Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

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

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

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

	September 30, 2013			December 31, 2012
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	—
Accounts receivable trade-affiliate		213,000			155,300
Accounts receivable monetized gains-affiliate		17,400			58,100
Current portion of derivative assets		2,300			2,900
Total current assets		232,700			216,300

Oil and gas properties, net		3,917,900			4,255,600
Long-term derivative assets		8,200			12,000
	$	4,158,800		$	4,483,900
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	12,500		$	200
Total current liabilities		12,500			200

Asset retirement obligation		2,518,800			2,420,100
Long-term put premiums payable-affiliate		9,900			4,100

Commitments and contingencies		—			—

Partners’ capital:
Managing general partner’s interest		1,273,700			1,372,800
Limited partners’ interest (1,265.38 units)		344,300			677,200
Accumulated other comprehensive (loss) income		(400	)		9,500
Total partners’ capital		1,617,600			2,059,500
	$	4,158,800		$	4,483,900

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
REVENUES
Natural gas, oil and liquid gas	$	248,000		$	282,800		$	816,900		$	697,700
Total revenues		248,000			282,800			816,900			697,700

COSTS AND EXPENSES
Production		189,600			231,300			563,700			610,900
Depletion		101,500			132,500			336,600			331,100
Accretion of asset retirement obligation		32,900			30,500			98,700			91,600
General and administrative		43,200			49,000			123,300			135,400
Total costs and expenses		367,200			443,300			1,122,300			1,169,000
Net loss	$	(119,200	)	$	(160,500	)	$	(305,400	)	$	(471,300	)

Allocation of net loss:
Managing general partner	$	(38,200	)	$	(39,800	)	$	(96,700	)	$	(125,200	)
Limited partners	$	(81,000	)	$	(120,700	)	$	(208,700	)	$	(346,100	)
Net loss per limited partnership unit	$	(64	)	$	(95	)	$	(165	)	$	(274	)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Net loss	$	(119,200	)	$	(160,500	)	$	(305,400	)	$	(471,300	)
Other comprehensive loss:
Unrealized holding gain (loss) on cash flow hedging contracts		2,000			(7,500	)		(7,700	)		(9,300	)
Difference in estimated hedge gains receivable		4,600			8,600			18,600			28,500
Reclassification adjustment for gains realized in net loss from cash flow hedges		(6,900	)		(14,400	)		(20,800	)		(49,100	)
Total other comprehensive loss		(300	)		(13,300	)		(9,900	)		(29,900	)
Comprehensive loss	$	(119,500	)	$	(173,800	)	$	(315,300	)	$	(501,200	)

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

Balance at January 1, 2013	$	1,372,800		$	677,200		$	9,500		$	2,059,500

Participation in revenues and expenses:
Net production revenues		85,600			167,600			—			253,200
Depletion		(104,600	)		(232,000	)		—			(336,600	)
Accretion of asset retirement obligation		(34,500	)		(64,200	)		—			(98,700	)
General and administrative		(43,200	)		(80,100	)		—			(123,300	)
Net income		(96,700	)		(208,700	)		—			(305,400	)

Other comprehensive loss		—			—			(9,900	)		(9,900	)

Distributions to partners		(2,400	)		(124,200	)		—			(126,600	)

Balance at September 30, 2013	$	1,273,700		$	344,300		$	(400	)	$	1,617,600

	Nine Months Ended September 30,
	2013			2012
Cash flows from operating activities:
Net loss	$	(305,400	)	$	(471,300	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion		336,600			331,100
Non-cash loss on derivative value		41,000			75,100
Accretion of asset retirement obligation		98,700			91,600
(Increase) decrease in accounts receivable-affiliate		(57,700	)		43,400
Increase in accrued liabilities		12,300			2,200
Net cash provided by operating activities		125,500			72,100

Cash flows from investing activities:
Proceeds from sale of tangible equipment		1,100			—
Net cash provided by (used in) investing activities		1,100			—

Cash flows from financing activities:
Distributions to partners		(126,600	)		(102,600	)
Net cash used in financing activities		(126,600	)		(102,600	)

Net decrease in cash and cash equivalents		—			(30,500	)
Cash and cash equivalents at beginning of period		—			30,500
Cash and cash equivalents at end of period	$	—		$	—

Atlas America Series 25-2004 (B) L.P. (the “Partnership”) is a Delaware limited partnership, formed on January 21, 2004 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP).

In March 2012, the MGP’s ultimate parent, Atlas Energy L.P. (“Atlas Energy”) (NYSE: ATLS), contributed to ARP, a newly-formed exploration and production master limited partnership, substantially all of Atlas Energy’s natural gas and oil development and production assets and its partnership management business, including ownership of the MGP.

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

The Partnership has drilled and currently operates wells located in Pennsylvania, Tennessee, and West Virginia. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy, for administrative services.

The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through affiliated and or third-party gas gathering systems. The Partnership does not plan to sell any of its wells and intends to produce them until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. The Partnership expects that no other wells will be drilled and no additional funds will be required for drilling.

The accompanying condensed financial statements, which are unaudited, except that the condensed balance sheet at December 31, 2012 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in the Partnership’s Form 10-K. These interim financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2012. The results of operations for the three and nine months ended September 30, 2013 may not necessarily be indicative of the results of operations for the year ended December 31, 2013.

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

In addition to matters discussed further in this note, the Partnership’s significant accounting policies are detailed in its audited financial statements and notes thereto in the Partnership’s annual report on Form 10-K for the year ended December 31, 2012 filed with the Securities and Exchange Commission (“SEC”).

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

The natural gas industry principally conducts its business by processing actual transactions as much as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following months’ financial results. Management believes that the operating results presented for the three and nine months ended September 30, 2013 and 2012 represent actual results in all material respects (see “Revenue Recognition” accounting policy for further description).

In evaluating the need for an allowance for possible losses, the MGP performs ongoing credit evaluations of the Partnership’s customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness as determined by review of such customers’ credit information. Credit is extended on an unsecured basis to many of the Partnership’s energy customers. At September 30, 2013 and December 31, 2012, the MGP’s credit evaluation indicated that the Partnership had no need for an allowance for possible losses.

Oil and gas properties are stated at cost. Maintenance and repairs that generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized.

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

The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties. The Partnership recorded depletion expense on natural gas and oil properties of $336,600 and $331,100 for the nine months ended September 30, 2013 and 2012, respectively.

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

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

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

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

In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. The Partnership may have to pay additional consideration in the future as a well becomes uneconomic under the terms of the Partnership Agreement in order to recover these reserves. There were no impairments recorded during the three and nine months ended September 30, 2013 and 2012. During the year ended December 31, 2012, the Partnership recognized an impairment charge of $92,400.

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

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

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGL’s, crude oil, and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees, which are, in turn, based upon applicable product prices. The Partnership had unbilled revenues at September 30, 2013 and December 31, 2012 of $149,800 and $139,200, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.

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

In July 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-10, Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes (“Update 2013-10”). Currently, Topic 815 provides guidance on the risks that are permitted to be hedged in a fair value or cash flow hedge. In addition, only the interest rates on direct Treasury obligations of the U.S. Government (“UST”) and the London Interbank Offered Rate (“LIBOR”) swap rate are considered benchmark interest rates. Update 2013-10 amends Topic 815 to include the Overnight Index Swap Rate (“OIS”), also referred to as the Fed Funds Effective Swap Rate, as a U.S. benchmark interest rate for hedge accounting purposes. Including the OIS as an acceptable U.S. benchmark interest rate in addition to UST and LIBOR will provide risk managers with a more comprehensive spectrum of interest rate resets to utilize as the designated benchmark interest rate risk component under the hedge accounting guidance in Topic 815. Update 2013-10 is effective for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. The Partnership adopted the requirements of Update 2013-10 upon its effective date of July 17, 2013, and it had no material impact on its financial position, results of operations or related disclosures.

In February 2013, the FASB issued ASU 2013-02, Comprehensive Income (Topic 220) (“Update 2013-02”). Update 2013-02 requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present significant amounts reclassified out of accumulated other comprehensive income if the amount reclassified to net income in its entirety is in the same reporting period as incurred. For other amounts that are not required to be reclassified in their entirety to net income, an entity is required to reference to other disclosures that provide additional detail about those amounts. Entities are required to implement the amendments prospectively for reporting periods beginning after December 15, 2012, with early adoption being permitted. The Partnership adopted the requirements of Update 2013-02 upon its effective date of January 1, 2013, and it had no material impact on its financial position, results of operations or related disclosures.

In February 2013, the FASB issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements, for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements, for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership will apply the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

The Partnership recognized 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 considered the estimated salvage value in the depletion calculation. The estimated liability is based on the MGP’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in cost estimates, 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 the Partnership’s gas and oil properties, the Partnership determined that there were no other material retirement obligations associated with tangible long-lived assets.

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

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

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

The Partnership enters into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s balance sheets as the initial value of the options. The Partnership reflected net derivative assets on its balance sheet of $10,500 and $14,900 at September 30, 2013 and December 31, 2012, respectively.

The Partnership enters into commodity future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in commodity prices. At any point in time, such contracts may include regulated 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 physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. NGL fixed price swaps are priced based on a WTI crude oil index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.

The following table summarizes the gain or loss recognized in the statements of operations for effective derivative instruments for the three and nine months ended September 30, 2013 and 2012:

As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three and nine months ended September 30, 2013 and 2012 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

Prior to February 17, 2011 (date of the Transferred Business), Atlas Energy Inc., (“AEI”) monetized its derivative instruments, including those related to the future natural gas and oil production of the Transferred Business. AEI also monetized derivative instruments that were specifically related to the future natural gas and oil production of the Partnership. At September 30, 2013 and December 31, 2012, remaining hedge monetization cash proceeds of $23,000 and $63,600 related to the amounts hedged on behalf of the Partnership’s limited partners were included within accounts receivable monetized gains-affiliate, respectively, and $2,700 and $12,700 in long-term put premiums payable-affiliate, respectively, on the Partnership’s balance sheets. The Partnership will allocate the monetized net proceeds to the limited partners based on the natural gas and oil production generated over the period of the original derivative contracts.

During June 2012, the MGP used the undistributed monetized funds to purchase natural gas put options on behalf of the limited partners of the Partnership only. A premium (“put premium”) was paid to purchase the contracts and will be allocated to natural gas production revenues generated over the contractual term of the purchased hedging instruments. At September 30, 2013 and December 31, 2012, the put premiums were recorded as short-term payables to affiliate of $5,600 and $5,500, respectively, and long-term payables to affiliate of $12,600 and $16,800, respectively. Furthermore, the current portion of the put premium liability was included in accounts receivable monetized gains-affiliate and the long-term receivable monetized gains-affiliate was included in long term put premiums payable-affiliate in the Partnership’s balance sheets, presenting the impact of offsetting the related party assets and liabilities. The put premiums included on the Partnership’s balance sheets are allocable to the limited partners only.

The following table summarizes the gross and net fair values of the Partnership’s affiliate balances on the Partnership’s balance sheets for the periods indicated:

Offsetting Assets	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheets			Net Amount of Assets Presented in the Balance Sheets
As of September 30, 2013
Accounts receivable monetized gains-affiliate	$	23,000	$	(5,600	)	$	17,400
Long-term receivable monetized gains-affiliate		2,700		(2,700	)		—
Total	$	25,700	$	(8,300	)	$	17,400

As of December 31, 2012
Accounts receivable monetized gains-affiliate	$	63,600	$	(5,500	)	$	58,100
Long-term receivable monetized gains-affiliate		12,700		(12,700	)		—
Total	$	76,300	$	(18,200	)	$	58,100

Offsetting Liabilities	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheets		Net Amount of Liabilities Presented in the Balance Sheets
As of September 30, 2013
Put premiums payable-affiliate	$	(5,600	)	$	5,600	$	—
Long-term put premiums payable-affiliate		(12,600	)		2,700		(9,900	)
Total	$	(18,200	)	$	8,300	$	(9,900	)

As of December 31, 2012
Put premiums payable-affiliate	$	(5,500	)	$	5,500	$	—
Long-term put premiums payable-affiliate		(16,800	)		12,700		(4,100	)
Total	$	(22,300	)	$	18,200	$	(4,100	)

As a result of the monetization and the early settlement of natural gas and oil derivative instruments, the put options, and the unrealized gains recognized in earnings in prior periods due to natural gas and oil property impairments, the Partnership recorded a net deferred loss on its balance sheets in accumulated other comprehensive loss of $400 as of September 30, 2013. Included in accumulated other comprehensive loss are unrealized gains of $18,400, net of the MGP interest, that were recognized into earnings as a result of oil and gas property impairments during prior periods. During the current year, $8,500 of net gains were recorded by the Partnership and allocated only to the limited partners. Of the remaining $400 of net unrealized loss in accumulated other comprehensive loss, the Partnership will reclassify $3,100 of net gains to the Partnership’s statements of operations over the next twelve month period and the remaining losses of $3,500 in later periods.

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

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

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

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

The carrying values of cash, accounts receivable, and accounts payable approximate their respective fair values due to the short term maturities of such financial instruments. The Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 4). The Partnership manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty. 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 assets and liabilities within the same class of nature and risk. These derivative instruments are calculated by utilizing commodity indices, quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument.

Information for assets and liabilities measured at fair value at September 30, 2013 and December 31, 2012 was as follows:

	Level 1		Level 2		Level 3		Total
As of September 30, 2013
Derivative assets, gross
Commodity puts	$	—	$	10,500	$	—	$	10,500
Derivative liabilities, gross
Commodity puts		—		—		—		—
Total derivative, fair value, net	$	—	$	10,500	$	—	$	10,500

As of December 31, 2012
Derivative assets, gross
Commodity puts	$	—	$	14,900	$	—	$	14,900
Derivative liabilities, gross
Commodity puts		—		—		—		—
Total derivative, fair value, net	$	—	$	14,900	$	—	$	14,900

The Partnership estimates the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates (see Note 3). There were no additional assets or liabilities that were measured at fair value on a nonrecurring basis for the three and nine months ended September 30, 2013 and 2012.

The Partnership has entered into the following significant transactions with the 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. Monthly well supervision fees, which are included in production expense in the Partnership’s statement of operations, are payable at $313 per well per month for operating and maintaining the wells. 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.

The following table provides information with respect to these costs and the periods incurred.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Administrative	$	25,600	$	28,400	$	74,400	$	84,100
Supervision		105,200		116,700		305,300		345,400
Transportation		26,600		33,400		90,100		79,800
Total	$	157,400	$	178,500	$	469,800	$	509,300

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

Subject to certain conditions, investor partners may present their interests for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. The MGP is not obligated to purchase more than 5% of the units in any calendar year. In the event that the MGP is unable to obtain the necessary funds, it may suspend its purchase obligation.

Beginning one year after each of the Partnership’s wells has been placed into production, the MGP, as operator, may retain $200 per month per well to cover estimated future plugging and abandonment costs. As of September 30, 2013, the MGP has not withheld any such funds. The MGP is currently evaluating its right to exercise this option based on several factors such as commodity prices, the natural decline in well production, and current and future plugging services and costs.

The Partnership 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.

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

When used in this Form 10-Q, the words “believes”, “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements. These risks and uncertainties 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 this Form 10-Q or to reflect the occurrence of unanticipated events.

Atlas America Series 25-2004 (B) L.P. (“we”, “us” or the “Partnership”) is a Delaware limited partnership, formed on January 21, 2004 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP).

We have drilled and currently operate wells located in Pennsylvania, Tennessee, and West Virginia. We have no employees and rely on our MGP for management, which in turn, relies on its parent company, Atlas Energy L.P. (“Atlas Energy”), for administrative services.

We do not plan to sell any of our wells and intend to produce them until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. We expect that no other wells will be drilled and no additional funds will be required for drilling.

The following discussion provides information to assist in understanding our financial condition and results of operations. Our operating cash flows are generated from our wells, which produce primarily natural gas, but also some oil. Our produced natural gas and oil is then delivered to market through affiliated and or third-party gas gathering systems. Our ongoing operating and maintenance costs have been and are expected to be fulfilled through revenues from the sale of our natural gas and oil production. We pay our MGP, as operator, a monthly well supervision fee, which covers all normal and regularly recurring operating expenses for the production and sale of natural gas and oil such as:

The well supervision fees, however, do not include costs and expenses related to the purchase of certain equipment, materials, and brine disposal. If these expenses are incurred, we pay cost for third-party services, materials, and a competitive charge for services performed directly by our MGP or its affiliates. Also, beginning one year after each of our wells has been placed into production, our MGP, as operator, may retain $200 per month, per well to cover the estimated future plugging and abandonment costs of the well. As of September 30, 2013, our MGP had not withheld any funds for this purpose.

The availability of a ready market for natural gas and oil produced by us, and the price obtained, depends on numerous factors beyond our control, including the extent of domestic production, imports of foreign natural gas and oil, political instability or terrorist acts in oil and gas producing countries and regions, market demand, competition from other energy sources, the effect of federal regulation on the sale of natural gas and oil in interstate commerce, other governmental regulation of the production and transportation of natural gas and oil and the proximity, availability and capacity of pipelines and other required facilities. Our MGP is responsible for selling our production. During 2013 and 2012, we experienced no problems in selling our natural gas and oil. Product availability and price are the principal means of competition in selling natural gas and oil production. While it is impossible to accurately determine our comparative position in the industry, we do not consider our operations to be a significant factor in the industry.

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 September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Production revenues (in thousands):
Gas	$	201		$	245		$	693		$	576
Oil		43			36			114			110
Liquids		4			2			10			12
Total	$	248		$	283		$	817		$	698

Production volumes:
Gas (mcf/day) ⁽¹⁾		581			857			640			709
Oil (bbls/day) ⁽¹⁾		4			4			4			4
Liquids (bbl/day) ⁽¹⁾		1			1			1			1
Total (mcfe/day) ⁽¹⁾		611			887			670			739

Average sales prices ⁽²⁾
Gas (per mcf) ⁽¹⁾⁽²⁾	$	3.98		$	3.41		$	4.21		$	3.35
Oil (per bbl) ⁽¹⁾	$	101.06		$	91.17		$	95.16		$	94.62
Liquids (per bbl) ⁽¹⁾	$	52.19		$	19.62		$	56.21		$	33.21

Production costs:
As a percent of revenues		76	%		82	%		69	%		88	%
Per mcfe ⁽¹⁾	$	3.36		$	2.83		$	3.08		$	3.00

Depletion per mcfe	$	1.80		$	1.62		$	1.84		$	1.63

Natural Gas Revenues. Our natural gas revenues were $200,500 and $245,300 for the three months ended September 30, 2013 and 2012, respectively, a decrease of $44,800 (18%). The $44,800 decrease in natural gas revenues for the three months ended September 30, 2013 as compared to the prior year similar period was attributable to a $79,100 decrease in production volumes, partially offset by $34,300 increase in our natural gas sales prices after the effect of financial hedges, which was driven by market conditions. Our production volumes decreased to 581 mcf per day for the three months ended September 30, 2013 from 857 mcf per day for the three months ended September 30, 2012, a decrease of 276 mcf per day (32%). The overall decrease in natural gas production volumes for the three months ended September 30, 2013 as compared to the prior year similar period resulted primarily from the normal decline inherent in the life of a well, and a decrease in the number of producing wells.

Our natural gas revenues were $693,500 and $575,800 for the nine months ended September 30, 2013 and 2012, respectively, an increase of $117,700 (20%). The $117,700 increase in natural gas revenues for the nine months ended September 30, 2013 as compared to the prior year similar period was attributable to a $176,100 increase in our natural gas sales prices after the effect of financial hedges, which was driven by market conditions, partially offset by a $58,400 decrease in production volumes. Our production volumes decreased to 640 mcf per day for the nine months ended September 30, 2013 from 709 mcf per day for the nine months ended September 30, 2012, a decrease of 69 mcf per day (10%). The overall decrease in natural gas production volumes for the nine months ended September 30, 2013 as compared to the prior year similar period resulted primarily from the normal decline inherent in the life of a well, and a decrease in the number of producing wells.

Oil Revenues. We drill wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $43,400 and $35,600 for the three months ended September 30, 2013 and 2012, respectively, an increase of $7,800 (22%). The $7,800 increase in oil revenues for the three months ended September 30, 2013 as compared to the prior year similar period was attributable to a $4,200 increase in oil prices after the effect of financial hedges and a $3,600 increase in production volumes. Our production volumes increased to 4.67 bbls per day for the three months ended September 30, 2013 from 4.24 bbls per day for the three months ended September 30, 2012, an increase of .43 bbl per day (10%).

Our oil revenues were $113,700 and $110,000 for the nine months ended September 30, 2013 and 2012, respectively, an increase of $3,700 (3%). The $3,700 increase in oil revenues for the nine months ended September 30, 2013 as compared to the prior year similar period was attributable to a $3,000 increase in production volumes and a $700 increase in oil prices after the effect of financial hedges. Our production volumes increased to 4.37 bbls per day for the nine months ended September 30, 2013 from 4.24 bbls per day for the nine months ended September 30, 2012, an increase of .13 bbls per day (3%).

Natural Gas Liquids Revenue. The majority of our wells produce “dry gas”, which is composed primarily of methane and requires no additional processing before being transported and sold to the purchaser. Some wells, however, produce “wet gas”, which contains larger amounts of ethane and other associated hydrocarbons (i.e. “natural gas liquids”) that must be removed prior to transporting the gas. Once removed, these natural gas liquids are sold to various purchasers. Our natural gas liquids revenues were $4,100 and $1,900 for the three months ended September 30, 2013 and 2012, respectively, an increase of $2,200 (116%). The $2,200 increase in liquid revenues for the three months ended September 30, 2013 as compared to the prior year similar period was attributed to a $2,600 increase in natural gas liquid prices, partially offset by a $400 decrease in production volumes. Our production volumes decreased to .85 bbls per day for the three months ended September 30, 2013 from 1.04 bbls per day for the three months ended September 30, 2012, a decrease of .19 bbls per day (18%).

Our natural gas liquids revenues were $9,700 and $11,900 for the nine months ended September 30, 2013 and 2012, respectively, a decrease of $2,200 (18%). The $2,200 decrease in natural gas liquids revenues for the nine months ended September 30, 2013 as compared to the prior year similar period was attributable to a $6,200 decrease in production volumes, partially offset by a $4,000 increase in natural gas liquid prices. Our production volumes decreased to .63 bbls per day for the nine months ended September 30, 2013 from 1.31 bbls per day for the nine months ended September 30, 2012, a decrease of .68 bbls per day (52%).

Costs and Expenses. Production expenses were $189,600 and $231,300 for the three months ended September 30, 2013 and 2012, respectively, a decrease of $41,700 (18%). Production expenses were $563,700 and $610,900 for the nine months ended September 30, 2013 and 2012, respectively, a decrease of $47,200 (8%). The decrease for the three and nine months ended September 30, 2013 was mostly due to lower operating costs.

Depletion of oil and gas properties as a percentage of oil and gas revenues was 41% and 47% for the three months ended September 30, 2013 and 2012, respectively, and 41% and 47% for the nine months ended September 30, 2013 and 2012, 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, 2013 and 2012 were $43,200 and $49,000, respectively, a decrease of $5,800 (12%). For the nine months ended September 30, 2013 and 2012 these expenses were $123,300 and $135,400, respectively, a decrease of $12,100 (9%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP. The decreases for the three and nine months ended September 30, 2013 are primarily due to third-party costs as compared to the prior year similar period.

Cash provided by operating activities increased $53,400 in the nine months ended September 30, 2013 to $125,500 as compared to $72,100 for the nine months ended September 30, 2012. This increase was due to an increase in net income before a non-cash loss on derivative value, depletion and accretion of $144,400 and an increase in the change in accrued liabilities of $10,100, partially offset by a decrease in the change in accounts receivable trade-affiliate of $101,100 for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012.

Cash provided by investing activities was $1,100 for the nine months ended September 30, 2013 due to the sale of tangible equipment.

Cash used in financing activities increased $24,000 during the nine months ended September 30, 2013 to $126,600 from $102,600 for the nine months ended September 30, 2012. This increase was due to an increase 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.

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 the U.S. GAAP. On an on-going basis, we evaluate our estimates, including those related to our asset retirement obligations, depletion and certain accrued receivables and liabilities. We base our estimates on historical experience and on various other assumptions that we believe reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. A discussion of 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, 2012.

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

Under the supervision of our Chairman of the Board of Directors, Chief Executive Officer, President, and Chief Financial Officer, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, concluded that, at September 30, 2013, our disclosure controls and procedures were effective at the reasonable assurance level.

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 affect, our internal control over financial reporting.

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’s 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.

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.

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.

Delaware		34-1980376
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

Park Place Corporate Center One 1000 Commerce Drive, 4^th Floor Pittsburgh, PA		15275
(Address of principal executive offices)		(zip code)

PART I.	FINANCIAL INFORMATION	PAGE

Item 1:	Condensed Balance Sheets as of September 30, 2013 and December 31, 2012	3

	Condensed Statements of Operations for the three and nine months ended September 30, 2013 and 2012	4

	Condensed Statements of Comprehensive Loss for the three and nine months ended September 30, 2013 and 2012	5

	Condensed Statement of Changes in Partners’ Capital for the nine months ended September 30, 2013	6

	Condensed Statements of Cash Flows for the nine months ended September 30, 2013 and 2012	7

	Notes to Condensed Financial Statements	8

Item 2:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18

Item 4:	Controls and Procedures	21

PART II	OTHER INFORMATION

Item 1:	Legal Proceedings	23

Item 6:	Exhibits	23

SIGNATURES		24

CERTIFICATIONS

	September 30, 2013			December 31, 2012
Proved properties:
Leasehold interest	$	898,600		$	898,600
Wells and related equipment		40,777,600			40,778,700
Total natural gas and oil properties		41,676,200			41,677,300
Accumulated depletion and impairment		(37,758,300	)		(37,421,700	)
Oil and gas properties, net	$	3,917,900		$	4,255,600

	(1)	“Mcf” represents thousand cubic feet, “mcfe” represents thousand cubic feet equivalent, and “bbl” represents barrels. Bbl is converted to mcfe using the ratio of six mcf to one bbl.
	(2)	Average sales prices represent accrual basis pricing after adjusting for the effect of previously recognized gains resulting from prior period impairment charges.
	(3)	Average gas prices are calculated by including in total revenue derivative gains previously recognized into income in connection with prior period impairment charges and dividing by the total volume for the period. Previously recognized derivative gains were $12,300 and $23,800 for the three months ended September 30, 2013 and 2012, respectively. Previously recognized derivative gains were $41,000 and $75,800 for the nine months ended September 30, 2013 and 2012, respectively.

Exhibit No.		Description

4.0		Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Series #25-2004 L.P. (B) ⁽¹⁾
31.1		Certification Pursuant to Rule 13a-14/15(d)-14
31.2		Certification Pursuant to Rule 13a-14/15(d)-14
32.1		Section 1350 Certification
32.2		Section 1350 Certification
101		Interactive Data File

Production Period Ending December 31,	Volumes (MMBtu) ⁽¹⁾	Average Fixed Price (per MMBtu) ⁽¹⁾		Fair Value Asset ⁽²⁾
2013	2,900	$	3.45	$	100
2014	9,700		3.80		2,900
2015	7,800		4.00		3,300
2016	7,800		4.15		4,200
				$	10,500


	ATLAS RESOURCES, LLC, Managing General Partner

Date: November 12, 2013	By:	/S/ FREDDIE M. KOTEK
		Freddie M. Kotek, Chairman of the Board of Directors, Chief Executive Officer and President

Date: November 12, 2013	By:	/S/ SEAN P. MCGRATH
		Sean P. McGrath, Chief Financial Officer