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 þ 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 þ 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):

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

	September 30, 2014			December 31 2013
ASSETS
Current assets:
Cash and cash equivalents	$	34,000		$	63,600
Accounts receivable trade–affiliate		118,600			289,500
Asset retirement receivable-affiliate		15,800			-
Accounts receivable monetized gains-affiliate		-			11,100
Current portion of derivative assets		2,600			1,400
Total current assets		171,000			365,600
Oil and gas properties, net		2,378,300			2,432,000
Long-term derivative assets		5,400			7,000
	$	2,554,700		$	2,804,600
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	9,900		$	9,300
Payable to limited partners		-			120,400
Current portion of put premiums payable-affiliate		2,600			-
Total current liabilities		12,500			129,700
Long-term put premiums payable-affiliate		8,200			12,600
Asset retirement obligation		2,127,000			2,036,400
Commitments and contingencies
Partners’ capital:
Managing general partner’s interest		618,600			682,300
Limited partners’ interest (1,106.76 units)		(205,600	)		(49,200	)
Accumulated other comprehensive loss		(6,000	)		(7,200	)
Total partners’ capital		407,000			625,900
	$	2,554,700		$	2,804,600

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
REVENUES
Natural gas, oil and liquids	$	140,100		$	293,600		$	715,400		$	827,200
Total revenues		140,100			293,600			715,400			827,200
COSTS AND EXPENSES
Production		158,600			190,100			516,300			550,100
Depletion		17,500			104,500			52,600			290,700
Accretion of asset retirement obligation		30,300			28,500			90,700			85,700
General and administrative		35,000			40,300			98,700			116,800
Total costs and expenses		241,400			363,400			758,300			1,043,300
Net loss	$	(101,300	)	$	(69,800	)	$	(42,900	)	$	(216,100	)
Allocation of net loss:
Managing general partner	$	(34,700	)	$	(19,100	)	$	(12,600	)	$	(59,400	)
Limited partners	$	(66,600	)	$	(50,700	)	$	(30,300	)	$	(156,700	)
Net loss per limited partnership unit	$	(60	)	$	(46	)	$	(27	)	$	(142	)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Net loss	$	(101,300	)	$	(69,800	)	$	(42,900	)	$	(216,100	)
Other comprehensive income (loss):
Unrealized holding gain (loss) on cash flow hedging contracts		3,400			17,600			(6,300	)		7,800
Difference in estimated hedge gains receivable		(900	)		(10,900	)		14,300			6,700
Reclassification adjustment for gains realized in net loss from cash flow hedges		-			(4,700	)		(6,800	)		(14,700	)
Total other comprehensive income (loss)		2,500			2,000			1,200			(200	)
Comprehensive loss	$	(98,800	)	$	(67,800	)	$	(41,700	)	$	(216,300	)

	Managing General Partner			Limited Partners			Accumulated Other Comprehensive Loss			Total
Balance at December 31, 2013	$	682,300		$	(49,200	)	$	(7,200	)	$	625,900
Participation in revenues and expenses:
Net production revenues		70,400			128,700			-			199,100
Depletion		(16,800	)		(35,800	)		-			(52,600	)
Accretion of asset retirement obligation		(31,700	)		(59,000	)		-			(90,700	)
General and administrative		(34,500	)		(64,200	)		-			(98,700	)
Net loss		(12,600	)		(30,300	)		-			(42,900	)
Other comprehensive income		-			-			1,200			1,200
Distributions to partners		(51,100	)		(126,100	)		-			(177,200	)
Balance at September 30, 2014	$	618,600		$	(205,600	)	$	(6,000	)	$	407,000

	Nine Months Ended September 30,
	2014			2013
Cash flows from operating activities:
Net loss	$	(42,900	)	$	(216,100	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion		52,600			290,700
Non cash loss on derivative value		10,900			54,800
Accretion of asset retirement obligation		90,700			85,700
Changes in operating assets and liabilities:
Decrease in accounts receivable-trade affiliate		170,900			31,700
Increase in accrued liabilities		600			12,500
Asset retirement receivable-affiliate		(15,800	)		-
Decrease in payable to limited partners		(120,400	)		-
Asset retirement obligation settled		(100	)		-
Net cash provided by operating activities		146,500			259,300

Cash flows from investing activities:
Proceeds from sale of tangible equipment		1,100			-
Net cash provided by operating activities		1,100			-
Cash flows from financing activities:
Distributions to partners		(177,200	)		(262,300	)
Net cash used in financing activities		(177,200	)		(262,300	)
Net decrease in cash and cash equivalents		(29,600	)		(3,000	)
Cash and cash equivalents at beginning of period		63,600			65,800
Cash and cash equivalents at end of period	$	34,000		$	62,800

Atlas America Series 25-2004 (A) 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 the “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP).

On October 13, 2014, the MGP’s ultimate parent, Atlas Energy L.P. (“Atlas Energy”) (NYSE: ATLS), and its midstream subsidiary, Atlas Pipeline Partners, L.P. (“APL”), entered into definitive agreements to be acquired by Targa Resources Corp. and Targa Resources Partners LP, respectively. Immediately prior to the acquisition, Atlas Energy will distribute to its unitholders 100% of the limited liability company interests in ARP’s general partner, which has changed its name to Atlas Energy Group, LLC (“New Atlas”) and will become a separate, publicly traded company as a result of the distribution. New Atlas will hold all of Atlas Energy’s non-midstream holdings, which includes the Partnership’s business as well as the general partner interest, incentive distribution rights and Atlas Energy’s limited partner interest in ARP.

In March 2012, Atlas Energy contributed to ARP, a newly-formed exploration and production master limited partnership, substantially all of Atlas Energy’s natural gas and oil development and production assets and its partnership management business, including ownership of the MGP.

On February 17, 2011, Atlas Energy, a then-majority owned subsidiary of Atlas Energy, Inc. and parent of the general partner of APL competed 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 and Tennessee. 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 intends to produce its wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. The Partnership does not expect to drill additional wells and expects no additional funds will be required for drilling.

The accompanying condensed financial statements, which are unaudited except for the balance sheet at December 31, 2013, which 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, 2013. The results of operations for the three and nine months ended September 30, 2014 may not necessarily be indicative of the results of operations for the year ended December 31, 2014.

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, 2013 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, 2014 and 2013 represent actual results in all material respects (see “Revenue Recognition” 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, 2014 and December 31, 2013, 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 (“NGLs”) are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to six million cubic feet (“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 $52,600 and $290,700 for the nine months ended September 30, 2014 and 2013, 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. Upon the sale of an entire interest, a gain or loss is recognized in the statement of operations.

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 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 available additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. There was no oil and gas properties impairment for the three and nine months ended September 30, 2014 or 2013, or during the year ended December 31, 2013.

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 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. 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. During the current quarter, the Partnership identified a material weakness in its revenue recognition process (See Item 4: Controls and Procedures). As a result of the weakness, the Partnership overestimated its June 30, 2014 unbilled revenues by $33,300. As a result, revenue and net income is overstated by $33,300 for the three and six months ended June 30, 2014. In adjusting for the overstatement of revenue and net income that existed at June 30, 2014, during the third quarter of 2014 revenue is understated by $33,300 and net loss is overstated for the three month period ended September 30, 2014. In addition, there was no impact on Partnership distributions. As of September 30, 2014, the weakness has been remediated and the Partnership had unbilled revenues at September 30, 2014 and December 31, 2013 of $88,200 and $135,500, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.

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

In February 2013, the Financial Accounting Standards Board (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 adopted the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it had no material impact on its financial position, results of operations or related disclosures.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide U.S. GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early adoption is permitted. The Partnership will adopt the requirements of Update 2014-15 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles – Goodwill and Other), are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. The Partnership will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2017, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

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

The MGP’s historical practice and continued intention is to retain distributions from the limited partners as the wells within the Partnership near the end of their useful life. On a partnership-by-partnership basis, the MGP assesses its right to withhold amounts related to plugging and abandonment costs based on several factors including commodity price trends, the natural decline in the production of the wells and current and future costs. Generally, the MGP’s intention is to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approaches the fair value of the future plugging and abandonment cost. Upon the MGP’s decision to retain all future distributions to the limited partners of the Partnership, the MGP will assume the related asset retirement obligations of the limited partners. As of September 30, 2014, the MGP withheld $15,800 of net production revenue for future plugging and abandonment costs.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014			2013
Asset retirement obligation at beginning of period	$	2,096,700	$	2,159,100	$	2,036,400		$	2,101,900
Liabilities settled		-		-		(100	)		-
Accretion expense		30,300		28,500		90,700			85,700
Asset retirement obligation at end of period	$	2,127,000	$	2,187,600	$	2,127,000		$	2,187,600

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 sheets of $8,000 and $8,400 at September 30, 2014 and December 31, 2013, 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 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 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 the three and nine months ended September 30, 2014 and 2013:

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 nine months ended September 30, 2014 and 2013 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

At September 30, 2014 and December 31, 2013, remaining hedge monetization cash proceeds of $3,400 and $17,400, respectively, related to the amounts hedged on behalf of the Partnership’s limited partners were included within accounts receivable monetized gains-affiliate. 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, 2014 and December 31, 2013, the put premiums were recorded as short-term payables to affiliate of $6,000 and $6,300, respectively, and long-term payables to affiliate of $8,200 and $12,600, respectively.

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

	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheets			Net Amount of Assets Presented in the Balance Sheets
Offsetting Assets
As of September 30, 2014
Accounts receivable monetized gains-affiliate	$	3,400	$	(3,400	)	$	-
As of December 31, 2013
Accounts receivable monetized gains-affiliate	$	17,400	$	(6,300	)	$	11,100

	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheets		Net Amount of Liabilities Presented in the Balance Sheets
Offsetting Liabilities
As of September 30, 2014
Put premiums payable-affiliate	$	(6,000	)	$	3,400	$	(2,600	)
Long-term put premiums payable-affiliate		(8,200	)		-		(8,200	)
Total	$	(14,200	)	$	3,400	$	(10,800	)
As of December 31, 2013
Put premiums payable-affiliate	$	(6,300	)	$	6,300	$	-
Long-term put premiums payable-affiliate		(12,600	)		-		(12,600	)
Total	$	(18,900	)	$	6,300	$	(12,600	)

As a result of the monetization and the early settlement of natural gas and oil derivative instruments, the put options, and the unrealized losses recognized in earnings in prior periods due to natural gas and oil property impairments, the Partnership recorded a net deferred loss on its balance sheet in accumulated other comprehensive loss of $6,000 as of September 30, 2014. Included in accumulated other comprehensive loss are unrealized gains of $3,200, net of the MGP interest, that were recognized into earnings as a result of oil and gas property impairments during prior periods. During the nine months ended September 30, 2014, $2,100 of net losses were recorded by the Partnership and allocated only to the limited partners. Of the remaining $6,000 of net unrealized loss in accumulated other comprehensive loss, the Partnership will reclassify $3,200 of net losses to the Partnership’s statements of operations over the next twelve month period and the remaining $2,800 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, 2014 and December 31, 2013 is as follows:

	Level 1		Level 2		Level 3		Total
As of September 30, 2014
Derivative assets, gross
Commodity puts	$	-	$	8,000	$	-	$	8,000
Derivative liabilities, gross
Commodity puts		-		-		-		-
Total derivatives, fair value, net	$	-	$	8,000	$	-	$	8,000

	Level 1		Level 2		Level 3		Total
As of December 31, 2013
Derivative assets, gross
Commodity puts	$	-	$	8,400	$	-	$	8,400
Derivative liabilities, gross
Commodity puts		-		-		-		-
Total derivatives, fair value, net	$	-	$	8,400	$	-	$	8,400

The Partnership estimates the fair value of its asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions, and judgments regarding 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 assets or liabilities that were measured at fair value on a nonrecurring basis for the three and nine months ended September 30, 2014 and 2013.

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. Direct costs, which are included in production and general administrative expense in the Partnership’s statement of operations, are payable to the MGP and its affiliates as a reimbursement for all costs expended on the Partnership’s behalf.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Administrative fees	$	22,200	$	22,500	$	64,000	$	67,600
Supervision fees		91,700		92,900		264,000		279,100
Transportation fees		13,200		33,700		78,300		100,400
Direct costs		66,500		81,300		208,700		219,800
Total	$	193,600	$	230,400	$	615,000	$	666,900

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 total outstanding 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, 2014, the MGP withheld $15,800 of net production revenue for future plugging and abandonment 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.

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.

When used in this Form 10-Q, the words “believes”, “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements. Such statements are subject to certain risks and uncertainties, which 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 (A) 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 the “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP).

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

We intend to continue to produce our wells 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, 2014, our MGP withheld $15,800 of net production revenue 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 2014 and 2013, 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,
	2014			2013			2014			2013
Production revenues (in thousands):
Gas	$	109		$	257		$	625		$	747
Oil		27			34			75			74
Liquids		4			3			15			6
Total	$	140		$	294		$	715		$	827
Production volumes:
Gas (mcf/day)⁽¹⁾		598			736			591			705
Oil (bbl/day) ⁽¹⁾		3			4			3			3
Liquids (bbl/day) ⁽¹⁾		1			1			1			1
Total (mcfe/day)⁽¹⁾		622			766			615			729
Average sales prices: ⁽²⁾
Gas (per mcf) ^{(1) (3)}⁽⁴⁾	$	2.66		$	4.03		$	3.94		$	4.17
Oil (per bbl) ⁽¹⁾	$	94.62		$	96.48		$	95.11		$	93.23
Liquids (per bbl) ⁽¹⁾	$	51.81		$	52.01		$	53.14		$	56.26
Production costs:
As a percent of revenues ⁽⁴⁾		92	%		65	%		72	%		66	%
Per mcfe ⁽¹⁾	$	2.78		$	2.71		$	3.08		$	2.78
Depletion per mcfe	$	0.31		$	1.49		$	0.31		$	1.47

Natural Gas Revenues. During the current year quarter, management identified a material weakness in the process used to estimate our unbilled revenue (See Item 4: Controls and Procedures). As a result, natural gas revenue for the three months ending September 30, 2014 includes an adjustment to reduce natural gas revenue by $33,300. The adjustment is the result of overestimating our unbilled revenues as of June 30, 2014. Our unadjusted natural gas revenues were $142,400 and $256,700 for the three months ended September 30, 2014 and 2013, respectively, a decrease of $114,300 (45%). The $114,300 decrease in natural gas revenues for the three months ended September 30, 2014 as compared to the prior year similar period was attributable to a $66,100 decrease in our natural gas sales prices after the effect of financial hedges, which was driven by market conditions and a $48,200 decrease in production volumes. Our production volumes decreased to 598 mcf per day for the three months ended September 30, 2014 from 736 mcf per day for the three months ended September 30, 2013, a decrease of 138 mcf per day (19%). The overall decrease in natural gas production volumes for the three months ended September 30, 2014 as compared to the prior year similar period resulted primarily from the normal decline inherent in the life of a well.

Our natural gas revenues were $625,300 and $747,000 for the nine months ended September 30, 2014 and 2013, respectively, a decrease of $121,700 (16%). The $121,700 decrease in natural gas revenues for the nine months ended September 30, 2014 as compared to the prior year similar period was attributable to a $120,900 decrease in production volumes and an $800 decrease in our natural gas sales prices after the effect of financial hedges, which was driven by market conditions. Our production volumes decreased to 591 mcf per day for the nine months ended September 30, 2014 from 705 mcf per day for the nine months ended September 30, 2013, a decrease of 114 mcf per day (16%). The overall decrease in natural gas production volumes for the nine months ended September 30, 2014 as compared to the prior year similar period 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 $27,100 and $34,300 for the three months ended September 30, 2014 and 2013, respectively, a decrease of $7,200 (21%). The $7,200 decrease in oil revenues for the three months ended September 30, 2014 as compared to the prior year similar period was attributable to a $6,700 decrease in production volumes and a $500 decrease in oil prices after the effect of financial hedges. Our production volumes decreased to 3 bbls per day for the three months ended September 30, 2014 from 4 bbls per day for the three months ended September 30, 2013, a decrease of 1 bbls per day (25%).

Our oil revenues were $75,200 and $73,600 for the nine months ended September 30, 2014 and 2013, respectively, an increase of $1,600 (2%). The $1,600 increase in oil revenues for the nine months ended September 30, 2014 as compared to the prior year similar period was attributable to a $1,500 increase in oil prices after the effect of financial hedges and a $100 increase in production volumes. Our production volumes increased to 2.90 bbls per day for the nine months ended September 30, 2014 from 2.89 bbls per day for the nine months ended September 30, 2013, an increase of .01 bbls per day (.35%).

Natural Gas Liquids Revenue. The majority of our wells produce “dry gas”, which is composed primarily of methane and requires no additional processing before being transported and sold to the purchaser. Some wells, however, produce “wet gas”, which contains larger amounts of ethane and other associated hydrocarbons (i.e. “natural gas liquids”) that must be removed prior to transporting the gas. Once removed, these natural gas liquids are sold to various purchasers. Our natural gas liquids revenues were $3,900 and $2,600 for the three months ended September 30, 2014 and 2013, respectively, an increase of $1,300 (50%). The $1,300 increase in liquid revenues for the three months ended September 30, 2014 as compared to the prior year similar period was attributed to a $1,300 increase in production volumes. Our production volumes increased to .81 bbls per day for the three months ended September 30, 2014 from .55 bbls per day for the three months ended September 30, 2013 an increase of .26 bbls per day (47%).

Our natural gas liquids revenues were $14,900 and $6,600 for the nine months ended September 30, 2014 and 2013, respectively, an increase of $8,300 (126%). The $8,300 increase in natural gas liquids revenues for the nine months ended September 30, 2014 as compared to the prior year similar period was attributable to a $9,200 increase in production volumes partially offset by a $900 decrease in natural gas liquid prices. Our production volumes increased to 1.03 bbls per day for the nine months ended September 30, 2014 from .43 bbls per day for the nine months ended September 30, 2013 an increase of .60 bbls per day (140%).

Costs and Expenses. Production expenses were $158,600 and $190,100 for the three months ended September 30, 2014 and 2013, respectively, a decrease of $31,500 (17%). Production expenses were $516,300 and $550,100 for the nine months ended September 30, 2014 and 2013, respectively, a decrease of $33,800 (6%). The decrease for the three and nine months ended September 30, 2014 was mostly due to a decrease in transportation and well supervision fees.

Depletion of oil and gas properties as a percentage of oil and gas revenues was 12% and 36% for the three months ended September 30, 2014 and 2013, respectively, and 7% and 35% for the nine months ended September 30, 2014 and 2013, respectively. These changes are primarily attributable to changes in oil and gas reserve quantities and to a lesser extent revenues, 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, 2014 and 2013, were $35,000 and $40,300, respectively, a decrease of $5,300 (13%). For the nine months ended September 30, 2014 and 2013, these expenses were $98,700 and $116,800, respectively, a decrease of $18,100 (15%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP. The changes for the three and nine months ended September 30, 2014 are primarily due to third-party costs as compared to the prior year similar period.

Cash provided by operating activities decreased $112,800 in the nine months ended September 30, 2014 to $146,500 as compared to $259,300 for the nine months ended September 30, 2013. This decrease was primarily due to a decrease in net income before depletion, accretion and a net non-cash loss in derivatives of $103,800, a decrease in the change in accrued liabilities of $11,900, a decrease in the change in asset retirement receivable-affiliate of $15,800, a decrease in the change in asset retirement obligations settled of $100 and a decrease in the change in limited partner payable of $120,400, partially offset by an increase in the change in accounts receivable-affiliate of $139,200 for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013.

Cash provided by investing activities was $1,100 for the nine months ended September 30, 2014 due to the sale of tangible equipment.

Cash used in financing activities decreased $85,100 during the nine months ended September 30, 2014 to $177,200 from $262,300 for the nine months ended September 30, 2013. This decrease was due to a decrease in cash distributions to partners.

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 at any one time 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 is based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. On an on-going basis, we evaluate our estimates, including those related to our asset retirement obligations, depletion and certain accrued receivables and liabilities. We base our estimates on historical experience and on various other assumptions that we believe reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. A discussion of 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, 2013.

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 on that evaluation, our Chief Executive Officer, President and Chief Financial Officer concluded that, as of September 30, 2014, our disclosure controls and procedures were effective at the reasonable assurance level.

During the current period, but before the June 30, 2014 Form 10-Q was filed, management identified a deficiency in our disclosure controls and procedures. Language indicating management’s conclusion on the Company’s internal control over financial reporting as of December 31, 2013 was not included in Management’s Report on Internal Control over Financial Reporting within Form 10-K, Item 9A. “Controls and Procedures.” As a result of the amendment required to our December 31, 2013 Form 10-K, our Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer concluded that, as of June 30, 2014, our disclosure controls and procedures were not effective at the reasonable assurance level.

As of the date of filing of this Form 10-Q, management has implemented a more formal and thorough review of its disclosures in Form 10-K, Item 9A and Form 10-Q, Item 4: Controls and Procedures. As of the date of filing of this Form 10-Q, management believes the deficiency in the Partnership’s disclosure controls and procedures has been remediated.

During the current quarter, management identified a material weakness in the process used to estimate the June 30, 2014 unbilled revenue. The weakness resulted from an insufficient review of contract pricing information used to estimate unbilled revenue. As a result, a change in a pricing index of a marketing contract was not properly reflected in the estimate of unbilled revenues. At June 30, 2014, the Partnership overestimated its unbilled revenues by $33,300 and the adjustment had no impact on cash distributions.

As of the date of filing this Form 10-Q, management has implemented a more formal and thorough review of its pricing inputs used to calculate the estimated unbilled revenue. As of the date of filing of this Form 10-Q, management believes the deficiency in the Partnership’s internal control over financial reporting has been remediated.

Other than as previously discussed, 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.

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		55-0856393
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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

		PAGE
PART I.	FINANCIAL INFORMATION (Unaudited)

Item 1:

	Condensed Balance Sheets as of September 30, 2014 and December 31, 2013	3

	Condensed Statements of Operations for the Three and Nine Months ended September 30, 2014 and 2013	4

	Condensed Statements of Comprehensive Loss for the Three and Nine Months ended September 30, 2014 and 2013	5

	Condensed Statement of Changes in Partners’ Capital for the Nine Months ended September 30, 2014	6

	Condensed Statements of Cash Flows for the Nine Months ended September 30, 2014 and 2013	7

	Notes to Condensed Financial Statements	8

Item 2:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19

Item 4:	Controls and Procedures	22

PART II.	OTHER INFORMATION

Item 1:	Legal Proceedings	23

Item 6:	Exhibits	24

SIGNATURES		25

CERTIFICATIONS

	September 30, 2014			December 31, 2013
Proved properties:
Leasehold interests	$	716,500		$	716,500
Wells and related equipment		34,932,100			34,933,200
Total natural gas and oil properties		35,648,600			35,649,700
Accumulated depletion and impairment		(33,270,300	)		(33,217,700	)
Oil and gas properties, net	$	2,378,300		$	2,432,000

Production Period Ending December 31,	Volumes	Average Fixed Price		Fair Value Asset ⁽²⁾
	(MMBtu) ⁽¹⁾	(per MMBtu) ⁽¹⁾
2014	2,800	$	3.80	$	100
2015	8,800		4.00		3,400
2016	8,800		4.15		4,500
				$	8,000

Exhibit No.		Description

3.1		Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Series 25-2004 (A) L.P. ⁽¹⁾
3.2		Agreement of Limited Partnership ⁽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

Large accelerated filer	¨	Accelerated filer	¨

Non-accelerated filer	¨	Smaller reporting company	þ

	ATLAS RESOURCES, LLC, Managing General Partner

Date: November 14, 2014	By:	/s/ FREDDIE M. KOTEK
		Freddie M. Kotek, Chairman of the Board of Directors, Chief Executive Officer and President

Date: November 14, 2014			By:		/s/ SEAN P. MCGRATH
					Sean P. McGrath, Chief Financial Officer