10-Q

United States

Securities and Exchange Commission

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2012

¨ 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  x    No  ¨

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

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

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

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

ATLAS AMERICA SERIES 26-2005 L.P.

(A Delaware Limited Partnership)

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

PART I.	FINANCIAL INFORMATION	PAGE
Item 1:	Financial Statements
	Balance Sheets as of March 31, 2012 and December 31, 2011		3
	Statements of Operations for the Three Months ended March 31, 2012 and 2011		4
	Statements of Comprehensive Loss for the Three Months ended March 31, 2012 and 2011		5
	Statement of Changes in Partners’ Capital for the Three Months ended March 31, 2012		6
	Statements of Cash Flows for the Three Months ended March 31, 2012 and 2011		7
	Notes to Financial Statements		8
Item 2:	Management’s Discussion and Analysis of Financial Condition and Results of Operations		15
Item 4:	Controls and Procedures		18
PART II.	OTHER INFORMATION
Item 1:	Legal Proceedings		18
Item 6:	Exhibits		18
SIGNATURES			19
CERTIFICATIONS

2

ATLAS AMERICA SERIES 26-2005 L.P.

BALANCE SHEETS

	March  31, 2012		December  31, 2011
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	44,200	$	71,600
Accounts receivable – affiliate		331,500		430,200
Total current assets		375,700		501,800
Oil and gas properties, net		4,511,200		4,603,700
Long-term receivable-affiliate		73,500		95,800
	$	4,960,400	$	5,201,300
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	19,500	$	7,700
Total current liabilities		19,500		7,700
Asset retirement obligation		2,126,700		2,100,000
Partners’ capital:
Managing general partner		1,342,100		1,406,500
Limited partners (1,400 units)		1,472,100		1,687,100
Accumulated other comprehensive income		—		—
Total partners’ capital		2,814,200		3,093,600
	$	4,960,400	$	5,201,300

See accompanying notes to financial statements.

3

ATLAS AMERICA SERIES 26-2005 L.P.

STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended March 31,
	2012			2011
REVENUES
Natural gas and oil	$	271,100		$	381,500
Total revenues		271,100			381,500
COSTS AND EXPENSES
Production		190,200			204,400
Depletion		92,500			167,200
Accretion of asset retirement obligation		26,700			28,200
General and administrative		44,900			47,900
Total costs and expenses		354,300			447,700
Net loss	$	(83,200	)	$	(66,200	)
Allocation of net loss:
Managing general partner	$	(16,700	)	$	(5,000	)
Limited partners	$	(66,500	)	$	(61,200	)
Net loss per limited partnership unit	$	(48	)	$	(44	)

See accompanying notes to financial statements.

4

ATLAS AMERICA SERIES 26-2005 L.P.

STATEMENTS OF COMPREHENSIVE LOSS

(Unaudited)

	Three Months Ended March 31,
	2012			2011
Net loss	$	(83,200	)	$	(66,200	)
Other comprehensive loss:
Unrealized holding gain on hedging contracts		—			133,300
Difference in estimated monetized gains receivable		20,700			—
Less: reclassification adjustment for gains realized in net loss		(20,700	)		(148,300	)
Total other comprehensive loss		—			(15,000	)
Comprehensive loss	$	(83,200	)	$	(81,200	)

See accompanying notes to financial statements.

5

ATLAS AMERICA SERIES 26-2005 L.P.

STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

FOR THE THREE MONTHS ENDED

March 31, 2012

(Unaudited)

	Managing General Partner			Limited Partners			Accumulated Other Comprehensive Income (Loss)		Total
Balance at January 1, 2012	$	1,406,500		$	1,687,100		$	—	$	3,093,600
Participation in revenues and expenses:
Net production revenues		27,600			53,300			—		80,900
Depletion		(18,500	)		(74,000	)		—		(92,500	)
Accretion of asset retirement obligation		(9,600	)		(17,100	)		—		(26,700	)
General and administrative		(16,200	)		(28,700	)		—		(44,900	)
Net loss		(16,700	)		(66,500	)		—		(83,200	)
Other comprehensive loss		—			—			—		—
Distributions to partners		(47,700	)		(148,500	)		—		(196,200	)
Balance at March 31, 2012	$	1,342,100		$	1,472,100		$	—	$	2,814,200

See accompanying notes to financial statements.

6

ATLAS AMERICA SERIES 26-2005 L.P.

STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2012			2011
Cash flows from operating activities:
Net loss	$	(83,200	)	$	(66,200	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion		92,500			167,200
Non-cash loss on derivative value		39,600			4,800
Accretion of asset retirement obligation		26,700			28,200
Decrease in accounts receivable-affiliate		81,400			153,500
Increase in accrued liabilities		11,800			1,400
Net cash provided by operating activities		168,800			288,900
Cash flows from investing activities:
Purchase of tangible equipment		—			(7,500	)
Net cash used in investing activities		—			(7,500	)
Cash flows from financing activities:
Distributions to partners		(196,200	)		(280,700	)
Net cash used in financing activities		(196,200	)		(280,700	)
Net (decrease) increase in cash and cash equivalents		(27,400	)		700
Cash and cash equivalents at beginning of period		71,600			105,500
Cash and cash equivalents at end of period	$	44,200		$	106,200
Supplement Schedule of non-cash operating and financing activities:
Distribution to managing general partner	$	—		$	106,000

See accompanying notes to financial statements.

7

ATLAS AMERICA SERIES 26-2005 L.P.

NOTES TO FINANCIAL STATEMENTS

March 31, 2012

(Unaudited)

NOTE 1 — DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

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 “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP).

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

In March 2012, Atlas Energy contributed to ARP, a newly formed exploration and production master limited partnership, substantially all of Atlas Energy’s natural gas and oil development and production assets and its partnership management business, including ownership of our MGP. Atlas Energy also distributed an approximate 19.6% limited partner interest in ARP to its unitholders, retaining a 78.4% limited partner interest. Atlas Energy also owns ARP’s general partner, which owns a 2% general partner interest and all of the incentive distribution rights in ARP.

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

Our operating cash flows are generated from our wells, which produce natural gas and oil. Our produced natural gas and oil is then delivered to market through third-party gas gathering systems. We do not plan to sell any of our wells and will continue to produce them until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. No other wells will be drilled and no additional funds will be required for drilling.

The accompanying financial statements, which are unaudited except that the balance sheet at December 31, 2011 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in the Form 10-K. These interim financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2011. The results of operations for the three months ended March 31, 2012 may not necessarily be indicative of the results of operations for the year ended December 31, 2012.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

In addition to matters discussed further in this note, the Partnership’s significant accounting policies are detailed in its audited financial statements and notes thereto in the Partnership’s annual report on Form 10-K for the year ended December 31, 2011 filed with the Securities and Exchange Commission (“SEC”).

8

ATLAS AMERICA SERIES 26-2005 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

March 31, 2012

(Unaudited)

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Use of Estimates

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

The natural gas industry principally conducts its business by processing actual transactions as much as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following months’ financial results. Management believes that the operating results presented for the three months ended March 31, 2012 and 2011 represent actual results in all material respects (see “Revenue Recognition” accounting policy for further description).

Accounts Receivable and Allowance for Possible Losses

In evaluating the need for an allowance for possible losses, the MGP performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness as determined by review of its customers’ credit information. Credit is extended on an unsecured basis to many of its energy customers. At March 31, 2012 and December 31, 2011, the Partnership’s MGP’s credit evaluation indicated that the Partnership had no need for an allowance for possible losses.

Oil and Gas Properties

Oil and gas properties are stated at cost. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized.

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

The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties. The Partnership recorded depletion expense on natural gas and oil properties of $92,500 and $167,200 for the three months ended March 31, 2012 and 2011, respectively.

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

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

	March  31, 2012			December  31, 2011
Proved properties:
Leasehold interests	$	1,110,900		$	1,110,900
Wells and related equipment		44,175,700			44,175,700
		45,286,600			45,286,600
Accumulated depletion and impairment		(40,775,400	)		(40,682,900	)
Oil and gas properties, net	$	4,511,200		$	4,603,700

9

ATLAS AMERICA SERIES 26-2005 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

March 31, 2012

(Unaudited)

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Impairment of Long-Lived Assets

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

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

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

In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. The Partnership may have to pay additional consideration in the future as a well becomes uneconomic under the terms of the Partnership Agreement in order to recover these reserves. There was no impairment charge recognized during the three months ended March 31, 2012. During the year ended December 31, 2011, the Partnership recognized an impairment charge of $4,331,800, net of an offsetting gain in accumulated other comprehensive income of $147,200.

Working Interest

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

10

ATLAS AMERICA SERIES 26-2005 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

March 31, 2012

(Unaudited)

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue Recognition

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

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGL’s, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “Use of Estimates” accounting policy for further description). The Partnership had unbilled revenues at March 31, 2012 and December 31, 2011 of $155,900 and $224,100, respectively, which were included in accounts receivable-affiliate within the Partnership’s balance sheets.

Comprehensive Loss

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

Recently Adopted Accounting Standards

In December 2011, the FASB issued Accounting Standards Update (“ASU”) 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (“Update 2011-12”). The amendments in this update effectively defer implementation of changes made in Update 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income (“Update 2011-05”), related to the presentation of reclassification adjustments out of accumulated other comprehensive income. Under Update 2011-05 which was issued by the FASB in June 2011, entities are provided the option to present the total of comprehensive income, the components of net income and the components of other comprehensive income in either a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with a total net income, each component of other comprehensive income and a total amount for comprehensive income. Update 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. As a result of Update 2011-12, entities are required to disclose reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect prior to Update 2011-05. All other requirements in Update 2011-05 are not affected by Update 2011-12. These requirements are effective for interim and annual reporting periods beginning after December 15, 2011. Accordingly, entities are not required to comply with presentation requirements of Update 2011-05 related to the disclosure of reclassifications out of accumulated other comprehensive income. The Partnership included separate but consecutive statements of income and comprehensive income within its Form 10-Qs upon the adoption of these ASUs on January 1, 2012. The adoption had no material impact on the Partnership’s financial condition or results of operations.

11

ATLAS AMERICA SERIES 26-2005 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

March 31, 2012

(Unaudited)

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Recently Adopted Accounting Standards (Continued)

In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosure about Offsetting Assets and Liabilities (“Update 2011-11”). The amendments in this update require an entity to disclose both gross and net information about both financial and derivative instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the statement of financial position. An entity shall disclose at the end of a reporting period certain quantitative information separately for assets and liabilities that are within the scope of Update 2011-11, as well as provide a description of the rights of setoff associated with an entity’s recognized assets and recognized liabilities subject to an enforceable master netting arrangement or similar agreement. Entities are required to implement the amendments for interim and annual reporting periods beginning after January 1, 2013 and shall be applied retrospectively for any period presented that begins before the date of initial application. The Partnership has elected to early adopt these requirements and updated its disclosures to meet these requirements effective January 1, 2012. The adoption had no material impact on the Partnership’s financial position or results of operations.

In May 2011, the FASB issued ASU 2011-04, Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“Update 2011-04”). The amendments in Update 2011-04 revise the wording used to describe many of the requirements for measuring fair value and for disclosing information about fair value measurements in U.S. GAAP. For many of the amendments, the guidance is not necessarily intended to result in a change in the application of the requirements in Topic 820; rather it is intended to clarify the intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. As a result, Update 2011-04 aims to provide common fair value measurement and disclosure requirements in U.S. GAAP and International Financial Reporting Standards. These requirements are effective for interim and annual reporting periods beginning after December 15, 2011. The Partnership updated its disclosures to meet these requirements upon the adoption of Update 2011-04 on January 1, 2012 (See Note 5). The adoption had no material impact on the Partnership’s financial position or results of operations.

NOTE 3 — ASSET RETIREMENT OBLIGATION

The Partnership recognizes an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. It also recognizes a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The estimated liability is based on the MGP’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in cost estimates or remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. The associated asset retirement costs from revisions are capitalized as part of the carrying amount of the long-lived asset. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its oil and gas properties, the Partnership has determined that there are no other material retirement obligations associated with tangible long-lived assets.

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

	Three Months Ended March 31,
	2012		2011
Asset retirement obligation at beginning of period	$	2,100,000	$	1,880,200
Accretion expense		26,700		28,200
Asset retirement obligation at end of period	$	2,126,700	$	1,908,400

12

ATLAS AMERICA SERIES 26-2005 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

March 31, 2012

(Unaudited)

NOTE 4 — DERIVATIVE INSTRUMENTS

The MGP on behalf of the Partnership uses a number of different derivative instruments, principally swaps, collars and options, in connection with its commodity price risk management activities. The MGP enters into financial instruments to hedge forecasted natural gas, natural gas liquids (“NGL”), crude oil and condensate sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs, crude oil and condensate are sold. Under commodity-based swap agreements, the MGP receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not the obligation, to receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period.

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

Prior to the sale on February 17, 2011 of the Transferred Business, Atlas Energy, Inc. monetized its derivative instruments related to the Transferred Business. The monetized proceeds related to instruments that were originally put into place to hedge future natural gas and oil production of the Transferred Business, including production generated through its drilling partnerships. As of March 31, 2012 and December 31, 2011, the Partnership recorded a net receivable from the monetized derivative instruments of $128,500 and $145,800 in accounts receivable-affiliate, respectively, and $73,500 and $95,800 in long-term receivable-affiliate, respectively, with the corresponding net unrealized gains in accumulated other comprehensive income on the Partnership’s balance sheets, which will be allocated to natural gas and oil production revenue generated over the period of the original instruments’ term. Total monetized gains of $202,000 included in other comprehensive income were entirely offset with unrealized gains recognized in income due to natural gas and oil property impairments of $115,500 and $86,500 recognized in 2011 and prior periods, respectively. The unrealized gains of $115,500 and $86,500 are net of the MGP interest. In 2011, the MGP’s portion of the unrealized gains of $106,000 was written off as part of the terms of the acquisition of the Transferred Business as a non-cash distribution to the MGP. During the current year, $4,400 of monetized proceeds were recorded by the Partnership and allocated only to the limited partners.

The following table summarizes the gain or loss recognized in the statements of operations for effective derivative instruments for the three months ending March 31, 2012 and 2011:

	March 31,
	2012		2011
Gain recognized in accumulated OCI	$	—	$	133,300
Gain reclassified from accumulated OCI into net loss	$	20,700	$	148,300

13

ATLAS AMERICA SERIES 26-2005 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

March 31, 2012

(Unaudited)

NOTE 4 — DERIVATIVE INSTRUMENTS (Continued)

The MGP entered into natural gas and crude oil future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in natural gas prices and oil prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.

The Partnership recognized a gain of $110,600 for the three months ended March 31, 2011 on settled contracts covering natural gas and oil production for historical periods prior to the acquisition of the Transferred Business. These gains are included within gas and oil production revenue in the Partnership’s statements of operations. 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 months ended March 31, 2011 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

NOTE 5 — FAIR VALUE OF FINANCIAL INSTRUMENTS

The Partnership has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

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

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

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

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

The Partnership estimates the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates (see Note 3). Information for assets that were measured at fair value on a nonrecurring basis as of March 31, 2012 and December 31, 2011 were as follows:

	March 31,				December 31,
	2012				2011
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	2,126,700	$	2,126,700	$	2,100,000	$	2,100,000

14

ATLAS AMERICA SERIES 26-2005 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

March 31, 2012

(Unaudited)

NOTE 6 — TRANSACTIONS WITH ATLAS RESOURCES, LLC, AND ITS AFFILIATES

The Partnership has entered into the following significant transactions with its MGP and its affiliates as provided under its Partnership Agreement:

• Administrative costs which are included in general and administrative expenses in the Partnership’s statements of operations are payable at $75 per well per month. Administrative costs incurred for the three months ended March 31, 2012 and 2011 were $24,800 and $25,800, respectively.

• Monthly well supervision fees which are included in production expenses in the Partnership’s statements of operations are payable at $318 per well per month for operating and maintaining the wells. Well supervision fees incurred for the three months ended March 31, 2012 and 2011 were $103,800 and $108,100, respectively.

• Transportation fees which are included in production expenses in the Partnership’s statements of operations are generally payable at 13% of the natural gas sales price. Transportation fees incurred for the three months ended March 31, 2012 and 2011 were $34,500 and $41,400, respectively.

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

Subordination by Managing General Partner

Under the terms of the Partnership Agreement, the MGP may be required to subordinate up to 50% of its share of net production revenues so that the limited partners receive a return of at least 10% of their net subscriptions, determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution to the limited partners (September 2006).

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

General

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 “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP).

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

Our operating cash flows are generated from our wells, which produce natural gas and oil. Our produced natural gas and oil is then delivered to market through third-party gas gathering systems. We do not plan to sell any of our wells and will continue to produce them until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. No other wells will be drilled and no additional funds will be required for drilling.

15

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 March 31,
	2012			2011
Production revenues (in thousands):
Gas	$	215		$	344
Oil		56			38
Total	$	271		$	382
Production volumes:
Gas (mcf/day) (1)		759			626
Oil (bbls/day) (1)		7			5
Total (mcfe/day) (1)		801			656
Average sales prices: (2)
Gas (per mcf) (1) (3)	$	3.69		$	6.12
Oil (per bbl) (1) (4)	$	93.57		$	85.52
Average production costs:
As a percent of revenues		70	%		54	%
Per mcfe (1)	$	2.62		$	3.45
Depletion per mcfe	$	1.27		$	2.82

(1) “Mcf” represents thousand cubic feet, “mcfe” represents thousand cubic feet equivalent, and “bbls” represents barrels. Bbls are 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.

(3) Average gas prices are calculated by including in total revenue derivative gains previously recognized into income and dividing by the total volume for the period. Previously recognized derivative gains were $39,900 and $1,100 for the three months ended March 31, 2012 and 2011, respectively. The derivative gains are included in other comprehensive loss and resulted from prior period impairment charges.

(4) Average oil prices are calculated by including in total revenue derivative gains previously recognized into income and dividing by the total volume for the period. Previously recognized derivative losses were $300 and previously recognized derivative gains were $3,700 for the three months ended March 31, 2012 and 2011, respectively. The derivative gains and losses are included in other comprehensive loss and resulted from prior period impairment charges.

Natural Gas Revenues. Our natural gas revenues were $215,300 and $343,700 for the three months ended March 31, 2012 and 2011, respectively, a decrease of $128,400 (37%). The $128,400 decrease in natural gas revenues for the three months ended March 31, 2012 as compared to the prior year similar period was attributable to a $206,200 decrease in our natural gas sales prices after the effect of financial hedges, which are driven by market conditions, partially offset by a $77,800 increase in production volumes. Our production volumes increased to 759 mcf per day for the three months ended March 31, 2012 from 626 mcf per day for the three months ended March 31, 2011, an increase of 133 mcf per day (21%). Production increased due to an increase in available pipeline capacity.

Oil Revenues. We drill wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $55,800 and $37,800 for the three months ended March 31, 2012 and 2011, respectively, an increase of $18,000 (48%). The $18,000 increase in oil revenues for the three months ended March 31, 2012 as compared to the prior year similar period was attributable to a $8,500 increase in oil prices after the effect of financial hedges and a $9,500 increase in production volumes. Our production volumes increased to 7 bbls per day for the three months ended March 31, 2012 from 5 bbls per day for the three months ended March 31, 2011, an increase of 2 bbls per day (40%).

16

Costs and Expenses. Production expenses were $190,200 and $204,400 for the three months ended March 31, 2012 and 2011, respectively, a decrease of $14,200 (7%). The decrease for the three months ended March 31, 2012 as compared to the prior year similar period was primarily attributable to a decrease in transportation fees, which are affected by a decrease in the price of natural gas, and a decrease in variable expenses.

Depletion of oil and gas properties as a percentage of oil and gas revenues was 34% and 44% for the three months ended March 31, 2012 and 2011, respectively. These percentage changes are directly attributable to changes in revenues, oil and gas reserve quantities, product prices, production volumes and changes in the depletable cost basis of our oil and gas properties.

General and administrative expenses for the three months ended March 31, 2012 and 2011, were $44,900 and $47,900, respectively, a decrease of $3,000 (6%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP, and vary from year to year due to the timing and billing of the costs and services provided to us.

Liquidity and Capital Resources

Cash provided by operating activities decreased $120,100 in the three months ended March 31, 2012 to $168,800 as compared to $288,900 for the three months ended March 31, 2011. This decrease was due to a decrease in net earnings before depletion, net non-cash loss on derivative values and accretion of $58,400 and a decrease in the change in accounts receivable-affiliate of $72,100. In addition, the change in accrued liabilities increased operating cash flows by $10,400 for the three months ended March 31, 2012 compared to the three months ended March 31, 2011.

Cash used in investing activities was $7,500 for the three months ended March 31, 2011 resulting from the purchase of tangible equipment.

Cash used in financing activities decreased $84,500 during the three months ended March 31, 2012 to $196,200 from $280,700 for the three months ended March 31, 2011. This decrease was due to a decrease in cash distributions.

Our MGP may withhold funds for future plugging and abandonment costs. Any additional funds, if required, will be obtained from production revenues or borrowings from our MGP or its affiliates, which are not contractually committed to make loans to us. The amount that we may borrow may not at any time exceed 5% of our total subscriptions, and we will not borrow from third-parties.

We believe that our future cash flows from operations and amounts available from borrowings from our MGP or its affiliates, if any, will be adequate to fund our operations.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. On an on-going basis, we evaluate our estimates, including those related to our asset retirement obligations, depletion and certain accrued receivables and liabilities. We base our estimates on historical experience and on various other assumptions that we believe reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. A discussion of our significant accounting policies we have adopted and followed in the preparation of our financial statements is included within “Notes to Financial Statements” in Part I, Item 1, “Financial Statements” in this quarterly report and in our Annual Report on Form 10-K for the year ended December 31, 2011.

17

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

Under the supervision of our Chairman of the Board of Directors, Chief Executive Officer, President, and Chief Financial Officer, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, concluded that, at March 31, 2012, 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 effect, our internal control over financial reporting.

PART II OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The Managing General Partner is not aware of any legal proceedings filed against the Partnership.

Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of their collective business. The MGP 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
4.0	Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Series 26-2005 L.P. (1)
31.1	Certification Pursuant to Rule 13a-14/15(d)-14
31.2	Certification Pursuant to Rule 13a-14/15(d)-14
32.1	Section 1350 Certification
32.2	Section 1350 Certification
101	Interactive Data File

(1) Filed on April 28, 2006 in the Form S-1 Registration Statement dated April 28, 2006, File No. 000-51945

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 26-2005 L.P.
	ATLAS RESOURCES, LLC, Managing General Partner
Date: May 14, 2012	By:/s/ FREDDIE M. KOTEK
	Freddie M. Kotek, Chairman of the Board of Directors, Chief Executive Officer and President

In accordance with the Exchange Act, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date: May 14, 2012	By:/s/ SEAN P. MCGRATH
	Sean P. McGrath, Chief Financial Officer

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 March 31, 2012 of Atlas America Series 26-2005 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 of the Managing General Partner
Date:	May 14, 2012

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Sean P. McGrath, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended March 31, 2012 of Atlas America Series 26-2005 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) valuated 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/ SEAN P. MCGRATH
Name:	Sean P. McGrath
Title:	Chief Financial Officer of the Managing General Partner
Date:	May 14, 2012

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 26-2005 L.P. (the “Partnership”) on Form 10-Q for the period ended March 31, 2012 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 of the Managing General Partner
Date:	May 14, 2012

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 26-2005 L.P. (the “Partnership”) on Form 10-Q for the period ended March 31, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Matthew A. Jones, Chief Financial Officer of the Partnership, 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/ SEAN P. MCGRATH
Name:	Sean P. McGrath
Title:	Chief Financial Officer of the Managing General Partner
Date:	May 14, 2012

XML

Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2012

Summary of Significant Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

In addition to matters discussed further in this note, the Partnership's significant accounting policies are detailed in its audited financial statements and notes thereto in the Partnership's annual report on Form 10-K for the year ended December 31, 2011 filed with the Securities and Exchange Commission ("SEC").

Use of Estimates

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

The natural gas industry principally conducts its business by processing actual transactions as much as 60 days after the month of delivery. Consequently, the most recent two months' financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following months' financial results. Management believes that the operating results presented for the three months ended March 31, 2012 and 2011 represent actual results in all material respects (see "Revenue Recognition" accounting policy for further description).

Accounts Receivable and Allowance for Possible Losses

In evaluating the need for an allowance for possible losses, the MGP performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customers' current creditworthiness as determined by review of its customers' credit information. Credit is extended on an unsecured basis to many of its energy customers. At March 31, 2012 and December 31, 2011, the Partnership's MGP's credit evaluation indicated that the Partnership had no need for an allowance for possible losses.

Oil and Gas Properties

Oil and gas properties are stated at cost. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized.

The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Oil is converted to gas equivalent basis ("Mcfe") at the rate of one barrel of oil to six Mcf of natural gas.

The Partnership's depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties. The Partnership recorded depletion expense on natural gas and oil properties of $92,500 and $167,200 for the three months ended March 31, 2012 and 2011, respectively.

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

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

	March  31, 2012			December  31, 2011
Proved properties:
Leasehold interests	$	1,110,900		$	1,110,900
Wells and related equipment		44,175,700			44,175,700
		45,286,600			45,286,600
Accumulated depletion and impairment		(40,775,400	)		(40,682,900	)
Oil and gas properties, net	$	4,511,200		$	4,603,700

Impairment of Long-Lived Assets

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

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

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

In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. The Partnership may have to pay additional consideration in the future as a well becomes uneconomic under the terms of the Partnership Agreement in order to recover these reserves. There was no impairment charge recognized during the three months ended March 31, 2012. During the year ended December 31, 2011, the Partnership recognized an impairment charge of $4,331,800, net of an offsetting gain in accumulated other comprehensive income of $147,200.

Working Interest

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

Revenue Recognition

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

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGL's, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership's records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see "Use of Estimates" accounting policy for further description). The Partnership had unbilled revenues at March 31, 2012 and December 31, 2011 of $155,900 and $224,100, respectively, which were included in accounts receivable-affiliate within the Partnership's balance sheets.

Comprehensive Loss

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

Recently Adopted Accounting Standards

In December 2011, the FASB issued Accounting Standards Update ("ASU") 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 ("Update 2011-12"). The amendments in this update effectively defer implementation of changes made in Update 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income ("Update 2011-05"), related to the presentation of reclassification adjustments out of accumulated other comprehensive income. Under Update 2011-05 which was issued by the FASB in June 2011, entities are provided the option to present the total of comprehensive income, the components of net income and the components of other comprehensive income in either a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with a total net income, each component of other comprehensive income and a total amount for comprehensive income. Update 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders' equity. As a result of Update 2011-12, entities are required to disclose reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect prior to Update 2011-05. All other requirements in Update 2011-05 are not affected by Update 2011-12. These requirements are effective for interim and annual reporting periods beginning after December 15, 2011. Accordingly, entities are not required to comply with presentation requirements of Update 2011-05 related to the disclosure of reclassifications out of accumulated other comprehensive income. The Partnership included separate but consecutive statements of income and comprehensive income within its Form 10-Qs upon the adoption of these ASUs on January 1, 2012. The adoption had no material impact on the Partnership's financial condition or results of operations.

In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosure about Offsetting Assets and Liabilities ("Update 2011-11"). The amendments in this update require an entity to disclose both gross and net information about both financial and derivative instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the statement of financial position. An entity shall disclose at the end of a reporting period certain quantitative information separately for assets and liabilities that are within the scope of Update 2011-11, as well as provide a description of the rights of setoff associated with an entity's recognized assets and recognized liabilities subject to an enforceable master netting arrangement or similar agreement. Entities are required to implement the amendments for interim and annual reporting periods beginning after January 1, 2013 and shall be applied retrospectively for any period presented that begins before the date of initial application. The Partnership has elected to early adopt these requirements and updated its disclosures to meet these requirements effective January 1, 2012. The adoption had no material impact on the Partnership's financial position or results of operations.

In May 2011, the FASB issued ASU 2011-04, Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs ("Update 2011-04"). The amendments in Update 2011-04 revise the wording used to describe many of the requirements for measuring fair value and for disclosing information about fair value measurements in U.S. GAAP. For many of the amendments, the guidance is not necessarily intended to result in a change in the application of the requirements in Topic 820; rather it is intended to clarify the intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. As a result, Update 2011-04 aims to provide common fair value measurement and disclosure requirements in U.S. GAAP and International Financial Reporting Standards. These requirements are effective for interim and annual reporting periods beginning after December 15, 2011. The Partnership updated its disclosures to meet these requirements upon the adoption of Update 2011-04 on January 1, 2012 (See Note 5). The adoption had no material impact on the Partnership's financial position or results of operations.

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Description of Business

3 Months Ended

Mar. 31, 2012

Description of Business [Abstract]

DESCRIPTION OF BUSINESS

NOTE 1 — DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

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 "MGP"). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. ("ARP") (NYSE: ARP).

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

In March 2012, Atlas Energy contributed to ARP, a newly formed exploration and production master limited partnership, substantially all of Atlas Energy's natural gas and oil development and production assets and its partnership management business, including ownership of our MGP. Atlas Energy also distributed an approximate 19.6% limited partner interest in ARP to its unitholders, retaining a 78.4% limited partner interest. Atlas Energy also owns ARP's general partner, which owns a 2% general partner interest and all of the incentive distribution rights in ARP.

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

Our operating cash flows are generated from our wells, which produce natural gas and oil. Our produced natural gas and oil is then delivered to market through third-party gas gathering systems. We do not plan to sell any of our wells and will continue to produce them until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. No other wells will be drilled and no additional funds will be required for drilling.

The accompanying financial statements, which are unaudited except that the balance sheet at December 31, 2011 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States of America ("U.S. GAAP") for interim reporting. They do not include all disclosures normally made in financial statements contained in the Form 10-K. These interim financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2011. The results of operations for the three months ended March 31, 2012 may not necessarily be indicative of the results of operations for the year ended December 31, 2012.

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Balance Sheets (USD $)	Mar. 31, 2012	Dec. 31, 2011
ASSETS
Cash and cash equivalents	$ 44,200	$ 71,600
Accounts receivable-affiliate	331,500	430,200
Total current assets	375,700	501,800
Oil and gas properties, net	4,511,200	4,603,700
Long-term receivable affiliate	73,500	95,800
TOTAL ASSETS	4,960,400	5,201,300
LIABILITIES AND PARTNERS' CAPITAL
Accrued liabilities	19,500	7,700
Total current liabilities	19,500	7,700
Asset retirement obligation	2,126,700	2,100,000
Partners' capital:
Managing general partner	1,342,100	1,406,500
Limited partners (1,400 units)	1,472,100	1,687,100
Accumulated other comprehensive income	0	0
Total partners' capital	2,814,200	3,093,600
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$ 4,960,400	$ 5,201,300

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Statement of Changes in Partners' Capital (USD $)	Managing General Partner [Member]	Limited Partners [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Total
Balance at Dec. 31, 2011	$ 1,406,500	$ 1,687,100	$ 0	$ 3,093,600
Participation in revenues and costs and expenses:
Net production revenues	27,600	53,300		80,900
Depletion	(18,500)	(74,000)		(92,500)
Accretion of asset retirement obligation	(9,600)	(17,100)		(26,700)
General and administrative	(16,200)	(28,700)		(44,900)
Net loss	(16,700)	(66,500)		(83,200)
Other comprehensive income (loss)			0	0
Distributions to partners	(47,700)	(148,500)		(196,200)
Balance at Mar. 31, 2012	$ 1,342,100	$ 1,472,100	$ 0	$ 2,814,200

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Statements of Cash Flows (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Cash flows from operating activities:
Net loss	$ (83,200)	$ (66,200)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion	92,500	167,200
Non cash loss on derivative value	39,600	4,800
Accretion of asset retirement obligation	26,700	28,200
Decrease in accounts receivable-affiliate	81,400	153,500
Increase in accrued liabilities	11,800	1,400
Net cash provided by operating activities	168,800	288,900
Cash flows from investing activities:
Purchase of tangible equipment	0	(7,500)
Net cash used in investing activities	0	(7,500)
Cash flows from financing activities:
Distributions to partners	(196,200)	(280,700)
Net cash used in financing activities	(196,200)	(280,700)
Net (decrease) increase in cash and cash equivalents	(27,400)	700
Cash and cash equivalents at beginning of period	71,600	105,500
Cash and cash equivalents at end of period	44,200	106,200
Supplement Schedule of non-cash operating and financing activities:
Distribution to managing general partner	$ 0	$ 106,000

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Balance Sheets (Parenthetical)	Mar. 31, 2012	Dec. 31, 2011
Balance Sheets
Limited Partners' Units	1,400	1,400

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Document and Entity Information	3 Months Ended
	Mar. 31, 2012
Document and Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q1
Entity Registrant Name	Atlas America Series 26-2005 L.P.
Entity Central Index Key	0001342514
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding	1,400

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Statements of Operations (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
REVENUES
Natural gas and oil	$ 271,100	$ 381,500
Total revenues	271,100	381,500
COSTS AND EXPENSES
Production	190,200	204,400
Depletion	92,500	167,200
Accretion of asset retirement obligation	26,700	28,200
General and administrative	44,900	47,900
Total costs and expenses	354,300	447,700
Net loss	(83,200)	(66,200)
Allocation of net loss:
Managing general partner	(16,700)	(5,000)
Limited partners	$ (66,500)	$ (61,200)
Net loss per limited partnership unit	$ (48)	$ (44)

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Fair Value of Financial Instruments

3 Months Ended

Mar. 31, 2012

Fair Value of Financial Instruments [Abstract]

FAIR VALUE OF FINANCIAL INSTRUMENTS

NOTE 5 — FAIR VALUE OF FINANCIAL INSTRUMENTS

The Partnership has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

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

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

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

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

The Partnership estimates the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates (see Note 3). Information for assets that were measured at fair value on a nonrecurring basis as of March 31, 2012 and December 31, 2011 were as follows:

	March 31,				December 31,
	2012				2011
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	2,126,700	$	2,126,700	$	2,100,000	$	2,100,000

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Derivative Instruments

3 Months Ended

Mar. 31, 2012

Derivative Instruments [Abstract]

DERIVATIVE INSTRUMENTS

NOTE 4 — DERIVATIVE INSTRUMENTS

The MGP on behalf of the Partnership uses a number of different derivative instruments, principally swaps, collars and options, in connection with its commodity price risk management activities. The MGP enters into financial instruments to hedge forecasted natural gas, natural gas liquids ("NGL"), crude oil and condensate sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs, crude oil and condensate are sold. Under commodity-based swap agreements, the MGP receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not the obligation, to receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period.

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

Prior to the sale on February 17, 2011 of the Transferred Business, Atlas Energy, Inc. monetized its derivative instruments related to the Transferred Business. The monetized proceeds related to instruments that were originally put into place to hedge future natural gas and oil production of the Transferred Business, including production generated through its drilling partnerships. As of March 31, 2012 and December 31, 2011, the Partnership recorded a net receivable from the monetized derivative instruments of $128,500 and $145,800 in accounts receivable-affiliate, respectively, and $73,500 and $95,800 in long-term receivable-affiliate, respectively, with the corresponding net unrealized gains in accumulated other comprehensive income on the Partnership's balance sheets, which will be allocated to natural gas and oil production revenue generated over the period of the original instruments' term. Total monetized gains of $202,000 included in other comprehensive income were entirely offset with unrealized gains recognized in income due to natural gas and oil property impairments of $115,500 and $86,500 recognized in 2011 and prior periods, respectively. The unrealized gains of $115,500 and $86,500 are net of the MGP interest. In 2011, the MGP's portion of the unrealized gains of $106,000 was written off as part of the terms of the acquisition of the Transferred Business as a non-cash distribution to the MGP. During the current year, $4,400 of monetized proceeds were recorded by the Partnership and allocated only to the limited partners.

The following table summarizes the gain or loss recognized in the statements of operations for effective derivative instruments for the three months ending March 31, 2012 and 2011:

	March 31,
	2012		2011
Gain recognized in accumulated OCI	$	—	$	133,300
Gain reclassified from accumulated OCI into net loss	$	20,700	$	148,300

The MGP entered into natural gas and crude oil future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in natural gas prices and oil prices. At any point in time, such contracts may include regulated New York Mercantile Exchange ("NYMEX") futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. Crude oil contracts are based on a West Texas Intermediate ("WTI") index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.

The Partnership recognized a gain of $110,600 for the three months ended March 31, 2011 on settled contracts covering natural gas and oil production for historical periods prior to the acquisition of the Transferred Business. These gains are included within gas and oil production revenue in the Partnership's statements of operations. 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 months ended March 31, 2011 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

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Transactions With Atlas Resources, LLC, And Its Affiliates

3 Months Ended

Mar. 31, 2012

Transactions With Atlas Resources, LLC, And Its Affiliates [Abstract]

TRANSACTIONS WITH ATLAS RESOURCES, LLC AND ITS AFFILIATES

NOTE 6 — TRANSACTIONS WITH ATLAS RESOURCES, LLC, AND ITS AFFILIATES

The Partnership has entered into the following significant transactions with its MGP and its affiliates as provided under its Partnership Agreement:

• Administrative costs which are included in general and administrative expenses in the Partnership's statements of operations are payable at $75 per well per month. Administrative costs incurred for the three months ended March 31, 2012 and 2011 were $24,800 and $25,800, respectively.

• Monthly well supervision fees which are included in production expenses in the Partnership's statements of operations are payable at $318 per well per month for operating and maintaining the wells. Well supervision fees incurred for the three months ended March 31, 2012 and 2011 were $103,800 and $108,100, respectively.

• Transportation fees which are included in production expenses in the Partnership's statements of operations are generally payable at 13% of the natural gas sales price. Transportation fees incurred for the three months ended March 31, 2012 and 2011 were $34,500 and $41,400, respectively.

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

Subordination by Managing General Partner

Under the terms of the Partnership Agreement, the MGP may be required to subordinate up to 50% of its share of net production revenues so that the limited partners receive a return of at least 10% of their net subscriptions, determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution to the limited partners (September 2006).

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Statements of Comprehensive Loss (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Statements of Comprehensive Loss
Net loss	$ (83,200)	$ (66,200)
Other comprehensive loss:
Unrealized holding gain on hedging contracts	0	133,300
Difference in estimated monetized gains receivable	20,700	0
Less: reclassification adjustment for gains realized in net loss	(20,700)	(148,300)
Total other comprehensive loss	0	(15,000)
Comprehensive loss	$ (83,200)	$ (81,200)

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Asset Retirement Obligation

3 Months Ended

Mar. 31, 2012

Asset Retirement Obligation [Abstract]

ASSET RETIREMENT OBLIGATION

NOTE 3 — ASSET RETIREMENT OBLIGATION

The Partnership recognizes an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. It also recognizes a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The estimated liability is based on the MGP's historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in cost estimates or remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. The associated asset retirement costs from revisions are capitalized as part of the carrying amount of the long-lived asset. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its oil and gas properties, the Partnership has determined that there are no other material retirement obligations associated with tangible long-lived assets.

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

	Three Months Ended March 31,
	2012		2011
Asset retirement obligation at beginning of period	$	2,100,000	$	1,880,200
Accretion expense		26,700		28,200
Asset retirement obligation at end of period	$	2,126,700	$	1,908,400