ser25a-10q_20150630.htm

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

	June 30,			December 31,
	2015			2014
ASSETS
Current assets:
Cash and cash equivalents	$	-		$	3,800
Accounts receivable trade–affiliate		40,500			93,400
Asset retirement receivable–affiliate		101,800			18,500
Current portion of derivative assets		9,200			8,800
Total current assets		151,500			124,500
Gas and oil properties, net		1,764,700			1,798,900
Long-term derivative assets		4,400			7,400
	$	1,920,600		$	1,930,800
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable trade-affiliate	$	166,400		$	-
Accrued liabilities		6,700			11,200
Current portion of put premiums payable-affiliate		6,100			5,600
Total current liabilities		179,200			16,800
Long-term put premiums payable-affiliate		3,200			6,500
Asset retirement obligations		3,218,000			3,128,500
Commitments and contingencies
Partners’ capital:
Managing general partner’s interest		(226,000	)		(131,900	)
Limited partners’ interest (1,106.76 units)		(1,256,100	)		(1,093,200	)
Accumulated other comprehensive income		2,300			4,100
Total partners’ capital		(1,479,800	)		(1,221,000	)
	$	1,920,600		$	1,930,800

	Three Months Ended June 30,					Six Months Ended June 30,
	2015			2014		2015			2014
REVENUES
Natural gas, oil and liquids	$	66,000		$	315,700	$	187,800		$	575,300
(Loss) gain on mark-to-market derivatives		(2,400	)		-		200			-
Total revenues		63,600			315,700		188,000			575,300
COSTS AND EXPENSES
Production		114,200			195,400		253,000			357,700
Depletion		16,000			19,400		34,200			35,100
Accretion of asset retirement obligation		44,800			30,200		89,500			60,400
General and administrative		31,200			28,700		66,400			63,700
Total costs and expenses		206,200			273,700		443,100			516,900
Net (loss) income	$	(142,600	)	$	42,000	$	(255,100	)	$	58,400
Allocation of net (loss) income:
Managing general partner	$	(51,500	)	$	15,500	$	(94,100	)	$	22,100
Limited partners	$	(91,100	)	$	26,500	$	(161,000	)	$	36,300
Net (loss) income per limited partnership unit	$	(82	)	$	24	$	(145	)	$	33

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Net (loss) income	$	(142,600	)	$	42,000		$	(255,100	)	$	58,400
Other comprehensive (loss) income:
Unrealized holding gain (loss) on cash flow hedging contracts		-			700			-			(9,700	)
Difference in estimated hedge gains receivable		1,100			(1,900	)		2,400			15,200
Reclassification adjustment for realized (gains) losses of cash flow hedges in net (loss) income		(2,000	)		700			(4,200	)		(6,800	)
Total other comprehensive loss		(900	)		(500	)		(1,800	)		(1,300	)
Comprehensive (loss) income	$	(143,500	)	$	41,500		$	(256,900	)	$	57,100

							Accumulated
	Managing						Other
	General			Limited			Comprehensive
	Partner			Partners			Income (Loss)			Total
Balance at December 31, 2014	$	(131,900	)	$	(1,093,200	)	$	4,100		$	(1,221,000	)
Participation in revenues, costs and expenses:
Net production expenses		(24,200	)		(41,000	)		-			(65,200	)
Gain on mark-to-market derivatives		-			200			-			200
Depletion		(15,400	)		(18,800	)		-			(34,200	)
Accretion of asset retirement obligation		(31,300	)		(58,200	)		-			(89,500	)
General and administrative		(23,200	)		(43,200	)		-			(66,400	)
Net loss		(94,100	)		(161,000	)		-			(255,100	)
Other comprehensive loss		-			-			(1,800	)		(1,800	)
Distributions to partners		-			(1,900	)		-			(1,900	)
Balance at June 30, 2015	$	(226,000	)	$	(1,256,100	)	$	2,300		$	(1,479,800	)

	Six Months Ended June 30,
	2015			2014
Cash flows from operating activities:
Net (loss) income	$	(255,100	)	$	58,400
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depletion		34,200			35,100
Non cash (gain) loss on derivative value		(2,000	)		7,200
Accretion of asset retirement obligation		89,500			60,400
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable-trade affiliate		52,900			(58,900	)
Increase in asset retirement receivable-affiliate		(83,300	)		(6,700	)
Increase in accounts payable trade-affiliate		166,400			-
Decrease in accrued liabilities		(4,500	)		(2,600	)
Decrease in payable to limited partners		-			(11,600	)
Asset retirement obligation settled		-			(100	)
Net cash (used in) provided by operating activities		(1,900	)		81,200
Cash flows from financing activities:
Distributions to partners		(1,900	)		(118,200	)
Net cash used in financing activities		(1,900	)		(118,200	)
Net decrease in cash and cash equivalents		(3,800	)		(37,000	)
Cash and cash equivalents at beginning of period		3,800			63,600
Cash and cash equivalents at end of period	$	-		$	26,600

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 February 27, 2015, the MGP’s ultimate parent, Atlas Energy, L.P. (“Atlas Energy”), which was a publicly traded master-limited partnership, was acquired by Targa Resources Corp. and distributed to Atlas Energy’s unitholders 100% of the limited liability company interests in ARP’s general partner, Atlas Energy Group, LLC (“Atlas Energy Group”; NYSE: ATLS). Atlas Energy Group became a separate, publicly traded company and the ultimate parent of the MGP as a result of the distribution. Following the distribution, Atlas Energy Group continues to manage ARP’s operations and activities through its ownership of ARP’s general partner interest.

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 Group (February 27, 2015 and prior, 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, 2014, 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, 2014. The results of operations for the three and six months ended June 30, 2015 may not necessarily be indicative of the results of operations for the year ended December 31, 2015.

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, 2014 filed with the Securities and Exchange Commission (“SEC”).

The preparation of the Partnership’s 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, 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 many 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 six months ended June 30, 2015 and 2014 represent actual results in all material respects (See “-Revenue Recognition”).

Accounts receivable on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of the Partnership’s accounts receivable, 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 June 30, 2015 and December 31, 2014, the MGP’s credit evaluation indicated that the Partnership had no need for an allowance for uncollectible accounts receivable.

Gas and oil properties are stated at cost. Maintenance and repairs which 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 gas and oil producing activities. Oil and natural gas liquids (“NGLs”) are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to six Mcf of natural gas. Mcf is defined as one thousand cubic feet.

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 $34,200 and $35,100 for the six months ended June 30, 2015 and 2014, respectively.

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

	June 30,			December 31,
	2015			2014
Proved properties:
Leasehold interests	$	716,500		$	716,500
Wells and related equipment		35,903,400			35,903,400
Total natural gas and oil properties		36,619,900			36,619,900
Accumulated depletion and impairment		(34,855,200	)		(34,821,000	)
Gas and oil properties, net	$	1,764,700		$	1,798,900

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 gas and oil properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion and impairment is less than the estimated expected undiscounted future cash flows including salvage. 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 natural gas and oil reserve estimates is a subjective process and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.

In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods.

There was no gas and oil properties impairment recorded for the three and six months ended June 30, 2015 and 2014. During the year ended December 31, 2014, the Partnership recognized an impairment charge of $1,460,100. This impairment relates to the carrying amount of these gas and oil properties being in excess of the Partnership’s estimate of their fair value at December 31, 2014. The estimate of the fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil prices at the date of measurement.

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, crude oil and NGLs at prevailing market prices. Typically, 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, crude oil and NGLs, in which the Partnership has an interest with other producers are recognized on the basis of its percentage ownership of the 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, NGLs, 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 (See “-Use of Estimates”). The Partnership had unbilled revenues at June 30, 2015 and December 31, 2014 of $40,500 and $90,100, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.

Comprehensive (loss) income includes net (loss) income and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net (loss) income. These changes, other than net (loss) income, are referred to as “other comprehensive loss” on the Partnership’s financial statements and, at June 30, 2015, only include changes in the fair value of unsettled derivative contracts which, prior to January 1, 2015, were accounted for as cash flow hedges (See Note 4). The Partnership does not have any other type of transaction which would be included within other comprehensive loss.

In January 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items (“Update 2015-01”). The amendments in Update 2015-01 simplify the income statement presentation requirements in Subtopic 225-20 by eliminating the concept of extraordinary items. Extraordinary items are events and transactions that are distinguished by their unusual nature and by the infrequency of their occurrence. The amendments in Update 2015-01 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A reporting entity may apply the amendments prospectively. A reporting entity may also apply the amendments retrospectively to all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. The Partnership will adopt the requirements of Update 2015-01 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 and 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 and interim periods thereafter. Early adoption is permitted. The Partnership will adopt the requirements of Update 2014-15 upon its effective date in 2016, and it does not anticipate it having a material impact on its financial position, results of operations and 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. On July 9, 2015, the FASB decided to defer the effective date of ASU 2014-09 by one year. As a result, public entities would apply the new revenue standard to annual reporting periods beginning after December 15, 2017, and to interim periods within that reporting period, with the option to adopt the standard as of the original effective date. The Partnership will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2018, and is evaluating the impact of the adoption on its financial position, results of operations and related disclosures.

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

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

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 June 30, 2015, the MGP has withheld $101,800 of net production revenue for future plugging and abandonment costs.

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

	Three Months Ended June 30,					Six Months Ended June 30,
	2015		2014			2015		2014
Asset retirement obligation at beginning of period	$	3,173,200	$	2,066,600		$	3,128,500	$	2,036,400
Asset retirement obligations settled		-		(100	)		-		(100	)
Accretion expense		44,800		30,200			89,500		60,400
Asset retirement obligation at end of period	$	3,218,000	$	2,096,700		$	3,218,000	$	2,096,700

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. To manage the risk of regional commodity price differences, the Partnership occasionally enters into basis swaps. Basis swaps are contractual arrangements that guarantee a price differential for a commodity from a specified delivery point price and the comparable national exchange price. For natural gas basis swaps, which have negative differentials to New York Mercantile Exchange (“NYMEX”), the Partnership receives or pays a payment from the counterparty if the price differential to NYMEX is greater or less than the stated terms of the contract. 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.

On January 1, 2015, the Partnership discontinued hedge accounting for its qualified commodity derivatives. As such, changes in fair value of these derivatives after December 31, 2014 are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations. The fair values of these commodity derivative instruments at December 31, 2014, which were recognized in accumulated other comprehensive income within partners’ capital on the Partnership’s balance sheet, will be reclassified to the Partnership’s statements of operations in the future at the time the originally hedged physical transactions affect earnings.

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 $13,600 and $16,200 at June 30, 2015 and December 31, 2014, respectively.

The following table summarizes the gains or losses recognized within the statements of operations for derivative instruments previously designated as cash flow hedges for the periods indicated:

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 been recorded at their fair values.

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

2015		4,200	$	4.00	$	4,700
2016		8,400		4.15		8,900
					$	13,600

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 six months ended June 30, 2015 and 2014 for hedge ineffectiveness.

During June 2012, 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 June 30, 2015 and December 31, 2014, $6,100 and $5,600, respectively, of the put premiums were recorded as short-term payables to affiliate, and $3,200 and $6,500, respectively, were recorded as long-term payables to affiliate.

As a result of the put options, the Partnership recorded a net deferred gain on its balance sheet in accumulated other comprehensive income of $2,300 as of June 30, 2015. During the six months ended June 30, 2015, $3,900 of net gains were recorded by the Partnership and allocated only to the limited partners. Of the remaining $2,300 of net unrealized gain in accumulated other comprehensive income, the Partnership will reclassify $1,900 of net gains to the Partnership’s statements of operations over the next twelve month period and the remaining $400 of gains 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. The fair values of 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 the pricing formula utilized in the derivative instrument.

Information for assets measured at fair value at June 30, 2015 and December 31, 2014 was as follows:

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 additional assets or liabilities that were measured at fair value on a nonrecurring basis for the three and six months ended June 30, 2015 and 2014.

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 statements of operations, are payable at $313 per well per month for operating and maintaining the wells. Well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of the working interest in a well. Transportation fees are included in production expense in the Partnership’s statements of operations and are generally payable at 13% of the natural gas sales price. Direct costs, which are included in production and general administrative expenses in the Partnership’s statements of operations, are payable to the MGP and its affiliates as 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 June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Administrative fees	$	16,900	$	21,100	$	38,100	$	41,800
Supervision fees		69,400		86,900		156,900		172,300
Transportation fees		7,400		33,800		21,200		65,100
Direct costs		51,700		82,300		103,200		142,200
Total	$	145,400	$	224,100	$	319,400	$	421,400

The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts payable trade affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP as of June 30, 2015. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due to the MGP as of December 31, 2014.

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 June 30, 2015, the MGP has withheld $101,800 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 respective businesses. 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 Group (February 27, 2015 and prior, 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 June 30, 2015, our MGP has withheld $101,800 of net production revenues 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 gas and oil 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 the first six months of 2015, we experienced no problems in selling our natural gas and oil. Product availability and price are the principal means of competing 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 June 30,						Six Months Ended June 30,
	20145			2014			2015			2014
Production revenues (in thousands):
Gas	$	61		$	273		$	170		$	516
Oil		5			35			17			48
Liquids		-			8			1			11
Total	$	66		$	316		$	188		$	575
Production volumes:
Gas (Mcf/day)⁽¹⁾		458			650			484			587
Oil (bbl/day) ⁽¹⁾		1			4			2			3
Liquids (bbl/day) ⁽¹⁾		-			2			-			1
Total (Mcfe/day)⁽¹⁾		464			686			496			611
Average sales prices: ⁽²⁾
Gas (per Mcf) ^{(1) (3)}	$	1.48		$	4.68		$	1.95		$	4.92
Oil (per bbl) ⁽¹⁾	$	56.26		$	97.91		$	47.45		$	95.40
Liquids (per bbl) ⁽¹⁾	$	24.70		$	54.03		$	26.92		$	53.62
Production costs:
As a percent of revenues		173	%		62	%		135	%		62	%
Per Mcfe ⁽¹⁾	$	2.78		$	3.14		$	2.82		$	3.23
Depletion per Mcfe	$	0.38		$	0.31		$	0.38		$	0.32

Natural Gas Revenues. Our natural gas revenues were $61,800 and $273,000 for the three months ended June 30, 2015 and 2014, respectively, a decrease of $211,200 (77%). The $211,200 decrease in natural gas revenues for the three months ended June 30, 2015 as compared to the prior year similar period was attributable to a $130,800 decrease in our natural gas sales prices after the effect of financial hedges, which was driven by market conditions, and an $80,400 decrease in production volumes. Our production volumes decreased to 458 Mcf per day for the three months ended June 30, 2015 from 650 Mcf per day for the three months ended June 30, 2014, a decrease of 192 Mcf per day (30%). The overall decrease in natural gas production volumes for the three months ended June 30, 2015 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 due to wells shut-in due to a decline in natural gas prices.

Our natural gas revenues were $170,300 and $516,200 for the six months ended June 30, 2015 and 2014, respectively, a decrease of $345,900 (67%). The $345,900 decrease in natural gas revenues for the six months ended June 30, 2015 as compared to the prior year similar period was attributable to a $254,800 decrease in our natural gas sales prices after the effect of financial hedges, which was driven by market conditions, and a $91,100 decrease in production volumes. Our production volumes decreased to 484 Mcf per day for the six months ended June 30, 2015 from 587 Mcf per day for the six months ended June 30, 2014, a decrease of 103 Mcf per day (18%). The overall decrease in natural gas production volumes for the six months ended June 30, 2015 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 due to wells shut-in due to a decline in natural gas prices.

Oil Revenues. We drill wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $4,100 and $35,200 for the three months ended June 30, 2015 and 2014, respectively, a decrease of $31,100 (88%). The $31,100 decrease in oil revenues for the three months ended June 30, 2015 as compared to the prior year similar period was attributable to a $28,100 decrease in production volumes and a $3,000 decrease in oil prices. Our production volumes decreased to 1 bbl per day for the three months ended June 30, 2015 from 4 bbls per day for the three months ended June 30, 2014, a decrease of 3 bbls per day (75%).

Our oil revenues were $16,800 and $48,100 for the six months ended June 30, 2015 and 2014, respectively, a decrease of $31,300 (65%). The $31,300 decrease in oil revenues for the six months ended June 30, 2015 as compared to the prior year similar period was attributable to a $17,000 decrease in oil prices and a $14,300 decrease in production volumes. Our production volumes decreased to 1.95 bbls per day for the six months ended June 30, 2015 from 2.79 bbls per day for the six months ended June 30, 2014, a decrease of 0.84 bbls per day (30%).

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 $100 and $7,500 for the three months ended June 30, 2015 and 2014, respectively, a decrease of $7,400 (99%). The $7,400 decrease in liquid revenues for the three months ended June 30, 2015 as compared to the prior year similar period was attributed to a $7,300 decrease in production volumes and a $100 decrease in natural gas liquid prices. Our production volumes decreased to 0.04 bbls per day for the three months ended June 30, 2015 from 1.53 bbls per day for the three months ended June 30, 2014 a decrease of 1.49 bbls per day (97%).

Our natural gas liquids revenues were $700 and $11,000 for the six months ended June 30, 2015 and 2014, respectively, a decrease of $10,300 (94%). The $10,300 decrease in natural gas liquids revenues for the six months ended June 30, 2015 as compared to the prior year similar period was attributable to a $9,800 decrease in production volumes and a $500 decrease in natural gas liquid prices. Our production volumes decreased to 0.13 bbls per day for the six months ended June 30, 2015 from 1.14 bbls per day for the six months ended June 30, 2014 a decrease of 1.01 bbls per day (89%).

Costs and Expenses. Production expenses were $114,200 and $195,400 for the three months ended June 30, 2015 and 2014, respectively, a decrease of $81,200 (42%). Production expenses were $253,000 and $357,700 for the six months ended June 30, 2015 and 2014, respectively, a decrease of $104,700 (29%). The decrease for the three months ended June 30, 2015 was due to a decrease in transportation fees. The decrease for the six months ended June 30, 2015 was due to a decrease in transportation and supervision fees. The transportation fees were affected by a decrease in natural gas prices.

Depletion of oil and gas properties as a percentage of oil and gas revenues was 24% and 6% for the three months ended June 30, 2015 and 2014, respectively, and 18% and 6% for the six months ended June 30, 2015 and 2014, 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 June 30, 2015 and 2014 were $31,200 and $28,700, respectively, an increase of $2,500 (8%). For the six months ended June 30, 2015 and 2014 these expenses were $66,400 and $63,700, respectively, an increase of $2,700 (4%). 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 six months ended June 30, 2015 are primarily due to third-party costs as compared to the prior year similar period.

Cash (used in) provided by operating activities decreased $83,100 in the six months ended June 30, 2015 to ($1,900) as compared to $81,200 for the six months ended June 30, 2014. This decrease was mostly due to a decrease in net (loss) income before depletion, accretion and a net non-cash (gain) loss in derivatives of $294,500, a decrease in the change in asset retirement receivable-affiliate of $76,600, and a decrease in the change in accrued liabilities of $1,900. The decrease was partially offset by an increase in accounts payable trade-affiliate of $166,400 and an increase in accounts receivable trade-affiliate of $111,800. In addition, an increase resulted from the change in limited partner payable of $11,600 and the change in asset retirement obligations settled of $100 for the six months ended June 30, 2015 compared to the six months ended June 30, 2014.

Cash used in financing activities decreased $116,300 during the six months ended June 30, 2015 to $1,900 from $118,200 for the six months ended June 30, 2014. This decrease was due to a decrease in cash distributions to partners.

Our MGP may withhold funds for future plugging and abandonment costs. Through June 30, 2015, our MGP has withheld $101,800 of funds for this purpose. 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.

We are 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 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, 2014.

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 general partner’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our general partner’s Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, 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 general partner’s Chief Executive Officer and Chief Financial Officer concluded that, as of June 30, 2015, 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.

Pursuant to the requirements of the Securities of the Exchange Act of 1934, this report has been signed below by the following person 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 June 30, 2015 and December 31, 2014	3

	Condensed Statements of Operations for the Three and Six Months ended June 30, 2015 and 2014	4

	Condensed Statements of Comprehensive (Loss) Income for the Three and Six Months ended June 30, 2015 and 2014	5

	Condensed Statement of Changes in Partners’ Capital for the Six Months ended June 30, 2015	6

	Condensed Statements of Cash Flows for the Six Months ended June 30, 2015 and 2014	7

	Notes to Condensed Financial Statements	8

Item 2:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16

Item 4:	Controls and Procedures	19

PART II.	OTHER INFORMATION

Item 1:	Legal Proceedings	20

Item 6:	Exhibits	21

SIGNATURES		22

CERTIFICATIONS

Exhibit No.		Description

4(a)		Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Series 25-2004 (A) ⁽¹⁾
10.1		Drilling and Operating Agreement for Atlas America Series 25-2004 (A) L.P. ⁽¹⁾
31.1		Rule 13a-14/15(d)-14 (a) Certification
31.2		Rule 13a-14/15(d)-14 (a) Certification
32.1		Section 1350 Certification
32.2		Section 1350 Certification
101		Interactive Data File


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


	By:		ATLAS RESOURCES, LLC, ITS
			GENERAL PARTNER

Date: August 14, 2015	By:		/s/ FREDDIE M. KOTEK
			Freddie M. Kotek, Chairman of the Board of Directors and Chief Executive Officer (principal executive officer)

Date: August 14, 2015		By:	/s/ SEAN P. MCGRATH
			Sean P. McGrath, Chief Financial Officer (principal financial officer and principal accounting officer)

Large accelerated filer	¨	Accelerated filer	¨

Non-accelerated filer	¨	Smaller reporting company	þ

	Level 1		Level 2		Level 3		Total
As of June 30, 2015
Derivative assets, gross
Commodity puts	$	-	$	13,600	$	-	$	13,600