The Partnership applies the provisions of SFAS 133, which requires each derivative instrument to be recorded in the balance sheet as either an asset or liability measured at fair value. Changes in a derivative instrument’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met.

The Partnership is exposed to certain risks relating to its ongoing business operations. The risk is managed by using derivative instruments related to commodity price risk. Forward contracts on natural gas and oil are entered into to manage the price risk associated with forecasted sales of natural gas and crude oil. In accordance with SFAS No. 133, the Partnership designates these derivatives as cash flow hedges and the derivative instruments have been recorded as either assets or liabilities at fair value in the balance sheet. The effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified to earnings in the same period during which the hedged transaction affects earnings. The following table summarizes the fair value of derivative instruments as of June 30, 2009 and December 31, 2008, as well as the gain or loss recognized for the three months and six months ended June 30, 2009 and 2008, respectively. There were no gains or losses recognized in income for ineffective derivative instruments for the three months and six months ended June 30, 2009 and 2008, respectively.

Fair Value of Derivative Instruments:
	Asset Derivatives					Liability Derivatives
Derivatives in		Fair Value					Fair Value
SFAS 133 Cash Flow	Balance Sheet	June 30,		December 31,		Balance Sheet	June 30,			December 31,
Hedging Relationships	Location	2009		2008		Location	2009			2008
Commodity contracts:	Current assets	$	828,300	$	1,288,800	Current liabilities	$	(2,700	)	$	(110,400	)
	Long-term assets		498,000		842,000	Long-term liabilities		(125,100	)		(99,400	)
Total derivatives under SFAS No. 133		$	1,326,300	$	2,130,800		$	(127,800	)	$	(209,800	)

Effects of Derivative Instruments on Statements of Net Earnings:

Derivatives in	Gain/(Loss) Recognized in OCI on Derivative (Effective Portion) Three Months Ended						Location of Gain/(Loss) Reclassified from Accumulated	Gain/(Loss) Reclassified from OCI into Income (Effective Portion) Three Months Ended
SFAS 133 Cash Flow	June 30,			June 30,			OCI into Income	June 30,		June 30,
Hedging Relationship	2009			2008			(Effective Portion)	2009		2008
Commodity contracts	$	(9,900	)	$	(3,734,500	)	Natural gas and oil revenue	$	221,400	$	(280,500	)

Derivatives in	Gain/(Loss) Recognized in OCI on Derivative (Effective Portion) Six Months Ended						Location of Gain/(Loss) Reclassified from Accumulated	Gain/(Loss) Reclassified from OCI into Income (Effective Portion) Six Months Ended
SFAS 133 Cash Flow	June 30,			June 30,			OCI into Income	June 30,		June 30,
Hedging Relationship	2009			2008			(Effective Portion)	2009		2008
Commodity contracts	$	(51,100	)	$	(5,622,600	)	Natural gas and oil revenue	$	548,600	$	(72,100	)

Atlas Energy, on behalf of the Partnership, from time to time enters into natural gas and crude oil future option and collar contracts to hedge exposure to changes in natural gas prices and oil prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures, 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 have qualified and been designated as cash flow hedges and recorded at their fair values.

12

ATLAS AMERICA PUBLIC #14-2004 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2009

(Unaudited)

NOTE 5 - DERIVATIVE INSTRUMENTS (Continued)

At June 30, 2009, the Partnership reflected a net hedge asset on its Balance Sheets of $1,198,500, however unrealized gains of $279,000 resulting from impairment charges of the Partnership’s oil and gas properties in prior periods results in a net unrealized accumulated gain of $919,500. Of the remaining $919,500 net unrealized gain in accumulated other comprehensive income at June 30, 2009, if the fair values of the instruments remain at current market values, the Partnership will reclassify $582,400 of net gain to its Statements of Net Earnings over the next twelve month period as these contracts settle, and $337,100 of net gains in later periods. Actual amounts that will be reclassified will vary as a result of future price changes. Ineffective hedge gains or losses are recorded within the Statements of Net Earnings while the hedge contract is open and may increase or decrease until settlement of the contract. The Partnership recognized no gains or losses during the three months and six months ended June 30, 2009 and 2008 for hedge ineffectiveness or as a result of the discontinuance of cash flow hedges.

As of June 30, 2009, Atlas Energy had allocated to the Partnership the following natural gas and oil volumes hedged:

Natural Gas Fixed Price Swaps

Production			Average
Period Ending	Volumes		Fixed Price		Fair Value
December 31,	(MMbtu) (1)		(per MMbtu)		Asset (2)
2009		155,600	$	8.04	$	572,000
2010		214,900		7.71		354,300
2011		131,100		7.04		105,000
2012		115,600		7.22		63,500
2013		55,200		7.13		400
					$	1,095,200

Natural Gas Costless Collars

Production				Average		Fair Value
Period Ending	Option	Volumes		Floor & Cap		Asset
December 31,	Type	(MMbtu) (1)		(per MMbtu)		(Liability) (2)
2009	Puts purchased		800	$	11.00	$	5,700
2009	Calls sold		800		15.35		—
2010	Puts purchased		22,400		7.84		44,600
2010	Calls sold		22,400		9.01		—
2011	Puts purchased		59,200		6.52		35,500
2011	Calls sold		59,200		7.67		—
2012	Puts purchased		22,600		6.51		—
2012	Calls sold		22,600		7.72		(3,700	)
2013	Puts purchased		28,100		6.52		—
2013	Calls sold		28,100		7.81		(8,800	)
						$	73,300

13

ATLAS AMERICA PUBLIC #14-2004 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2009

(Unaudited)

NOTE 5 - DERIVATIVE INSTRUMENTS (Continued)

Crude Oil Fixed Price Swaps

Production			Average
Period Ending	Volumes		Fixed Price		Fair Value
December 31,	(Bbl)		(per Bbl)		Asset (3)
2009		200	$	99.50	$	6,100
2010		300		97.40		6,900
2011		200		77.46		4,600
2012		200		76.86		2,900
2013		100		77.36		800
					$	21,300

Crude Oil Costless Collars

Production				Average
Period Ending	Option	Volumes		Floor & Cap		Fair Value
December 31,	Type	(Bbl)		(per Bbl)		Asset (3)
2009	Puts purchased		100	$	85.00	$	2,000
2009	Calls sold		100		116.88		—
2010	Puts purchased		200		85.00		2,900
2010	Calls sold		200		112.92		—
2011	Puts purchased		200		67.22		2,100
2011	Calls sold		200		89.44		—
2012	Puts purchased		100		65.51		1,400
2012	Calls sold		100		91.45		—
2013	Puts purchased		100		65.36		300
2013	Calls sold		100		93.44		—
						$	8,700
				Total Net Asset		$	1,198,500

____________

(1)   MMBTU represents million British Thermal Units.

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

(3)   Fair value based on forward WTI crude oil prices.

NOTE 6 - FAIR VALUE OF FINANCIAL INSTRUMENTS

SFAS 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The Partnership prioritizes the inputs of the valuation techniques used to measure fair value into three levels.

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

14

ATLAS AMERICA PUBLIC #14-2004 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2009

(Unaudited)

NOTE 6 - FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)

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 that market participants would use in the pricing of the asset or liability and are consequently not based on market activity, but rather through particular valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

All of the Partnership’s derivatives contracts are defined as Level 2. The Partnership's natural gas and crude oil derivative contracts are valued based on prices quoted on the NYMEX or WTI and adjusted by the respective counterparty using various assumptions including quoted forward prices, time value, volatility factors, and contractual prices for the underlying instruments. In accordance with SFAS 157, the following table represents the Partnership's fair value hierarchy for its financial instruments at June 30, 2009.

	Fair Value Measurements at June 30, 2009 Using
	Quoted prices		Significant other		Significant
	in active		observable		unobservable
	markets		inputs		inputs
	(Level 1)		(Level 2)		(Level 3)
Commodity-based derivatives	$	—	$	1,198,500	$	—
Total	$	—	$	1,198,500	$	—

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The Partnership has certain assets and liabilities that are reported at fair value on a nonrecurring basis in its Balance Sheets. The following methods and assumptions were used to estimate fair values.

Oil and Gas Property Impairments. In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Partnership reviews its proved oil and gas properties for impairment annually or when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. The Partnership estimates the expected future cash flows from its oil and gas properties and compares such future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Partnership will adjust the carrying amount of the oil and gas properties to their fair value in the current period. The factors used to determine fair value include, but are not limited to, estimates of reserves, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected. There was no impairment charge for the three months and six months ended June 30, 2009 and 2008, respectively.

Asset Retirement Obligations. 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 for a legal obligation for an asset retirement obligation such as: amounts and timing of settlements; interest rates; and estimated inflation rates. There were no new asset retirement obligations incurred for the three months and sixmonths ended June 30, 2009 and 2008, respectively.

15

ATLAS AMERICA PUBLIC #14-2004 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2009

(Unaudited)

NOTE 7 - ASSET RETIREMENT OBLIGATION

The Partnership accounts for the estimated plugging and abandonment costs for its oil and gas properties in accordance with Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations ("SFAS 143") and FASB, Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations.

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
Asset retirement obligation at beginning of period	$	2,316,700	$	2,356,200	$	2,282,500	$	2,321,400
Accretion expense		34,300		34,900		68,500		69,700
Asset retirement obligation at end of period	$	2,351,000	$	2,391,100	$	2,351,000	$	2,391,100

NOTE 8 – COMMITMENTS AND CONTINGENCIES

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.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION OR PLAN OF OPERATIONS (UNAUDITED)

Forward-Looking Statements

The matters discussed within this report include forward-looking statements. These statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “should,” or “will,” or the negative thereof or other variations thereon or comparable terminology. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this report are forward-looking statements. We have based these forward-looking statements on our current expectations, assumptions, estimates and projections. While we believe these expectations, assumptions, estimates and projections are reasonable, such forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control. These and other important factors may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements.

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

16

General

We were formed as a Delaware limited partnership on May 3, 2004, with Atlas Resources, Inc. as our Managing General Partner, or MGP, to drill natural gas development wells. Atlas Resources, Inc. was merged into a newly-formed limited liability company, Atlas Resources LLC, which now serves as our MGP. We have no employees and rely on our MGP for management, which, in turn, relies on its parent company, Atlas Energy Resources, LLC (NYSE:ATN), or Atlas Energy, for administrative services. Atlas Energy is a subsidiary of Atlas America, Inc. (NASDAQ:ATLS).

Our wells are currently producing natural gas and, to a far lesser extent, oil which are our only products. Most of our gas is gathered and delivered to market through Laurel Mountain Midstream, LLC’s gas gathering system, a newly-formed joint-venture between Atlas Energy’s affiliate, Atlas Pipeline Partners, L.P. (NYSE:APL) and The Williams Companies (NYSE:WMB). 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.

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						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Production revenues (in thousands):
Gas	$	826		$	1,786		$	2,117		$	3,761
Oil		71			102			128			236
Total	$	897		$	1,888		$	2,245		$	3,997
Production volumes:
Gas (mcf/day) (1)		1,362			2,370			1,425			2,399
Oil (bbls/day) (1)		15			10			13			14
Total (mcfe/day) (1)		1,452			2,430			1,503			2,483
Average sales prices: (2)
Gas (per mcf) (1) (3)	$	8.19		$	9.45		$	8.68		$	9.18
Oil (per bbl) (1) (4)	$	51.57		$	107.19		$	54.60		$	95.07
Average production costs:
As a percent of revenues		50	%		32	%		40	%		30	%
Per mcfe (1)	$	3.39		$	2.74		$	3.30		$	2.66
Depletion per mcfe	$	3.24		$	2.94		$	3.22		$	2.96

___________

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

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

(3)   Average gas prices are calculated by including in total revenue gains previously recognized into income and dividing by the total volume for the period. Gas revenue was adjusted for previously recognized gains of $189,200 and $122,800 for the three and six months June 30, 2009. Gas revenue was adjusted for previously recognized gains of $251,400 and $246,500 for the three and six months ended June 30, 2008.

(4)   Average oil prices are calculated by including in total revenue gains previously recognized into income and dividing by the total volume for the period.

17

Natural Gas Revenues. Our natural gas revenues were $826,300 and $1,785,900 for the three months ended June 30, 2009 and 2008, respectively, a decrease of $959,600 (54%). The $959,600 decrease in natural gas revenues for the three months ended June 30, 2009 as compared to the prior year similar period was attributable to a $759,700 decrease in production volumes and a $199,900 decrease in natural gas sales prices after the effect of financial hedges. Our production volumes decreased to 1,362 mcf per day for the three months ended June 30, 2009 from 2,370 mcf per day for the three months ended June 30, 2008, a decrease of 1,008 mcf per day (43%). The overall decrease in natural gas production volumes for the three months ended June 30, 2009 resulted primarily from the normal decline inherent in the life of a well.

Our natural gas revenues were $2,117,000 and $3,760,600 for the six months ended June 30, 2009 and 2008, respectively, a decrease of $1,643,600 (44%). The $1,643,600 decrease in natural gas revenues for the six months ended June 30, 2009 as compared to the prior year similar period was attributable to a $1,538,600 decrease in production volumes and a $105,000 decrease in natural gas sales prices after the effect of financial hedges. Our production volumes decreased to a decrease in production volumes to 1,425 mcf per day for the six months ended June 30, 2009 from 2,399 mcf per day for the six months ended June 30, 2008, a decrease of 974 mcf per day (41%). The overall decrease in natural gas production volumes for the six months ended June 30, 2009 resulted primarily from the normal decline inherent in the life of a well.

Oil Revenues. We drill wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $70,800 and $102,400 for the three months ended June 30, 2009 and 2008, respectively, a decrease of $31,600 (31%). The $31,600 decrease in oil revenues for the three months ended June 30, 2009 as compared to the prior year similar period was attributable to a $76,500 decrease in oil prices, partially offset by a $44,900 increase in production volumes.

Our oil revenues were $127,500 and $236,600 for the six months ended June 30, 2009 and 2008, respectively, a decrease of $109,100 (46%). The $109,100 decrease in oil revenues for the six months ended June 30, 2009 as compared to the prior year similar period was attributable to a $94,500 decrease in oil prices and a $14,600 decrease in production volumes. Our production volumes decreased to 13 bbls per day for the six months ended June 30, 2009 from 14 bbls per day for the six months ended June 30, 2008, a decrease of 1 bbl per day (7%).

Expenses.  Production expenses were $447,700 and $606,300 for the three months ended June 30, 2009 and 2008, respectively, a decrease of $158,600 (26%). Production expenses were $898,900 and $1,202,400 for the six months ended June 30, 2009 and 2008, respectively, a decrease of $303,500 (25%). These decreases were primarily attributable to lower transportation fees and other variable expenses as compared to the prior year similar period.

Depletion of oil and gas properties as a percentage of oil and gas revenues were 48% and 34% for the three months ended June 30, 2009 and 2008, respectively; and 39% and 33% for the six months ended June 30, 2009 and 2008, respectively. These percentage changes were directly attributable to changes in revenues, oil and gas reserve quantities, product prices, production volumes and changes in the depletable cost basis of oil and gas properties.

General and administrative expenses for the three months ended June 30, 2009 and 2008 were $71,100 and $79,000, respectively, a decrease of $7,900 (10%). For the six months ended June 30, 2009 and 2008 these expenses were $134,100 and $140,100, respectively, a decrease of $6,000 (4%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP. These decreases were primarily due to lower third-party costs as compared to the prior year similar period.

Liquidity and Capital Resources

Cash provided by operating activities decreased $1,334,000 in the six months ended June 30, 2009 to $1,499,500 as compared to $2,833,500 for the six months ended June 30, 2008. This decrease was primarily due to a decrease in the net earnings before depletion, net non-cash loss on derivative value and accretion of $1,572,200. In addition, the change in accounts receivable-affiliate increased operating cash flows by $246,100 in the six months ended June 30, 2009 as compared to the six months ended June 30, 2008.

18

Cash provided by investing activities was $2,000 for the six months ended June 30, 2009, which were proceeds from sale of tangible equipment.

Cash used in financing activities decreased $797,700 during the six months ended June 30, 2009 to $2,228,800 from $3,026,500 for the six months ended June 30, 2008. This decrease was due to a decrease in cash distributions.

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

We believe that our future cash flows from operations and amounts available from borrowings from our MGP or its affiliates, if any, will be adequate to fund our operations.

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 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, 2008.

Subordination by Managing General Partner

Under the terms of the Partnership agreement, the MGP may be required to subordinate up to 50% of its share of net production revenues of the Partnership to provide a distribution to the limited partners equal to at least 10% of their agreed subscriptions. Subordination is determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution of net revenues to the investor partners (July 2005) and expiring 60 months from that date. For the six months ended June 30, 2009, the MGP was required to subordinate $338,200 of its net revenues of $676,400. Therefore MGP distributions were decreased and the limited partners were increased by $338,200 as shown on the Statement of Changes in Partners’ Capital for the six months ended June 30, 2009.

Recently Adopted and Issued Financial Accounting Standards

In June 2009, the FASB issued Statement No. 165, Subsequent Events or SFAS No. 165. SFAS No. 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS No. 165 requires management of a reporting entity to evaluate events or transactions that may occur after the balance sheet date for potential recognition or disclosure in the financial statements and provides guidance for disclosures that an entity should make about those events. SFAS No. 165 is effective for interim or annual financial periods ending after June 15, 2009 and shall be applied prospectively. We adopted the requirements of SFAS No. 165 on April 1, 2009 and its adoption did not have a material impact on our financial position or results of operations.

19

In June 2009, the FASB issued Statement No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – A Replacement of FASB Statement No. 162 or SFAS No. 168. SFAS No. 168 establishes the FASB Accounting Standards Codification or Codification as the single source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. The Codification supersedes all existing non-Securities and Exchange Commission accounting and reporting standards. Following SFAS No. 168, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead, the FASB will issue Accounting Standards Updates, which will serve only to update the Codification. SFAS No. 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. We will apply the requirements of SFAS No. 168 to our financial statements and will update its disclosure references to the new FASB codification for the interim period ended September 30, 2009 and does not expect it to have a material impact on our financial position or results of operations.

In April 2009, the Financial Accounting Standards Board, or FASB issued Staff Position 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly or FSP FAS 157-4. FSP FAS 157-4 applies to all fair value measurements and provides additional clarification on estimating fair value when the market activity for an asset has declined significantly. FSP FAS 157-4 also requires an entity to disclose a change in valuation technique and related inputs to the valuation calculation and to quantify its effects, if practicable. FSP FAS 157-4 is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. We adopted the requirements of FSP FAS 157-4 on April 1, 2009 and its adoption did not have a material impact on our financial position or results of operations.

In April 2009, the FASB issued Staff Position 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments or FSP FAS 107-1 and APB 28-1. FSP FAS 107-1 and APB 28-1 require an entity to provide disclosures about fair value of financial instruments in interim financial information. In addition, an entity shall disclose in the body or in the accompanying notes of its summarized financial information for interim reporting periods and in its financial statements for annual reporting periods the fair value of all financial instruments for which it is practicable to estimate that value, whether recognized or not recognized in the statement of financial position. FSP FAS 107-1 APB 28-1 is effective for interim periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. We adopted the requirements of FSP FAS 107-1 APB 28-1 on April 1, 2009 and its adoption did not have a material impact on our financial position or results of operations.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, - an amendment of FASB Statement No. 133 or SFAS No. 161. SFAS No. 161 amends the requirement of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, or SFAS No. 133, to require enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedge items are accounted for under SFAS No. 133 and its related interpretations and how derivative instruments and related hedge items affect an entity’s financial position, financial performance and cash flows. We adopted the requirements of SFAS No. 161 on January 1, 2009 and its adoption did not have a material impact on our financial position or results of operations (See Note 5).

20

Modernization of Oil and Gas Reporting

In December 2008, the Securities and Exchange Commission or SEC announced that it had approved revisions to its oil and gas reporting disclosures by adopting amendments to Rule 4-10 of Regulation S-X and Items 201, 801, and 802 of Regulation S-K. These new disclosure requirements are referred to as “Modernization of Oil and Gas Reporting” and include provisions that:

·   Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.

·   Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end pricing. This should maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date.

·   Permit companies to disclose their probable and possible reserves on a voluntary basis. Current rules limit disclosure to only proved reserves.

·   Update and revise reserve definitions to reflect changes in the oil and gas industry and new technologies. New updated definitions include “by geographic area” and “reasonable certainty.”

·   Permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.

·   Require additional disclosures regarding the qualifications of the chief technical person who oversees the Partnership’s overall reserve estimation process. Additionally, disclosures are required related to internal controls over reserve estimation, as well as a report addressing the independence and qualifications of a Partnership’s reserves preparer or auditor based on Society of Petroleum Engineers criteria.

We will begin complying with the disclosure requirements in its annual report on Form 10-K for the year ending December 31, 2009. The new rules may not be applied to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required. We are currently in the process of evaluating the new requirements.

ITEM 4.  CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Partnership maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in Securities and 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 the MGP’s management, including the chief executive officer and the chief financial officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, the MGP’s 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 the MGP’s management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

21

Under the supervision of the chief executive officer and chief financial officer, the MGP has carried out an evaluation of the effectiveness of the Partnership’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the chief executive officer and chief financial officer concluded that the Partnership’s disclosure controls and procedures are effective at the reasonable assurance level at June 30, 2009.

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 6.  EXHIBITS

EXHIBIT INDEX

Exhibit No.	Description
4.0	Amended and Restated Certificate and Agreement of Limited Partnership for Public #14-2004 L.P. (1)
10.1	Drilling and Operating Agreement 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	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley
	Act of 2002
32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley
	Act of 2002

____________

(1) Filed on June 30, 2004 in the Form S-1 Registration Statement dated June 30, 2004, File No. 333-117035

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 13, 2009	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 13, 2009	By:/s/ Freddie M. Kotek
	Freddie M. Kotek, Chairman of the Board of Directors, Chief Executive
	Officer and President
Date:  August 13, 2009	By:/s/ Matthew A. Jones
	Matthew A. Jones, Chief Financial Officer
Date:  August 13, 2009	By:/s/ Sean P. McGrath
	Sean P. McGrath, Chief Accounting Officer

23