Atlas America Series 25-2004 10Q 2009 Q3 Quarterly report

	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 September 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 0-51271


	ATLAS AMERICA SERIES 25-2004 (B) L.P.
	(Name of small business issuer in its charter)



Delaware		34-1980376
(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. Yes R 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”, “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 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 SERIES 25-2004 (B) 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 September 30, 2009 and December 31, 2008	3

	Statements of Operations for the Three Months and Nine Months ended September 30, 2009 and 2008	4

	Statement of Changes in Partners’ Capital for the Nine Months ended September 30, 2009	5

	Statements of Cash Flows for the Nine Months ended September 30, 2009 and 2008	6

	Notes to Financial Statements	7-18

Item 2:	Management’s Discussion and Analysis of Financial Condition or Plan of Operations	18-23

Item 4:	Controls and Procedures	23-24

PART II.	OTHER INFORMATION

Item 6:	Exhibits	24


SIGNATURES		25

CERTIFICATIONS		26-29

ATLAS AMERICA SERIES 25-2004 (B) L.P.

BALANCE SHEETS

	September 30,		December 31,
	2009		2008
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	135,500	$	265,100
Accounts receivable-affiliate		549,700		905,700
Short-term hedge receivable due from affiliate		339,200		821,800
Total current assets		1,024,400		1,992,600

Oil and gas properties, net		12,093,400		12,761,600
Long-term hedge receivable due from affiliate		238,800		521,400
	$	13,356,600	$	15,275,600

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	28,100	$	22,200
Short-term hedge liability due to affiliate		5,000		72,200
Total current liabilities		33,100		94,400

Asset retirement obligation		1,584,400		1,516,200
Long-term hedge liability due to affiliate		59,800		65,000

Partners’ capital:
Managing general partner		3,639,500		4,072,800
Limited partners (1,265.38 units)		7,703,000		8,790,400
Accumulated other comprehensive income		336,800		736,800
Total partners' capital		11,679,300		13,600,000
	$	13,356,600	$	15,275,600

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

ATLAS AMERICA SERIES 25-2004 (B) L.P.

STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2009			2008		2009		2008

REVENUES
Natural gas and oil	$	466,800		$	1,237,000	$	1,816,200	$	3,621,200
Total revenues		466,800			1,237,000		1,816,200		3,621,200

COSTS AND EXPENSES
Production		217,700			332,700		790,200		1,039,500
Depletion		191,000			457,100		668,200		1,454,800
Accretion of asset retirement obligation		22,700			22,200		68,200		66,400
General and administrative		42,400			44,900		129,600		141,400
Total expenses		473,800			856,900		1,656,200		2,702,100
Net (loss) earnings	$	(7,000	)	$	380,100	$	160,000	$	919,100

Allocation of net (loss) earnings:
Managing general partner	$	25,800		$	207,900	$	154,900	$	560,300
Limited partners	$	(32,800	)	$	172,200	$	5,100	$	358,800
Net (loss) earnings per limited partnership unit	$	(26	)	$	137	$	4	$	284

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

ATLAS AMERICA SERIES 25-2004 (B) L.P.

STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

FOR THE NINE MONTHS ENDED

September 30, 2009

(Unaudited)

							Accumulated
	Managing						Other
	General			Limited			Comprehensive
	Partner			Partners			Income (Loss)			Total

Balance at January 1, 2009	$	4,072,800		$	8,790,400		$	736,800		$	13,600,000

Participation in revenues and expenses:
Net production revenues		359,100			666,900			—			1,026,000
Depletion		(135,000	)		(533,200	)		—			(668,200	)
Accretion of asset retirement obligation		(23,900	)		(44,300	)		—			(68,200	)
General and administrative		(45,300	)		(84,300	)		—			(129,600	)
Net earnings		154,900			5,100			—			160,000

Other comprehensive loss		—			—			(400,000	)		(400,000	)

Distributions to partners		(588,200	)		(1,092,500	)		—			(1,680,700	)

Balance at September 30, 2009	$	3,639,500		$	7,703,000		$	336,800		$	11,679,300

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

ATLAS AMERICA SERIES 25-2004 (B) L.P.

STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended
	September 30,
	2009			2008
Cash flows from operating activities:
Net earnings	$	160,000		$	919,100
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depletion		668,200			1,454,800
Non-cash loss on derivative value		292,800			295,300
Accretion of asset retirement obligation		68,200			66,400
Decrease (increase) in accounts receivable – affiliate		356,000			(180,000	)
Increase in accrued liabilities		5,900			100
Net cash provided by operating activities		1,551,100			2,555,700

Cash flows from investing activities:
Proceeds from sale of tangible equipment		—			1,500
Net cash provided by investing activities		—			1,500

Cash flows from financing activities:
Distributions to partners		(1,680,700	)		(2,457,800	)
Net cash used in financing activities		(1,680,700	)		(2,457,800	)

Net (decrease) increase in cash and cash equivalents		(129,600	)		99,400
Cash and cash equivalents at beginning of period		265,100			229,600
Cash and cash equivalents at end of period	$	135,500		$	329,000

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

ATLAS AMERICA SERIES 25-2004 (B) L.P.

NOTES TO FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

NOTE 1 - DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

Atlas America Series 25-2004 (B) 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 647 subscribers to units as Limited Partners. The Partnership was formed on January 21, 2004 to drill and operate gas wells located primarily in Pennsylvania, West Virginia, 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, ("Atlas Energy"), for administrative services. On September 29, 2009, Atlas Energy Resources, LLC and Atlas America, Inc. (“Atlas America”) (NASDAQ: ATLS) merged with Atlas Energy Resources, LLC becoming a wholly owned subsidiary of Atlas America. In addition, Atlas America changed its name to “Atlas Energy, Inc.”

The financial statements as of September 30, 2009 and for the three months and nine months ended September 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 (“SEC”). 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 considered for disclosure any material subsequent events through November 16, 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 nine months ended September 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 Form 10-K for the year ended December 31, 2008 filed with the 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 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 September 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.

ATLAS AMERICA SERIES 25-2004 (B) L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

September 30, 2009

(Unaudited)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue Recognition

The Partnership generally sells natural gas and crude oil at prevailing market prices. Revenue is 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 are 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 the Partnership’s percentage ownership of working interest or overriding royalty. Generally, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain adjustments based on proximity to gathering and transmission lines and the quality of its natural gas.

Because there are timing differences between the delivery of natural gas and oil and its 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 at September 30, 2009 and December 31, 2008 of $374,000 and $659,800, respectively, which are included in accounts receivable 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 determined on a field-by-field basis using the units-of-production method for well and related equipment costs based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of developed producing properties. 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 the property are capitalized. Oil is converted to gas equivalent basis (“Mcfe”) at the rate one barrel equals 6 thousand cubic feet (“Mcf”).

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is recorded in operations. Upon the sale or retirement of an individual well, the net book value is credited to accumulated depletion.

Oil and gas properties consist of the following at the dates indicated:	September 30,			December 31,
	2009			2008
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	898,600		$	898,600
Wells and related equipment		40,325,100			40,325,100
		41,223,700			41,223,700
Accumulated depletion		(29,130,300	)		(28,462,100	)
	$	12,093,400		$	12,761,600

ATLAS AMERICA SERIES 25-2004 (B) L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

September 30, 2009

(Unaudited)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Impairment of Oil and Gas Properties and Long-Lived Assets

The Partnership’s oil and gas properties are reviewed for impairment annually or whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable. Oil and gas properties are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows.

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 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 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 levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. If the carrying value exceeds such 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. There were no impairments of oil and gas properties recorded by the Partnership for the three and nine months ended September 30, 2009 and 2008.

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, (“the 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.

ATLAS AMERICA SERIES 25-2004 (B) L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

September 30, 2009

(Unaudited)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Recently Adopted Accounting Standards

In August 2009, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2009-05, Fair Value Measurements and Disclosures (Topic 820) – Measuring Liabilities at Fair Value (“Update 2009-05”). Update 2009-05 amends subtopic 820-10, “Fair Value Measurements and Disclosures- Overall” and provides clarification for the fair value measurement of liabilities in circumstances where quoted prices for an identical liability in an active market are not available. The amendments also provide clarification for not requiring the reporting entity to include separate inputs or adjustments to other inputs relating to the existence of a restriction that prevents the transfer of a liability when estimating the fair value of a liability. Additionally, these amendments clarify that both the quoted price in an active market for an identical liability at the measurement date and the quoted price for an identical liability when traded as an asset in an active market when no adjustments to the quoted price of the asset are required are considered Level 1 fair value measurements. These requirements are effective for financial statements issued after the release of Update 2009-05. The Partnership adopted the requirements on September 30, 2009 and it did not have a material impact on its financial position, results of operations or related disclosures.

In June 2009, the FASB issued Accounting Standards Update 2009-01, Topic 105- Generally Accepted Accounting Principles Amendments Based on Statements of Financial Accounting Standards No. 168- The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles (“Update 2009-01”). Update 2009-01 establishes the FASB Accounting Standards Codification (“ASC”) as the single source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. The ASC supersedes all existing non-Securities and Exchange Commission accounting and reporting standards. Following the ASC, 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 ASC. ASC 105 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. Entities are not required to include specific references to the ASC in their financial statements and, therefore, the Partnership has removed all previous references to FASB authoritative guidance and describes its accounting policies using a “plain English” approach. The Partnership adopted the requirements of Update 2009-01 to its financial statements on September 30, 2009 and it did not have a material impact to the Partnership’s financial statement disclosures.

In May 2009, the FASB issued ASC 855-10, Subsequent Events (“ASC 855-10”). ASC 855-10 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. The provisions require 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. ASC 855-10 is effective for interim or annual financial periods ending after June 15, 2009 and shall be applied prospectively. The Partnership adopted the requirements of this standard on June 30, 2009 and it did not have a material impact to its financial position or results of operations or related disclosures. The adoption of these provisions does not change the Partnership’s current practices with respect to evaluating, recording and disclosing subsequent events.

ATLAS AMERICA SERIES 25-2004 (B) L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

September 30, 2009

(Unaudited)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Recently Adopted Accounting Standards (Continued)

In April 2009, the FASB issued ASC 820-10-65-4, 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 (“ASC 820-10-65-4”). ASC 820-10-65-4 applies to all fair value measurements and provides additional clarification on estimating fair value when the market activity for an asset has declined significantly. ASC 820-10-65-4 also require an entity to disclose a change in valuation technique and related inputs to the valuation calculation and to quantify its effects, if practicable. ASC 820-10-65-4 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 ASC 820-10-65-4 on April 1, 2009 and its adoption did not have a material impact on the Partnership’s financial position and results of operations.

In April 2009, the FASB issued ASC 825-10-65-1, Interim Disclosures about Fair Value of Financial Instruments (“ASC 825-10-65-1”), which requires 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. ASC 825-10-65-1 is effective for interim periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Partnership adopted these requirements on April 1, 2009 and its adoption did not have a material impact on the Partnership’s financial position and results of operations.

In March 2008, the FASB issued ASC 815-10-50-1, Disclosures about Derivative Instruments and Hedging Activities (“ASC 815-10-50-1”), to require enhanced disclosure about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The Partnership adopted the requirements of this section of ASC 815-10-50-1 on January 1, 2009 and it did not have a material impact on its financial position or results of operations (see Note 5).

Modernization of Oil and Gas Reporting

In December 2008, the 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.

ATLAS AMERICA SERIES 25-2004 (B) L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

September 30, 2009

(Unaudited)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Modernization of Oil and Gas Reporting (Continued)

·	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 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 months and nine months ended September 30, 2009 were $20,700 and $84,100, respectively. Administrative costs incurred for the three months and nine months ended September 30, 2008 were $32,100 and $96,000, respectively.

Monthly well supervision fees which are included in production expenses in the Partnership’s Statements of Operations are payable at $313 per well per month in 2009 and 2008, for operating and maintaining the wells. Well supervision fees incurred for the three months and nine months ended September 30, 2009 were $84,200 and $345,000, respectively. Well supervision fees incurred for the three months and nine months ended September 30, 2008 were $132,600 and $395,400, 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 months and nine months ended September 30, 2009 were $68,200 and $227,800, respectively. Transportation fees incurred for the three months and nine months ended September 30, 2008 were $119,100 and $399,200, 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.

ATLAS AMERICA SERIES 25-2004 (B) L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

September 30, 2009

(Unaudited)

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

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 (February 2005). Since inception of the program, the MGP has not been required to subordinate any of its distributions to its limited partners.

NOTE 4 - COMPREHENSIVE (LOSS) EARNINGS

Comprehensive (loss) earnings includes net (loss) earnings 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 (loss) earnings, are referred to as "other comprehensive (loss) earnings" 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) earnings the periods indicated is as follows:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2009			2008		2009			2008
Net (loss) earnings	$	(7,000	)	$	380,100	$	160,000		$	919,100
Other comprehensive (loss) earnings
Unrealized holding gain (loss) on hedging contracts		26,600			2,971,900		(7,900	)		(129,600	)
Less: reclassification adjustment for (gains) losses realized in net (loss) earnings		(111,500	)		415,800		(392,100	)		478,800
Total other comprehensive (loss) earnings		(84,900	)		3,387,700		(400,000	)		349,200
Comprehensive (loss) earnings	$	(91,900	)	$	3,767,800	$	(240,000	)	$	1,268,300

NOTE 5 - DERIVATIVE INSTRUMENTS

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. The Partnership designates these derivatives as cash flow hedges and the derivative instruments have been recorded as either assets or liabilities at fair value on the balance sheets. The effective portion of the gain or loss on the derivative is reported as a component of other comprehensive (loss) earnings 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 September 30, 2009 and December 31, 2008, as well as the gain or loss recognized for the three and nine months ended September 30, 2009 and 2008, respectively. There were no gains or losses recognized in income for ineffective derivative instruments for the three months and nine months ended September 30, 2009 and 2008, respectively.

ATLAS AMERICA SERIES 25-2004 (B) L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

September 30, 2009

(Unaudited)

NOTE 5 - DERIVATIVE INSTRUMENTS (Continued)

Fair Value of Derivative Instruments:

	Asset Derivatives					Liability Derivatives
Derivatives in		Fair Value					Fair Value
Cash Flow Hedging	Balance Sheet	September 30,		December 31,		Balance Sheet	September 30,			December 31,
Relationships	Location	2009		2008		Location	2009			2008


Commodity contracts:	Current assets	$	339,200	$	821,800	Current liabilities	$	(5,000	)	$	(72,200	)
	Long-term assets		238,800		521,400	Long-term liabilities		(59,800	)		(65,000	)

Total derivatives		$	578,000	$	1,343,200		$	(64,800	)	$	(137,200	)

Effects of Derivative Instruments on Statements of Operations:

Derivatives in	Gain 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
Cash Flow Hedging	September 30,		September 30,		OCI into Income	September 30,		September 30,
Relationship	2009		2008		(Effective Portion)	2009		2008

Commodity contracts	$	26,600	$	2,971,900	Natural gas and oil revenue	$	111,500	$	(415,800	)

Derivatives in	Loss Recognized in OCI on Derivative (Effective Portion) Nine Months Ended						Location of Gain/(Loss) Reclassified from Accumulated	Gain/(Loss) Reclassified from OCI into Income (Effective Portion) Nine Months Ended
Cash Flow Hedging	September 30,			September 30,			OCI into Income	September 30,			September 30,
Relationship	2009			2008			(Effective Portion)	2009		��	2008

Commodity contracts	$	(7,900	)	$	(129,600	)	Natural gas and oil revenue	$	392,100		$	(478,800	)

Atlas Energy, on behalf of the Partnership, from time to time enters into natural gas and crude oil future option contracts 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.

At September 30, 2009, the Partnership reflected a net hedge asset on its Balance Sheets of $513,200, however unrealized gains of $176,400 which were required to be recognized in net income which were related to impairment charges of the Partnership’s oil and gas properties for the year ended December 31, 2008 and prior period's results in a net unrealized accumulated gain of $336,800. Of the remaining $336,800 net unrealized gain in accumulated other comprehensive income at September 30, 2009, if the fair values of the instruments remain at current market values, the Partnership will reclassify $207,400 of net gain to its Statements of Operations over the next twelve month period as these contracts settle, and $129,400 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 Operations 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 nine months ended September 30, 2009 and 2008 for hedge ineffectiveness or as a result of the discontinuance of cash flow hedges.

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

ATLAS AMERICA SERIES 25-2004 (B) L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

September 30, 2009

(Unaudited)

NOTE 5 - DERIVATIVE INSTRUMENTS (Continued)

Natural Gas Fixed Price Swaps


Production			Average
Period Ending	Volumes		Fixed Price		Fair Value
December 31,	(MMbtu) (1)		(per MMbtu) (1)		Asset (2)

2009		42,200	$	8.24	$	147,700
2010		124,300		7.71		187,100
2011		75,800		7.04		62,700
2012		69,500		7.22		47,300
2013		40,500		7.08		5,900
					$	450,700

Natural Gas Costless Collars


Production				Average		Fair Value
Period Ending	Option	Volumes		Floor & Cap		Asset
December 31,	Type	(MMbtu) (1)		(per MMbtu) (1)		(Liability) (2)

2009	Puts purchased		200	$	11.00	$	1,500
2009	Calls sold		200		15.35		—
2010	Puts purchased		13,000		7.84		23,600
2010	Calls sold		13,000		9.01		—
2011	Puts purchased		34,300		6.52		22,300
2011	Calls sold		34,300		7.67		—
2012	Puts purchased		13,000		6.51		100
2012	Calls sold		13,000		7.72		—
2013	Puts purchased		16,300		6.52		—
2013	Calls sold		16,300		7.81		(1,600	)
						$	45,900

Crude Oil Fixed Price Swaps


Production			Average
Period Ending	Volumes		Fixed Price		Fair Value
December 31,	(Bbl) (1)		(per Bbl) (1)		Asset (3)

2009		100	$	99.32	$	1,800
2010		200		97.40		4,500
2011		200		77.46		3,000
2012		100		76.86		1,900
2013		50		77.36		500
					$	11,700

ATLAS AMERICA SERIES 25-2004 (B) L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

September 30, 2009

(Unaudited)

NOTE 5 - DERIVATIVE INSTRUMENTS (Continued)

Crude Oil Costless Collars


Production				Average
Period Ending	Option	Volumes		Floor & Cap		Fair Value
December 31,	Type	(Bbl) (1)		(per Bbl) (1)		Asset (3)

2009	Puts purchased		50	$	85.00	$	500
2009	Calls sold		50		116.56		—
2010	Puts purchased		100		85.00		1,900
2010	Calls sold		100		112.92		—
2011	Puts purchased		100		67.22		1,400
2011	Calls sold		100		89.44		—
2012	Puts purchased		100		65.51		900
2012	Calls sold		100		91.45		—
2013	Puts purchased		50		65.36		200
2013	Calls sold		50		93.44		—
						$	4,900

				Total Net Asset		$	513,200

_____________

(1)	MMBTU represents million British Thermal Units. Bbl represents barrels.

(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

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. The hierarchy defines three levels of inputs that may be used to measure fair value.

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.

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 entities 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.

ATLAS AMERICA SERIES 25-2004 (B) L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

September 30, 2009

(Unaudited)

NOTE 6 - FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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

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. Information for assets and liabilities measured at fair value on a recurring basis at September 30, 2009 and December 31, 2008 is as follows.

	September 30, 2009				December 31, 2008
	Level 2		Total		Level 2		Total

Commodity-based derivatives	$	513,200	$	513,200	$	1,206,000	$	1,206,000
Total	$	513,200	$	513,200	$	1,206,000	$	1,206,000

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.

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 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. There were no new asset retirement obligations incurred for the three months and nine months ended September 30, 2009.

NOTE 7 - ASSET RETIREMENT OBLIGATION

The Partnership recognizes an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. It also recognizes a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability is based on 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 estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements.

The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its oil and gas properties, the Partnership has determined that there are no other material retirement obligations associated with tangible long-lived assets.

ATLAS AMERICA SERIES 25-2004 (B) L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

September 30, 2009

(Unaudited)

NOTE 7 - ASSET RETIREMENT OBLIGATION (Continued)

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2009		2008		2009		2008
Asset retirement obligation at beginning of period	$	1,561,700	$	1,518,900	$	1,516,200	$	1,474,700
Accretion expense		22,700		22,200		68,200		66,400
Asset retirement obligation at end of period	$	1,584,400	$	1,541,100	$	1,584,400	$	1,541,100

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.

General

We were formed as a Delaware limited partnership on January 21, 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. On September 29, 2009 Atlas Energy completed its merger with Atlas America, Inc. (NASDAQ:ATLS). In addition, Atlas America changed its name to Atlas Energy, Inc.

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						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008

Production revenues (in thousands):
Gas	$	426		$	1,065		$	1,705		$	3,280
Oil		41			172			111			341
Total	$	467		$	1,237		$	1,816		$	3,621

Production volumes:
Gas (mcf/day) (1)		696			1,222			828			1,346
Oil (bbls/day) (1)		7			17			7			12
Total (mcfe/day) (1)		738			1,324			870			1,418

Average sales prices: (2)
Gas (per mcf) (1) (3)	$	8.81		$	10.71		$	8.82		$	9.69
Oil (per bbl) (1) (4)	$	66.02		$	110.70		$	59.51		$	101.14

Average production costs:
As a percent of revenues		47	%		27	%		44	%		29	%
Per mcfe (1)	$	3.21		$	2.73		$	3.33		$	2.67

Depletion per mcfe	$	2.81		$	3.75		$	2.81		$	3.74

___________

(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 derivative gains previously recognized into income and dividing by the total volume for the period. Previously recognized derivative gains were $139,000 and $289,800 for the three months and nine months ended September 30, 2009. Previously recognized derivative gains were $138,900 and gains of $295,300 for the three months and nine months ended September 30, 2008. The derivative gains are included in other comprehensive income and resulted from prior period impairment charges.

(4)

Average oil prices are calculated by including in total revenue derivative gains previously recognized into income and dividing by the total volume for the period. Previously recognized derivative gains were $900 and $3,000 for the three months and nine months ended September 30, 2009. The derivative gains are included in other comprehensive income and resulted from prior period impairment charges.

Natural Gas Revenues. Our natural gas revenues were $425,500 and $1,065,400 for the three months ended September 30, 2009 and 2008, respectively, a decrease of $639,900 (60%). The $639,900 decrease in natural gas revenues for the three months ended September 30, 2009 as compared to the prior year similar period was attributable to a $458,600 decrease in production volumes and a $181,300 decrease in natural gas sales prices after the effect of financial hedges. Our production volumes decreased to 696 mcf per day for the three months ended September 30, 2009 from 1,222 mcf per day for the three months ended September 30, 2008, a decrease of 526 mcf per day (43%). The overall decrease in natural gas production volumes for the three months ended September 30, 2009 resulted primarily from the normal decline inherent in the life of a well.

Our natural gas revenues were $1,704,900 and $3,280,400 for the nine months ended September 30, 2009 and 2008, respectively, a decrease of $1,575,500 (48%). The $1,575,500 decrease in natural gas revenues for the nine months ended September 30, 2009 as compared to the prior year similar period was attributable to a $1,270,200 decrease in production volumes and a $305,300 decrease in natural gas sales prices after the effect of financial hedges. Our production volumes decreased to 828 mcf per day for the nine months ended September 30, 2009 from 1,346 mcf per day for the nine months ended September 30, 2008, a decrease of 518 mcf per day (38%). The overall decrease in natural gas production volumes for the nine months ended September 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 $41,300 and $171,600 for the three months ended September 30, 2009 and 2008, respectively, a decrease of $130,300 (76%). The $130,300 decrease in oil revenues for the three months ended September 30, 2009 as compared to the prior year similar period was attributable to a $29,600 decrease in oil prices and a $100,700 decrease in production volumes. Our production volumes decreased to 7 bbls per day for the three months ended September 30, 2009 from 17 bbls per day for the three months ended September 30, 2008, a decrease of 10 bbls per day (59%).

Our oil revenues were $111,300 and $340,800 for the nine months ended September 30, 2009 and 2008, respectively, a decrease of $229,500 (67%). The $229,500 decrease in oil revenues for the nine months ended September 30, 2009 as compared to the prior year similar period was attributable to a $146,600 decrease in production volumes and a $82,900 decrease in oil prices. Our production volumes decreased to 7 bbls per day for the nine months ended September 30, 2009 from 12 bbls per day for the nine months ended September 30, 2008, a decrease of 5 bbls per day (42%).

Expenses. Production expenses were $217,700 and $332,700 for the three months ended September 30, 2009 and 2008, respectively, a decrease of $115,000 (35%). Production expenses were $790,200 and $1,039,500 for the nine months ended September 30, 2009 and 2008, respectively, a decrease of $249,300 (24%). These decreases were primarily attributable to lower variable and transportation expenses as compared to the prior year similar period.

Depletion of oil and gas properties as a percentage of oil and gas revenues were 41% and 37% for the three months ended September 30, 2009 and 2008, respectively; and 37% and 40% for the nine months ended September 30, 2009 and 2008, respectively. These percentage changes are 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 September 30, 2009 and 2008 were $42,400 and $44,900, respectively, a decrease of $2,500 (6%). For the nine months ended September 30, 2009 and 2008 these expenses were $129,600 and $141,400, respectively, a decrease of $11,800 (8%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP and vary from period to period due to the timing and billing of the costs and services provided to the Partnership.

Liquidity and Capital Resources

Cash provided by operating activities decreased $1,004,600 in the nine months ended September 30, 2009 to $1,551,100 as compared to $2,555,700 for the nine months ended September 30, 2008. This decrease was primarily due to a decrease in net earnings before depletion, net non-cash loss on derivative values and accretion of $1,546,400. This was partially offset by the change in accounts receivable-affiliate which increased operating cash flows by $536,000 in the nine months ended September 30, 2009 as compared to the nine months ended September 30, 2008.

Cash provided by investing activities were $1,500 for the nine months ended September 30, 2008, from the sale of tangible equipment.

Cash used in financing activities decreased $777,100 during the nine months ended September 30, 2009 to $1,680,700 from $2,457,800 for the nine months ended September 30, 2008. This decrease was due to a decrease in cash distributions to partners.

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

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

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

Recently Adopted Accounting Standards

In August 2009, the Financial Accounting Standards Board or FASB issued Accounting Standards Update 2009-05, Fair Value Measurements and Disclosures (Topic 820) – Measuring Liabilities at Fair Value an Update 2009-05. Update 2009-05 amends subtopic 820-10, “Fair Value Measurements and Disclosures- Overall” and provides clarification for the fair value measurement of liabilities in circumstances where quoted prices for an identical liability in an active market are not available. The amendments also provide clarification for not requiring the reporting entity to include separate inputs or adjustments to other inputs relating to the existence of a restriction that prevents the transfer of a liability when estimating the fair value of a liability. Additionally, these amendments clarify that both the quoted price in an active market for an identical liability at the measurement date and the quoted price for an identical liability when traded as an asset in an active market when no adjustments to the quoted price of the asset are required are considered Level 1 fair value measurements. These requirements are effective for financial statements issued after the release of Update 2009-05. We adopted the requirements on September 30, 2009 and it did not have a material impact on our financial position, results of operations or related disclosures.

In June 2009, the FASB issued Accounting Standards Update 2009-01, Topic 105- Generally Accepted Accounting Principles Amendments Based on Statements of Financial Accounting Standards No. 168- The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles an Update 2009-01. Update 2009-01 establishes the FASB Accounting Standards Codification or ASC as the single source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. The ASC supersedes all existing non-Securities and Exchange Commission accounting and reporting standards. Following the ASC, 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 ASC. ASC 105 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. Entities are not required to include specific references to the ASC in their financial statements and, therefore, we have removed all previous references to FASB authoritative guidance and describes our accounting policies using a “plain English” approach. We adopted the requirements of Update 2009-01 to our financial statements on September 30, 2009 and it did not have a material impact to our financial statement disclosures.

In May 2009, the FASB issued ASC 855-10, Subsequent Events or ASC 855-10. ASC 855-10 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. The provisions require 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. ASC 855-10 is effective for interim or annual financial periods ending after June 15, 2009 and shall be applied prospectively. We adopted the requirements of this standard on June 30, 2009 and it did not have a material impact to our financial position or results of operations or related disclosures. The adoption of these provisions does not change our current practices with respect to evaluating, recording and disclosing subsequent events.

In April 2009, the FASB issued ASC 820-10-65-4, 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 ASC 820-10-65-4. ASC 820-10-65-4 applies to all fair value measurements and provides additional clarification on estimating fair value when the market activity for an asset has declined significantly. ASC 820-10-65-4 also require an entity to disclose a change in valuation technique and related inputs to the valuation calculation and to quantify its effects, if practicable. ASC 820-10-65-4 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 ASC 820-10-65-4 on April 1, 2009 and its adoption did not have a material impact on our financial position and results of operations.

In April 2009, the FASB issued ASC 825-10-65-1, Interim Disclosures about Fair Value of Financial Instruments or ASC 825-10-65-1, which requires 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. ASC 825-10-65-1 is effective for interim periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. We adopted these requirements on April 1, 2009 and its adoption did not have a material impact on our financial position and results of operations.

In March 2008, the FASB issued ASC 815-10-50-1, Disclosures about Derivative Instruments and Hedging Activities or ASC 815-10-50-1, to require enhanced disclosure about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. We adopted the requirements of this section of ASC 815-10-50-1 on January 1, 2009 and it did not have a material impact on our financial position or results of operations (see Note 5).

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:

·	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.

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.

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 September 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 Atlas America Series 25-2004
		(B) L.P. (1)
10.1		Drilling and Operating Agreement for Atlas America Series 25-2004 (B) 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 April 29, 2005 in the Form S-1 Registration Statement dated April 29, 2005, File No. 0-51271

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 Series 25-2004 (B) L.P.



		Atlas Resources, LLC, Managing General Partner

Date: November 16, 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: November 16, 2009		By:/s/ Freddie M. Kotek
		Freddie M. Kotek, Chairman of the Board of Directors, Chief Executive
		Officer and President


Date: November 16, 2009		By:/s/ Matthew A. Jones
		Matthew A. Jones, Chief Financial Officer


Date: November 16, 2009		By:/s/ Sean P. McGrath
		Sean P. McGrath, Chief Accounting Officer

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Atlas America Series 25-2004 Inactive 10-Q2009 Q3 Quarterly report

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