Form 10-K

United States
Securities and Exchange Commission

Washington, D.C. 20549

Form 10-K

(Mark One)


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

For the fiscal year ended December 31, 2009


o		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 0-51945

ATLAS AMERICA SERIES 26-2005 L.P.

(Exact name of registrant as specified in its charter)


Delaware		20-2879859
(State or other jurisdiction of		(I.R.S. Employer
Incorporation or organization)		Identification No.)

Westpointe Corporate Center One
1550 Coraopolis Heights Road, 2nd Floor
Moon Township, PA		15108
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number (412) 262-2830

Securities registered under Section 12(b) of the Exchange Act.


Title of each class		Name of each exchange on which registered
None		None

Securities registered under Section 12(g) of the Exchange Act: Investor General Partner Units and Limited Partner Units

(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K þ

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 o		Accelerated filer o		Non-accelerated filer o		Smaller reporting company þ

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

DOCUMENTS INCORPORATED BY REFERENCE: None

The matters discussed within this report include forward-looking statements. These statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “should,” or “will,” or the negative thereof or other variations thereon or comparable terminology. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this report are forward-looking statements. We have based these forward-looking statements on our current expectations, assumptions, estimates and projections. While we believe these expectations, assumptions, estimates and projections are reasonable, such forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control. These and other important factors may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements.

PART I

ITEM 1. DESCRIPTION OF BUSINESS

General. We were formed as a Delaware limited partnership on May 26, 2005 with Atlas Resources, Inc. as our Managing General Partner or MGP. In March 2006, Atlas Resources, Inc. merged into a newly-formed limited liability company, Atlas Resources, LLC, which is an indirect subsidiary of Atlas Energy, Inc. (NASDAQ:ATLS) or Atlas Energy.

Atlas Energy’s focus is on the development and production of natural gas and oil in the Appalachian Basin, Michigan Basin and Illinois Basin regions of the United States of America. Atlas Energy is also a leading sponsor of and manages tax-advantaged direct investment partnerships, in which it co-invests to finance the exploitation and development of its acreage. Atlas Energy Resources, LLC is managed by Atlas Energy Management, Inc., through which Atlas Energy, Inc. provides Atlas Energy Resources, LLC with the personnel necessary to manage its assets and raise capital.

We 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, Inc. for administrative services. See Item 11 “Executive Compensation.”

We received total cash subscriptions from investors of $34,886,500, which were paid to our MGP acting as operator and general drilling contractor under our drilling and operating agreements. Our MGP contributed leases, tangible equipment, and paid all syndication and offering costs for a total capital contribution of $14,779,500. We have drilled 144 developmental wells to the Clinton/Medina, Upper Devonian Sandstones and Southern Appalachia Shale geological formations in Pennsylvania and Tennessee.

Our wells are currently producing natural gas and oil, which are our only products. Most of our gas is gathered and delivered to market through Laurel Mountain Midstream, LLC’s gas gathering system, a newly formed joint-venture between Atlas Energy, Inc.’s affiliate, Atlas Pipeline Partners L.P. (NYSE: APL), and The Williams Companies Inc. (NYSE: WMB).

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. See Item 2 “Properties” for information concerning our wells.

Our ongoing operating and maintenance costs have been and are expected to be fulfilled through revenues from the sale of our natural gas and oil production. We pay our MGP a monthly well supervision fee of $318 per well, as outlined in our drilling and operating agreement. This well supervision fee covers all normal and regularly recurring operating expenses for the production and sale of natural gas and oil, such as:

•

well tending, routine maintenance and adjustment;

•

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

•

preparation of reports for us and government agencies.

The well supervision fees, however, do not include costs and expenses related to the purchase of certain equipment, materials and brine disposal. If these expenses are incurred, we pay cost for third-party services, materials, and a reasonable charge for services performed directly by our MGP or its affiliates. Also, beginning one year after each of our wells has been placed into production our MGP, as operator, may retain $200 per month per well to cover the estimated future plugging and abandonment costs of the well. At December 31, 2009, our MGP had not withheld any funds for this purpose.

Markets and Competition. The availability of a ready market for natural gas and oil produced by us, and the price obtained, depends on numerous factors beyond our control, including the extent of domestic production, imports of foreign natural gas and oil, political instability or terrorist acts in oil and gas producing countries and regions, market demand, competition from other energy sources, the effect of federal regulation on the sale of natural gas and oil in interstate commerce, other governmental regulation of the production and transportation of natural gas and oil and the proximity, availability and capacity of pipelines and other required facilities. Our MGP is responsible for selling our natural gas production. Our natural gas is sold as discussed in Item 2 “Properties.” During 2009 and 2008, we experienced no problems in selling our natural gas and oil. Product availability and price are the principal means of competition in selling natural gas and oil production.

While it is impossible to accurately determine our comparative position in the industry, we do not consider our operations to be a significant factor in the industry. See Item 2 “Properties” regarding the marketing of our natural gas and oil.

Governmental Regulation. The energy industry in general is heavily regulated by federal and state authorities, including regulation of production, environmental quality and pollution control. The intent of federal and state regulations generally is to prevent waste, protect rights to produce natural gas and oil between owners in a common reservoir and control contamination of the environment. Failure to comply with regulatory requirements can result in substantial fines and other penalties. The following discussion of the regulation of the United States of America energy industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental orders to which our operations may be subject.

Regulation of oil and gas producing activities. State regulatory agencies where a producing natural gas well is located provide a comprehensive statutory and regulatory scheme for oil and gas operations such as ours including supervising the production activities and the transportation of natural gas sold in intrastate markets. Our oil and gas operations in Pennsylvania are regulated by the Department of Environmental Resources, Division of Oil and Gas, our oil and gas operations in Tennessee are regulated by the Tennessee Department of Environment and Conservation and the Division of Geology.

Among other things, these regulations involve:

•

new well permit and well registration requirements, procedures and fees;

•

minimum well spacing requirements;

•

restriction on well locations and underground gas storage;

•

certain well site restoration, groundwater protection and safety measures;

•

landowner notification requirements;

•

certain bonding or other security measures;

•

various reporting requirements;

•

well plugging standards and procedures; and

•

broad enforcement powers.

Environmental and Safety Regulation. Under the Comprehensive Environmental Response, Compensation and Liability Act, the Toxic Substances Control Act, the Resource Conservation and Recovery Act, the Oil Pollution Act of 1990, the Clean Air Act, and other federal and state laws relating to the environment, owners and operators of wells producing natural gas or oil can be liable for fines, penalties and clean-up costs for pollution caused by the wells. Moreover, the owners or operators’ liability can extend to pollution costs from situations that occurred prior to their acquisition of the assets. State public utility regulators have either adopted federal standards or promulgated their own safety requirements consistent with the federal regulations.

We believe we have complied in all material respects with applicable federal and state regulations and do not expect that these regulations will have a material adverse impact on our operations. Our producing activities also must comply with various federal, state and local laws not mentioned, including those covering the discharge of materials into the environment, or otherwise relating to the protection of the environment.

Where can you find more information. We file a Form 10-K Annual Report and Form 10-Q Quarterly Reports as well as other non-recurring special purpose reports with the Securities and Exchange Commission. A complete list of our filings is available on the Securities and Exchange Commission’s website at www.sec.gov. Any of our filings are also available at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The Public Reference Room may be contacted at 1-800- SEC-0330 for further information.

Additionally, our MGP will provide copies of any of these reports to you without charge. Such requests should be made to:

Atlas America Series 26-2005 L.P.
Westpointe Corporate Center One
1550 Coraopolis Heights Road, 2nd Floor
Moon Township, PA 15108

ITEM 2. DESCRIPTION OF PROPERTIES

Drilling Activity. For the years ended December 31, 2009 and 2008, we did not drill any wells nor do we expect to do so in future years.

Summary of Producing Wells. The table below presents the number of producing gross and net wells at December 31, 2009, in which we have a working interest. All wells are located in the Appalachian Basin.


	Number of Producing Wells
	Gross		Net
Gas		133		123.53
Oil		9		9.00

Total		142		132.53

Production. The following table presents the quantities of natural gas and oil we produced (net to our interest), our average sales price, and our average production (lifting) cost per equivalent unit of production for the period indicated.


									Average
Year									Production Cost
Ended	Production				Average Sales Price				(Lifting Cost)
December 31,	Oil (bbls)⁽¹⁾		Gas (mcf)⁽¹⁾		per bbl^{(1) (3) (5)}		per mcf^{(1) (3) (4)}		per mcfe^{(1) (2)}
2009		4,200		396,800	$	61.01	$	7.81	$	2.58
2008		4,800		596,600	$	98.60	$	9.52	$	2.27


(1)		“Mcf” represents one thousand cubic feet of natural gas. “Mcfe” represents a thousand cubic feet equivalent. Oil production is converted to mcfe at the rate of six mcf per barrel (“bbl”).

(2)		Lifting costs include labor to operate the wells and related equipment, repairs and maintenance, materials and supplies, property taxes, insurance and gathering charges.

(3)		Average sales prices represent accrual basis pricing after reversing the effect of previously recognized gains resulting from prior period impairment charges.

(4)		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 $957,700 for the year ended December 31, 2009. The derivative gains are included in other comprehensive income and resulted from prior period impairment charges.

(5)		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 gains were $37,600 for the year ended December 31, 2009. The derivative gains are included in other comprehensive income and resulted from prior period impairment charges.

Natural Gas and Oil Reserve Information. In December 2008, the Securities and Exchange Commission (“SEC”) approved revisions to its oil and gas reporting disclosures by adopting amendments to Rule 4-10 of Regulation S-X and Items 201, 801, and 802 of Regulation S-K effective for fiscal years ending on or after December 31, 2009. These new disclosure requirements are referred to as “Modernization of Oil and Gas Reporting” and include provisions that:

•

Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.

•

Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end pricing. This should maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date.

•

Permit companies to disclose their probable and possible reserves on a voluntary basis. Current rules limit disclosure to only proved reserves.

•

Update and revise reserve definitions to reflect changes in the oil and gas industry and new technologies. New updated definitions include “by geographic area” and “reasonable certainty.”

•

Permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.

•

Require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures are required related to internal controls over reserve estimation, as well as a report addressing the independence and qualifications of a company’s reserves preparer or auditor based on Society of Petroleum Engineers’ criteria.

We have complied with these disclosure requirements for the year ended December 31, 2009.

The following tables summarize information regarding our estimated proved natural gas and oil reserves as of the dates indicated. Proved reserves are the estimated quantities of crude oil and natural gas, which, by an analysis of geological and engineering data, can be estimated with reasonable certainty to be recoverable in future years from known reservoirs under existing economic conditions, operating methods and government regulations (i.e., prices and costs as of the date the estimate is made). Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. The estimated reserves include reserves attributable to our direct ownership interests in oil and gas properties. For the year ended December 31, 2009, we based our estimates of proved reserves on the 12-month unweighted average price of the first-day-of-the-month price for each calendar month 2009 and then applied any basis and British Thermal Units (“btu”) differentials specifically applicable to each oil and gas property based on location and pricing details. For the year ended December 31, 2008, we based our estimates of proved reserves using the natural gas and oil prices as of December 31, 2008 of the respective year. The following table summarizes the natural gas and oil prices used in the estimation of proved reserves:


	December 31,
	2009		2008
Natural gas (per mcf)	$	3.87	$	5.71
Oil (per bbl)		61.18		44.80

Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas and oil reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The preparation of our natural gas and oil reserve estimates were completed in accordance with our prescribed internal control procedures, which include verification of input data delivered to our third-party reserve specialist, as well as a multi-functional management review. For the year ended December 31, 2009, we retained Wright & Company, Inc., a third-party, independent petroleum engineering firm, to prepare a report of proved reserves. The reserves report included a detailed review of our properties. Wright & Company’s evaluation was based on more than 35 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations applicable as of December 31, 2009. The Wright & Company report, including the qualifications of the chief technical person responsible for the report, was prepared in accordance with generally accepted petroleum engineering and evaluation principles and is attached as Exhibit 99.1 to this Annual Report on Form 10-K. Results of production subsequent to the date of the estimate may justify revision of this estimate. Future prices received from the sale of natural gas and oil may be different from those estimated by our independent petroleum engineering firm in preparing their reports. The amounts and timing of future operating costs may also differ from those used. Accordingly, the reserves set forth in the following tables ultimately may not be produced and the proved undeveloped reserves may not be developed within the periods anticipated. You should not construe the estimated PV-10 and standardized measure values as representative of the current or future fair market value of our proved natural gas and oil properties. PV-10 and standardized measure values are based upon projected cash inflows, which do not provide for changes in natural gas and oil prices or for the escalation of expenses. The meaningfulness of these estimates depends upon the accuracy of the assumptions upon which they were based.

We evaluate natural gas reserves at constant temperature and pressure. A change in either of these factors can affect the measurement of natural gas reserves. We deducted when applicable, operating costs, development costs and production-related and ad valorem taxes in arriving at the estimated future cash flows. The following table presents our reserve information for the previous two years. We base the estimates on operating methods and conditions prevailing as of the dates indicated:


	At December 31,
	2009		2008

Natural gas reserves – Proved Reserves (Mcf) (1)(4):
Proved developed reserves (2)		2,721,400		3,907,700

Total proved reserves of natural gas		2,721,400		3,907,700

Oil reserves – Proved Reserves (Bbl) (1)(4):
Proved developed reserves (2)		12,200		20,300

Total proved reserves of oil		12,200		20,300

Total proved reserves (Mcfe)		2,794,600		4,029,500


PV-10 estimate of cash flows of proved reserves (3)(4):
Proved developed reserves	$	3,504,900	$	8,081,500

Total PV-10 estimate	$	3,504,900	$	8,081,500

PV-10 estimate per limited partner unit (5)	$	1,599	$	3,619

Undiscounted estimate per limited partner unit (5)	$	2,588	$	6,151


(1)		“Proved reserves” generally refers to the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Reservoirs are considered proved if economic production is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes: that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data.

(2)		“Proved developed reserves” generally refers to reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

(3)		The present value of estimated future net cash flows is calculated by discounting estimated future net cash flows by 10% annually.

(4)		Please see Regulation S-X rule 4-10 for complete definitions of each reserve category.

(5)		This value per $25,000 unit is determined by following the methodology used for determining our proved reserves using the data discussed above. However, this value does not necessarily reflect the fair market value of a unit, and each unit is illiquid. Also, the value of a unit for purposes of presentment of the unit to our managing general partner for purchase is different, because it is calculated under a formula set forth in the partnership agreement.

We have not filed any estimates of our gas and oil reserves with, nor were such estimates included in any reports to, any Federal or foreign governmental agency other than the SEC within the 12 months before the date of this filing.

Title to Properties. We believe that we hold good and indefeasible title to our properties in accordance with standards generally accepted in the natural gas industry, subject to exceptions stated in the opinions of counsel employed by us in the various areas in which we conduct our activities. We do not believe that these exceptions detract substantially from our use of any property. As is customary in the natural gas industry, our MGP conducts only a perfunctory title examination at the time it acquires a property. Before our MGP commences drilling operations, it conducts an extensive title examination and performs curative work on defects that it deems significant. Our MGP has obtained title examinations for substantially all of our producing properties. No single property represents a material portion of our holdings.

Our properties are subject to royalty, overriding royalty and other outstanding interests customary in the natural gas industry. Our properties are also subject to burdens such as liens incident to operating agreements, taxes, development obligations under natural gas and oil leases, farm-out arrangements and other encumbrances, easements and restrictions. We do not believe that any of these burdens will materially interfere with our use of our properties.

Acreage. The table below presents, by state, the estimated acres of developed oil and gas acreage in which we had an interest at December 31, 2009. There was no undeveloped acreage at December 31, 2009.


	Developed Acreage
Location	Gross⁽¹⁾		Net⁽²⁾
Pennsylvania		2,886		2,680
Tennessee		920		841

Total		3,806		3,521


(1)		A “gross” acre is an acre in which we own a working interest.

(2)		A “net” acre represents the actual working interest we own in one gross acre divided by one hundred. For example, a 50% working interest in an acre is one gross acre, but a .50 net acre.

Delivery Commitments. Atlas Energy markets our natural gas, which is principally located in Fayette County, PA area, primarily to Colonial Energy, Inc., Atmos Energy Marketing LLC, South Jersey Resources Group, LLC, Conoco Phillips Company and to other third-party natural gas purchasers or marketers.

The pricing arrangements with Colonial Energy, Inc., Atmos Energy Marketing LLC, South Jersey Resources Group, LLC, Conoco Phillips Company and other third-party gas purchasers or marketers are tied to the New York Mercantile Exchange Commissions or NYMEX spot market contract price. The total price received for our gas is a combination of the monthly NYMEX spot price plus a basis adjustment. For example, the NYMEX spot price is the base price and there is an additional premium paid because of the location of the gas (the Appalachian Basin) in relation to the gas market, which is referred to as the “basis.”

Pricing for natural gas and oil has been volatile and uncertain for many years. The agreements with Colonial Energy, Inc., Atmos Energy Marketing LLC, South Jersey Resources Group, LLC, Conoco Phillips Company and the other third-party gas purchasers or marketers also permit Atlas Energy and its affiliates to implement gas forward sales transactions through those companies. Colonial Energy, Inc., Atmos Energy Marketing LLC, South Jersey Resources Group, LLC, Conoco Phillips Company and the other third-party purchasers or marketers also use NYMEX based financial instruments to hedge their pricing exposure and make price-hedging opportunities available to Atlas Energy, which then makes those arrangements available to us and its other partnerships. The price paid by Colonial Energy, Inc., Atmos Energy Marketing LLC, South Jersey Resources Group, LLC, Conoco Phillips Company and any other third-party purchasers for certain volumes of natural gas sold under these hedge agreements may be significantly different from the underlying monthly spot market price. Also, Atlas Energy’s hedges may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. The futures contracts employed by Atlas Energy are commitments to purchase or sell natural gas at future dates and generally cover one-month periods for up to six years in the future. The overall portion of our natural gas portfolio that is hedged changes from time to time.

To assure that all financial instruments will be used solely for hedging price risks and not for speculative purposes, Atlas Energy has established a committee to assure that all financial trading is done in compliance with Atlas Energy’s hedging policies and procedures. Atlas Energy does not intend to contract for positions that it cannot offset with actual production.

We are not required to provide any fixed and determinable quantities of gas under any agreement other than with Colonial Energy, Inc., Atmos Energy Marketing LLC, South Jersey Resources Group, LLC, Conoco Phillips Company and the other third-party gas purchasers or marketers.

ITEM 3. LEGAL PROCEEDINGS

The MGP is not aware of any legal proceedings filed against us.

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 4. (REMOVED AND RESERVED)

None.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED SECURITY HOLDER MATTERS

Market Information. There is no established public trading market for our units and we do not anticipate a market for our units will develop. Our units may be transferred only in accordance with the provisions of Article VI of our partnership agreement which requires:

•

our managing general partner consent;

•

the transfer not result in materially adverse tax consequences to us; and

•

the transfer not violate federal or state securities laws.

An assignee of a unit may become a substituted partner only upon meeting the following conditions:

•

the assignor gives the assignee the right;

•

our managing general partner consents to the substitution;

•

the assignee pays to us all costs and expenses incurred in connection with the substitution; and

•

the assignee executes and delivers the instruments, which our managing general partner requires to effect the substitution and to confirm his or her agreement to be bound by the terms of our partnership agreement.

A substitute partner is entitled to all of the rights of full ownership of the assigned units, including the right to vote.

Holders. As of December 31, 2009, we had 589 unit holders.

Distributions. Our MGP reviews our accounts monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any. We distribute those funds, which our MGP determines are not necessary for us to retain, to our partners. We will not advance or borrow funds for purposes of making distributions.

The determination of our revenues and costs is made in accordance with generally accepted accounting principles, consistently applied, and cash distributions to our MGP may only be made in conjunction with distributions to our limited partners.

During the years ended December 31, 2009 and 2008, we distributed the following:

	•		$1,942,700 and $3,474,800 to our limited partners; and

	•		$761,300 and $1,862,300 to our managing general partner, respectively.


ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION OR PLAN OF OPERATIONS

The following discussion provides information to assist in understanding our financial condition and result of operations. This discussion should be read in conjunction with our financial statements and related notes appearing elsewhere in this report.

General. We were formed as a Delaware limited partnership on May 26, 2005, with Atlas Resources, Inc. as our Managing General Partner, or MGP, to drill natural gas development wells. Our MGP is Atlas resources, LLC an indirect subsidiary of Atlas Energy, Inc. (NASDAQ:ATLS) or Atlas Energy. We have no current plans 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.

In March 2006, Atlas Resources, Inc. merged into a newly-formed limited liability company, Atlas Resources, LLC, which became an indirect subsidiary of Atlas Energy Resources, LLC, a newly-formed subsidiary of Atlas America, Inc. In December 2006, Atlas America, Inc. contributed substantially all of its natural gas and oil assets and its investment partnership management business to Atlas Energy Resources, LLC. On September 29, 2009 Atlas Energy Resources, LLC and Atlas America, Inc. merged, with Atlas Energy Resources, LLC becoming a wholly owned subsidiary of Atlas America, Inc. In addition, Atlas America, Inc. changed its name to Atlas Energy, Inc, (NASDAQ: ATLS). Atlas Resources, LLC serves as our MGP.

Atlas Energy’s focus is on the development and production of natural gas and oil in the Appalachian Basin, Michigan Basin and the Illinois Basin, regions of the United States of America. Atlas Energy is also leading sponsor of and manages tax-advantaged direct investment partnerships, in which it co-invests to finance the exploitation and development of its acreage. Atlas Energy Resources, LLC is managed by Atlas Energy Management, Inc., through which Atlas Energy, Inc. provides Atlas Energy Resources, LLC with the personnel necessary to manage its assets and raise capital.

Results of Operations. The following table sets forth information related to our production revenues, volumes, sales prices, production costs and depletion during the periods indicated:


	Years Ended December 31,
	2009			2008
Production revenues (in thousands):
Gas	$	2,142		$	5,680
Oil		219			470

Total	$	2,361		$	6,150

Production volumes:
Gas (mcf/day) ⁽¹⁾		1,087			1,630
Oil (bbls/day) ⁽¹⁾		12			13

Total (mcfe/day) ⁽¹⁾		1,159			1,708

Average sales prices: ⁽²⁾
Gas (per mcf) ^{(1) (3)}	$	7.81		$	9.52
Oil (per bbl) ^{(1) (4)}	$	61.01		$	98.60

Average production costs:
As a percent of revenues		46	%		23	%
Per mcfe ⁽¹⁾	$	2.58		$	2.27

Depletion per mcfe	$	2.52		$	4.96


(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 reversing 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 $957,700 for the year ended December 31, 2009. The derivative gains are included in other comprehensive income 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 gains were $37,600 for the year ended December 31, 2009 The derivative gains are included in other comprehensive income and resulted from prior period impairment charges.

Natural Gas Revenues. Our natural gas revenues were $2,141,900 and $5,680,200 for the years ended December 31, 2009 and 2008, respectively, a decrease of $3,538,300 (62%). The $3,538,300 decrease in natural gas revenues for the year ended December 31, 2009 as compared to the prior year period was attributable to a $1,902,300 decrease in production volumes and a $1,636,000 decrease in natural gas sales prices after the effect of financial hedges which were driven by market conditions. Our production volumes decreased to 1,087 mcf per day for the year ended December 31, 2009 from 1,630 mcf per day for the year ended December 31, 2008, a decrease of 543 mcf per day (33%). The overall decrease in natural gas production volumes for the year ended December 31, 2009 resulted primarily from the normal decline inherent in the life of a well.

The price we receive for our natural gas is primarily a result of the index driven agreement with Colonial Energy, Inc., Atmos Energy Marketing LLC, South Jersey Resources Group, LLC, Conoco Phillips Company and our other natural gas purchasers. See Item 2 “Properties.” Thus, the price we receive for our natural gas may vary significantly each month as the underlying index changes in response to market conditions.

Oil Revenues. We drill wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $219,200 and $470,000 for the year ended December 31, 2009 and 2008, respectively, a decrease of $250,800 (53%). The $250,800 decrease in oil revenues for the year ended December 31, 2009 as compared to the prior year period was attributable to a $195,900 decrease in oil prices and by a $54,900 decrease in production volumes. Our average price we received for our oil decreased to $61.01 per bbl for the year ended December 31, 2009, as compared to $98.60 per bbl for the year ended December 31, 2008, a decrease of $37.59 per bbl (38%); which was driven by market conditions. Our production volumes decreased to 12 bbls per day for the year ended December 31, 2009 from 13 bbls per day for the year ended December 31, 2008, a decrease of 1 bbl per day (8%).

Expenses. Production expenses were $1,088,500 and $1,417,700 for the years ended December 31, 2009 and 2008, respectively, a decrease of $329,200 (23%). The decrease for the year ended December 31, 2009 was primarily due to lower transportation expenses, which were affected by a decrease in production volumes.

Depletion expense as a percentage of oil and gas revenues was 45% for the year ended December 31, 2009 as compared to 50% for the year ended December 31, 2008. 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.

There was no impairment for the year ended December 31, 2009. Impairment of oil and gas properties for the year ended December 31, 2008 was $16,792,900. Annually, we compare the carrying value of our proved developed oil and gas producing properties to their estimated fair market value. To the extent our carrying value exceeds the estimated fair market value an impairment charge is recognized. This impairment charge is based on reserve quantities, future market values and our carrying value. We cannot provide any assurance that similar charges may or may not be taken in future periods.

General and administrative expenses for the years ended December 31, 2009 and 2008 were $155,200 and $167,400, respectively, a decrease of $12,200 (7%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP and vary from period to period due to the timing and billing of the costs and services provided by the partnership.

Liquidity and Capital Resources. Cash provided by operating activities decreased $2,616,900 in the year ended December 31, 2009 to $2,532,900 as compared to $5,149,800 for the year ended December 31, 2008. This decrease was primarily due to a decrease in net earnings before depletion, net non-cash gain on derivative value, impairment and accretion of $2,452,400. This decrease was also due to the change in accounts receivable-affiliate which decreased operating cash flows by $180,500 in the year ended December 31, 2009 as compared to the year ended December 31, 2008.

There was no cash provided by investing activities for the year ended December 31, 2009. Cash provided by investing activities was $1,400 for the year ended December 31, 2008, which were proceeds from the sale of tangible assets.

Cash used in financing activities decreased $2,633,100 during the year ended December 31, 2009 to $2,704,000 from $5,337,100 for the year ended December 31, 2008. This decrease was due to a decrease in cash distributions to partners.

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 anytime exceed 5% of our total subscriptions, and we will not borrow from third-parties.

The Partnership is generally limited to the amount of funds generated by the cash flows from our operations, which we believe is adequate to fund future operations and distributions to our partners. Historically, there has been no need to borrow funds from our MGP to fund operations.

Critical Accounting Policies. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include depletion and depreciation, asset impairment, fair value of derivative instruments, and the probability of forecasted transactions. We summarize our significant accounting policies within our financial statements included in Item 8, “Financial Statements.” The critical accounting policies and estimates we have identified are discussed below.

Impairment of Long-Lived Assets. The cost of oil and gas properties, less estimated salvage value, is depleted on the units-of-production method and is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. Events or changes in circumstances that would indicate the need for impairment testing include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions. During 2009 we did not recognize an impairment charge. During 2008, we recognized an impairment charge of $16,792,900 net of an offsetting gain in other comprehensive income of $1,607,700.

Fair Value of Financial Instruments

We have established a hierarchy to measure our financial instruments at fair value which requires us 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.

Our MGP uses a fair value methodology to value the assets and liabilities for our outstanding derivative contracts. The commodity hedges are calculated based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements.

Assets and liabilities that are required to be measured at fair value on a nonrecurring basis include our oil and gas properties and asset retirement obligations (“ARO’s”) that are defined as Level 3. Estimates of the fair value of ARO’s are based on discounted cash flows using numerous estimates, assumptions, and judgments regarding the cost, timing of settlement, our credit-adjusted risk-free rate and inflation rates.

Reserve Estimates. Our estimates of proved natural gas and oil reserves and future net revenues from them are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Any significant variance in these assumptions could materially affect the estimated quantity of our reserves. As a result, our estimates of proved natural gas and oil reserves are inherently imprecise. Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves may vary substantially from our estimates or estimates contained in the reserve reports and may affect partnership distributions. In addition, our proved reserves may be subject to downward or upward revision based upon production history, results of future development, prevailing natural gas and oil prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control.

Asset Retirement Obligations. On an annual basis, we estimate the costs of future dismantlement, restoration, reclamation and abandonment of our operating assets. We also estimate the salvage value of equipment recoverable upon abandonment. Projecting future retirement cost estimates is difficult as it involves the estimation of many variables such as economic recoveries of reserves, future labor and equipment rates, future inflation rates and a credit adjusted risk free rate. To the extent future revisions to these assumptions impact the fair value of our existing asset retirement obligation, a corresponding adjustment is made to our oil and gas properties. A decrease in salvage values or an increase in dismantlement, restoration, reclamation and abandonment costs from those we and our subsidiaries have estimated, or changes in their estimates or costs, could reduce our gross profit from operations.

Working Interest. Our agreement establishes that revenues and expensed will be allocated to our MGP and limited partners based on their ratio of capital contributions to total contributions. (“working interest”). Our MGP is also provided an additional working interest of 7% as provided in our agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocated 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. As of December 31, 2009, $229,600 of net earnings resulting from the working interest adjustment was reclassified from our MGP’s capital account to the limited partner’s capital account.

ITEM 8. FINANCIAL STATEMENTS

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of
Atlas America Series #26-2005 L.P.

We have audited the accompanying balance sheets of Atlas America Series #26-2005 L.P. (a Delaware Limited Partnership) as of December 31, 2009 and 2008, and the related statements of operations, comprehensive income (loss), changes in partners’ capital, and cash flows for the years then ended. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Atlas America Series #26-2005 L.P. as of December 31, 2009 and 2008, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Cleveland, Ohio
March 30, 2010

ATLAS AMERICA SERIES 26-2005 L.P.

BALANCE SHEETS

DECEMBER 31,


	2009		2008
ASSETS
Current Assets:
Cash and cash equivalents	$	148,400	$	319,500
Accounts receivable-affiliate		629,700		1,034,400
Short-term hedge receivable due from affiliate		395,300		1,089,000

Total current assets		1,173,400		2,442,900

Oil and gas properties, net		10,717,800		11,658,000
Long-term hedge receivable due from affiliate		324,600		698,800

	$	12,215,800	$	14,799,700


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	37,700	$	22,200
Short-term hedge liability due to affiliate		4,700		94,800

Total current liabilities		42,400		117,000

Asset retirement obligation		1,497,600		1,296,600
Long-term hedge liability due to affiliate		51,200		85,300

Partners’ capital:
Managing general partner		3,333,500		4,156,800
Limited partners (1,400 units)		7,239,500		9,144,000
Accumulated other comprehensive income		51,600		—

Total partners’ capital		10,624,600		13,300,800

	$	12,215,800	$	14,799,700

The accompanying notes are an integral part of these financial statements.

ATLAS AMERICA SERIES 26-2005 L.P.

STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

YEARS ENDED DECEMBER 31, 2009 AND 2008


							Accumulated
	Managing						Other
	General			Limited			Comprehensive
	Partner			Partners			(Loss) Income			Total

Balance at December 31, 2007	$	8,122,800		$	25,812,900		$	(212,600	)	$	33,723,100

Participation in revenue and costs and expenses
Net production revenues		1,765,700			2,966,800			—			4,732,500
Depletion		(605,300	)		(2,498,000	)		—			(3,103,300	)
Impairment		(3,275,500	)		(13,517,400	)		—			(16,792,900	)
Accretion expense		(24,100	)		(40,600	)		—			(64,700	)
General and administrative		(62,500	)		(104,900	)		—			(167,400	)

Net loss		(2,201,700	)		(13,194,100	)		—			(15,395,800	)

MGP asset contribution		98,000			—			—			98,000

Other comprehensive income		—			—			212,600			212,600

Distributions to partners		(1,862,300	)		(3,474,800	)		—			(5,337,100	)


Balance at December 31, 2008	$	4,156,800		$	9,144,000		$	—		$	13,300,800

Participation in revenue and costs and expenses
Net production revenues		459,800			812,800			—			1,272,600
Depletion		(208,000	)		(855,400	)		—			(1,063,400	)
Accretion expense		(28,100	)		(49,700	)		—			(77,800	)
General and administrative		(56,100	)		(99,100	)		—			(155,200	)

Net earnings (loss)		167,600			(191,400	)		—			(23,800	)

Other comprehensive income		—			—			51,600			51,600

Working interest adjustment		(229,600	)		229,600			—			—

Distributions to partners		(761,300	)		(1,942,700	)		—			(2,704,000	)


Balance at December 31, 2009	$	3,333,500		$	7,239,500		$	51,600		$	10,624,600

The accompanying notes are an integral part of these financial statements.

ATLAS AMERICA SERIES 26-2005 L.P.

STATEMENTS OF CASH FLOWS

YEARS ENDED DECEMBER 31, 2009 AND 2008


	2009			2008
Cash flows from operating activities:
Net loss	$	(23,800	)	$	(15,395,800	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion		1,063,400			3,103,300
Non cash loss (gain) on derivative		995,300			(1,607,700	)
Impairment of oil and gas properties		—			18,400,600
Accretion of asset retirement obligation		77,800			64,700
Increase (decrease) in accrued liabilities		15,500			(500	)
Decrease in accounts receivable-affiliate		404,700			585,200

Net cash provided by operating activities		2,532,900			5,149,800

Cash flows from investing activities:
Proceeds from sale of tangible equipment		—			1,400

Net cash provided by investing activities		—			1,400

Cash flows from financing activities:
Distributions to partners		(2,704,000	)		(5,337,100	)

Net cash used in financing activities		(2,704,000	)		(5,337,100	)


Net decrease in cash and cash equivalents		(171,100	)		(185,900	)
Cash and cash equivalents at beginning of period		319,500			505,400

Cash and cash equivalents at end of period	$	148,400		$	319,500


Supplemental Schedule of non-cash investing and financing activities:

Assets contributed by the managing general partner:
Tangible equipment	$	—		$	53,100
Intangible drilling costs		—			44,900

Total assets contributed by the managing general partner	$	—		$	98,000


Asset retirement obligation revision	$	123,200		$	153,100

The accompanying notes are an integral part of these financial statements.

ATLAS AMERICA SERIES 26-2005 L.P.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009 AND 2008

NOTE 1 — DESCRIPTION OF BUSINESS

Atlas America Series 26-2005 L.P. (the “Partnership”) is a Delaware Limited Partnership, which includes Atlas Resources, LLC of Pittsburgh, Pennsylvania, as Managing General Partner (“MGP”) and Operator, and 588 Limited Partners. The Partnership was formed on May 26, 2005 to drill and operate gas wells located in Pennsylvania and Tennessee.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A summary of significant accounting policies applied in the preparation of the accompanying financial statements follows:

Use of Estimates

The preparation of the Partnership’s financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenue 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.

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 customer’s 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 December 31, 2009 and 2008, the Partnership’s MGP’s credit evaluation indicated that the Partnership had no need for an allowance for possible losses.

ATLAS AMERICA SERIES 26-2005 L.P.
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2009 AND 2008

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue Recognition

The Partnership’s natural gas and oil is sold under various contracts entered into by its MGP. The Partnership generally sells natural gas and crude oil at prevailing market prices. Revenue is 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 the Partnership’s percentage ownership of working interest. Generally, the MGP’s sales contracts are based on pricing provisions that are tied to a market index, with certain adjustments based on proximity to gathering and transmission lines and the quality of its natural gas.

Because there are timing differences between the delivery the Partnership’s natural gas and oil and its receipt of a delivery statement, the Partnership has unbilled revenues. These revenues are accrued based on volumetric data from the Partnership’s records and its estimates of the related transportation and compression fees which are, in turn, based upon applicable product prices. The Partnership had unbilled trade receivables of $429,600 and $714,400 at December 31, 2009 and 2008, respectively, which are included in Accounts receivable – affiliate on the Partnership’s Balance Sheets.

Fair Value of Financial Instruments

The carrying amounts of the Partnership’s cash and receivables approximate fair values because of the short maturities of these instruments.

For derivatives, the carrying value approximates fair value because they have been marked to market.

Supplemental Cash Flow Information

The Partnership considers temporary investments with a maturity at the date of acquisition of 90 days or less to be cash equivalents. No cash was paid by the Partnership for interest or income taxes for the years ended December 31, 2009 and 2008.

Concentration of Credit Risk

Financial instruments, which potentially subject the Partnership to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Partnership places its temporary cash investments in deposits with high-quality financial institutions. At December 31, 2009, the Partnership had $154,800 in deposits of which none was over the insurance limit of the Federal Deposit Insurance Corporation and at December 31, 2008, the Partnership had $350,100 in deposits of which none was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments.

Comprehensive Income (Loss)

Comprehensive income (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. These changes, other than net loss, are referred to as “other comprehensive income” and, for the Partnership, include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges.

ATLAS AMERICA SERIES 26-2005 L.P.
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2009 AND 2008

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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 net 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 net revenues based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership. As of December 31, 2009, $229,600 of net earnings resulting from the working interest adjustment was reclassified from the MGP’s capital account to the limited partner’s capital account.

Oil and Gas Properties

The Partnership follows the successful-efforts method of accounting for oil and gas producing activities. Oil and gas properties are recorded at cost. Depletion is determined on a field-by-field basis using the units-of-production method for well and related equipment costs based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of developed producing properties. In addition, accumulated depletion includes impairment adjustments to reflect the write-down to fair market value of the oil and gas properties. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of the property are capitalized. The Partnership is required to consider estimated salvage value in the calculation of depletion.

Oil and gas properties consist of the following at the dates indicated:


	December 31,			December 31,
	2009			2008
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	1,119,300		$	1,119,300
Wells and related equipment		44,089,100			43,965,900

		45,208,400			45,085,200

Accumulated depletion		(34,490,600	)		(33,427,200	)

	$	10,717,800		$	11,658,000

ATLAS AMERICA SERIES 26-2005 L.P.
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2009 AND 2008

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

The Partnership’s long-lived assets are reviewed for impairment at least annually or whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows. The review is done by determining if the historical cost of proved properties less the applicable accumulated depletion and salvage value 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. 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. If the carrying value exceeds such undiscounted cash flows, an impairment loss is recognized for the difference between the estimated fair market value and the carrying value of the assets. The fair market value is determined as the present value of future net revenues from the production of proved reserves discounted using an annual discount rate of 12% in 2009 and 2008. During the year ended December 31, 2009, the Partnership did not recognize an impairment charge. During the year ended December 31 2008, the Partnership recognized an impairment charge of $16,792,900 net of an offsetting gain in accumulated other comprehensive income of $1,607,700.

Upon the sale or retirement of a complete or partial unit of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to accumulated depletion. The Partnership did not reclassify any costs from oil and gas properties to accumulated depletion for the year ended December 31, 2009, however as a result of retirements, the Partnership reclassified $3,300 from oil and gas properties to accumulated depletion for the year ended December 31, 2008 Upon the sale of an entire interest where the property had been assessed for impairment, a gain or loss is recognized in the Statement of Operations.

Asset Retirement Obligation

The Partnership recognizes an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities, or asset retirement obligations (see Note 9). The Partnership recognizes a liability for future asset retirement obligations in the current period if a reasonable estimate of the fair value of the liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset.

Environmental Matters

The Partnership is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Partnership has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.

Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. Atlas Energy maintains insurance that may cover in whole or in part, certain environmental expenditures. For the years ended December 31, 2009 and 2008, the Partnership had no environmental matters requiring specific disclosure or the recording of a liability.

ATLAS AMERICA SERIES 26-2005 L.P.
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2009 AND 2008

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Major Customers

The Partnership’s natural gas is sold under contract to various purchasers. For the year ended December 31, 2009, sales to Colonial Energy Inc., Atmos Energy Marketing, LLC, South Jersey Resources, LLC and Conoco Phillips accounted for 18%, 13%, 12%, and 12% of total revenues, respectively. For the year ended December 31, 2008, sales to Interstate Gas Supply Inc., UGI Energy Services, Inc., Conoco Phillips Company and Colonial Energy, Inc. accounted for 15%, 14%, 13%, and 11% of total revenues, respectively. No other customers accounted for 10% or more of total revenues for the years ended December 31, 2009 and 2008.

Income Taxes

The Partnership is not treated as a taxable entity for federal income tax purposes. Any item of income, gain, loss, deduction or credit flows through to the partners as though each partner had incurred such item directly. As a result, each partner must take into account their pro rata share of all items of partnership income and deductions in computing their federal income tax liability.

Recently Issued Financial Accounting Standards

In February 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2010-09 “Amendments to Certain Recognition and Disclosure Requirements” (“Update 2010-09”). Update 2010-09 amends Accounting Standards Codification (“ASC”) 855-10-50-1 to clarify that all entities other than SEC filers must disclose (1) the date through, which subsequent events have been evaluated and (2) whether that date is the date the financial statements were issued or available to be issued. However, the date-disclosure exemption for SEC filers does not relieve management from its responsibility to evaluate subsequent events through the date on which financial statements are issued. The Partnership adopted the requirements of Update 2010-09 on December 31, 2009, and it did not have a material impact on its financial position, results of operations or related disclosures.

In January 2010, the FASB issued Accounting Standards Update 2010-03, “Extractive Activities Oil and Gas (Topic 932) — Oil and Gas Reserve Estimation and Disclosures” (“Update 2010-03”). Update 2010-03 includes amendments to ASC Topic 932 “Extractive Activities – Oil and Gas,” to include within the ASC the reporting requirements covered in the Securities and Exchange Commission’s (“SEC”) final rule, “Modernization of Oil and Gas Reporting” issued on December 31, 2008. The Partnership adopted the requirements of Update 2010-03 on December 31, 2009. These new disclosure requirements include provisions that:

•

Permit companies to disclose their probable and possible reserves on a voluntary basis. Current rules limit disclosure to only proved reserves;

ATLAS AMERICA SERIES 26-2005 L.P.
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2009 AND 2008

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Recently Issued Financial Accounting Standards (Continued)

•

Update and revise reserve definitions to reflect changes in the oil and gas industry and new technologies. New updated definitions include “by geographic area” and “reasonable certainty”;

•

Permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes; and

•

Require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures are required with regard to internal controls over reserve estimation, as well as a report addressing the independence and qualifications of a company’s reserves preparer or auditor based on Society of Petroleum Engineers criteria.

The Partnership has complied with the disclosure requirements for the year ended December 31, 2009.

In August 2009, the FASB issued Accounting Standards Update 2009-05, “Fair Value Measurements and Disclosures (Topic 820) – Measuring Liabilities at Fair Value” (“Update 2009-05”). Update 2009-05 amends Subtopic 820-10, “Fair Value Measurements and Disclosures — Overall” and provides clarification for the fair value measurement of liabilities in circumstances where quoted prices for an identical liability in an active market are not available. The amendments also provide clarification for not requiring the reporting entity to include separate inputs or adjustments to other inputs relating to the existence of a restriction that prevents the transfer of a liability when estimating the fair value of a liability. Additionally, these amendments clarify that both the quoted price in an active market for an identical liability at the measurement date and the quoted price for an identical liability when traded as an asset in an active market when no adjustments to the quoted price of the asset are required are considered Level 1 fair value measurements. These requirements are effective for financial statements issued after the release of Update 2009-05. The Partnership adopted the requirements of Update 2009-05 on September 30, 2009, and it did not have a material impact on its financial position, results of operations or related disclosures.

In June 2009, the FASB issued Accounting Standards Update 2009-01, “Topic 105 — Generally Acceptable Accounting Principles Amendments Based on Statement of Financial Accounting Standards No. 168 — The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (“Update 2009-01”). Update 2009-01 establishes the FASB ASC as the single source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. The ASC supersedes all existing non-Securities and Exchange Commission accounting and reporting standards. Following the ASC, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead, the FASB will issue Accounting Standards Updates, which will serve only to update the ASC. The ASC is effective for financial statements issued for interim and annual periods ending after September 15, 2009. All required references to non-SEC accounting standards have been modified by the Partnership. The Partnership adopted the requirements of Update 2009-01 for its financial statements on September 30, 2009, and it did not have a material impact on its financial statement disclosures.

ATLAS AMERICA SERIES 26-2005 L.P.
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2009 AND 2008

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Recently Issued Financial Accounting Standards (Continued)

In May 2009, the FASB issued ASC 855-10, “Subsequent Events” (“ASC 855-10”). ASC 855-10 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The provisions require management of a reporting entity to evaluate events or transactions that may occur after the balance sheet date for potential recognition or disclosure in the financial statements and provides guidance for disclosures that an entity should make about those events. ASC 855-10 is effective for interim or annual financial periods ending after June 15, 2009 and shall be applied prospectively. The Partnership adopted the requirements of this standard on June 30, 2009, and it did not have a material impact on its financial position or results of operations or related disclosures. The adoption of these provisions does not change the Partnership’s current practices with respect to evaluating, recording and disclosing subsequent events.

In April 2009, the FASB issued ASC 820-10-65-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“ASC 820-10-65-4”). ASC 820-10-65-4 applies to all fair value measurements and provides additional clarification on estimating fair value when the market activity for an asset has declined significantly. ASC 820-10-65-4 also require an entity to disclose a change in valuation technique and related inputs to the valuation calculation and to quantify its effects, if practicable. ASC 820-10-65-4 is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Partnership adopted the requirements of ASC 820-10-65-4 on April 1, 2009, and its adoption did not have a material impact on its financial position and results of operations.

In April 2009, the FASB issued ASC 825-10-65-1, “Interim Disclosures about Fair Value of Financial Instruments” (“ASC 825-10-65-1”), which requires an entity to provide disclosures about fair value of financial instruments in interim financial information. In addition, an entity shall disclose in the body or in the accompanying notes of its summarized financial information for interim reporting periods and in its financial statements for annual reporting periods the fair value of all financial instruments for which it is practicable to estimate that value, whether recognized or not recognized in the statement of financial position. ASC 825-10-65-1 is effective for interim periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Partnership adopted these requirements on April 1, 2009, and its adoption did not have a material impact on its financial position and results of operations.

In March 2008, the FASB issued ASC 815-10-50-1, “Disclosures about Derivative Instruments and Hedging Activities” (“ASC 815-10-50-1”), to require enhanced disclosure about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The Partnership adopted the requirements of this section of ASC 815-10-50-1 on January 1, 2009, and it did not have a material impact on its financial position or results of operations (see Note 7).

ATLAS AMERICA SERIES 26-2005 L.P.
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2009 AND 2008

NOTE 3 — PARTICIPATION IN REVENUES AND COSTS

The MGP and the limited partners will generally participate in revenues and costs in the following manner:


	Managing
	General			Limited
	Partner			Partners
Organization and offering costs		100	%		0	%
Lease costs		100	%		0	%
Revenues (1)		36.13	%		63.87	%
Operating costs, administrative costs, direct costs and all other operating costs (2)		36.13	%		63.87	%
Intangible drilling costs		2.90	%		97.10	%
Tangible equipment costs		68.18	%		31.82	%


(1)		Subject to the MGP’s subordination obligation, substantially all partnership revenues will be shared in the same percentage as capital contributions are to the total partnership capital contributions, except that the MGP will receive an additional 7% of the partnership revenues, and the MGP revenue percentage may not exceed 40%.

(2)		These costs will be charged to the partners in the same ratio as the related production revenues are credited.

NOTE 4 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The Partnership has entered into the following significant transactions with it’s MGP and its affiliates as provided under the Partnership agreement:

•

Administrative costs which are included in general and administrative expenses in the Partnership’s Statements of Operations are at $75 per well, per month. Administrative costs incurred in 2009 and 2008 were $106,700 and $110,700, 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 in 2009 and 2008, for operating and maintaining the wells. Well supervision fees incurred in 2009 and 2008 were $445,700 and $462,900, 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 in 2009 and 2008 were $363,200 and $633,400, respectively.

•

Direct costs which are included in production and general administrative expenses in the Partnership’s Statements of Operations are payable to the MGP and its affiliates as reimbursement for all costs expended on the Partnership’s behalf. Direct costs incurred in 2009 and 2008 were $328,100 and $378,100, respectively.

•

Asset contributions from the MGP which are reported on the Partnership’s Statements of Cash Flows as non-cash investing activities for the year ended December 31, 2008 was $98,000. The MGP did not make any asset contributions for the year ended December 31, 2009.

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.

ATLAS AMERICA SERIES 26-2005 L.P.
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2009 AND 2008

NOTE 5 — COMMITMENTS

Subject to certain conditions, investor partners may present their interests beginning in 2010 for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. The MGP is not obligated to purchase more than 5% of the units in any calendar year. In the event that the MGP is unable to obtain the necessary funds, it may suspend its purchase obligation.

Beginning one year after each of the Partnership’s wells has been placed into production, the MGP, as operator, may retain $200 per month per well to cover estimated future plugging and abandonment costs. As of December 31, 2009, the MGP has not withheld any such funds.

NOTE 6 — 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 production revenues of the Partnership to the benefit of the limited partners for an amount equal to 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 investor partners (June 2006) and expiring 60 months after that date. Since the inception of the Partnership, the MGP has not been required to subordinate any of its net production to the limited partners.

NOTE 7 — DERIVATIVE INSTRUMENTS

The MGP on behalf of the Partnership uses a number of different derivative instruments, principally swaps and collars, in connection with its commodity price risk management activities. The MGP enters into financial instruments to hedge the Partnership’s forecasted natural gas and crude oil 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 and crude oil is sold. Under swap agreements, the Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not obligation, to purchase or sell natural gas and crude oil at a fixed price for the relevant contract period.

The MGP formally documents all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity derivative contracts to the forecasted transactions. The MGP assesses, both at the inception of the derivative and on an ongoing basis, whether the derivative 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 Partnership will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by 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 in partners capital as accumulated other comprehensive income and will reclassify commodity derivatives to gas and oil production revenues in 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. The following table summarizes the fair value of derivative instruments as of December 31, 2009 and 2008.

ATLAS AMERICA SERIES 26-2005 L.P.
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2009 AND 2008

NOTE 7 — DERIVATIVE INSTRUMENTS (Continued)

Fair Value of Derivative Instruments:


	Asset Derivatives					Liability Derivatives
Derivatives in		Fair Value					Fair Value
Cash Flow	Balance Sheet	December 31,		December 31,		Balance Sheet	December 31,		December 31,
Hedging Relationships	Location	2009		2008		Location	2009		2008

Commodity contracts:	Current assets	$	395,300	$	1,089,000	Current liabilities	$	4,700	$	94,800
	Long-term assets		324,600		698,800	Long-term liabilities		51,200		85,300


Total derivatives		$	719,900	$	1,787,800		$	55,900	$	180,100

Effects of Derivative Instruments on Statements of Operations:

Gain

Gain (Loss)

Recognized in OCI on Derivative

Reclassified from OCI into Income

(Effective Portion)

Location of Gain/(Loss)

(Effective Portion)

Derivatives in

Twelve Months Ended

Reclassified from Accumulated

Twelve Months Ended

Cash Flow

December 31,

OCI into Income

December 31,

Hedging Relationship

2009

2008

(Effective Portion)

2009

2008

Commodity contracts

213,200

42,500

Natural gas and oil revenue

161,600

(170,100

)

At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures, 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.

At December 31, 2009, the Partnership reflected a net hedge asset on our Balance Sheets of $664,000, however unrealized gains of $612,400 recognized in income results in a net accumulated other comprehensive income balance of $51,600. The unrealized gains of $612,400 are comprised entirely from the 2008 impairment of oil and gas properties. Of the $51,600 net gain in accumulated other comprehensive income at December 31, 2009, if the fair values of the instruments remain at current market values, we will reclassify $76,200 of net gains to our Statements of Operations over the next twelve month period as these contracts expire, and $24,600 of net losses later periods. Actual amounts that will be reclassified will vary as a result of future price changes. Ineffective hedge gains or losses are recorded within the Statements of Operations while the hedge contract is open and may increase or decrease until settlement of the contract. The Partnership recognized no gains or losses during the years ended December 31, 2009 and 2008, respectively, for hedge ineffectiveness or as a result of the discontinuance of cash flow hedges.

ATLAS AMERICA SERIES 26-2005 L.P.
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2009 AND 2008

NOTE 7 — DERIVATIVE INSTRUMENTS (Continued)

As of December 31, 2009, Atlas Energy had allocated to the Partnership the following natural gas and oil volumes hedged:

Natural Gas Fixed Price Swaps


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

2010		224,500	$	7.34	$	344,300
2011		117,300		6.98		103,600
2012		93,200		7.22		77,800
2013		50,500		7.08		21,100

					$	546,800

Natural Gas Costless Collars


Production				Average
Period Ending	Option	Volumes		Floor & Cap		Fair Value
December 31,	Type	(MMbtu)⁽¹⁾		(per MMbtu)⁽¹⁾		Asset⁽²⁾

2010	Puts purchased		15,600	$	7.84	$	38,300
2010	Calls sold		15,600		9.01		—
2011	Puts purchased		68,400		6.45		44,000
2011	Calls sold		68,400		7.63		—
2012	Puts purchased		35,300		6.51		15,900
2012	Calls sold		35,300		7.71		—
2013	Puts purchased		32,800		6.58		9,300
2013	Calls sold		32,800		7.79		—

						$	107,500

Crude Oil Fixed Price Swaps


Production			Average
Period Ending	Volumes		Fixed Price		Fair Value
December 31,	(Bbl)⁽¹⁾		(per Bbl)⁽¹⁾		Asset⁽³⁾

2010		400	$	97.40	$	6,000
2011		300		77.46		1,100
2012		200		76.86		200
2013		100		77.36		100

					$	7,400

ATLAS AMERICA SERIES 26-2005 L.P.
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2009 AND 2008

NOTE 7 — DERIVATIVE INSTRUMENTS (Continued)

Crude Oil Costless Collars


Production				Average
Period Ending	Option	Volumes		Floor & Cap		Fair Value
December 31,	Type	(Bbl)⁽¹⁾		(per Bbl)⁽¹⁾		Asset (Liability)⁽³⁾

2010	Puts purchased		200	$	85.00	$	2,000
2010	Calls sold		200		112.92		—
2011	Puts purchased		200		67.22		300
2011	Calls sold		200		89.44		—
2012	Puts purchased		200		65.51		100
2012	Calls sold		200		91.45		—
2013	Puts purchased		50		65.36		—
2013	Calls sold		50		93.44		(100	)

						$	2,300


					Total Net Asset	$	664,000


(1)		MMBTU represents million British Thermal Units. Bbl represents barrels.

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

(3)		Fair value based on forward WTI crude oil prices.

NOTE 8 — 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 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 entities own assumptions about the assumptions that 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.

ATLAS AMERICA SERIES 26-2005 L.P.
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2009 AND 2008

NOTE 8 — FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Partnership uses a fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 7). The Partnership’s derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements. Assets and Liabilities measured at fair value at December 31, 2009 and 2008 were as follows.


	December 31, 2009				December 31, 2008
	Level 2		Total		Level 2		Total

Commodity-based derivatives	$	664,000	$	664,000	$	1,607,700	$	1,607,700

Total	$	664,000	$	664,000	$	1,607,700	$	1,607,700

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The Partnership estimates the fair value of asset retirement obligations, using Level 3 inputs 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: amount and timing of settlements; the risk-free rate of the Partnership; and estimated inflation rates (see Note 9).

The Partnership’s long-lived assets are reviewed for impairment at least annually or whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the carrying value exceeds such undiscounted cash flows, an impairment loss is recognized for the difference between the estimated fair market value and the carrying value of the assets. The fair market value using Level 3 inputs is determined as the present value of future net revenues from the production of proved reserves discounted using an annual discount rate of 12% in 2009 and 2008 (see Note 2).

NOTE 9 — ASSET RETIREMENT OBLIGATION

The Partnership recognizes an estimated liability for the plugging and abandonment of its oil and gas wells. The associated asset retirement costs are capitalized as part of oil and gas properties. The Partnership also considers the estimated salvage value in the calculation of depletion.

The estimated liability is based on the MGP’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed risk free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations.

ATLAS AMERICA SERIES 26-2005 L.P.
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2009 AND 2008

NOTE 9 — ASSET RETIREMENT OBLIGATION (Continued)

A reconciliation of the Partnership’s liability for plugging and abandonment costs for the years indicated are:


	Years Ended
	December 31,
	2009		2008
Asset retirement obligation at beginning of year	$	1,296,600	$	1,078,800
Revision in estimates		123,200		153,100
Accretion expense		77,800		64,700

Asset retirement obligation at end of year	$	1,497,600	$	1,296,600

NOTE 10 — NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)

(1) Capitalized Costs Related to Oil and Gas Producing Activities

The following table presents the capitalized costs related to natural gas and oil producing activities at the periods indicated:


	At December 31,
	2009			2008
Leasehold interest:	$	1,119,300		$	1,119,300
Wells and related equipment		44,089,100			43,965,900
Accumulated depletion		(34,490,600	)		(33,427,200	)

Net capitalized cost	$	10,717,800		$	11,658,000

(2) Oil and Gas Reserve Information

In accordance with the modernization of oil and gas accounting (see Note 2), the Partnership changed its calculation of proved reserves. Under the current accounting literature, the proved reserves quantities and future net cash flows are estimated using a 12-month average pricing at December 31, 2009 based on the prices on the first day of each month. Using this calculation resulted in the use of lower prices at December 31, 2009 than would have resulted using year-end prices as required by the previous rules.

The preparation of the Company’s natural gas and oil reserve estimates were completed in accordance with its prescribed internal control procedures, which include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review. For the year ended December 31, 2009, the Company retained Wright & Company, independent, third-party reserves engineers, to prepare a report of proved reserves. The reserves report included a detailed review of our properties. Wright & Company’s evaluation was based on more than 35 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations applicable as of December 31, 2009. The Wright & Company report was prepared in accordance with generally accepted petroleum engineering and evaluation principles.

The reserve disclosures that follow reflect estimates of proved reserves consisting of proved developed, net to the Partnership’s interests, of natural gas, crude oil, condensate and NGLs owned at year end and changes in proved reserves during the previous two years. Proved developed reserves are those proved reserves, which can be expected to be recovered from existing wells with existing equipment and operating methods.

ATLAS AMERICA SERIES 26-2005 L.P.
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2009 AND 2008

NOTE 10 — NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) (Continued)

There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of the Partnership’s oil and gas reserves or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil and gas prices and in production and development costs and other factors for effects have not been proved.


	Natural Gas			Oil
	(Mcf)			(Bbls)
Proved developed reserves:
Balance at December 31, 2007		6,228,200			30,500
Production		(596,600	)		(4,800	)
Revisions to previous estimates		(1,723,900	)		(5,400	)


Balance at December 31, 2008		3,907,700			20,300
Production		(396,800	)		(4,200	)
Revisions to previous estimates		(789,500	)		(3,900	)


Balance at December 31, 2009		2,721,400			12,200


ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness 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, as of December 31, 2009, our disclosure controls and procedures were effective at the reasonable assurance level.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of management, including our Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, we conducted an evaluation of the effectiveness of internal control over financial reporting based upon criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework (COSO framework).

An effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, effectiveness of an internal control system in future periods cannot be guaranteed because the design of any system of internal controls is based in part upon assumptions about the likelihood of future events. There can be no assurance that any control design will succeed in achieving its stated goals under all potential future conditions. Over time certain controls may become inadequate because of changes in business conditions, or the degree of compliance with policies and procedures may deteriorate. As such, misstatements due to error or fraud may occur and not be detected.

Based on our evaluation under the COSO framework, management concluded that our internal control over financial reporting as of December 31, 2009 was effective.

This annual report does not include an attestation report by the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Atlas Energy is headquartered at Westpointe Corporate Center One, 1550 Coraopolis Heights Road, 2^nd Floor, Moon Township, Pennsylvania 15108, which is also our MGP’s primary office.

Executive Officers and Directors. The executive officers and directors of our MGP will serve until their successors are elected. The executive officers and directors of our MGP are as follows:


NAME	AGE		POSITION OR OFFICE

Freddie M. Kotek		54	Chairman of the Board of Directors, Chief Executive Officer and President
Frank P. Carolas		50	Executive Vice President – Land and Geology and a Director
Jeffrey C. Simmons		51	Executive Vice President – Operations and a Director
Jack L. Hollander		53	Senior Vice President – Direct Participation Programs
Sean P. McGrath		38	Chief Accounting Officer
Matthew A. Jones		48	Chief Financial Officer

With respect to the biographical information set forth below:

•

the approximate amount of an individual’s professional time devoted to the business and affairs of our MGP and Atlas America have been aggregated because there is no reasonable method for them to distinguish their activities between the two companies; and

•

for those individuals who also hold senior positions with other affiliates of our MGP, if it is stated that they devote approximately 100% of their professional time to our MGP and Atlas America, it is because either the other affiliates are not currently active in drilling new wells, such as Viking Resources or Resource Energy, and the individuals are not required to devote a material amount of their professional time to the affiliates, or there is no reasonable method to distinguish their activities between our MGP and Atlas America as compared with the other affiliates of our MGP, such as Viking Resources or Resource Energy.

Freddie M. Kotek has been an Executive Vice President since February 2004 and served as a director from September 2001 until February 2004. Mr. Kotek has been Chairman of Atlas Resources, LLC since September 2001 and has served as an Executive Vice President since October 2009. He has also served as Chief Executive Officer and President of Atlas Resources since January 2002. Mr. Kotek was our Chief Financial Officer from February 2004 until March 2005. Mr. Kotek was a Senior Vice President of Resource America from 1995 until May 2004 and President of Resource Leasing, Inc. (a wholly-owned subsidiary of Resource America) from 1995 until May 2004. Kotek will devote approximately 95% of his professional time to the business and affairs of the MGP and Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc., and the remainder of his professional time to the business and affairs of the MGP’s other affiliates.

Frank P. Carolas. Executive Vice President-Land and Geology and a Director since January 2001. Mr. Carolas has been an Executive Vice President of Atlas America since January 2001 and served as a Director of Atlas America from January 2002 until February 2004. Mr. Carolas has been a Senior Vice President of Atlas Energy Management, Inc. since 2006. Mr. Carolas was a Vice President of Resource America from April 2001 until May 2004 when he resigned from Resource America. Mr. Carolas served as Vice President of Land and Geology for the MGP from July 1999 until December 2000 and for Atlas America from 1998 until December 2000. Before that Mr. Carolas served as Vice President of Atlas Energy Group, Inc. from 1997 until 1998, which was the former parent company of the MGP. Mr. Carolas is a certified petroleum geologist and has been with the MGP and its affiliates since 1981. He received a Bachelor of Science degree in Geology from Pennsylvania State University in 1981 and is an active member of the American Association of Petroleum Geologists. Mr. Carolas devotes approximately 100% of his professional time to the business and affairs of the MGP, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.

Jeffrey C. Simmons. Executive Vice President-Operations and a Director since January 2001. Mr. Simmons has been an Executive Vice President of Atlas America since January 2001 and was a Director of Atlas America from January 2002 until February 2004. Mr. Simmons has been a Senior Vice President of Atlas Energy Management, Inc., since 2006. Mr. Simmons was a Vice President of Resource America from April 2001 until May 2004 when he resigned from Resource America. Mr. Simmons served as Vice President of Operations for the MGP from July 1999 until December 2000 and for Atlas America from 1998 until December 2000. Mr. Simmons joined Resource America in 1986 as a senior petroleum engineer and has served in various executive positions with its energy subsidiaries since then. Mr. Simmons received his Bachelor of Science degree with honors from Marietta College in 1981 and his Masters degree in Business Administration from Ashland University in 1992. Mr. Simmons devotes approximately 90% of his professional time to the business and affairs of the MGP, Atlas America, and the remainder of his professional time to the business and affairs of the MGP’s other affiliates, primarily Viking Resources and Resource Energy, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.

Jack L. Hollander. Senior Vice President – Direct Participation Programs since January 2002 and before that he served as Vice President – Direct Participation Programs from January 2001 until December 2001. Mr. Hollander also serves as Senior Vice President – Direct Participation Programs of Atlas America since January 2002. Mr. Hollander practiced law with Rattet, Hollander & Pasternak, concentrating in tax matters and real estate transactions, from 1990 to January 2001, and served as in-house counsel for Integrated Resources, Inc. (a diversified financial services company) from 1982 to 1990. Mr. Hollander earned a Bachelor of Science degree from the University of Rhode Island in 1978, his law degree from Brooklyn Law School in 1981, and a Master of Law degree in Taxation from New York University School of Law Graduate Division in 1982. Mr. Hollander is a member of the New York State bar, and the Chairman of the Investment Program Association which is an industry association, as of March 2005. Mr. Hollander devotes approximately 100% of his professional time to the business and affairs of the MGP, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.

Sean P. McGrath has been our Chief Accounting Officer and the Chief Accounting Officer of Atlas Energy Resources since December 2008. Mr. McGrath served as the Chief Accounting Officer of Atlas Pipeline Holdings GP from January 2006 until November 2009 and as the Chief Accounting Officer of Atlas Pipeline GP from May 2005 until November 2009. Mr. McGrath was the Controller of Sunoco Logistics Partners L.P., a publicly-traded partnership that transports, terminals and stores refined products and crude oil, from 2002 to 2005. From 1998 to 2002, Mr. McGrath was Assistant Controller of Asplundh Tree Expert Co., a utility services and vegetation management company. Mr. McGrath is a Certified Public Accountant. Mr. McGrath will devote approximately 70% of his professional time to the business and affairs of the managing general partner and Atlas America, and the remainder of his professional time to the business and affairs of the managing general partner’s other affiliates.

Matthew A. Jones has been our Chief Financial Officer since March 2005 and an Executive Vice President since October 2009. Mr. Jones has been the Chief Financial Officer of Atlas Energy Resources and Atlas Energy Management since their formation. Mr. Jones served as the Chief Financial Officer of Atlas Pipeline Holdings GP from January 2006 until September 2009 as the Chief Financial Officer of Atlas Pipeline GP from March 2005 to September 2009. From 1996 to 2005, Mr. Jones worked in the Investment Banking Group at Friedman Billings Ramsey, concluding as Managing Director. Mr. Jones worked in Friedman Billings Ramsey’s Energy Investment Banking Group from 1999 to 2005, and in Friedman Billings Ramsey’s Specialty Finance and Real Estate Group from 1996 to 1999. Mr. Jones has served as a director of Atlas Pipeline Holdings GP since February 2006. Mr. Jones is a Chartered Financial Analyst. Mr. Jones devotes approximately 55% of his professional time to the business and affairs of the MGP, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc. and the remainder of his professional time to the business and affairs of the MGP’s other affiliates.

Audit Committee Financial Expert. The Board of Directors of our MGP acts as the audit committee. The Board of Directors has determined that Freddie M. Kotek, Chairman and President of the MGP, meets the requirement of an “audit committee financial expert.” He is not independent.

Remuneration of Officers and Directors. No officer or director of the MGP will receive any direct remuneration or other compensation from the Partnership. These persons will receive compensation solely from affiliated companies of the MGP.

Code of Business Conduct and Ethics. Because the Partnership does not directly employ any persons, the MGP has determined that the partnership will rely on a Code of business Conduct and Ethics adopted by Atlas America, Inc. and/or Atlas Energy Resources, LLC that applies to the principal executive officer, principal financial officer and principal accounting officer of the MGP, as well as to persons performing services for the managing general partner generally. You may obtain a copy of this Code of Business Conduct and Ethics by a request to the MGP at Atlas Resources, LLC, Westpointe Corporate Center One, 1550 Coraopolis Heights Road, 2^nd Floor, Moon Township, Pennsylvania 15108.

ITEM 11. EXECUTIVE COMPENSATION

We have no employees and rely on the employees of our MGP and its affiliates for all services. No officer or director of our MGP will receive any direct remuneration or other compensation from us. Those persons will receive compensation solely from affiliated companies of our MGP. See Item 13 Certain Relationships and Related Party Transactions for a discussion of compensation paid by us to our MGP.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

As of December 31, 2009, we had 1,400 units outstanding. No officer or director of our MGP owns any units. Although, subject to certain conditions, investor partners may present their units to us beginning in 2010 for purchase, the MGP is not obligated by the Partnership agreement from purchasing more than 5% of our total outstanding units in any calendar year.

Organizational and Security Ownership of Beneficial Owners. Atlas Energy, Inc. owns approximately 100% of the limited liability company interest of Atlas Energy Resources, LLC which owns 100% of the limited liability company interests of Atlas Energy Operating Company, LLC, which owns 100% of the limited liability company interests of AIC, LLC, which owns 100% of the limited liability company interest of the managing general partner. The officers and directors of Atlas America and Atlas Energy Resources LLC are set forth below. The directors of AIC, LLC are Jonathan Z. Cohen and Jeffrey Simmons.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Oil and Gas Revenues. Our MGP is allocated 36.13% of our oil and gas revenues in return for its payment and/or contribution of services towards our syndication and offering costs equal to 13% of our subscriptions, its payment of 68.18% of the tangible costs of drilling and completing our wells and its contributions to us of all of our oil and gas leases for a total capital contribution of $14,779,500. During the years ended December 31, 2009 and 2008 our MGP received $459,800 and $1,765,700, respectively from our net production revenues.

Administrative Costs. Our MGP and its affiliates receive an unaccountable, fixed fee reimbursement for the administrative costs they incur on our behalf of $75 per well per month, which is proportionately reduced to the extent we acquired less than 100% of the working interest in a well. During the year ended December 31, 2009 and 2008 our MGP received $106,700 and $110,700, respectively for administrative costs.

Direct Costs. Our MGP and its affiliates are reimbursed by us for all direct costs expended by them on our behalf. During the year ended December 31, 2009 and 2008 we reimbursed our MGP $328,100 and $378,100, respectively for direct costs.

Well Charges. Our MGP, as operator or our wells, is reimbursed at actual cost for all direct expenses incurred on our behalf and receives well supervision fees for operating and maintaining the wells during producing operations in the amount of $318 per well per month in 2009 and 2008, subject to an annual adjustment for inflation. The well supervision fees were proportionately reduced to the extent we acquired less than 100% of the working interest in a well. For the years ended December 31, 2009 and 2008 our MGP received $445,700 and $462,900, respectively for well supervision fees.

Transportation Fees. We pay gathering fees to our MGP at a competitive rate for each mcf of our natural gas transported. Transportation rate is 13% of the natural gas sales price. For the years ended December 31, 2009 and 2008, $363,200 and $633,400, respectively, was paid to our MGP for gathering fees. In turn, our MGP paid 100% of this amount to Atlas America, for the use of its gathering system in transporting a majority of our natural gas production.

Other Compensation. For the years ended December 31, 2009 and 2008, our MGP did not advance any funds to us, or did they provide us with any equipment, supplies or other services.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees. The aggregate fees recognized by the Partnership from our independent auditors, Grant Thornton LLP, for professional services rendered for the audit of our annual financial statements for the years ended December 31, 2009 and 2008, and for the reviews of the financial statements included in our quarterly reports on Form 10-Q during such years were $31,600 and $30,800, respectively.

Procedures for Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Auditor. Pursuant to its charter, the Audit Committee of Atlas Energy, Inc. is responsible for reviewing and approving, in advance, any audit and any permissible non-audit engagement or relationship between us and our independent auditors. We do not have a separate audit committee.

PART IV

ITEM 15. EXHIBITS

EXHIBIT INDEX


	Description	Location
4(a)	Certificate of Limited Partnership for Atlas America Series 26-2005 L.P.	Previously filed in our Form S-1 on August 9, 2005

4(b)	Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Series 26-2005 L.P. ⁽¹⁾	Previously filed in our Form S-1 on August 9, 2005

4(c)	Drilling and Operating Agreement for Atlas America Series 26-2005 L.P.	Previously filed in our Form S-1 on August 9, 2005

23.1	Consent of Wright and Company

31.1	Rule 13a-14(a)/15(d) – 14 (a) Certification.

31.2	Rule 13a-14(a)/15(d) – 14 (a) Certification.

32.1	Section 1350 Certification.

32.2	Section 1350 Certification.

99.1	Summary Reserve Report.


(1)		Filed on April 28, 2006 in the Form S-1 Registration Statement dated April 28, 2006, File No. 0-51945

SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Atlas America Series 26-2005 L.P.


Date: March 30, 2010	Atlas Resources, LLC, Managing General Partner
	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: March 30, 2010	By:	/s/ Freddie M. Kotek
		Freddie M. Kotek, Chairman of the Board of Directors, Chief Executive Officer and President

Date: March 30, 2010	By:	/s/ Frank P. Carolas
		Frank P. Carolas, Executive Vice President – Land and Geology

Date: March 30, 2010	By:	/s/ Jeffrey C. Simmons
		Jeffrey C. Simmons, Executive Vice President – Operations

Date: March 30, 2010	By:	/s/ Sean P. McGrath
		Sean P. McGrath, Chief Accounting Officer

Date: March 30, 2010	By:	/s/ Matthew A. Jones
		Matthew A. Jones, Chief Financial Officer

Supplemental information to be furnished with reports filed pursuant to Section 15(d) of the
Exchange Act by Non-reporting Issuers

An annual report will be furnished to security holders subsequent to the filing of this report.


	PAGE
PART I

Item 1: Business		3-5

Item 2: Properties		5-9

Item 3: Legal Proceedings		10

Item 4: (Removed and Reserved)		10

PART II

Item 5: Market for Registrant’s Common Equity and Related Security Holder Matters		10-11

Item 7: Management’s Discussion and Analysis of Financial Condition or Plan of Operations		11-15

Item 8: Financial Statements		16-36

Item 9: Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		36

Item 9A: Controls and Procedures		36-37

Item 9B: Other Information		37

PART III

Item 10: Directors and Executive Officers of the Registrant		37-39

Item 11: Executive Compensation		40

Item 12: Security Ownership of Certain Beneficial Owners and Management		40

Item 13: Certain Relationships and Related Party Transactions		40

Item 14: Principal Accountant Fees and Services		41

PART IV

Item 15: Exhibits		41

SIGNATURES		42

Exhibit 23.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2
Exhibit 99.1


	2009			2008

REVENUES
Natural gas and oil	$	2,361,100		$	6,150,200

Total revenues		2,361,100			6,150,200

COSTS AND EXPENSES
Production		1,088,500			1,417,700
Depletion		1,063,400			3,103,300
Impairment of oil and gas properties		—			16,792,900
Accretion of asset retirement obligation		77,800			64,700
General and administrative		155,200			167,400

Total expenses		2,384,900			21,546,000

Net loss	$	(23,800	)	$	(15,395,800	)


Allocation of net (loss) earnings:
Managing general partner	$	167,600		$	(2,201,700	)

Limited partners	$	(191,400	)	$	(13,194,100	)

Net loss per limited partnership unit	$	(137	)	$	(9,424	)