10-Q

United States

Securities and Exchange Commission

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2016

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

For the transition period from to

Commission file number 000-51271

ATLAS AMERICA SERIES 25-2004 (B) L.P.

(Name of small business issuer in its charter)

Delaware	34-1980376
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
Park Place Corporate Center One 1000 Commerce Drive, 4th Floor Pittsburgh, PA	15275
(Address of principal executive offices)	(zip code)

Issuer’s telephone number, including area code:(412)-489-0006

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):

Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	¨	Smaller reporting company	þ

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

ATLAS AMERICA SERIES 25-2004 (B) L.P.

(A Delaware Limited Partnership)

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

		PAGE
PART I.	FINANCIAL INFORMATION (Unaudited)
Item 1:
	Condensed Balance Sheets as of June 30, 2016 and December 31, 2015	3
	Condensed Statements of Operations for the Three and Six Months ended June 30, 2016 and 2015	4
	Condensed Statements of Comprehensive Loss for the Three and Six Months ended June 30, 2016 and 2015	5
	Condensed Statement of Changes in Partners’ Deficit for the Six Months ended June 30, 2016	6
	Condensed Statements of Cash Flows for the Six Months ended June 30, 2016 and 2015	7
	Notes to Condensed Financial Statements	8
Item 2:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13
Item 4:	Controls and Procedures	17
PART II.	OTHER INFORMATION
Item 1:	Legal Proceedings	17
Item 6:	Exhibits	18
SIGNATURES		19
CERTIFICATIONS

2

ATLAS AMERICA SERIES 25-2004 (B) L.P.

CONDENSED BALANCE SHEETS

(Unaudited)

	June 30,		December 31,
	2016		2015
ASSETS
Current assets:
Cash	$	-	$	-
Accounts receivable trade–affiliate		42,300		44,200
Current portion of derivative assets		6,300		19,000
Total current assets		48,600		63,200
Gas and oil properties, net		1,326,900		1,326,900
Long-term asset retirement receivable-affiliate		525,100		322,300
Total assets	$	1,900,600	$	1,712,400
LIABILITIES AND PARTNERS’ DEFICIT
Current liabilities:
Accounts payable trade-affiliate	$	912,600	$	550,200
Accrued liabilities		9,600		8,600
Put premiums payable-affiliate		4,300		8,800
Total current liabilities		926,500		567,600
Asset retirement obligations		3,859,600		3,803,400
Commitments and contingencies (Note 6)
Partners’ deficit:
Managing general partner’s deficit		(539,600)		(460,800	)
Limited partners’ deficit (1,265.38 units)		(2,346,200)		(2,198,600	)
Accumulated other comprehensive income		300		800
Total partners’ deficit		(2,885,500)		(2,658,600	)
Total liabilities and partners’ deficit	$	1,900,600	$	1,712,400

See accompanying notes to condensed financial statements.

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ATLAS AMERICA SERIES 25-2004 (B) L.P.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2016		2015		2016		2015
REVENUES
Natural gas, oil and liquids	$	74,400	$	71,600	$	132,700	$	204,100
(Loss) gain on mark-to-market derivatives		(3,700)		(2,100)		(800)		200
Total revenues		70,700		69,500		131,900		204,300
COSTS AND EXPENSES
Production		131,600		121,800		234,700		266,200
Depletion		-		20,900		-		44,100
Accretion of asset retirement obligations		28,100		51,500		56,200		102,900
General and administrative		37,100		33,200		67,400		69,200
Total costs and expenses		196,800		227,400		358,300		482,400
Net loss	$	(126,100)	$	(157,900)	$	(226,400)	$	(278,100)
Allocation of net loss:
Managing general partner	$	(42,800)	$	(57,000)	$	(78,800)	$	(102,300)
Limited partners	$	(83,300)	$	(100,900)	$	(147,600)	$	(175,800)
Net loss per limited partnership unit	$	(66)	$	(80)	$	(117)	$	(139)

See accompanying notes to condensed financial statements.

4

ATLAS AMERICA SERIES 25-2004 (B) L.P.

CONDENSED STATEMENTS OF COMPREHENSIVE LOSS

(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2016		2015		2016		2015
Net loss	$	(126,100)	$	(157,900)	$	(226,400)	$	(278,100)
Other comprehensive loss:
Difference in estimated hedge receivable		-		1,100		-		2,400
Reclassification adjustment to net loss of mark-to-market gains on cash flow hedges		(300)		(1,900)		(500)		(4,000)
Total other comprehensive loss		(300)		(800)		(500)		(1,600)
Comprehensive loss	$	(126,400)	$	(158,700)	$	(226,900)	$	(279,700)

See accompanying notes to condensed financial statements.

5

ATLAS AMERICA SERIES 25-2004 (B) L.P.

CONDENSED STATEMENT OF CHANGES IN PARTNERS’ DEFICIT

FOR THE SIX MONTHS ENDED

June 30, 2016

(Unaudited)

	Managing						Accumulated Other
	General			Limited			Comprehensive
	Partner			Partners			Income (Loss)		Total
Balance at December 31, 2015	$	(460,800	)	$	(2,198,600	)	$	800	$	(2,658,600)
Participation in revenues, costs and expenses:
Net production expenses		(35,500)			(66,500)			-		(102,000)
Gain on mark-to-market derivatives		-			(800)			-		(800)
Accretion of asset retirement obligations		(19,700)			(36,500)			-		(56,200)
General and administrative		(23,600)			(43,800)			-		(67,400)
Net loss		(78,800)			(147,600)			-		(226,400)
Other comprehensive loss		-			-			(500)		(500)
Balance at June 30, 2016	$	(539,600)		$	(2,346,200)		$	300	$	(2,885,500)

See accompanying notes to condensed financial statements.

6

ATLAS AMERICA SERIES 25-2004 (B) L.P.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended
	June 30,
	2016			2015
Cash flows from operating activities:
Net loss	$	(226,400	)	$	(278,100)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion		-			44,100
Non cash loss (gain) on derivative value		7,700			(1,700)
Accretion of asset retirement obligations		56,200			102,900
Changes in operating assets and liabilities:
Decrease in accounts receivable trade-affiliate		1,900			34,300
Increase in asset retirement receivable-affiliate		(202,800	)		(102,000)
Increase in accounts payable trade-affiliate		362,400			205,500
Increase (decrease) in accrued liabilities		1,000			(5,000)
Net cash provided by operating activities		-			-
Cash flows from investing activities:
Net cash flow used in investing activities		-			-
Cash flows from financing activities:
Net cash used in financing activities		-			-
Net change in cash		-			-
Cash at beginning of period		-			-
Cash at end of period	$	-		$	-

See accompanying notes to condensed financial statements.

7

ATLAS AMERICA SERIES 25-2004 (B) L.P.

NOTES TO CONDENSED FINANCIAL STATEMENTS

June 30, 2016

(Unaudited)

NOTE 1 - DESCRIPTION OF BUSINESS

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

Atlas Energy Group, LLC (“Atlas Energy Group”; OTC: ATLS) manages 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, Tennessee and West Virginia. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy Group, for administrative services.

The Partnership’s operating cash flows are generated from its wells, which produce natural gas, oil and NGL. 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 condensed financial statements, which are unaudited, except for the balance sheet at December 31, 2015, which is derived from audited financial statements, have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission and accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim reporting. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. GAAP have been condensed or omitted pursuant to those rules and regulations, although we believe that the disclosures made are adequate to make the information not misleading.  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, 2015. The results of operations for the three and six months ended June 30, 2016 may not necessarily be indicative of the results of operations for the year ended December 31, 2016.

The economic viability of the Partnership’s production is based on a variety of factors including proved developed reserves that it can expect to recover through existing wells with existing equipment and operating methods or in which the cost of additional required extraction equipment is relatively minor compared to the cost of a new well; and through currently installed extraction equipment and related infrastructure which is operational at the time of the reserves estimate (if the extraction is by means not involving drilling, completing or reworking a well). There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues.

The prices at which the Partnership’s natural gas, oil and NGL will be sold are uncertain and the Partnership is not guaranteed a specific price for the sale of its production. Changes in natural gas, oil and NGL prices have a significant impact on the Partnership’s cash flow and the value of its reserves. Lower natural gas, oil and NGL prices may not only decrease the Partnership’s revenues, but also may reduce the amount of natural gas, oil and NGL that the Partnership can produce economically.

Liquidity and Capital Resources

The Partnership is generally limited to the amount of funds generated by the cash flow from its operations to fund its obligations and make distributions, if any, to its partners. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2016. These lower commodity prices have negatively impacted the Partnership’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on the Partnership’s liquidity position. In addition, the Partnership has experienced significant downward revisions of its natural gas and oil reserves volumes and values due to the declines in commodity prices. The MGP continues to implement various cost saving measures to reduce the Partnership’s operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. The MGP will continue to be strategic in managing the Partnership’s cost structure and, in turn, liquidity to meet its operating needs. To the extent commodity prices remain low or decline further, or the Partnership experiences other disruptions in the industry, the Partnership’s ability to fund its operations and make distributions may be further impacted, and could result in the MGP’s decision to liquidate the Partnership’s operations.

8

If, however, the MGP were to decide to liquidate our operations, the liquidation valuation of the Partnership’s assets and liabilities would be determined by an independent expert. It is possible that based on such determination, we would not be able to make any liquidation distributions to our limited partners. A liquidation could result in the transfer of the post-liquidation assets and liabilities of the Partnership to the MGP and would occur without any further contributions from or distributions to the limited partners.

Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from the Partnership’s operations have been adequate to fund its obligations and distributions to its partners. However, the recent significant declines in commodity prices have challenged the Partnership’s ability to fund its operations and may make it uneconomical for the Partnership to produce its wells until they are depleted as the Partnership originally intended. Accordingly, the MGP determined that there is substantial doubt about the Partnership’s ability to continue as a going concern. The MGP intends, as necessary, to continue the Partnership’s operations and to fund the Partnership’s obligations for at least the next twelve months. To the extent commodity prices remain low or decline further or ARP is unsuccessful in completing its Restructuring (as defined below) or the Plan (as defined below), the MGP’s ability to continue the Partnership’s operations may be further impacted.

ARP Restructuring and Chapter 11 Bankruptcy Proceedings

On July 25, 2016, ARP and certain of its subsidiaries, including the MGP, and Atlas Energy Group, solely with respect to certain sections thereof, entered into a restructuring support agreement with ARP’s lenders (the “Restructuring Support Agreement”) to support ARP’s restructuring that will reduce debt on its balance sheet (the “Restructuring”) pursuant to a pre-packaged plan of reorganization (the “Plan”).  The Plan will position ARP for the future and is expected to be completed before the end of the third quarter of 2016, after which ARP should emerge from Chapter 11 (as defined below), backed by its stakeholders, committed to investing capital to develop its exploration and production assets, as well as its tax-advantaged drilling partnership program.

On July 27, 2016, ARP and certain of its subsidiaries, including the MGP, filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”) in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court”). The cases commenced thereby are being jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.” Interested parties should refer to the information and the limitations and qualifications discussed in the disclosure statement related to the Restructuring which was filed as Exhibit 99.1 to ARP’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 25, 2016.

The MGP intends to continue to operate the Partnership’s businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of Chapter 11 and the orders of the Bankruptcy Court. Under the Plan, it is contemplated that all suppliers, vendors, employees, royalty owners, trade partners and landlords will be unimpaired and will be satisfied in full in the ordinary course of business, and the MGP’s existing trade contracts and terms will be maintained. To assure ordinary course operations, the MGP obtained interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions seeking authority to use cash collateral on a consensual basis, pay wages and benefits for individuals who provide services to the Partnership, and pay vendors, oil and gas obligations and other creditor claims in the ordinary course of business.

The Partnership is not a party to the Restructuring Support Agreement. The ARP Restructuring is not expected to materially impact the MGP or its ability to perform as the managing general partner and operator of the Partnership’s operations. On July 26, 2016, the MGP adopted certain amendments to our partnership agreement, in accordance with the MGP’s ability to amend our partnership agreement to cure an ambiguity in or correct or supplement any provision of our partnership agreement as may be inconsistent with any other provision, to provide that bankruptcy and insolvency events, such as the MGP’s Chapter 11 filing, with respect to the managing general partner will not cause the managing general partner to cease to serve as the managing general partner of the Partnership nor cause the termination of the Partnership.

Atlas Energy Group is not a party to the ARP Restructuring. Atlas Energy Group remains controlled by the same ownership group and management team and thus, the ARP Restructuring is not expected to have a material impact on the ability of Atlas Energy Group management to operate ARP or the other Atlas Energy Group businesses

9

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of the Partnership’s condensed 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 condensed financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s condensed 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. The natural gas industry principally conducts its business by processing actual transactions 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. Actual results could differ from those estimates.  

Gas and Oil Properties

The following is a summary of gas and oil properties at the dates indicated:

	June 30,		December 31,
	2016		2015
Proved properties:
Leasehold interests	$	898,600	$	898,600
Wells and related equipment		41,682,000		41,682,000
Total natural gas and oil properties		42,580,600		42,580,600
Accumulated depletion and impairment		(41,253,700)		(41,253,700	)
Gas and oil properties, net	$	1,326,900	$	1,326,900

As a result of the recent significant declines in commodity prices and associated recorded impairment charges, remaining net book value of gas and oil properties on our condensed balance sheets at June 30, 2016 and December 31, 2015 was primarily related to the estimated salvage value of such properties.  The estimated salvage values were based on the MGP’s historical experience in determining such values.

Recently Issued Accounting Standards

In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management 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 and provide footnote disclosures, if necessary. The updated guidance is effective as of January 1, 2017 and the Partnership is currently in the process of determining the impact of providing the enhanced disclosures, as applicable, within its condensed financial statements.

In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. The Partnership is currently in the process of determining the impact that the updated accounting guidance will have on its condensed financial statements and its method of adoption.

NOTE 3 - DERIVATIVE INSTRUMENTS

The MGP, on behalf of the Partnership, uses a number of different derivative instruments, principally put contracts, in connection with the Partnership’s commodity price risk management activities. The Partnership does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses associated with derivative instruments are recognized in earnings.

10

The Partnership enters into commodity put contracts to achieve more predictable cash flows by hedging the Partnership’s exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Stock 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. These contracts have been recorded at their fair values.

The Partnership reflected net derivative assets on its condensed balance sheets of $6,300 and $19,000 at June 30, 2016 and December 31, 2015, respectively.

The following table summarizes the commodity derivate activity and presentation in the condensed statements of operations for the periods indicated:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2016		2015		2016		2015
Gains reclassified from accumulated other comprehensive income into natural gas and oil and liquids revenues	$	300	$	1,900	$	500	$	4,000
Gains subsequent to hedge accounting recognized in gain on mark-to-market derivatives	$	(3,700)	$	(2,100)	$	(800)	$	200

At June 30, 2016, the Partnership had the following commodity derivatives:

Natural Gas Put Options

Production Period Ending December 31,	Volumes(3)		AverageFixed Price			Fair Value Asset (2)
	(MMBtu) (1)		(per MMBtu) (1)
2016		5,600	$	4.15	$		6,300

(1) “MMBtu” represents million British Thermal Units.

(2) Fair value based on forward NYMEX natural gas prices, as applicable.

(3)     The production volume for 2016 include the remaining six months of 2016 beginning July 1, 2016.

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, 2016 and 2015 for hedge ineffectiveness.

NOTE 4 - FAIR VALUE OF FINANCIAL INSTRUMENTS

The Partnership uses a market approach fair value methodology to value its outstanding derivative contracts. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. The Partnership separates the fair value of its financial instruments into three levels (Levels 1, 2 and 3) based on its assessment of the availability of observable market data and the significance of non-observable data used to determine fair value.  As of June 30, 2016 and December 31, 2015, all derivative financial instruments were classified as Level 2.

11

Information for assets measured at fair value at June 30, 2016 and December 31, 2015 was as follows:

	Level 1		Level 2		Level 3		Total
As of June 30, 2016
Derivative assets, gross
Commodity puts	$	-	$	6,300	$	-	$	6,300

	Level 1		Level 2		Level 3		Total
As of December 31, 2015
Derivative assets, gross
Commodity puts	$	-	$	19,000	$	-	$	19,000

NOTE 5 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

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 condensed 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 condensed 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 expenses in the Partnership’s condensed 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 condensed 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 EndedJune 30,				Six Months EndedJune 30,
	2016		2015		2016		2015
Administrative fees	$	22,700	$	18,500	$	38,900	$	40,700
Supervision fees		93,300		75,700		159,700		166,400
Transportation fees		9,200		7,600		16,800		22,300
Direct costs		43,500		53,200		86,700		106,000
Total	$	168,700	$	155,000	$	302,100	$	335,400

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 condensed balance sheets includes the net production expenses due to the MGP.

NOTE 6 - COMMITMENTS AND CONTINGENCIES

General Commitments

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, 2016, the MGP has withheld $525,100 of net production revenue for future plugging and abandonment costs.

Legal Proceedings

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

12

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

Forward-Looking Statements

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.

General

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

Atlas Energy Group, LLC (“Atlas Energy Group”) manages ARP’s operations and activities through its ownership of the ARP’s general partner interest.

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

Overview

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:

· well tending, routine maintenance and adjustment;

· reading meters, recording production, pumping, maintaining appropriate books and records; and

· preparation of reports for us and government agencies.

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 have 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, 2016, our MGP has withheld $525,100 of net production revenues for this purpose.

Markets and Competition

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 2016 and 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.

13

Results of Operations

The following table sets forth information relating to our production revenues, volumes, sales prices, production costs and depletion during the periods indicated:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2016			2015		2016		2015
Production revenues (in thousands):
Gas	$	60		$	58	$	114	$	172
Oil		14			13		18		30
Liquids		-			1		1		3
Total	$	75		$	72	$	133	$	205
Production volumes:
Gas (mcf/day) (1)		446			411		422		462
Oil (bbl/day) (1)		4			2		3		3
Liquids (bbl/day) (1)		-			-		-		1
Total (mcfe/day) (1)		470			423		440		486
Average sales prices (2)
Gas (per mcf) (1)	$	1.49		$	1.55	$	1.48	$	2.06
Oil (per bbl) (1)	$	42.61		$	64.48	$	39.77	$	56.58
Liquids (per bbl) (1)	$	-		$	13.55	$	11.35	$	22.98
Production costs:
As a percent of revenues		177	%		170%		177%		130%
Per mcfe (1)	$	3.10		$	3.14	$	2.94	$	3.05
Depletion per mcfe	$	-		$	0.54	$	-	$	0.50

(1) “Mcf” represents thousand cubic feet, “mcfe” represents thousand cubic feet equivalent, and “bbl” represents barrels. Bbl is converted to mcfe using the ratio of six mcfs to one bbl.

(2) Average sales prices represent accrual basis pricing.

Natural Gas Revenues. Our natural gas revenues were $60,600 and $58,100 for the three months ended June 30, 2016 and 2015, respectively, an increase of $2,500 (4%). The $2,500 increase in natural gas revenues for the three months ended June 30, 2016 as compared to the prior year similar period was attributable to a $5,000 increase in production volumes, partially offset by a $2,500 decrease in our natural gas sales prices after the effect of financial hedges, which were driven by market conditions. Our production volumes increased to 446 mcf per day for the three months ended June 30, 2016 from 411 mcf per day for the three months ended June 30, 2015, an increase of 35 mcf per day (9%). The overall increase in natural gas production volumes for the three months ended June 30, 2016 as compared to the prior year similar period resulted primarily from the normal decline inherent in the life of a well, in addition to wells shut-in due to it being uneconomical to continue production in the current pricing environment.

Our natural gas revenues were $113,700 and $172,000 for the six months ended June 30, 2016 and 2015, respectively, a decrease of $58,300 (34%). The $58,300 decrease in natural gas revenues for the six months ended June 30, 2016 as compared to the prior year similar period was attributable to a $44,300 decrease in our natural gas sales prices after the effect of financial hedges, which were driven by market conditions, and a $14,000 decrease in production volumes. Our production volumes decreased to 422 Mcf per day for the six months ended June 30, 2016 from 462 Mcf per day for the six months ended June 30, 2015, a decrease of 40 Mcf per day (9%). The overall decrease in natural gas production volumes for the six months ended June 30, 2016 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 drilled wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $13,800 and $13,000 for the three months ended June 30, 2016 and 2015, respectively, an increase of $800 (6%). The $800 increase in oil revenues for the three months ended June 30, 2016 as compared to the prior year similar period was attributable to a $6,900 increase in production volumes, partially offset by a $6,100 decrease in oil prices. Our production volumes increased to 3.72 bbl per day for the three months ended June 30, 2016 from 2.22 bbls per day for the three months ended June 30, 2015, an increase of 1.5 bbl per day (68%).

14

Our oil revenues were $18,500 and $29,500 for the six months ended June 30, 2016 and 2015, respectively, a decrease of $11,000 (37%). The $11,000 decrease in oil revenues for the six months ended June 30, 2016 as compared to the prior year similar period wasattributable to a $3,200 decrease in production volumes and a $7,800 decrease in oil prices. Our production volumesdecreased to 2.56 bbls per day for the six months ended June 30, 2016 from 2.88 bbls per day for the six months ended June 30, 2015, a decrease of 0.32 bbls per day (11%).

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 $0 and $500 for the three months ended June 30, 2016 and 2015, respectively.

Our natural gas liquids revenues were $500 and $2,600 for the six months ended June 30, 2016 and 2015, respectively, a decrease of $2,100 (81%). The $2,100 decrease in natural gas liquids revenues for the six months ended June 30, 2016 as compared to the prior year similar period was attributable to a $1,600 decrease in production volumes and a $500 decrease in natural gas liquid prices. Our production volumes decreased to 0.26 bbls per day for the six months ended June 30, 2016 from 0.63 bbls per day for the six months ended June 30, 2015, a decrease of 0.37 bbls per day (59%).

(Loss) Gain on Mark-to-Market Derivatives. We recognize changes in fair value of our derivatives immediately within gain on mark-to-market derivatives on our condensed statements of operations.

We recognized a loss on mark-to-market derivatives of $3,700 and $2,100, for the three months ended June 30, 2016 and 2015, respectively. We recognized a loss on mark-to-market derivatives of $800 and a gain on mark-to-market derivatives of $200 for the six months ended June 30, 2016 and 2015, respectively. These losses and gains were due to mark-to-market losses and gains in the current year primarily related to the change in natural gas prices during the periods.

Costs and Expenses.Production expenses were $131,600 and $121,800 for the three months ended June 30, 2016 and 2015, respectively, an increase of $9,800 (8%). Production expenses were $234,700 and $266,200 for the six months ended June 30, 2016 and 2015, respectively, a decrease of $31,500 (12%). This decrease was attributable to a decrease in monthly well supervision fees and transportation fees.

For the six months ended June 30, 2016, there was no depletion recorded due to the recent significant declines in commodity prices and associated previously recorded impairment charges. Therefore, the remaining net book value of gas and oil properties on our balance sheets at June 30, 2016 and December 31, 2015 was primarily related to the estimated salvage value of such properties. For the three and six months ended June 30, 2015, depletion of gas and oil properties as a percentage of gas and oil revenues was 29% and 22%.

General and administrative expenses for the three months ended June 30, 2016 and 2015 were $37,100 and $33,200, respectively, an increase of $3,900 (12%). For the six months ended June 30, 2016 and 2015, these expenses were $67,400 and $69,200, respectively, a decrease of $1,800 (3%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP and vary from period to period due to the costs charged to us and services provided to us.

Liquidity and Capital Resources

We are generally limited to the amount of funds generated by the cash flow from our operations to fund our obligations and make distributions, if any, to our partners. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2016. These lower commodity prices have negatively impacted our revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on our liquidity position. In addition, we have experienced significant downward revisions of its natural gas and oil reserves volumes and values due to the declines in commodity prices. The MGP continues to implement various cost saving measures to reduce our operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. The MGP will continue to be strategic in managing our cost structure and, in turn, liquidity to meet our operating needs. To the extent commodity prices remain low or decline further, or we experience other disruptions in the industry, our ability to fund our operations and make distributions may be further impacted, and could result in the MGP’s decision to liquidate our operations.

15

If, however, the MGP were to decide to liquidate our operations, the liquidation valuation of our assets and liabilities would be determined by an independent expert. It is possible that based on such determination, we would not be able to make any liquidation distributions to our limited partners. A liquidation could result in the transfer of the post-liquidation assets and liabilities of the Partnership to the MGP and would occur without any further contributions from or distributions to the limited partners.

Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from our operations have been adequate to fund our obligations and distributions to our partners. However, the recent significant declines in commodity prices have challenged our ability to fund our operations and may make it uneconomical for us to produce our wells until they are depleted as we originally intended. Accordingly, the MGP determined that there is substantial doubt about our ability to continue as a going concern. The MGP intends, as necessary, to continue our operations and to fund our obligations for at least the next twelve months. To the extent commodity prices remain low or decline further or ARP is unsuccessful in completing its Restructuring (as defined below) or the Plan (as defined below), the MGP’s ability to continue our operations may be further impacted.

ARP Restructuring and Chapter 11 Bankruptcy Proceedings

On July 25, 2016, ARP and certain of its subsidiaries, including the MGP, and Atlas Energy Group, solely with respect to certain sections thereof, entered into a restructuring support agreement with ARP’s lenders (the “Restructuring Support Agreement”) to support ARP’s restructuring that will reduce debt on its balance sheet (the “Restructuring”) pursuant to a pre-packaged plan of reorganization (the “Plan”).  The Plan will position ARP for the future and is expected to be completed before the end of the third quarter of 2016, after which ARP should emerge from Chapter 11 (as defined below), backed by its stakeholders, committed to investing capital to develop its exploration and production assets, as well as its tax-advantaged drilling partnership program.

On July 27, 2016, ARP and certain of its subsidiaries, including the MGP, filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”) in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court”). The cases commenced thereby are being jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.” Interested parties should refer to the information and the limitations and qualifications discussed in the disclosure statement related to the Restructuring which was filed as Exhibit 99.1 to ARP’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 25, 2016.

The MGP intends to continue to operate the Partnership’s businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of Chapter 11 and the orders of the Bankruptcy Court. Under the Plan, it is contemplated that all suppliers, vendors, employees, royalty owners, trade partners and landlords will be unimpaired and will be satisfied in full in the ordinary course of business, and the MGP’s existing trade contracts and terms will be maintained. To assure ordinary course operations, the MGP obtained interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions seeking authority to use cash collateral on a consensual basis, pay wages and benefits for individuals who provide services to the Partnership, and pay vendors, oil and gas obligations and other creditor claims in the ordinary course of business.

The Partnership is not a party to the Restructuring Support Agreement. The ARP Restructuring is not expected to materially impact the MGP or its ability to perform as the managing general partner and operator of the Partnership’s operations. On July 26, 2016, the MGP adopted certain amendments to our partnership agreement, in accordance with the MGP’s ability to amend our partnership agreement to cure an ambiguity in or correct or supplement any provision of our partnership agreement as may be inconsistent with any other provision, to provide that bankruptcy and insolvency events, such as the MGP’s Chapter 11 filing, with respect to the managing general partner will not cause the managing general partner to cease to serve as the managing general partner of the Partnership nor cause the termination of the Partnership.

Atlas Energy Group is not a party to the ARP Restructuring. Atlas Energy Group remains controlled by the same ownership group and management team and thus, the ARP Restructuring is not expected to have a material impact on the ability of Atlas Energy Group management to operate ARP or the other Atlas Energy Group businesses.

There was no cash provided by operating activities for the six months ended June 30, 2016 and 2015. This was mostly due to a decrease in the change in asset retirement receivable-affiliate of $100,800, a decrease in the change in accounts receivable trade-affiliate of $32,400, and a decrease in net earnings before a non-cash loss (gain) on derivative value, depletion and accretion of $29,700, partially offset by an increase in the change in accounts payable trade-affiliate of $156,900 and an increase in accrued liabilities of $6,000 for the six months ended June 30, 2016 compared to the six months ended June 30, 2015.

Our MGP may withhold funds for future plugging and abandonment costs. Through June 30, 2016, our MGP has withheld $525,100 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.

16

Critical Accounting Policies

See Note 2 to our condensed financial statements for additional information related to recently issued accounting standards.

For a more complete discussion of the accounting policies and estimates that we have identified as critical in the preparation of our condensed financial statements, please refer to our Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our 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, 2016, our disclosure controls and procedures were effective at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

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.

PART II OTHER INFORMATION

ITEM  1. LEGAL PROCEEDINGS

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.

17

ITEM 6. EXHIBITS

EXHIBIT INDEX

Exhibit No.	Description
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

18

SIGNATURES

Pursuant to the requirements of the Securities of the Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		ATLAS AMERICA SERIES 25-2004 (B) L.P.
	By:	Atlas Resources, LLC, its
		Managing General Partner
Date: August 15, 2016	By:	/s/ FREDDIE M. KOTEK
		Freddie M. Kotek, Chief Executive Officer and President of the Managing General Partner

Date: August 15, 2016	By:	/s/JEFFREY M. SLOTTERBACK
		Jeffrey M. Slotterback, Chief Financial Officer of the Managing General Partner

19

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Freddie M. Kotek, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2016 of Atlas America Series 25-2004 (B) L.P.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have;

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within the entity, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

By:	/s/ FREDDIE M. KOTEK
Name:	Freddie M. Kotek
Title:	Chief Executive Officer and President of the Managing General Partner
Date:	August 15, 2016

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Jeffrey M. Slotterback, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2016 of Atlas America Series 25-2004 (B) L.P.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have;

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within the entity, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

By:	/s/JEFFREY M. SLOTTERBACK
Name:	Jeffrey M. Slotterback
Title:	Chief Financial Officer of the Managing General Partner
Date:	August 15, 2016

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Atlas America Series 25-2004 (B) L.P. (the “Partnership”) on Form 10-Q for the period ended June 30, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Freddie M. Kotek, Chief Executive Officer of the Managing General Partner, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

By:	/s/ FREDDIE M. KOTEK
Name:	Freddie M. Kotek
Title:	Chief Executive Officer and President of the Managing General Partner
Date:	August 15, 2016

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Atlas America Series 25-2004 (B) L.P. (the “Partnership”) on Form 10-Q for the period ended June 30, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jeffrey M. Slotterback, Chief Financial Officer of the Managing General Partner, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

By:	/s/JEFFREY M. SLOTTERBACK
Name:	Jeffrey M. Slotterback
Title:	Chief Financial Officer  of the Managing General Partner
Date:	August 15, 2016

XML

Document and Entity Information	6 Months Ended
	Jun. 30, 2016 shares
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q2
Entity Registrant Name	ATLAS AMERICA SERIES 25-2004 (B) L.P.
Entity Central Index Key	0001294208
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding	0

XML

CONDENSED BALANCE SHEETS (Unaudited) - USD ($)	Jun. 30, 2016	Dec. 31, 2015
Current assets:
Cash	$ 0	$ 0
Accounts receivable trade–affiliate	42,300	44,200
Current portion of derivative assets	6,300	19,000
Total current assets	48,600	63,200
Gas and oil properties, net	1,326,900	1,326,900
Long-term asset retirement receivable-affiliate	525,100	322,300
Total assets	1,900,600	1,712,400
Current liabilities:
Accounts payable trade-affiliate	912,600	550,200
Accrued liabilities	9,600	8,600
Put premiums payable-affiliate	4,300	8,800
Total current liabilities	926,500	567,600
Asset retirement obligations	3,859,600	3,803,400
Commitments and contingencies (Note 6)
Partners’ deficit:
Managing general partner’s deficit	(539,600)	(460,800)
Limited partners’ deficit (1,265.38 units)	(2,346,200)	(2,198,600)
Accumulated other comprehensive income	300	800
Total partners’ deficit	(2,885,500)	(2,658,600)
Total liabilities and partners’ deficit	$ 1,900,600	$ 1,712,400

XML

CONDENSED BALANCE SHEETS (Unaudited) (Parenthetical)	Jun. 30, 2016 shares
Statement Of Financial Position [Abstract]
Limited partners' units	1,265.38

XML

CONDENSED STATEMENTS OF OPERATIONS (Unaudited) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
REVENUES
Natural gas, oil and liquids	$ 74,400	$ 71,600	$ 132,700	$ 204,100
(Loss) gain on mark-to-market derivatives	(3,700)	(2,100)	(800)	200
Total revenues	70,700	69,500	131,900	204,300
COSTS AND EXPENSES
Production	131,600	121,800	234,700	266,200
Depletion		20,900	0	44,100
Accretion of asset retirement obligations	28,100	51,500	56,200	102,900
General and administrative	37,100	33,200	67,400	69,200
Total costs and expenses	196,800	227,400	358,300	482,400
Net loss	(126,100)	(157,900)	(226,400)	(278,100)
Allocation of net loss:
Managing general partner	(42,800)	(57,000)	(78,800)	(102,300)
Limited partners	$ (83,300)	$ (100,900)	$ (147,600)	$ (175,800)
Net loss per limited partnership unit	$ (66)	$ (80)	$ (117)	$ (139)

XML

CONDENSED STATEMENTS OF COMPREHENSIVE LOSS (Unaudited) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Statement Of Income And Comprehensive Income [Abstract]
Net loss	$ (126,100)	$ (157,900)	$ (226,400)	$ (278,100)
Other comprehensive loss:
Difference in estimated hedge receivable		1,100		2,400
Reclassification adjustment to net loss of mark-to-market gains on cash flow hedges	(300)	(1,900)	(500)	(4,000)
Total other comprehensive loss	(300)	(800)	(500)	(1,600)
Comprehensive loss	$ (126,400)	$ (158,700)	$ (226,900)	$ (279,700)

XML

CONDENSED STATEMENT OF CHANGES IN PARTNERS' CAPITAL (DEFICIT) (Unaudited) - 6 months ended Jun. 30, 2016 - USD ($)	Total	Managing General Partner	Limited Partners	Accumulated Other Comprehensive Income (Loss)
Beginning balance at Dec. 31, 2015	$ (2,658,600)	$ (460,800)	$ (2,198,600)	$ 800
Participation in revenues, costs and expenses:
Net production expenses	(102,000)	(35,500)	(66,500)
(Loss) gain on mark-to-market derivatives	(800)		(800)
Accretion of asset retirement obligations	(56,200)	(19,700)	(36,500)
General and administrative	(67,400)	(23,600)	(43,800)
Net loss	(226,400)	(78,800)	(147,600)
Other comprehensive loss	(500)			(500)
Ending balance at Jun. 30, 2016	$ (2,885,500)	$ (539,600)	$ (2,346,200)	$ 300

XML

CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($)	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Cash flows from operating activities:
Net loss	$ (226,400)	$ (278,100)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion	0	44,100
Non cash loss (gain) on derivative value	7,700	(1,700)
Accretion of asset retirement obligations	56,200	102,900
Changes in operating assets and liabilities:
Decrease in accounts receivable trade-affiliate	1,900	34,300
Increase in asset retirement receivable-affiliate	(202,800)	(102,000)
Increase in accounts payable trade-affiliate	362,400	205,500
Increase (decrease) in accrued liabilities	1,000	(5,000)
Net cash provided by operating activities	0	0
Cash flows from investing activities:
Net cash flow used in investing activities	0	0
Cash flows from financing activities:
Net cash used in financing activities	0	0
Net change in cash	0	0
Cash at beginning of period	0	0
Cash at end of period	$ 0	$ 0

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Description of Business

6 Months Ended

Jun. 30, 2016

Organization Consolidation And Presentation Of Financial Statements [Abstract]

DESCRIPTION OF BUSINESS

NOTE 1 - DESCRIPTION OF BUSINESS

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

Atlas Energy Group, LLC (“Atlas Energy Group”; OTC: ATLS) manages 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, Tennessee and West Virginia. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy Group, for administrative services.

The Partnership’s operating cash flows are generated from its wells, which produce natural gas, oil and NGL. 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 condensed financial statements, which are unaudited, except for the balance sheet at December 31, 2015, which is derived from audited financial statements, have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission and accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim reporting. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. GAAP have been condensed or omitted pursuant to those rules and regulations, although we believe that the disclosures made are adequate to make the information not misleading.  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, 2015. The results of operations for the three and six months ended June 30, 2016 may not necessarily be indicative of the results of operations for the year ended December 31, 2016.

The economic viability of the Partnership’s production is based on a variety of factors including proved developed reserves that it can expect to recover through existing wells with existing equipment and operating methods or in which the cost of additional required extraction equipment is relatively minor compared to the cost of a new well; and through currently installed extraction equipment and related infrastructure which is operational at the time of the reserves estimate (if the extraction is by means not involving drilling, completing or reworking a well). There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues.

The prices at which the Partnership’s natural gas, oil and NGL will be sold are uncertain and the Partnership is not guaranteed a specific price for the sale of its production. Changes in natural gas, oil and NGL prices have a significant impact on the Partnership’s cash flow and the value of its reserves. Lower natural gas, oil and NGL prices may not only decrease the Partnership’s revenues, but also may reduce the amount of natural gas, oil and NGL that the Partnership can produce economically.

Liquidity and Capital Resources

The Partnership is generally limited to the amount of funds generated by the cash flow from its operations to fund its obligations and make distributions, if any, to its partners. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2016. These lower commodity prices have negatively impacted the Partnership’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on the Partnership’s liquidity position. In addition, the Partnership has experienced significant downward revisions of its natural gas and oil reserves volumes and values due to the declines in commodity prices. The MGP continues to implement various cost saving measures to reduce the Partnership’s operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. The MGP will continue to be strategic in managing the Partnership’s cost structure and, in turn, liquidity to meet its operating needs. To the extent commodity prices remain low or decline further, or the Partnership experiences other disruptions in the industry, the Partnership’s ability to fund its operations and make distributions may be further impacted, and could result in the MGP’s decision to liquidate the Partnership’s operations.

If, however, the MGP were to decide to liquidate our operations, the liquidation valuation of the Partnership’s assets and liabilities would be determined by an independent expert. It is possible that based on such determination, we would not be able to make any liquidation distributions to our limited partners. A liquidation could result in the transfer of the post-liquidation assets and liabilities of the Partnership to the MGP and would occur without any further contributions from or distributions to the limited partners.

Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from the Partnership’s operations have been adequate to fund its obligations and distributions to its partners. However, the recent significant declines in commodity prices have challenged the Partnership’s ability to fund its operations and may make it uneconomical for the Partnership to produce its wells until they are depleted as the Partnership originally intended. Accordingly, the MGP determined that there is substantial doubt about the Partnership’s ability to continue as a going concern. The MGP intends, as necessary, to continue the Partnership’s operations and to fund the Partnership’s obligations for at least the next twelve months. To the extent commodity prices remain low or decline further or ARP is unsuccessful in completing its Restructuring (as defined below) or the Plan (as defined below), the MGP’s ability to continue the Partnership’s operations may be further impacted.

ARP Restructuring and Chapter 11 Bankruptcy Proceedings

On July 25, 2016, ARP and certain of its subsidiaries, including the MGP, and Atlas Energy Group, solely with respect to certain sections thereof, entered into a restructuring support agreement with ARP’s lenders (the “Restructuring Support Agreement”) to support ARP’s restructuring that will reduce debt on its balance sheet (the “Restructuring”) pursuant to a pre-packaged plan of reorganization (the “Plan”).  The Plan will position ARP for the future and is expected to be completed before the end of the third quarter of 2016, after which ARP should emerge from Chapter 11 (as defined below), backed by its stakeholders, committed to investing capital to develop its exploration and production assets, as well as its tax-advantaged drilling partnership program.

On July 27, 2016, ARP and certain of its subsidiaries, including the MGP, filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”) in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court”). The cases commenced thereby are being jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.” Interested parties should refer to the information and the limitations and qualifications discussed in the disclosure statement related to the Restructuring which was filed as Exhibit 99.1 to ARP’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 25, 2016.

The MGP intends to continue to operate the Partnership’s businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of Chapter 11 and the orders of the Bankruptcy Court. Under the Plan, it is contemplated that all suppliers, vendors, employees, royalty owners, trade partners and landlords will be unimpaired and will be satisfied in full in the ordinary course of business, and the MGP’s existing trade contracts and terms will be maintained. To assure ordinary course operations, the MGP obtained interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions seeking authority to use cash collateral on a consensual basis, pay wages and benefits for individuals who provide services to the Partnership, and pay vendors, oil and gas obligations and other creditor claims in the ordinary course of business.

The Partnership is not a party to the Restructuring Support Agreement. The ARP Restructuring is not expected to materially impact the MGP or its ability to perform as the managing general partner and operator of the Partnership’s operations. On July 26, 2016, the MGP adopted certain amendments to our partnership agreement, in accordance with the MGP’s ability to amend our partnership agreement to cure an ambiguity in or correct or supplement any provision of our partnership agreement as may be inconsistent with any other provision, to provide that bankruptcy and insolvency events, such as the MGP’s Chapter 11 filing, with respect to the managing general partner will not cause the managing general partner to cease to serve as the managing general partner of the Partnership nor cause the termination of the Partnership.

Atlas Energy Group is not a party to the ARP Restructuring. Atlas Energy Group remains controlled by the same ownership group and management team and thus, the ARP Restructuring is not expected to have a material impact on the ability of Atlas Energy Group management to operate ARP or the other Atlas Energy Group businesses

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2016

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of the Partnership’s condensed 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 condensed financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s condensed 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. The natural gas industry principally conducts its business by processing actual transactions 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. Actual results could differ from those estimates.  

Gas and Oil Properties

The following is a summary of gas and oil properties at the dates indicated:

	June 30,		December 31,
	2016		2015
Proved properties:
Leasehold interests	$	898,600	$	898,600
Wells and related equipment		41,682,000		41,682,000
Total natural gas and oil properties		42,580,600		42,580,600
Accumulated depletion and impairment		(41,253,700)		(41,253,700	)
Gas and oil properties, net	$	1,326,900	$	1,326,900

As a result of the recent significant declines in commodity prices and associated recorded impairment charges, remaining net book value of gas and oil properties on our condensed balance sheets at June 30, 2016 and December 31, 2015 was primarily related to the estimated salvage value of such properties.  The estimated salvage values were based on the MGP’s historical experience in determining such values.

Recently Issued Accounting Standards

In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management 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 and provide footnote disclosures, if necessary. The updated guidance is effective as of January 1, 2017 and the Partnership is currently in the process of determining the impact of providing the enhanced disclosures, as applicable, within its condensed financial statements.

In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. The Partnership is currently in the process of determining the impact that the updated accounting guidance will have on its condensed financial statements and its method of adoption.

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Derivative Instruments

6 Months Ended

Jun. 30, 2016

Derivative Instruments And Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS

NOTE 3 - DERIVATIVE INSTRUMENTS

The MGP, on behalf of the Partnership, uses a number of different derivative instruments, principally put contracts, in connection with the Partnership’s commodity price risk management activities. The Partnership does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses associated with derivative instruments are recognized in earnings.

The Partnership enters into commodity put contracts to achieve more predictable cash flows by hedging the Partnership’s exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Stock 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. These contracts have been recorded at their fair values.

The Partnership reflected net derivative assets on its condensed balance sheets of $6,300 and $19,000 at June 30, 2016 and December 31, 2015, respectively.

The following table summarizes the commodity derivate activity and presentation in the condensed statements of operations for the periods indicated:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2016		2015		2016		2015
Gains reclassified from accumulated other comprehensive income into natural gas and oil and liquids revenues	$	300	$	1,900	$	500	$	4,000
Gains subsequent to hedge accounting recognized in gain on mark-to-market derivatives	$	(3,700)	$	(2,100)	$	(800)	$	200

At June 30, 2016, the Partnership had the following commodity derivatives:

Natural Gas Put Options

Production Period Ending December 31,	Volumes(3)		AverageFixed Price			Fair Value Asset (2)
	(MMBtu) (1)		(per MMBtu) (1)
2016		5,600	$	4.15	$		6,300

(1) “MMBtu” represents million British Thermal Units.

(2) Fair value based on forward NYMEX natural gas prices, as applicable.

(3)     The production volume for 2016 include the remaining six months of 2016 beginning July 1, 2016.

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, 2016 and 2015 for hedge ineffectiveness.

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Fair Value of Financial Instruments

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

FAIR VALUE OF FINANCIAL INSTRUMENTS

NOTE 4 - FAIR VALUE OF FINANCIAL INSTRUMENTS

The Partnership uses a market approach fair value methodology to value its outstanding derivative contracts. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. The Partnership separates the fair value of its financial instruments into three levels (Levels 1, 2 and 3) based on its assessment of the availability of observable market data and the significance of non-observable data used to determine fair value.  As of June 30, 2016 and December 31, 2015, all derivative financial instruments were classified as Level 2.

Information for assets measured at fair value at June 30, 2016 and December 31, 2015 was as follows:

	Level 1		Level 2		Level 3		Total
As of June 30, 2016
Derivative assets, gross
Commodity puts	$	-	$	6,300	$	-	$	6,300

	Level 1		Level 2		Level 3		Total
As of December 31, 2015
Derivative assets, gross
Commodity puts	$	-	$	19,000	$	-	$	19,000

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Certain Relationships and Related Party Transactions

6 Months Ended

Jun. 30, 2016

Related Party Transactions [Abstract]

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

NOTE 5 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

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 condensed 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 condensed 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 expenses in the Partnership’s condensed 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 condensed 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 EndedJune 30,				Six Months EndedJune 30,
	2016		2015		2016		2015
Administrative fees	$	22,700	$	18,500	$	38,900	$	40,700
Supervision fees		93,300		75,700		159,700		166,400
Transportation fees		9,200		7,600		16,800		22,300
Direct costs		43,500		53,200		86,700		106,000
Total	$	168,700	$	155,000	$	302,100	$	335,400

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 condensed balance sheets includes the net production expenses due to the MGP.

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2016

Commitments And Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

NOTE 6 - COMMITMENTS AND CONTINGENCIES

General Commitments

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, 2016, the MGP has withheld $525,100 of net production revenue for future plugging and abandonment costs.

Legal Proceedings

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

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Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2016

Accounting Policies [Abstract]

Liquidity and Capital Resources

Liquidity and Capital Resources

The Partnership is generally limited to the amount of funds generated by the cash flow from its operations to fund its obligations and make distributions, if any, to its partners. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2016. These lower commodity prices have negatively impacted the Partnership’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on the Partnership’s liquidity position. In addition, the Partnership has experienced significant downward revisions of its natural gas and oil reserves volumes and values due to the declines in commodity prices. The MGP continues to implement various cost saving measures to reduce the Partnership’s operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. The MGP will continue to be strategic in managing the Partnership’s cost structure and, in turn, liquidity to meet its operating needs. To the extent commodity prices remain low or decline further, or the Partnership experiences other disruptions in the industry, the Partnership’s ability to fund its operations and make distributions may be further impacted, and could result in the MGP’s decision to liquidate the Partnership’s operations.

If, however, the MGP were to decide to liquidate our operations, the liquidation valuation of the Partnership’s assets and liabilities would be determined by an independent expert. It is possible that based on such determination, we would not be able to make any liquidation distributions to our limited partners. A liquidation could result in the transfer of the post-liquidation assets and liabilities of the Partnership to the MGP and would occur without any further contributions from or distributions to the limited partners.

Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from the Partnership’s operations have been adequate to fund its obligations and distributions to its partners. However, the recent significant declines in commodity prices have challenged the Partnership’s ability to fund its operations and may make it uneconomical for the Partnership to produce its wells until they are depleted as the Partnership originally intended. Accordingly, the MGP determined that there is substantial doubt about the Partnership’s ability to continue as a going concern. The MGP intends, as necessary, to continue the Partnership’s operations and to fund the Partnership’s obligations for at least the next twelve months. To the extent commodity prices remain low or decline further or ARP is unsuccessful in completing its Restructuring (as defined below) or the Plan (as defined below), the MGP’s ability to continue the Partnership’s operations may be further impacted.

ARP Restructuring and Chapter 11 Bankruptcy Proceedings

On July 25, 2016, ARP and certain of its subsidiaries, including the MGP, and Atlas Energy Group, solely with respect to certain sections thereof, entered into a restructuring support agreement with ARP’s lenders (the “Restructuring Support Agreement”) to support ARP’s restructuring that will reduce debt on its balance sheet (the “Restructuring”) pursuant to a pre-packaged plan of reorganization (the “Plan”).  The Plan will position ARP for the future and is expected to be completed before the end of the third quarter of 2016, after which ARP should emerge from Chapter 11 (as defined below), backed by its stakeholders, committed to investing capital to develop its exploration and production assets, as well as its tax-advantaged drilling partnership program.

On July 27, 2016, ARP and certain of its subsidiaries, including the MGP, filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”) in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court”). The cases commenced thereby are being jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.” Interested parties should refer to the information and the limitations and qualifications discussed in the disclosure statement related to the Restructuring which was filed as Exhibit 99.1 to ARP’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 25, 2016.

The MGP intends to continue to operate the Partnership’s businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of Chapter 11 and the orders of the Bankruptcy Court. Under the Plan, it is contemplated that all suppliers, vendors, employees, royalty owners, trade partners and landlords will be unimpaired and will be satisfied in full in the ordinary course of business, and the MGP’s existing trade contracts and terms will be maintained. To assure ordinary course operations, the MGP obtained interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions seeking authority to use cash collateral on a consensual basis, pay wages and benefits for individuals who provide services to the Partnership, and pay vendors, oil and gas obligations and other creditor claims in the ordinary course of business.

The Partnership is not a party to the Restructuring Support Agreement. The ARP Restructuring is not expected to materially impact the MGP or its ability to perform as the managing general partner and operator of the Partnership’s operations. On July 26, 2016, the MGP adopted certain amendments to our partnership agreement, in accordance with the MGP’s ability to amend our partnership agreement to cure an ambiguity in or correct or supplement any provision of our partnership agreement as may be inconsistent with any other provision, to provide that bankruptcy and insolvency events, such as the MGP’s Chapter 11 filing, with respect to the managing general partner will not cause the managing general partner to cease to serve as the managing general partner of the Partnership nor cause the termination of the Partnership.

Atlas Energy Group is not a party to the ARP Restructuring. Atlas Energy Group remains controlled by the same ownership group and management team and thus, the ARP Restructuring is not expected to have a material impact on the ability of Atlas Energy Group management to operate ARP or the other Atlas Energy Group businesses

Use of Estimates

Use of Estimates

The preparation of the Partnership’s condensed 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 condensed financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s condensed 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. The natural gas industry principally conducts its business by processing actual transactions 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. Actual results could differ from those estimates.  

Gas and Oil Properties

Gas and Oil Properties

The following is a summary of gas and oil properties at the dates indicated:

	June 30,		December 31,
	2016		2015
Proved properties:
Leasehold interests	$	898,600	$	898,600
Wells and related equipment		41,682,000		41,682,000
Total natural gas and oil properties		42,580,600		42,580,600
Accumulated depletion and impairment		(41,253,700)		(41,253,700	)
Gas and oil properties, net	$	1,326,900	$	1,326,900

As a result of the recent significant declines in commodity prices and associated recorded impairment charges, remaining net book value of gas and oil properties on our condensed balance sheets at June 30, 2016 and December 31, 2015 was primarily related to the estimated salvage value of such properties.  The estimated salvage values were based on the MGP’s historical experience in determining such values.

Recently Issued Accounting Standards

Recently Issued Accounting Standards

In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management 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 and provide footnote disclosures, if necessary. The updated guidance is effective as of January 1, 2017 and the Partnership is currently in the process of determining the impact of providing the enhanced disclosures, as applicable, within its condensed financial statements.

In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. The Partnership is currently in the process of determining the impact that the updated accounting guidance will have on its condensed financial statements and its method of adoption.

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Summary of Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2016

Accounting Policies [Abstract]

Summary of Gas and Oil Properties

The following is a summary of gas and oil properties at the dates indicated:

	June 30,		December 31,
	2016		2015
Proved properties:
Leasehold interests	$	898,600	$	898,600
Wells and related equipment		41,682,000		41,682,000
Total natural gas and oil properties		42,580,600		42,580,600
Accumulated depletion and impairment		(41,253,700)		(41,253,700	)
Gas and oil properties, net	$	1,326,900	$	1,326,900

XML

Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2016

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Summary of Commodity Derivate Activity and Presentation in the Condensed Statements of Operations

The following table summarizes the commodity derivate activity and presentation in the condensed statements of operations for the periods indicated:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2016		2015		2016		2015
Gains reclassified from accumulated other comprehensive income into natural gas and oil and liquids revenues	$	300	$	1,900	$	500	$	4,000
Gains subsequent to hedge accounting recognized in gain on mark-to-market derivatives	$	(3,700)	$	(2,100)	$	(800)	$	200

Commodity Derivatives

At June 30, 2016, the Partnership had the following commodity derivatives:

Natural Gas Put Options

Production Period Ending December 31,	Volumes(3)		AverageFixed Price			Fair Value Asset (2)
	(MMBtu) (1)		(per MMBtu) (1)
2016		5,600	$	4.15	$		6,300

(1) “MMBtu” represents million British Thermal Units.

(2) Fair value based on forward NYMEX natural gas prices, as applicable.

(3)     The production volume for 2016 include the remaining six months of 2016 beginning July 1, 2016.

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Fair Value of Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

Assets Measured at Fair Value on a Recurring Basis

Information for assets measured at fair value at June 30, 2016 and December 31, 2015 was as follows:

	Level 1		Level 2		Level 3		Total
As of June 30, 2016
Derivative assets, gross
Commodity puts	$	-	$	6,300	$	-	$	6,300

	Level 1		Level 2		Level 3		Total
As of December 31, 2015
Derivative assets, gross
Commodity puts	$	-	$	19,000	$	-	$	19,000

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Certain Relationships and Related Party Transactions (Tables)

6 Months Ended

Jun. 30, 2016

Related Party Transactions [Abstract]

Certain Relationships and Related Party Transactions

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

	Three Months EndedJune 30,				Six Months EndedJune 30,
	2016		2015		2016		2015
Administrative fees	$	22,700	$	18,500	$	38,900	$	40,700
Supervision fees		93,300		75,700		159,700		166,400
Transportation fees		9,200		7,600		16,800		22,300
Direct costs		43,500		53,200		86,700		106,000
Total	$	168,700	$	155,000	$	302,100	$	335,400

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Description of Business (Details)	6 Months Ended
	Jun. 30, 2016
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Atlas America Series 25-2004 (B) L.P. Formation Date	Jan. 21, 2004

XML

Summary of Significant Accounting Policies (Summary of Gas and Oil Properties) (Details) - USD ($)	Jun. 30, 2016	Dec. 31, 2015
Property Plant And Equipment [Line Items]
Total natural gas and oil properties	$ 42,580,600	$ 42,580,600
Accumulated depletion and impairment	(41,253,700)	(41,253,700)
Gas and oil properties, net	1,326,900	1,326,900
Leasehold interests
Property Plant And Equipment [Line Items]
Total natural gas and oil properties	898,600	898,600
Wells and related equipment
Property Plant And Equipment [Line Items]
Total natural gas and oil properties	$ 41,682,000	$ 41,682,000

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Derivative Instruments (Narrative) (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Net derivative assets	$ 6,300		$ 6,300		$ 19,000
Gains (Losses) on Fair Value Hedge Ineffectiveness, Net	$ 0	$ 0	$ 0	$ 0

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Derivative Instruments (Summary of Commodity Derivate Activity and Presentation in the Condensed Statements of Operations) (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Gains reclassified from accumulated other comprehensive income into natural gas and oil and liquids revenues	$ 300	$ 1,900	$ 500	$ 4,000
Gains subsequent to hedge accounting recognized in gain on mark-to-market derivatives	$ (3,700)	$ (2,100)	$ (800)	$ 200

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Derivative Instruments (Commodity Derivatives) (Details)		6 Months Ended
		Jun. 30, 2016 USD ($) MMBTU $ / MMBTU	Dec. 31, 2015 USD ($)
Derivative [Line Items]
Fair Value Asset		$ 6,300	$ 19,000
Natural Gas Put Options Production Period Ending December 31, 2016 | Designated as Hedging Instrument
Derivative [Line Items]
Volumes (MMBtu) | MMBTU	[1],[2]	5,600
Average Fixed Price (per MMBtu) | $ / MMBTU	[2]	4.15
Fair Value Asset	[3]	$ 6,300

[1] The production volume for 2016 include the remaining six months of 2016 beginning July 1, 2016.

[2] “MMBtu” represents million British Thermal Units.

[3] Fair value based on forward NYMEX natural gas prices, as applicable.

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Fair Value of Financial Instruments (Assets Measured at Fair Value on a Recurring Basis) (Details) - USD ($)	Jun. 30, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair Value Asset	$ 6,300	$ 19,000
Commodity Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair Value Asset	6,300	19,000
Commodity Puts | Fair Value, Inputs, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair Value Asset	$ 6,300	$ 19,000

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Certain Relationships and Related Party Transactions (Narrative) (Details) - MGP and Affiliates	6 Months Ended
	Jun. 30, 2016 $ / mo
Administrative costs
Related Party Transaction [Line Items]
Monthly Administrative Costs Per Well	75
Supervision fees
Related Party Transaction [Line Items]
Monthly Supervision Fees Per Well	313
Transportation fees
Related Party Transaction [Line Items]
Transportation Fees Rate As Percentage Of Natural Gas Sales Price	13.00%

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Certain Relationships and Related Party Transactions (Certain Relationships and Related Party Transactions) (Details) - MGP and Affiliates - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 168,700	$ 155,000	$ 302,100	$ 335,400
Administrative fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	22,700	18,500	38,900	40,700
Supervision fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	93,300	75,700	159,700	166,400
Transportation fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	9,200	7,600	16,800	22,300
Direct costs
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 43,500	$ 53,200	$ 86,700	$ 106,000

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Commitments and Contingencies (Narrative) (Details)	6 Months Ended
	Jun. 30, 2016 USD ($) $ / mo
Commitments And Contingencies Disclosure [Abstract]
Investor Partners Ownership Interest Presented For Purchase By The MGP, Maximum Percentage	5.00%
Operator Fee Per Well To Cover Estimated Future Plugging And Abandonment Costs, Monthly | $ / mo	200
Net production revenue for future plugging and abandonment costs | $	$ 525,100