Atlas America Series 25-2004 10-Q 2010 Q3 Quarterly report

United States
Securities and Exchange Commission

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2010

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	(I.R.S. Employer
incorporation or organization)	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. Yesþ Noo

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). Yeso Noo

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 filero Accelerated filero Non-accelerated filero Smaller reporting companyþ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

ATLAS AMERICA SERIES 25-2004 (B) L.P.
(A Delaware Limited Partnership)
INDEX TO QUARTERLY REPORT
ON FORM 10-Q

	PAGE
PART I. FINANCIAL INFORMATION
Item 1: Financial Statements
Balance Sheets as of September 30, 2010 and December 31, 2009	3
Statements of Operations for the Three Months and Nine Months ended September 30, 2010 and 2009	4
Statement of Changes in Partners’ Capital for the Nine Months ended September 30, 2010	5
Statements of Cash Flows for the Nine Months ended September 30, 2010 and 2009	6
Notes to Financial Statements	7-17
Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations	17-21
Item 4: Controls and Procedures	21
PART II. OTHER INFORMATION
Item 1: Legal Proceedings	22
Item 6: Exhibits	22
SIGNATURES	23
CERTIFICATIONS
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

2

PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS
ATLAS AMERICA SERIES 25-2004(B) L.P.

BALANCE SHEETS

	September 30,		December 31,
	2010		2009
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	57,600	$	116,400
Accounts receivable-affiliate		399,500		438,400
Short-term hedge receivable due from affiliate		581,200		375,200
Total current assets		1,038,300		930,000
Oil and gas properties, net		10,519,800		11,240,000
Long-term hedge receivable due from affiliate		610,400		308,500
	$	12,168,500	$	12,478,500
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	25,900	$	36,100
Short-term hedge liability due to affiliate		1,700		4,500
Total current liabilities		27,600		40,600
Asset retirement obligation		1,798,500		1,721,100
Long-term hedge liability due to affiliate		100,100		47,300
Partners’ capital:
Managing general partner		3,140,100		3,343,600
Limited partners (1,265.38 units)		6,071,400		6,811,100
Accumulated other comprehensive income		1,030,800		514,800
Total partners’ capital		10,242,300		10,669,500
	$	12,168,500	$	12,478,500

See accompanying notes to financial statements.

3

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

STATEMENTS OF OPERATIONS
(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
REVENUES
Natural gas and oil	$	486,300		$	466,800		$	1,555,100		$	1,816,200
Total revenues		486,300			466,800			1,555,100			1,816,200
COSTS AND EXPENSES
Production		262,000			217,700			771,700			790,200
Depletion		233,900			191,000			721,400			668,200
Accretion of asset retirement obligation		25,800			22,700			77,400			68,200
General and administrative		39,800			42,400			129,400			129,600
Total expenses		561,500			473,800			1,699,900			1,656,200
Net (loss) earnings	$	(75,200	)	$	(7,000	)	$	(144,800	)	$	160,000
Allocation of net (loss) earnings:
Managing general partner	$	7,900		$	25,800		$	54,800		$	154,900
Limited partners	$	(83,100	)	$	(32,800	)	$	(199,600	)	$	5,100
Net (loss) earnings per limited partnership unit	$	(66	)	$	(26	)	$	(158	)	$	4

See accompanying notes to financial statements.

4

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

STATEMENT OF CHANGES IN PARTNERS’ CAPITAL
FOR THE NINE MONTHS ENDED
September 30, 2010
(Unaudited)

							Accumulated
	Managing						Other
	General			Limited			Comprehensive
	Partner			Partners			Income		Total
Balance at January 1, 2010	$	3,343,600		$	6,811,100		$	514,800	$	10,669,500
Participation in revenues and expenses:
Net production revenues		274,200			509,200			—		783,400
Depletion		(147,000	)		(574,400	)		—		(721,400	)
Accretion of asset retirement obligation		(27,100	)		(50,300	)		—		(77,400	)
General and administrative		(45,300	)		(84,100	)		—		(129,400	)
Net earnings (loss)		54,800			(199,600	)		—		(144,800	)
Other comprehensive income		—			—			516,000		516,000
Asset contributed by MGP		1,200			—			—		1,200
Distributions to partners		(259,500	)		(540,100	)		—		(799,600	)
Balance at September 30, 2010	$	3,140,100		$	6,071,400		$	1,030,800	$	10,242,300

See accompanying notes to financial statements.

5

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

STATEMENTS OF CASH FLOWS
(Unaudited)

	Nine Months Ended
	September 30,
	2010			2009
Cash flows from operating activities:
Net (loss) earnings	$	(144,800	)	$	160,000
Adjustments to reconcile net (loss) earnings to net cash provided by operating activities:
Depletion		721,400			668,200
Non-cash loss on derivative value		58,100			292,800
Accretion of asset retirement obligation		77,400			68,200
Decrease in accounts receivable – affiliate		38,900			356,000
(Decrease) increase in accrued liabilities		(10,200	)		5,900
Net cash provided by operating activities		740,800			1,551,100
Cash flows from financing activities:
Distributions to partners		(799,600	)		(1,680,700	)
Net cash used in financing activities		(799,600	)		(1,680,700	)
Net decrease in cash and cash equivalents		(58,800	)		(129,600	)
Cash and cash equivalents at beginning of period		116,400			265,100
Cash and cash equivalents at end of period	$	57,600		$	135,500
Supplemental schedule of non-cash investing and financing activities:
Assets contributed by managing general partner:
Tangible equipment	$	1,200		$	—
	$	1,200		$	—

See accompanying notes to financial statements.

6

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

NOTES TO FINANCIAL STATEMENTS
September 30, 2010

(Unaudited)

NOTE 1 — BASIS OF PRESENTATION

Atlas America Series 25-2004 (B) L.P. (the “Partnership”) is a Delaware Limited Partnership which operates gas wells located primarily in Pennsylvania, Tennessee, and West Virginia. The Partnership includes Atlas Resources, LLC of Pittsburgh, Pennsylvania, as Managing General Partner (“MGP”) and operator, and 648 Limited Partners. The MGP is a wholly-owned subsidiary of Atlas Energy Resources, LLC (“ATN”), an independent developer and producer of natural gas and oil, with operations in the Appalachian, Michigan and Illinois Basin. ATN is a wholly-owned subsidiary of Atlas Energy, Inc. (NASDAQ: ATLS).

The accompanying financial statements, which are unaudited except that the balance sheet at December 31, 2009 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States of America for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. Management has considered for disclosure any material subsequent events through the date the financial statements were issued. These interim financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009. The results of operations for the three and nine month periods ended September 30, 2010 may not necessarily be indicative of the results of operations for the full year ending December 31, 2010.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of the Partnership’s 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 disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, asset impairments, fair value of derivative instruments, and the probability of forecasted transactions. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions as much as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the three and nine months ended September 30, 2010 and 2009 represent actual results in all material respects (see “Revenue Recognition” accounting policy for further description).

Fair Value of Financial Instruments

The carrying amounts of the Partnership’s cash and receivables approximate fair values because of the short maturities of these instruments.

7

ATLAS AMERICA SERIES 25-2004(B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2010
(Unaudited)

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Oil and Gas Properties

Oil and gas properties are stated at cost. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized. The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Oil is converted to gas equivalent basis (“Mcfe”) at the rate of one barrel equals 6 Mcf.

The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of developed producing properties. Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the cost from the property accounts and the resultant gain or loss is reclassified to the Partnership’s statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its balance sheets.

Impairment of Long-Lived Assets

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

The review of the Partnership’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce 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 prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

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

There were no impairments of proved oil and gas properties recorded by the Partnership for the three and nine months ended September 30, 2010 and 2009. During the year ended December 31, 2009, the Partnership recognized a $626,900 asset impairment related to oil and gas properties net of an offsetting gain in accumulated other comprehensive income of $18,000. This impairment related to the carrying amount of these oil and gas properties being in excess of its estimate of their fair value at December 31, 2009. The estimate of fair value of these oil and gas properties was impacted by, among other factors, the deterioration of natural gas prices.

8

ATLAS AMERICA SERIES 25-2004(B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2010
(Unaudited)

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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.

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 is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil in which the Partnership has an interest with other producers are recognized on the basis of the Partnership’s percentage ownership of working interest. 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.

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation fees which are, in turn, based upon applicable product prices (see “Use of Estimates” accounting policy for further description). The Partnership had unbilled revenues at September 30, 2010 and December 31, 2009 of $283,700 and $318,600, respectively, which are included in accounts receivable – affiliate within the Partnership’s balance sheets.

Comprehensive Income (Loss)

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Net (loss) earnings	$	(75,200	)	$	(7,000	)	$	(144,800	)	$	160,000
Other comprehensive income (loss):
Unrealized holding gain (loss) on hedging contracts		361,800			26,600			846,800			(7,900	)
Less: reclassification adjustment for gains realized in net (loss) earnings		(98,300	)		(111,500	)		(330,800	)		(392,100	)
Total other comprehensive income (loss)		263,500			(84,900	)		516,000			(400,000	)
Comprehensive income (loss)	$	188,300		$	(91,900	)	$	371,200		$	(240,000	)

9

ATLAS AMERICA SERIES 25-2004(B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2010
(Unaudited)

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Recently Adopted Accounting Standards

In August 2010, the FASB issued Accounting Standards Update 2010-21, “Accounting for Technical Amendments to Various SEC Rules and Schedules” (“Update 2010-21”). Update 2010-21 codified minor language changes to the Accounting Standards Codification (“ASC”) related to various SEC rules and schedules. As Update 2010-21 serves only to clarify an accounting language in the ASC, the FASB did not provide a required adoption date. The Partnership adopted the requirements of Update 2009-21 on September 30, 2010, and it did not have a material impact on its financial position, results of operations or related disclosures.

In April 2010, the FASB issued Accounting Standards Update 2010-14, “Accounting for Extractive Industries – Oil & Gas: Amendments to Paragraph 932-10-S99-1” (“Update 2010-14”). Update 2010-14 provides amendments to add the SEC’s Regulation S-X Rule 4-10, “Financial Accounting and Reporting for Oil and Gas Producing Activities Pursuant to the Federal Securities Laws and the Energy Policy and Conservation Act of 1975” (“S-X Rule 4-10”) to ASC Topic 932 “Extractive Activities – Oil and Gas”. S-X Rule 4-10 was included in the SEC’s Final Rule, “Modernization of Oil and Gas Reporting, which became effective January 1, 2010. As Update 2010-14 only served to align the FASB’s ASC Topic 932 with the SEC’s S-X Rule 4-10, the Partnership’s adoption did not have a material impact on its financial position, results of operations or related disclosures.

In February 2010, the FASB issued Accounting Standards Update 2010-09, “Subsequent Events (Topic 855): Amendments to Certain Recognition and Disclosure Requirements” (“Update 2010-09”). Update 2010-09 removes the requirement for an SEC filer to disclose a date through which subsequent events have been evaluated in both issued and revised financial statements. Revised financial statements include financial statements revised as a result of either correction of an error or retrospective application of U.S. generally accepted accounting standards. The requirements of Update 2010-09 were effective upon its issuance, February 24, 2010. The Partnership applied the requirements of Update 2010-09 upon its adoption and it did not have an impact on its financial position, results of operations or related disclosures.

In January 2010, the FASB issued Accounting Standards Update 2010-06, “Fair Value Measurement and Disclosures (Topic (820) – Improving Disclosures about Fair Value Measurement” (“Update 2010-06”). Update 2010-06 clarifies and requires new disclosures about the transfer of amounts between Level 1 and Level 2, as well as significant transfers in and out of Level 3. In addition, for Level 2 and Level 3 measurements, Update 2010-06 requires additional disclosure about the valuation technique used or any changes in technique. Update 2010-06 also clarifies that entities must disclose fair value measurements by classes of assets and liabilities, based on the nature and risks of the assets and liabilities. The requirements of Update 2010-06 are effective at the start of a reporting entity’s first fiscal year beginning after December 15, 2009 (January 1, 2010 for the Partnership). The Partnership applied the requirements of Update 2010-06 upon its adoption on January 1, 2010, and it did not have a material impact on its financial position, results of operations or related disclosures.

10

ATLAS AMERICA SERIES 25-2004(B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2010
(Unaudited)

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Recently Issued Accounting Standards

In July 2010, the FASB issued Accounting Standards Update 2010-20, “Receivables – Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses” (“Update 2010-20”). Update 2010-20 provides enhanced disclosure requirements for allowance for credit losses and the credit quality of financing receivables to assist financial statement users in assessing credit risk exposures and evaluating the adequacy of the allowance for credit losses. This amendment requires disclosures on a disaggregated basis that will further facilitate the evaluation of the nature of credit risk inherent in an entity’s financing receivables, how the risks are analyzed and assessed in arriving at the allowance for credit losses, and the changes and reasons for such changes in the allowance for credit losses. This amendment also requires disclosure of credit quality indicators, past due information, a roll-forward schedule of the allowance for credit losses, and any modifications to financing receivables. The requirements of Update 2010-20 are effective at the end of a reporting entity’s first annual or quarterly reporting period ending after December 15, 2010 (December 31, 2010 for the Partnership). The Partnership will apply the requirements of Update 2010-20 upon its adoption on December 31, 2010 and does not expect it to have a material impact on its financial position, results of operations or related disclosures.

In March 2010, the FASB issued Accounting Standards Update 2010-11, “Derivatives and Hedging (Topic 815): Scope Exception Related to Embedded Credit Derivatives” (“Update 2010-11”). Update 2010-11 provides clarification with regard to the type of embedded credit derivative that is exempt from embedded derivative bifurcation requirements. Specifically, only one form of embedded credit derivative qualifies for the exemption – one that is related only to the subordination of one financial instrument to another. As a result, entities that have contracts containing an embedded credit derivative feature in a form other than such subordination may need to separately account for the embedded credit derivative feature. The requirements of Update 2010-11 are effective at the start of a reporting entity’s first fiscal year beginning after June 15, 2010 (January 1, 2011 for the Partnership). The Partnership will apply the requirements of Update 2010-11 upon its adoption on January 1, 2011 and does not expect it to have a material impact on its financial position, results of operations or related disclosures.

NOTE 3 — OIL AND GAS PROPERTIES

The following is a summary of oil and gas properties:

	September 30,			December 31,
	2010			2009
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	898,600		$	898,600
Wells and related equipment		40,440,200			40,439,000
		41,338,800			41,337,600
Accumulated depletion		(30,819,000	)		(30,097,600	)
	$	10,519,800		$	11,240,000

11

ATLAS AMERICA SERIES 25-2004(B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2010
(Unaudited)

NOTE 4 — ASSET RETIREMENT OBLIGATIONS

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 depletion.

The estimated liability is based on the MGP’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in 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.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
Asset retirement obligation at beginning of period	$	1,772,700	$	1,561,700	$	1,721,100	$	1,516,200
Accretion expense		25,800		22,700		77,400		68,200
Asset retirement obligation at end of period	$	1,798,500	$	1,584,400	$	1,798,500	$	1,584,400

NOTE 5 — DERIVATIVE INSTRUMENTS

The MGP on behalf of the Partnership uses a number of different derivative instruments, principally swaps, collars, and options, in connection with its commodity price risk management activities. The MGP enters into financial instruments to hedge its forecasted natural gas and crude oil sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas and crude oil is sold. Under swap agreements, the MGP receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not obligation, to purchase or sell natural gas and crude oil at a fixed price for the relevant contract period.

12

ATLAS AMERICA SERIES 25-2004(B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2010
(Unaudited)

NOTE 5 — DERIVATIVE INSTRUMENTS (Continued)

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

Derivatives are recorded on the Partnership’s balance sheet as assets or liabilities at fair value. The Partnership reflected a net derivative asset on its balance sheets of $1,089,800 at September 30, 2010, however unrealized gain of $59,000 recognized in income results in a net accumulated other comprehensive income balance of $1,030,800. The unrealized gain of $59,000 is comprised of $9,400, $46,800 and $2,800 from 2009, 2008 and prior periods impairments, respectively. Of the remaining $1,030,800 net unrealized gain in accumulated other comprehensive income at September 30, 2010, if the fair values of the instruments remain at current market values, the Partnership will reclassify $548,000 of gains to the Partnership’s statements of operations over the next twelve month period as these contracts expire. Aggregate gains of $482,800 will be reclassified to the Partnership’s statements of operations in later periods as these remaining contracts expire. Actual amounts that will be reclassified will vary as a result of future price changes.

The following table summarizes the fair value of the Partnership’s derivative instruments as of September 30, 2010 and December 31, 2009, as well as the gain or loss recognized in the statements of operations for effective derivative instruments for the three months and nine months ended September 30, 2010 and 2009:

Fair Value of Derivative Instruments:

		Asset Derivatives					Liability Derivatives
Derivatives in		Fair Value					Fair Value
Cash Flow	Balance Sheet	September 30,		December 31,		Balance sheet	September 30,			December 31,
Hedging Relationships	Location	2010		2009		Location	2010			2009
Commodity Contracts	Current Assets	$	581,200	$	375,200	Current liabilities	$	(1,700	)	$	(4,500	)
	Long-Term Assets		610,400		308,500	Long-term liabilities		(100,100	)		(47,300	)
Total Derivatives		$	1,191,600	$	683,700		$	(101,800	)	$	(51,800	)

Effects of Derivative Instruments on Statements of Operations:

						Gain
	Gain Recognized in OCI on Derivative					Reclassified from Accumulated OCI into (Loss) Earnings
	(Effective Portion)				Location of Gain	(Effective Portion)
Derivatives in	Three Months Ended				Reclassified from Accumulated	Three Months Ended
Cash Flow	September 30,		September 30,		OCI into (Loss) Earnings	September 30,		September 30,
Hedging Relationships	2010		2009		(Effective Portion)	2010		2009
Commodity Contracts	$	361,800	$	26,600	Natural Gas and Oil Revenue	$	98,300	$	111,500

13

ATLAS AMERICA SERIES 25-2004(B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2010
(Unaudited)

NOTE 5 — DERIVATIVE INSTRUMENTS (Continued)

							Gain
	Gain/(Loss) Recognized in OCI on Derivative						Reclassified from Accumulated OCI into (Loss) Earnings
	(Effective Portion)					Location of Gain	(Effective Portion)
Derivatives in	Nine Months Ended					Reclassified from Accumulated	Nine Months Ended
Cash Flow	September 30,		September 30,			OCI into (Loss) Earnings	September 30,		September 30,
Hedging Relationships	2010		2009			(Effective Portion)	2010		2009
Commodity Contracts	$	846,800	$	(7,900	)	Natural Gas and Oil Revenue	$	330,800	$	392,100

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

Natural Gas Fixed Price Swaps

Production			Average
Period Ending	Volumes		Fixed Price		Fair Value
December 31,	(MMbtu)(1)		(per MMbtu)(1)		Asset(2)
2010		53,600	$	7.236	$	176,400
2011		142,900		6.845		343,600
2012		96,000		7.172		200,200
2013		53,900		6.544		65,700
2014		23,500		5.899		10,800
					$	796,700

Natural Gas Costless Collars

Production				Average
Period Ending	Option	Volumes		Floor & Cap		Fair Value
December 31,	Type	(MMbtu)(1)		(per MMbtu)(1)		Asset (Liability)(2)
2010	Puts purchased		9,100	$	5.774	$	17,200
2010	Calls sold		9,100		6.996		(100	)
2011	Puts purchased		66,200		6.441		139,600
2011	Calls sold		66,200		7.551		(3,000	)
2012	Puts purchased		59,500		6.013		89,700
2012	Calls sold		59,500		7.183		(19,800	)
2013	Puts purchased		69,700		5.749		103,700
2013	Calls sold		69,700		6.937		(49,400	)
2014	Puts purchased		25,600		5.613		39,100
2014	Calls sold		25,600		6.724		(26,100	)
						$	290,900

14

ATLAS AMERICA SERIES 25-2004(B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2010
(Unaudited)

NOTE 5 — DERIVATIVE INSTRUMENTS (Continued)

Crude Oil Fixed Price Swaps

Production			Average
Period Ending	Volumes		Fixed Price		Fair Value
December 31,	(Bbl)(1)		(per Bbl)(1)		Asset(3)
2010		50	$	97.061	$	900
2011		200		88.498		600
2012		100		88.093		100
2013		50		88.398		100
2014		—		—		—
					$	1,700

Crude Oil Costless Collars

Production				Average
Period Ending	Option	Volumes		Floor & Cap		Fair Value
December 31,	Type	(Bbl)(1)		(per Bbl)(1)		Asset (Liability)(3)
2010	Puts purchased		50	$	85.000	$	200
2010	Calls sold		50		112.220		—
2011	Puts purchased		100		77.563		600
2011	Calls sold		100		101.861		(400	)
2012	Puts purchased		100		76.952		700
2012	Calls sold		100		102.368		(600	)
2013	Puts purchased		50		76.952		200
2013	Calls sold		50		103.269		(200	)
2014	Puts purchased		—		—		—
2014	Calls sold		—		—		—
						$	500
				Total Net Asset		$	1,089,800

(1)	“MMBTU” represents million British Thermal Units. “Bbl” represents barrels.
(2)	Fair value based on forward NYMEX natural gas prices, as applicable.
(3)	Fair value based on forward WTI crude oil prices, as applicable.

15

ATLAS AMERICA SERIES 25-2004(B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2010
(Unaudited)

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

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

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Partnership uses a fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 5). The Partnership’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements.

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

The Partnership estimates the fair value of asset retirement obligations using Level 3 inputs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements; the credit-adjusted risk-free rate of the Partnership; and estimated inflation rates (see Note 4).

NOTE 7 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

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

• Administrative costs, which are included in general and administrative expenses in the Partnership’s statements of operations, are payable at $75 per well per month. Administrative costs incurred for the three months and nine months ended September 30, 2010 were $30,800 and $92,300, respectively. Administrative costs incurred for the three months and nine months ended September 30, 2009 were $20,700 and $84,100, respectively.

• Monthly well supervision fees, which are included in production expenses in the Partnership’s statements of operations, are payable at $313 per well per month for operating and maintaining the wells. Well supervision fees incurred for the three months and nine months ended September 30, 2010 were $126,900 and $379,700, respectively. Well supervision fees incurred for the three months and nine months ended September 30, 2009 were $84,200 and $345,000, 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, 2010 were $51,700 and $161,600, respectively. Transportation fees incurred for the three months and nine months ended September 30, 2009 were $68,200 and $227,800, respectively.

• Assets contributed by the MGP, which are disclosed in the Partnership’s statement of cash flows as a non-cash activity for the nine months ended September 30, 2010, were $1,200.

16

ATLAS AMERICA SERIES 25-2004(B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
September 30, 2010
(Unaudited)

NOTE 7 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS (Continued)

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 production revenues of the Partnership to the benefit of the limited partners for an amount equal to at least 10% of their net subscriptions, determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution to the investor partners (February 2005) and expiring 60 months from that date. During the nine months ended September 30, 2010, the MGP was not required to subordinate any of its net production revenue to the limited partners.

NOTE 8 — COMMITMENTS AND CONTINGENCIES

Legal Proceedings

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

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

NOTE 9 — SUBSEQUENT EVENT-MERGER AGREEMENT

On November 9, 2010, ATLS announced that it entered into a definitive merger agreement (the “Merger” or “Merger Agreement”) with Chevron Corporation (“Chevron”) (NYSE:CVX), pursuant to which Chevron agreed to acquire ATLS through a merger of a newly formed wholly-owned subsidiary of Chevron with and into ATLS (the “Merger”). In the Merger, each share of ATLS common stock will receive $38.25 in cash, and each share of outstanding ATLS common stock will also receive a pro rata share of the distribution of approximately 41 million common units of Atlas Pipeline Holdings, L.P. (“AHD”) held by ATLS.

Concurrently with entering into the Merger Agreement, ATLS and ATN entered into a transaction agreement (the “Transaction Agreement”) with AHD, pursuant to which ATN agreed to sell to AHD approximately 175 Bcfe of natural gas reserves, certain other energy assets and fee revenues from the partnership management business owned by ATLS, for $250.0 million, comprised of approximately 23.38 million AHD units (which had a value of approximately $220 million as of November 8, 2010) and $30.0 million in cash (“AHD Sale”). Following the issuance of these AHD units to ATLS, ATLS will own approximately 41 million units of AHD, or approximately 81% of the outstanding units of AHD, all of which will be distributed to ATLS’s shareholders immediately prior to the Merger. AHD will also acquire the general partner interest in AHD so that, following the AHD distribution, AHD will cease to be controlled by ATLS.

Concurrently with entering into the Merger Agreement and the Transaction Agreement, ATN and Atlas Pipeline Partners, L.P. ( “APL”) have agreed that, prior to the Merger, ATN will acquire APL’s 49% interest in Laurel Mountain Midstream, LLC for $403.0 million in cash payable to APL (the “LMM Sale”).

The closing of the Merger is subject to approval by ATLS’s shareholders and other customary closing conditions, as well as the completion of the AHD Sale and the LMM Sale. Completion of each of the AHD Sale and the LMM Sale are also conditioned on the subsequent completion of the Merger.

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

Forward-Looking Statements

When used in thisForm 10-Q, the words “believes,” “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements. There are risks and uncertainties that could cause actual results to differ materially from the results stated or implied in this document. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of thisForm 10-Q or to reflect the occurrence of unanticipated events.

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BUSINESS OVERVIEW

We are a Delaware Limited Partnership which operates gas wells located primarily in western Pennsylvania, Tennessee, and West Virginia. Our Partnership includes Atlas Resources, LLC of Pittsburgh, Pennsylvania, as Managing General Partner (“MGP”) and operator, and 648 Limited Partners. The MGP is a wholly-owned subsidiary of Atlas Energy Resources, LLC (ATN), an independent developer and producer of natural gas and oil, with operations in the Appalachian, Michigan, and Illinois Basin. ATN is a wholly-owned subsidiary of Atlas Energy, Inc, (NASDAQ: ATLS).

Our wells are currently producing natural gas and, to a 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 venture between Atlas Energy’s affiliate, Atlas Pipeline Partners, L.P. (NYSE: APL) and The Williams Companies, Inc. (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,
	2010			2009			2010			2009
Production revenues (in thousands):
Gas	$	429		$	426		$	1,410		$	1,705
Oil		57			41			145			111
Total	$	486		$	467		$	1,555		$	1,816
Production volumes:
Gas (mcf/day)(1)		731			696			768			828
Oil (bbls/day)(1)		8			7			7			7
Total (mcfe/day)(1)		779			738			810			870
Average sales prices:(2)
Gas (per mcf)(1) (3)	$	6.88		$	8.81		$	7.00		$	8.82
Oil (per bbl)(1) (4)	$	78.57		$	66.02		$	76.43		$	59.51
Average production costs:
As a percent of revenues		54	%		47	%		50	%		44	%
Per mcfe(1)	$	3.66		$	3.21		$	3.49		$	3.33
Depletion per mcfe	$	3.26		$	2.81		$	3.26		$	2.81

(1)	“Mcf” represents thousand cubic feet, “mcfe” represents thousand cubic feet equivalent, and “bbls” represents barrels. Bbls are converted to mcfe using the ratio of six mcfs to one bbl.
(2)	Average sales prices represent accrual basis pricing after 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 (loss) earnings and dividing by the total volume for the period. Previously recognized derivative gains were $33,800 and $139,000 for the three months ended September 30, 2010 and 2009, respectively. Previously recognized derivative gains were $56,400 and $289,800 for the nine months ended September 30, 2010 and 2009, respectively. The derivative gains are included in other comprehensive income (loss) and resulted from prior period impairment charges.
(4)	Average oil prices are calculated by including in total revenue derivative gains previously recognized into (loss) earnings and dividing by the total volume for the period. Previously recognized derivative gains were $600 and $900 for the three months ended September 30, 2010 and 2009, respectively. Previously recognized derivative gains were $1,700 and $3,000 for the nine months ended September 30, 2010 and 2009, respectively. The derivative gains are included in other comprehensive income (loss) and resulted from prior period impairment charges.

18

Natural Gas Revenues.Our natural gas revenues were $428,900 and $425,500 for the three months ended September 30, 2010 and 2009, respectively, an increase of $3,400 (1%). The $3,400 increase in natural gas revenues for the three months ended September 30, 2010 as compared to the prior year similar period was attributable to a $21,000 increase in production volumes, partially offset by a $17,600 decrease in our natural gas sales prices after the effect of financial hedges, which were driven by market conditions. Our production volumes increased to 731 mcf per day for the three months ended September 30, 2010 from 696 mcf per day for the three months ended September 30, 2009, an increase of 35 mcf per day (5%).

Our natural gas revenues were $1,410,100 and $1,704,900 for the nine months ended September 30, 2010 and 2009, respectively, a decrease of $294,800 (17%). The $294,800 decrease in natural gas revenues for the nine months ended September 30, 2010 as compared to the prior year similar period was attributable to a $170,700 decrease in our natural gas sales prices after the effect of financial hedges, which were driven by market conditions and a $124,100 decrease in production volumes. Our production volumes decreased to 768 mcf per day for the nine months ended September 30, 2010 from 828 mcf per day for the nine months ended September 30, 2009, a decrease of 60 mcf per day (7%). The overall decrease in natural gas production volumes for the nine months ended September 30, 2010 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 $57,400 and $41,300 for the three months ended September 30, 2010 and 2009, respectively, an increase of $16,100 (39%). The $16,100 increase in oil revenues for the three months ended September 30, 2010 as compared to the prior year similar period was attributable to a $9,800 increase in oil prices after the effect of financial hedges and a $6,300 increase in production volumes. Our production volumes increased to 8 bbls per day for the three months ended September 30, 2010 from 7 bbls per day for the three months ended September 30, 2009, an increase of 1 bbl per day (14%).

Our oil revenues were $145,000 and $111,300 for the nine months ended September 30, 2010 and 2009, respectively, an increase of $33,700 (30%). The $33,700 increase in oil revenues for the nine months ended September 30, 2010 as compared to the prior year similar period was attributable to a $33,800 increase in oil prices after the effect of financial hedges, partially offset by a $100 decrease in production volumes. Our production volumes decreased to 7.03 bbls per day for the nine months ended September 30, 2010 from 7.04 bbls per day for the nine months ended September 30, 2009, a decrease of 0.01 bbl per day.

Expenses.Production expenses were $262,000 and $217,700 for the three months ended September 30, 2010 and 2009, respectively, an increase of $44,300 (20%). Production expenses were $771,700 and $790,200 for the nine months ended September 30, 2010 and 2009, respectively, a decrease of $18,500 (2%). These changes were primarily attributable to changes in transportation and well supervision fees 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 41% for the three months ended September 30, 2010 and 2009, respectively; and 46% and 37% for the nine months ended September 30, 2010 and 2009, respectively. These percentage changes are directly attributable to changes in revenues, oil and gas reserve quantities, product prices and production volumes and changes in the depletable cost basis of oil and gas properties.

General and administrative expenses for the three months ended September 30, 2010 and 2009 were $39,800 and $42,400, respectively, a decrease of $2,600 (6%). For the nine months ended September 30, 2010 and 2009 these expenses were $129,400 and $129,600, respectively, a decrease of $200 (0.15%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP. These decreases for the three and nine months ended September 30, 2010 were primarily due to lower third-party costs as compared to the prior year similar period.

19

Liquidity and Capital Resources

Cash provided by operating activities decreased $810,300 in the nine months ended September 30, 2010 to $740,800 as compared to $1,551,100 for the nine months ended September 30, 2009. This decrease was due to a decrease in net earnings before depletion, accretion, and non-cash loss of $477,100 and a decrease in the change in accounts receivable-affiliate of $317,100, in the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009.

Cash used in financing activities decreased $881,100 during the nine months ended September 30, 2010 to $799,600 from $1,680,700 for the nine months ended September 30, 2009. 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.

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 production revenues of the Partnership to the benefit of the limited partners for an amount equal to at least 10% of their net subscriptions, determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution to the investor partners (February 2005) and expiring 60 months from that date. During the nine months ended September 30, 2010, the MGP was not required to subordinate any of its net production revenue to the limited partners.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include revenue and expense accruals, depletion, asset impairment, fair value of derivative instruments, and the probability of forecasted transactions. A discussion of our significant accounting policies we have adopted and followed in the preparation of our financial statements is included within our Annual Report on Form 10-K for the year ended December 31, 2009 and in Note 2 under Item 1, “Financial Statements” included in this report, and there have been no material changes to these policies through September 30, 2010.

20

Fair Value of Financial Instruments

We have established a hierarchy to measure our financial instruments at fair value which requires us 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 —Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

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

Level 3 —Unobservable inputs that reflect the entity’s own assumptions about the assumption 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.

We use a fair value methodology to value the assets and liabilities for our outstanding derivative contracts. Our commodity hedges are calculated based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements.

Liabilities that are required to be measured at fair value on a nonrecurring basis include our asset retirement obligations (“ARO’s”) that are defined as Level 3. Estimates of the fair value of ARO’s are based on discounted cash flows using numerous estimates, assumptions, and judgments regarding the cost, timing of settlement, our credit-adjusted risk-free rate and inflation rates.

ITEM 4. CONTROLS AND PROCEDURES

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

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of September 30, 2010, our disclosure controls and procedures were effective at the reasonable assurance level.

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

21

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

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

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	Rule 13a-14(a)/15d-14(a) Certification.
	31.2	Rule 13a-14(a)/15d-14(a) Certification.
	32.1	Section 1350 Certification.
	32.2	Section 1350 Certification.

(1) Filed on April 29, 2005 in the Form S-1 Registration Statement dated April 29, 2005, File No. 0-51271

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 Series 25-2004 (B) L.P. Atlas Resources, LLC, Managing General Partner
Date: November 12, 2010	By:	/s/ FREDDIE M. KOTEK
		Freddie M. Kotek
		Chairman of the Board of Directors, Chief Executive Officer and President
Date: November 12, 2010	By:	/s/ MATTHEW A. JONES
		Matthew A. Jones
		Chief Financial Officer

23