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 000-51945

ATLAS AMERICA SERIES 26-2005 L.P.

(Name of small business issuer in its charter)

Delaware		20-2879859
(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 26-2005 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	16
PART II.	OTHER INFORMATION
Item 1:	Legal Proceedings	17
Item 6:	Exhibits	18
SIGNATURES		19
CERTIFICATIONS

PART I. FINANCIAL INFORMATION

ITEM I. FINANCIAL STATEMENTS

ATLAS AMERICA SERIES 26-2005 L.P.

CONDENSED BALANCE SHEETS

(Unaudited)

	June 30, 2016		December 31, 2015
	June 30, 2016		December 31, 2015
ASSETS
Current assets:
Cash	$	-	$	-
Accounts receivable trade–affiliate		47,000		46,900
Current portion of derivative assets		7,100		20,800
Total current assets		54,100		67,700
Gas and oil properties, net		1,199,400		1,199,400
Long-term asset retirement receivable-affiliate		118,700		36,100
Total assets	$	1,372,200	$	1,303,200
LIABILITIES AND PARTNERS’ DEFICIT
Current liabilities:
Accounts payable trade-affiliate	$	346,500	$	138,900
Accrued liabilities		9,200		8,500
Put premiums payable-affiliate		4,800		9,600
Total current liabilities		360,500		157,000
Asset retirement obligations		3,061,800		3,011,400
Commitments and contingencies (Note 6)
Partners’ deficit:
Managing general partner’s deficit		(397,800)		(331,600	)
Limited partners’ deficit (1,400 units)		(1,652,700)		(1,534,600	)
Accumulated other comprehensive income		400		1,000
Total partners’ deficit		(2,050,100)		(1,865,200	)
Total liabilities and partners’ deficit	$	1,372,200	$	1,303,200

See accompanying notes to condensed financial statements.

ATLAS AMERICA SERIES 26-2005 L.P.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
REVENUES
Natural gas and oil	$	84,200	$	108,100	$	158,200	$	261,700
(Loss) gain on mark-to-market derivatives		(4,000)		(2,600)		(600)		200
Total revenues		80,200		105,500		157,600		261,900
COSTS AND EXPENSES
Production		129,400		133,500		227,600		301,600
Depletion		-		23,400		-		47,800
Accretion of asset retirement obligations		25,300		40,800		50,600		81,500
General and administrative		35,100		32,800		63,700		68,900
Total costs and expenses		189,800		230,500		341,900		499,800
Net loss	$	(109,600)	$	(125,000)	$	(184,300)	$	(237,900)
Allocation of net loss:
Managing general partner	$	(38,000)	$	(45,900)	$	(66,200)	$	(89,100)
Limited partners	$	(71,600)	$	(79,100)	$	(118,100)	$	(148,800)
Net loss per limited partnership unit	$	(51)	$	(56)	$	(84)	$	(106)

See accompanying notes to condensed financial statements.

ATLAS AMERICA SERIES 26-2005 L.P.

CONDENSED STATEMENTS OF COMPREHENSIVE LOSS

(Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Net loss	$	(109,600)	$	(125,000)	$	(184,300)	$	(237,900)
Other comprehensive loss:
Difference in estimated hedge receivable		-		1,300		-		2,800
Reclassification adjustment to net loss of mark-to-market (losses) gains on cash flow hedges		(300)		(2,400)		(600)		(4,800)
Total other comprehensive loss		(300)		(1,100)		(600)		(2,000)
Comprehensive loss	$	(109,900)	$	(126,100)	$	(184,900)	$	(239,900)

See accompanying notes to condensed financial statements.

ATLAS AMERICA SERIES 26-2005 L.P.

CONDENSED STATEMENT OF CHANGES IN PARTNERS’ DEFICIT

FOR THE SIX MONTHS ENDED

June 30, 2016

(Unaudited)

	Managing General Partner		Limited Partners		Accumulated Other Comprehensive Income (Loss)		Total
Balance at December 31, 2015	$	(331,600)	$	(1,534,600)	$	1,000	$	(1,865,200)
Participation in revenues, costs and expenses:
Net production expenses		(24,900)		(44,500)		-		(69,400)
Loss on mark-to-market derivatives		-		(600)		-		(600)
Accretion of asset retirement obligations		(18,300)		(32,300)		-		(50,600)
General and administrative		(23,000)		(40,700)		-		(63,700)
Net loss		(66,200)		(118,100)		-		(184,300)
Other comprehensive loss		-		-		(600)		(600)
Balance at June 30, 2016	$	(397,800)	$	(1,652,700)	$	400	$	(2,050,100)

See accompanying notes to condensed financial statements.

ATLAS AMERICA SERIES 26-2005 L.P.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	2016		2015
Cash flows from operating activities:
Net loss	$	(184,300)	$	(237,900)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion		-		47,800
Non cash loss (gain) on derivative value		8,300		(2,200)
Accretion of asset retirement obligations		50,600		81,500
Asset retirement obligation liabilities settled		(200)		-
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable trade-affiliate		(100)		98,700
Increase in asset retirement receivable-affiliate		(82,600)		(13,300)
Increase in accounts payable trade-affiliate		207,600		29,500
Increase (decrease) in accrued liabilities		700		(4,100)
Net cash provided by operating activities		-		-

Cash flows from investing activities:
Net cash 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.

ATLAS AMERICA SERIES 26-2005 L.P.

NOTES TO CONDENSED FINANCIAL STATEMENTS

June 30, 2016

(Unaudited)

NOTE 1 – DESCRIPTION OF BUSINESS

Atlas America Series 26-2005 L.P. (the “Partnership”) is a Delaware limited partnership, formed on May 26, 2005 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 26-2005 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 and Tennessee. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy Group, for administrative services.

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

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

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, 2016		December 31, 2015
Proved properties:
Leasehold interests	$	1,102,500	$	1,102,500
Wells and related equipment		44,267,700		44,267,700
Total natural gas and oil properties		45,370,200		45,370,200
Accumulated depletion and impairment		(44,170,800)		(44,170,800	)
Gas and oil properties, net	$	1,199,400	$	1,199,400

As a result of the recent significant declines in commodity prices and associated recorded impairment charges, the 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.

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 $7,100 and $20,800 at June 30, 2016 and December 31, 2015, respectively.

The following table summarizes the commodity derivative 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 revenues	$	300	$	2,400	$	600	$	4,800
(Losses) gains subsequent to hedge accounting recognized in (loss) gain on mark-to-market derivatives	$	(4,000)	$	(2,600)	$	(600)	$	200

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

Natural Gas Put Options

Production Period Ending December 31,	Volumes ⁽³⁾		Average Fixed Price		Fair Value Asset ⁽²⁾
	(MMBtu) ⁽¹⁾		(per MMBtu) ⁽¹⁾
2016		6,300		$4.15	$	7,100

(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.

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	$	-	$	7,100	$	-	$	7,100

	Level 1		Level 2		Level 3		Total
As of December 31, 2015
Derivative assets, gross
Commodity puts	$	-	$	20,800	$	-	$	20,800

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 $318 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 Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Administrative fees	$	21,000	$	18,300	$	35,700	$	40,800
Supervision fees		88,100		76,200		149,200		170,500
Transportation fees		13,200		14,300		23,100		33,500
Direct costs		42,200		57,500		83,300		125,700
Total	$	164,500	$	166,300	$	291,300	$	370,500

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 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 $118,700 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.

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 26-2005 L.P. (“we”, “us”, or the “Partnership”) is a Delaware limited partnership, formed on May 26, 2005 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 26-2005 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 and Tennessee. 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 $118,700 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.

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 June 30,				Six Months Ended June 30,
	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Production revenues (in thousands):
Gas	$	70	$	90	$	134	$	233
Oil		14		18		24		29
Total	$	84	$	108	$	158	$	262
Production volumes:
Gas (mcf/day) ⁽¹⁾		515		577		477		603
Oil (bbl/day) ⁽¹⁾		4		5		4		4
Total (mcfe/day) ⁽¹⁾		539		607		501		627
Average sales prices ⁽²⁾
Gas (per mcf) ⁽¹⁾	$	1.50	$	1.71	$	1.54	$	2.13
Oil (per bbl) ⁽¹⁾	$	35.10	$	44.26	$	31.45	$	43.05
Production costs:
As a percent of revenues		154%		124%		144%		115%
Per mcfe ⁽¹⁾	$	2.63	$	2.43	$	2.49	$	2.67
Depletion per mcfe	$	-	$	0.43	$	-	$	0.42

(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 after adjusting for the effect of previously recognized gains resulting from prior period impairment charges.

Natural Gas Revenues. Our natural gas revenues were $70,500 and $89,800 for the three months ended June 30, 2016 and 2015, respectively, a decrease of $19,300 (21%). The $19,300 decrease in natural gas revenues for the three months ended June 30, 2016 as compared to the prior year similar period was attributable to a $9,700 decrease in our natural gas sales prices after the effect of financial hedges and a $9,600 decrease in production volumes. Our production volumes decreased to 515 mcf per day for the three months ended June 30, 2016 from 577 mcf per day for the three months ended June 30, 2015, a decrease of 62 mcf per day (11%). The decrease in production volumes is mostly due to the normal decline inherent in the life of the wells in addition to wells shut-in due to it being uneconomical to continue production in the current pricing environment.

Our natural gas revenues were $133,800 and $232,700 for the six months ended June 30, 2016 and 2015, respectively, a decrease of $98,900 (43%). The $98,900 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 $51,500 decrease in our natural gas sales prices after the effect of financial hedges, which were driven by market conditions, and a $47,400 decrease in production volumes. Our production volumes decreased to 477 Mcf per day for the six months ended June 30, 2016 from 603 Mcf per day for the six months ended June 30, 2015, a decrease of 126 Mcf per day (21%). The overall decrease in natural gas production is primarily due to the normal decline inherent in the life of a well.

Oil Revenues. We drilled wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $13,700 and $18,300 for the three months ended June 30, 2016 and 2015, respectively, a decrease of $4,600 (25%). The $4,600 decrease in oil revenues for the three months ended June 30, 2016 as compared to the prior year similar period was attributable to a $3,600 decrease in oil prices after the effect of financial hedges and a $1,000 decrease in production volumes. Our production volumes decreased to 4 bbls per day for the three months ended June 30, 2016 from 5 bbls per day for the three months ended June 30, 2015, a decrease of 1 bbls per day (5%).

Our oil revenues were $24,400 and $29,000 for the six months ended June 30, 2016 and 2015, respectively, a decrease of $4,600 (16%). The $4,600 decrease in oil revenues for the six months ended June 30, 2016 as compared to the prior year similar period was attributable to a $9,000 decrease in oil prices after the effect of financial hedges partially offset by a $4,400 increase in production volumes. Our production volumes increased to 4.27 bbls per day for the six months ended June 30, 2015 from 3.73 bbls per day for the six months ended June 30, 2015, an increase of 0.54 bbls per day (15%).

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

We recognized a loss on mark-to-market derivatives of $4,000 and $2,600 for the three months ended June 30, 2016 and 2015, respectively. We recognized a loss on mark-to-market derivatives of $600 and a gain on mark-to-market derivatives of $200 for the six months ended June 30, 2016 and 2015. These (losses) gains were due to mark-to-market (losses) gains primarily related to the change in natural gas prices during the periods.

Costs and Expenses. Production expenses were $129,400 and $133,500 for the three months ended June 30, 2016 and 2015, respectively, a decrease of $4,100 (3%). Production expenses were $227,600 and $301,600 for the six months ended June 30, 2016 and 2015, respectively, a decrease of $74,000 (25%). This decrease was mostly attributable to a decrease in monthly well supervision fees and transportation expenses.

For the three 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 sheet at June 30, 2016 and December 31, 2015 was primarily related to the estimated salvage value of such properties. For the three months ended June 30, 2015, depletion of gas and oil properties as a percentage of gas and oil revenues was 22% and 18%.

General and administrative expenses for the three months ended June 30, 2016 and 2015 were $35,100 and $32,800, respectively, an increase of $2,300 (7%). For the six months ended June 30, 2016 and 2015 these expenses were $63,700 and $68,900, respectively, a decrease of $5,200 (8%). 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.

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

There was no cash provided by operating activities for the six months ended June 30, 2016 and 2015. This was due to an increase in the change in accounts payable-affiliate of $178,100 and an increase in the change in accrued liabilities of $4,800. This increase was offset by decrease in the change in accounts receivable trade-affiliate of $98,800 and a decrease in asset retirement receivable-affiliate of $69,300, a decrease in net earnings before depletion, accretion, and non cash loss (gain) on derivative value of $14,600, and a decrease in the change in asset retirement obligation settled of $200 for the six months ended June 30, 2016 compared to the six months ended June 30, 2015, respectively.

There was no cash provided by investing activities for the six months ended June 30, 2016 and 2015.

There was no cash provided by financing activities for the six months ended June 30, 2016 and 2015.

Our MGP may withhold funds for future plugging and abandonment costs. Through June 30, 2016, our MGP has withheld $118,700 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.

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.

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

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 26-2005 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

Atlas America Series 26-2005 L.P. 10-Q