10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2013

OR

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

For the transition period from to

Commission file number: 000-50246

ATLAS AMERICA Public #11-2002 LTD.

(Exact name of registrant as specified in its charter)

Delaware	02-0600231
(State or other jurisdiction or incorporation or organization)	(I.R.S. Employer Identification No.)
Park Place Corporate Center One 1000 Commerce Drive, Suite 400 Pittsburgh, PA	15275
(Address of principal executive offices)	Zip code

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

Securities registered pursuant to Section 12(b) of the Act:

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

Securities registered pursuant to Section 12(g) of the Exchange Act:

Common Units representing Limited Partnership Interests

(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  ¨    No  x

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  ¨    No  x

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

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

Indicate by check mark 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.  x

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 definitions of “large accelerated filer”, “accelerated filer”, and “small reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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

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

DOCUMENTS INCORPORATED BY REFERENCE: None

ATLAS AMERICA PUBLIC #11-2002 LTD.

INDEX TO ANNUAL REPORT

ON FORM 10-K

TABLE OF CONTENTS

			Page
PART I	Item 1:	Business	4
	Item 2:	Properties	13
	Item 3:	Legal Proceedings	15
	Item 4:	Mine Safety Disclosures (Not Applicable)	15
PART II	Item 5:	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	16
	Item 7:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
	Item 8:	Financial Statements and Supplementary Data	23
	Item 9:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	41
	Item 9A:	Controls and Procedures	41
PART III	Item 10:	Directors, Executive Officers and Corporate Governance	42
	Item 11:	Executive Compensation	43
	Item 12:	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	43
	Item 13:	Certain Relationships and Related Transactions	43
	Item 14:	Principal Accountant Fees and Services	44
PART IV	Item 15:	Exhibits	45
SIGNATURES			46

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GLOSSARY OF TERMS

Bbl. One stock tank barrel or 42 United States gallons liquid volume.

Developed acres. Acres spaced or assigned to productive wells.

Development well. A well drilled within a proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

FASB. Financial Accounting Standards Board.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

GAAP. Generally Accepted Accounting Principles.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

MBbl. One thousand barrels of oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet.

Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil, condensate or natural gas liquids.

MGP. Managing General Partner

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

NGL. Natural gas liquids, which are the hydrocarbon liquids contained within gas.

NYMEX. The New York Mercantile Exchange.

Oil. Crude oil and condensate.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved reserves. Proved oil and gas reserves are those quantities of oil and gas that by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

PV-10. Present value of future net revenues. See the definition of “standardized measure”.

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Reservoir. A porous and permeable underground formation containing a natural accumulation of economically productive oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

SEC. Securities Exchange Commission.

Standardized Measure. Standardized measure, or standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities, is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as general and administrative expenses, debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

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FORWARD-LOOKING STATEMENTS

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: BUSINESS

Overview

Atlas America Public #11-2002 LTD. (“we, “us”, or “the Partnership”) is a Delaware limited partnership and was formed on June 5, 2002 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or “the MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE:ARP). ARP is a publicly traded master limited partnership and an independent developer and producer of natural gas, crude oil, and natural gas liquids, with operations in basins across the United States. ARP is a leading sponsor and manager of tax-advantaged investment partnerships, in which it co-invests, to finance a portion of its natural gas and oil production activities.

We have drilled and currently operate wells located in Pennsylvania and Ohio. We have no employees and rely on our MGP for management, which in turn, relies on its ultimate Parent Company, Atlas Energy L.P., formerly known as Atlas Pipeline Holdings, L.P. (“Atlas Energy”) (NYSE: ATLS) for administrative services. (See Item 11 “Executive Compensation”). In March 2012, Atlas Energy contributed to ARP, substantially all of Atlas Energy’s natural gas and oil development and production assets and it partnership management business, including ownership of our MGP.

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

After formation, we received total cash subscriptions from investors of $31,178,100 which were paid to our MGP acting as operator and general drilling contractor under our drilling and operating agreement. Our MGP contributed leases, tangible equipment, and paid all syndication and offering costs for a total capital contribution of $13,295,200. We have drilled 167 development wells within the Clinton/Medina and Upper Devonian Sandstones geological formations in Pennsylvania and Ohio.

Business Strategy

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).

The MGP continues to manage our exposure to commodity price risk. To limit our exposure to changing commodity prices and enhance and stabilize our cash flow, our MGP uses financial hedges for a portion of our natural gas and oil production. Principally, the MGP uses fixed price swaps and puts on our behalf as the mechanism for the financial hedging of our commodity prices.

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Our operating cash flows are generated from our wells, which produce natural gas and oil. Our produced natural gas and oil is then delivered to market through third-party gas gathering systems. The majority of our natural gas and oil is delivered into the Laurel Mountain Midstream, LLC (“Laurel Mountain”) gas gathering system, a joint venture between Chevron Corporation (NYSE: CVX) and the Williams Companies, Inc. (NYSE: WMB). Laurel Mountain owns and operates all of APL’s previously owned Northern Appalachian assets. Upon formation of the joint venture in May 2009, subsidiaries of Atlas Energy, Inc. including our MGP, entered into new gas gathering agreements with Laurel Mountain, whereby they pay to Laurel Mountain a gathering fee based on a range, generally from $0.35 per Mcf to the amount of the competitive gathering fee which is currently defined as 16% of the gross sales price received for our gas.

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 $320 per well per month 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, routing 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 and materials and brine disposal. If these expenses are incurred, we pay the costs 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 cost of the well. As of December 31, 2013, our MGP had not withheld any funds for this purpose. The MGP is currently evaluating its right to exercise this option based on several factors such as commodity prices, the natural decline in well production, and current and future plugging services and costs.

Gas and Oil Production

Production Volumes

The following table presents our total net natural gas, oil and natural gas liquids production volumes for the years ended December 31, 2013 and 2012:

	Years Ended December 31,
	2013		2012
Production:(1)
Natural gas (Mcf)		240,530		285,179
Oil (Bbl)		1,622		1,033
Natural gas liquids (Bbl)		64		95
Total (Mcfe)		250,646		291,947

(1) Production quantities consist of the sum of our proportionate share of production from wells in which we have a direct interest, based on our proportionate net revenue interest in such wells.

Production Revenues, Prices and Costs

The MGP markets the majority of our natural gas production to gas marketers directly or to third-party plant operators who process and market the gas. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The production area and pricing indices for the Appalachian Basin are the Dominion South Point, Tennessee Gas Pipeline, and Transco Leidy Line.

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The following table presents our production revenues and average sales prices for our natural gas, oil and natural gas liquids production for the years ended December 31, 2013 and 2012, along with our average production costs in each of the reported periods:

	Years Ended December 31,
	2013		2012
Production revenues (in thousands):
Natural gas revenue	$	900	$	826
Oil revenue		155		96
Natural gas liquids revenue		3		4
Total revenues	$	1,058	$	926
Average sales price: (1)
Natural gas (per Mcf) (2)	$	4.05	$	3.37
Oil (per Bbl)	$	95.53	$	93.16
Natural gas liquids (per Bbl)	$	47.79	$	37.57
Production costs (per Mcfe)	$	2.89	$	2.62

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

(2) Average gas prices are calculated by including in total revenue derivative gains previously recognized into income in connection with prior period impairment charges and dividing by the total volume for the period. Previously recognized derivative gains were $73,000 and $134,800 for the years ended December 31, 2013 and 2012, respectively.

Drilling Activity

We received total cash subscriptions from investors of $31,178,100, which were paid to our MGP acting as operator and general drilling contractor under our drilling and operating agreement. Our MGP contributed leases, tangible equipment, and paid all syndication and offering costs for a total capital contribution of $13,295,200. We have drilled 167 development wells within the Clinton/Medina and Upper Devonian Sandstones geological formations in Pennsylvania and Ohio, respectively. We do not plan to sell any of our wells and will continue to produce them until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. No other wells will be drilled and no additional funds will be required for drilling. The following table summarizes the number of gross and net wells drilled by the Partnership:

	Gross		Net
Gas and/or oil wells drilled		167		160.50
Dry hole		-		-
Total wells drilled		167		160.50

Contractual Revenue Arrangements

Natural gas. The MGP markets the majority of our natural gas production to gas utility companies, gas marketers, local distribution companies and industrial or other end-users. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index.

We do not hold firm transportation obligations on any pipeline that requires payment of transportation fees regardless of natural gas production volumes. As is customary in certain of our other operating areas, we occasionally commit a predictable portion of monthly production to the purchaser in order to maintain a gathering agreement.

Crude oil. Crude oil produced from our wells flows directly into leasehold storage tanks where it is picked up by an oil company or a common carrier acting for an oil company. The crude oil is typically sold at the prevailing spot market price for each region, less appropriate trucking charges. We do not have delivery commitments for fixed and determinable quantities of crude oil in any future periods under existing contracts or agreements.

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Natural gas liquids. NGL’s are extracted from the natural gas stream by processing and fractionation plants enabling the remaining “dry” gas to meet pipeline specifications for transport to end users or marketers operating on the receiving pipeline. The resulting dry natural gas is sold as described above and our NGLs are generally priced using the Mont Belvieu (TX) or Conway (KS) regional processing indices. The cost to process and fractionate the NGLs from the gas stream is typically either a volumetric fee for the gas and liquids processed or a volumetric retention by the processing and fractionation facility. We do not have delivery commitments for fixed and determinable quantities of NGLs in any future periods under existing contracts or agreements.

Natural Gas and Oil Hedging

The MGP provides greater stability in our cash flows through its use of financial hedges. The financial hedges may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures and options contracts with qualified counterparties. Financial hedges are contracts between ourselves and counterparties and do not require physical delivery of hydrocarbons. Financial hedges allow us to mitigate hydrocarbon price risk, and cash is settled to the extent there is a price difference between the hedge price and the actual NYMEX settlement price. Settlement typically occurs on a monthly basis, at the time in the future dictated within the hedge contract. Financial hedges executed in accordance with the MGP’s secured credit facility do not require cash margin and are secured by our natural gas and oil properties. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, the MGP has a management committee to assure that all financial trading is done in compliance with its hedging policies and procedures. The MGP does not intend to contract for positions that we cannot offset with actual production.

Natural Gas Gathering Agreements

Virtually all natural gas produced is gathered through one or more pipeline systems before sale or delivery to an end user, a marketer, or an interstate pipeline. A gathering fee can be charged for each gathering activity that is utilized and by each separate gatherer providing the service. Fees will vary depending on the distance the gas travels and whether additional services such as compression, blending, or contaminant removal are provided.

In Appalachia, our MGP’s two primary gathering agreements are with Laurel Mountain Midstream, LLC (“Laurel Mountain”). Under the gathering agreements, we dedicate our natural gas production in certain areas within the Appalachian Basin to Laurel Mountain for transportation to interstate pipeline systems, local distribution companies, and/or end users in the area, subject to certain exceptions. In return, Laurel Mountain is required to accept and transport our dedicated natural gas in the Appalachian Basin subject to certain conditions.

Markets and Competition

The availability of a ready market for natural gas, oil and NGLs and the price obtained, depends upon numerous factors beyond our control. Product availability and price are the principal means of competition in selling natural gas, oil, and NGLs. During the years ended December 31, 2013 and 2012, our MGP did not experience problems in selling our natural gas, oil, and NGLs, although prices have varied significantly during those periods. While it is impossible to accurately determine our competitive position in the industry, we do not consider our operations to be a significant factor in the industry.

Seasonal Nature of Business

Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. In addition, seasonal weather conditions and lease stipulations can limit our producing activities and other operations in certain areas of the Appalachian region and Michigan/Indiana. These seasonal anomalies may pose challenges and increase competition for equipment, supplies, and personnel, which could lead to shortages and increase costs or delay our operations.

Environmental Matters and Regulation

Overview. Our operations are subject to comprehensive and stringent federal, state and local laws and regulations governing, among other things, where and how we drill wells, how we handle waste from our operations and the discharge of materials into the environment. Our operations will be subject to the same environmental laws and regulations as other companies in the natural gas and oil industry. Among other requirements and restrictions, these laws and regulations may:

— require the acquisition of various permits before drilling commences;

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— require the installation of expensive pollution control equipment and water treatment facilities;

— restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling, completion and production activities;

— limit or prohibit drilling activities on certain land;

— require remedial measures to reduce, mitigate and/or respond to releases of pollutants or hazardous substances from existing and former operations, such as pit closure and plugging of abandoned wells;

— impose substantial liabilities for pollution resulting from our operations; and

— with respect to operations affecting federal lands or leases, require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement.

These laws, rules and regulations may also restrict the rate of natural gas and oil production below the rate that would otherwise be possible. The regulatory burden on the natural gas and oil industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently enact new, and revise existing, environmental laws and regulations, and any new laws or changes to existing laws that result in more stringent and costly waste handling, disposal and clean-up requirements for the natural gas and oil industry could have a significant impact on our operating costs. We believe that our operations substantially comply with all currently applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict how environmental laws and regulations that may take effect in the future may impact our properties or operations. For the three-year period ended December 31, 2013, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. We are not aware of any environmental issues or claims that will require material capital expenditures during 2014, or that will otherwise have a material impact on our financial position or results of operations.

Environmental laws and regulations that could have a material impact on the natural gas and oil exploration and production industry include the following:

National Environmental Policy Act. Natural gas and oil exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major federal agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will typically require an Environmental Assessment to assess the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that will be made available for public review and comment. All of our proposed exploration and production activities on federal lands require governmental permits, many of which are subject to the requirements of NEPA. This process has the potential to delay the development of natural gas and oil projects.

Waste Handling. The Solid Waste Disposal Act, including the Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal of non-hazardous wastes. Under the auspices of the Environmental Protection Agency (“EPA”), individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil and natural gas constitute “solid wastes”, which are regulated under the less stringent non-hazardous waste provisions, but there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation.

We believe that our operations are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes to be significant, any more stringent regulation of natural gas and oil exploitation and production wastes could increase our costs to manage and dispose of such wastes.

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Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes joint and several liability, without regard to fault or legality of conduct, on persons who are considered under the statute to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

Our operations are, in many cases, conducted at properties that have been used for natural gas and oil exploitation and production for many years. Although we believe we utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons was not under our control. These properties, and the substances disposed or released on them, may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other natural gas and oil wastes, into navigable waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or the relevant state. These permits may require pretreatment of produced waters before discharge. Compliance with such permits and requirements may be costly. Further, much of our natural gas extraction activity utilizes a process called hydraulic fracturing, which results in water discharges that must be treated and disposed of in accordance with applicable regulatory requirements.

The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The Clean Water Act also requires specified facilities to maintain and implement spill prevention, control and countermeasure plans and to take measures to minimize the risks of petroleum spills. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for failure to obtain or non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. We believe our operations are in substantial compliance with the requirements of the Clean Water Act.

Air Emissions. The Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through permits and other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic and other air pollutants at specified sources. In 2012, specific federal regulations applicable to the natural gas industry were finalized under the New Source Performance Standards (“NSPS”) program along with National Emissions Standards for Hazardous Air Pollutants (“NESHAP”). These new regulations impose additional emissions control requirements and practices on our operations. Some of our new facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to comply with new emission limitations. These regulations may increase the costs of compliance for some facilities, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance. These laws and regulations also apply to entities that use natural gas as fuel, and may increase the costs of compliance of our customers to the point where demand for natural gas is affected. We believe that our operations are in substantial compliance with the requirements of the Clean Air Act.

OSHA and other regulations. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

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Greenhouse gas regulation and climate change. Natural gas contains methane, which is considered to be a greenhouse gas. Additionally, the burning of natural gas produces carbon dioxide, which is also a greenhouse gas. Published studies have suggested that the emission of greenhouse gases may be contributing to global warming. To date, legislative and regulatory initiatives relating to greenhouse gas emissions have not had a material impact on our business. However, Congress has been actively considering climate change legislation. More directly, the EPA has begun regulating greenhouse gas emissions under the federal Clean Air Act. In response to the Supreme Court’s decision in Massachusetts V. EPA, 549 U.S. 497 (2007) (holding that greenhouse gases are air pollutants covered by the Clean Air Act), the EPA made a final determination that greenhouse gases endangered public health and welfare, 74 Fed. Reg. 66,496 (December 15, 2009). This finding led to the regulation of greenhouse gases under the Clean Air Act. Currently, the EPA has promulgated two rules that will impact our business.

First, the EPA promulgated the so-called “Tailoring Rule” which established emission thresholds for greenhouse gases under the Clean Air Act permitting programs, 75 Fed. Reg. 31514 (June 3, 2010). Both the federal preconstruction review program (“Prevention of Significant Deterioration” or “PSD”) and the operating permit program (“Title V”) are now implicated by emissions of greenhouse gases. These programs, as modified by the Tailoring Rule, could require some new facilities to obtain a PSD permit depending on the size of the new facilities. In addition, existing facilities as well as new facilities that exceed the emissions thresholds could be required to obtain Title V operating permits.

Second, the EPA finalized its Mandatory Reporting of Greenhouse Gases rule in 2009, 74 Fed. Reg. 56,260 (October 30, 2009). Subsequent revisions, additions, and clarification rules were promulgated, including a rule specifically addressing the natural gas industry. These rules require certain industry sectors that emit greenhouse gases above a specified threshold to report greenhouse gas emissions to the EPA on an annual basis. The natural gas industry is covered by the rule and requires annual greenhouse gas emissions to be reported by March 31 of each year for the emissions during the preceding calendar year. This rule imposes additional obligations on us to determine whether the greenhouse gas reporting applies and if so, to calculate and report greenhouse gas emissions.

There are also ongoing legislative and regulatory efforts to encourage the use of cleaner energy technologies. While natural gas is a fossil fuel, it is considered to be more benign, from a greenhouse gas standpoint, than other carbon-based fuels, such as coal or oil. Thus future regulatory developments could have a positive impact on our business to the extent that they either decrease the demand for other carbon-based fuels or position natural gas as a favored fuel.

In addition to domestic regulatory developments, the United States is a participant in multi-national discussion intended to deal with the greenhouse gas issue on a global basis. To date, those discussions have not resulted in the imposition of any specific regulatory system, but such talks are continuing and may result in treaties or other multi-national agreements that could have an impact on our business.

Finally, as noted above, the scientific community continues to engage in a healthy debate as to the impact of greenhouse gas emissions on planetary conditions. For example, such emissions may be responsible for increasing global temperatures, and/or enhancing the frequency and severity of storms, flooding and other similar adverse weather conditions. We do not believe that these conditions are having any material current adverse impact on our business, and we are unable to predict at this time, what, if any, long-term impact such climate effects would have.

Other regulation of the natural gas and oil industry. The natural gas and oil industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the natural gas and oil industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the natural gas and oil industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in their industries with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including natural gas and oil facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

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Energy Policy Act of 2005. Much of our natural gas extraction activity utilizes a process called hydraulic fracturing. The Energy Policy Act of 2005 amended the definition of “underground injection” in the Federal Safe Drinking Water Act of 1974 (“SDWA”). This amendment effectively excluded hydraulic fracturing for oil, gas, or geothermal activities from the SDWA permitting requirements, except when “diesel fuels” are used in the hydraulic fracturing operations. Recently, this subject has received much regulatory and legislative attention at both the federal and state level and we anticipate that the permitting and compliance requirements applicable to hydraulic fracturing activity are likely to become more stringent and could have a material adverse impact on ARP’s business and operations. For instance, the U.S. EPA published a draft “Permitting Guidance for Oil and Gas Hydraulic Fracturing Activities Using Diesel Fuels” (“Draft Diesel Guidance”) on May 10, 2012 for public comment through August 23, 2012. In that Draft Diesel Guidance, the EPA asserts SDWA permitting authority over hydraulic fracturing activities that employ the injection of diesel fuel. The EPA submitted its draft guidance to the White House Office of Management and Budget in September 2013. The draft guidance submitted to the White House Office of Management and Budget was not published by the EPA, so it is not clear what changes may have been made to the guidance by the EPA as a result of the comments received during the 2012 public comment period. The EPA has not provided a specific timeframe for the release of the final guidance.

The U.S. Senate and House of Representatives considered legislative bills in the 111^th and 112^th Sessions of Congress that, if enacted, would have repealed the SDWA permitting exemption for hydraulic fracturing activities. Titled the “Fracturing Responsibility and Awareness of Chemicals Act” (or “Frac Act”), the legislative bills as proposed could have potentially led to significant oversight of hydraulic fracturing activities by federal and state agencies. In 2013, the Frac Act was re-introduced in the 113^th Session of Congress. If enacted into law, the legislation as proposed could potentially result in significant regulatory oversight, which may include additional permitting, monitoring, recording, and recordkeeping requirements for us.

We believe our operations are in substantial compliance with existing SDWA requirements. However, future compliance with the SDWA could result in additional requirements and costs due to the possibility that new or amended laws, regulations, or policies could be implemented or enacted in the future.

Hydrogen Sulfide. Exposure to gas containing high levels of hydrogen sulfide, referred to as sour gas, is harmful to humans and can result in death. We conduct our natural gas extraction activities in certain formations where hydrogen sulfide may be, or is known to be, present. We employ numerous safety precautions at our operations to ensure the safety of its employees. There are various federal and state environmental and safety requirements for handling sour gas, and we believe we are in substantial compliance with all such requirements.

Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we will operate also regulate one or more of the following:

— the location of wells;

— the manner in which water necessary to develop wells is accessed, utilized, managed and disposed of;

— the method of drilling, completing and casing and producing wells;

— the surface use and restoration of properties upon which wells are drilled;

— the plugging and abandoning of wells; and

— notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of natural gas and oil properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil we can produce from its wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax or impact fee with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

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State Regulation and Taxation of Drilling. The various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Pennsylvania has imposed an impact fee on wells drilled into an unconventional formation, which includes the Marcellus Shale. The impact fee, which changes from year to year, is based on the average annual price of natural gas as determined by the NYMEX price, as reported by the Wall Street Journal for the last trading day of each calendar month. For example, based upon natural gas prices for 2013, the impact fee for qualifying unconventional horizontal wells spudded during 2013 was $50,000 per well, while the impact fee for unconventional vertical wells was $10,000 per well. The payment structure for the impact fee makes the fee due the year after an unconventional well is spudded, and the fee will continue for 15 years for an unconventional horizontal well and 10 years for an unconventional vertical well. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum limits on daily production allowable from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells, the type of wells that may be drilled in the future in proximity to existing wells and to limit the number of wells or locations from which we can drill. Texas imposes a 7.5% tax on the market value of natural gas sold, 4.6% on the market value of condensate and a fee of $0.000667 per Mcf of gas produced and $.00625 per barrel of crude.  New Mexico imposes a severance tax of up to 3.75% of the value of oil and gas produced, a conservation tax equal to 0.19% of the oil and gas sold, and a school emergency tax of up to 3.15% for oil and 4% for gas.  Alabama imposes a production tax of up to 2% on oil or gas and a privilege tax of up to 8% of oil or gas. Oklahoma imposes a gross production tax of 7% per Bbl of oil, 7% per Mcf of natural gas and a petroleum excise tax of $0.095 on the gross production of oil and gas.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect upon our unitholders.

Oil Spills and Hydraulic Fracturing. The Oil Pollution Act of 1990, as amended, (“OPA”), contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters. While we believe we have been in compliance with OPA, noncompliance could result in varying civil and criminal penalties and liabilities.

A number of federal agencies, including but not limited to the EPA and the Department of Interior, are currently evaluating a variety of environmental issues related to hydraulic fracturing. For example, the EPA is conducting a study that evaluates any potential impacts of hydraulic fracturing on drinking water and ground water. The EPA released a progress report on this study on December 21, 2012 that did not present any conclusions, but notes that results will be released in draft form in late 2014 for review by the public and the EPA Science Advisory Board. The Department of Interior’s Bureau of Land Management published a revised proposed rule to regulate hydraulic fracturing on federal and Indian lands on May 24, 2013, and a final rule is expected to be issued in 2014.

In addition, state, local conservancy districts and river basin commissions have all previously exercised their various regulatory powers to curtail and, in some cases, place moratoriums on hydraulic fracturing. State regulations include express inclusion of hydraulic fracturing into existing regulations covering other aspects of exploration and production and specifically may include, but not be limited to, the following:

— requirement that logs and pressure test results are included in disclosures to state authorities;

— disclosure of hydraulic fracturing fluids and chemicals, and the ratios of same used in operations;

— specific disposal regimens for hydraulic fracturing fluids;

— replacement/remediation of contaminated water assets; and

— minimum depth of hydraulic fracturing.

Local regulations, which may be preempted by state and federal regulations, have included, but have not been limited to, the following which may extend to all operations including those beyond hydraulic fracturing:

— noise control ordinances;

— traffic control ordinances;

— limitations on the hours of operations; and

— mandatory reporting of accidents, spills and pressure test failures.

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Employees

We do not directly employ any of the persons responsible for our management or operation. In general, personnel employed by Atlas Energy manage and operate our business. Some of the officers of our general partner may spend a substantial amount of time managing the business and affairs of Atlas Energy and its affiliates other than us and may face a conflict regarding the allocation of their time between our business and affairs and their other business interests.

Available Information

We make our periodic reports under the Securities Exchange Act of 1934, including our annual report on Form 10-K, our quarterly reports on Form 10-Q, our current reports on Form 8-K, and any amendments to those reports, available through our MGP’s website at www.atlasresourcepartners.com as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (“SEC”). To view these reports, click on “Investment Programs”, then “Drilling Program SEC Filings” and finally the respective program of your inquiry. You may also receive, without charge, a paper copy of any such filings by request to us at Park Place Corporate Center One, 1000 Commerce Drive, Suite 400, Pittsburgh, Pennsylvania 15275, telephone number (800) 251-0171. A complete list of our filings is available on the SEC’s website at www.sec.gov. Any of our filings are also available at the Securities and Exchange Commission’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. The Public Reference Room may be contacted at telephone number (800) 732-0330 for further information.

ITEM 2: PROPERTIES

Natural Gas, Oil and NGL Reserves

The following tables summarize information regarding our estimated proved natural gas and oil reserves as of December 31, 2013 and 2012. Proved reserves are 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. All of the reserves are located in the United States. We base these estimated proved natural gas, oil and NGL reserves and future net revenues of natural gas, oil and NGL reserves upon reports prepared by Wright & Company, Inc., an independent third-party reserve engineer. We have adjusted these estimates to reflect the settlement of asset retirement obligations on gas and oil properties. A summary of the reserve report related to our estimated proved reserves at December 31, 2013 is included as Exhibit 99.1 to this report. In accordance with SEC guidelines, we make the standardized measure estimates of future net cash flows from proved reserves using natural gas, oil and NGL sales prices in effect as of the dates of the estimates which are held constant throughout the life of the properties. Our estimates of proved reserves are calculated on the basis of the unweighted adjusted average of the first-day-of-the-month price for each month during the years ended December 2013 and 2012 and are listed below as of the dates indicated:

	December 31,
	2013		2012
Natural gas (per Mcf)	$	3.67	$	2.76
Oil (per Bbl)	$	96.78	$	94.71
Natural gas liquids (per Bbl)	$	30.10	$	33.91

Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas, oil and NGL 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 and the timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas, oil and NGL’s 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, oil and NGL reserve estimates was completed in accordance with our MGP’s prescribed internal control procedures by its reserve engineers. For the periods presented, Wright and Company, Inc., was retained to prepare a report of proved reserves. The reserve information includes natural gas and oil reserves which are all located in the United States, primarily in Pennsylvania and Ohio. The independent reserves engineer’s evaluation was based on more than 37 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. Our internal control procedures include verification of input data delivered to our third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our MGP’s Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 15 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by our MGP’s senior engineering staff and management, with final approval by our MGP’s Chief Operating Officer and President.

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Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of these estimates. Future prices received from the sale of natural gas, oil and NGL’s may be different from those estimated by Wright & Company, Inc. in preparing its reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, the reserves set forth in the following tables ultimately may not be produced. You should not construe the estimated standardized measure values as representative of the current or future fair market value of our proved natural gas and oil properties. Standardized measure values are based upon projected cash inflows, which do not provide for changes in natural gas, oil and NGL prices or for the escalation of expenses and capital costs. 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 deduct operating costs, development costs and production-related and ad valorem taxes in arriving at the estimated future cash flows. We base the estimates on operating methods and conditions prevailing as of the dates indicated. Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods:

	Proved Reserves at December 31,
	2013		2012
Proved reserves:
Natural gas reserves (Mcf)		1,048,300		330,600
Oil reserves (Bbl)		5,300		2,800
Natural gas liquids (Bbl)		-		-
Total proved developed reserves (Mcfe)		1,080,100		347,400
Standardized measure of discounted future cash flows (1)	$	774,100	$	167,100
Standardized measure of discounted future cash flows per Limited Partner Unit (2)	$	161	$	35
Undiscounted future cash flows per Limited Partner Unit	$	211	$	40

(1) Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC without giving effect to non-property related expenses, such as general and administrative expenses, interest and income tax expenses, or to depletion, depreciation and amortization. The future cash flows are discounted using an annual discount rate of 10%. Standardized measure does not give effect to commodity derivative contracts. Because we are a limited partnership, no provision for federal or state income taxes has been included in the December 31, 2013 and 2012 calculations of standardized measure, which is, therefore, the same as the PV-10 value.

(2) This value per limited partner 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 the unit for purposes of presentment of the unit to our MGP for purchase is different, because it is calculated under a formula set forth in the Partnership Agreement.

Productive Wells

Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest and net wells are the sum of our fractional working interests in gross wells. The following table sets forth information regarding productive natural gas and oil wells in which we have a working interest as of December 31, 2013:

	Number of productive wells
	Gross		Net
Gas and/or oil wells		167		160.50

Developed Acreage

The following table sets forth information about our developed natural gas and oil acreage as of December 31, 2013:

	Developed Acreage
	Gross		Net
Pennsylvania		4,433.24		4,338.34
Ohio		74		74
Total		4,507.24		4,412.34

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The leases for our developed acreage generally have terms that extend for the life of the wells. We believe that we hold good and indefeasible title to our producing 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, we conduct only a perfunctory title examination at the time we acquire a property. Before we commence drilling operations, we conduct an extensive title examination and we perform curative work on defects that we deem significant. We or our predecessors have obtained title examinations for substantially all of our managed 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 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.

ITEM 3: LEGAL PROCEEDINGS

We are party to various routine legal proceedings arising out of the ordinary course of our business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations. (See Item 8: Note 9 Commitments and Contingencies).

ITEM 4: MINE SAFETY DISCLOSURES (Not applicable)

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PART II

ITEM 5: MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

There is no established public trading market for our units and we do not anticipate that 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 MGP consent;

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

— the transfer does 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 MGP 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 MGP requires to effect the substitution and to confirm his or her agreement to be bound by the term 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. As of December 31, 2013, we had 1,022 limited partners.

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. We will not advance or borrow funds for purposes of making distributions. During the years ended December 31, 2013 and 2012, we distributed the following:

	Distributions
	2013		2012
Limited Partners	$	206,700	$	224,000
Managing General Partner		44,000		44,700
Total distributions	$	250,700	$	268,700

ITEM 7: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The discussion and analysis presented below provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with (“Item 8: Financial Statements and Supplementary Data”), which contains our financial statements.

The following discussion may contain forward-looking statements that reflect our plans, estimates and beliefs. Forward-looking statements speak only as of the date the statements were made. The matters discussed in these forward-looking statements are subject to risks, uncertainties and other factors that could cause actual results to differ materially from those made, projected or implied in the forward-looking statements. We believe the assumptions underlying the financial statements are reasonable. However, our financial statements included herein may not necessarily reflect our results of operations, financial position and cash flows in the future.

BUSINESS OVERVIEW

Atlas America Public #11-2002 LTD. (“we”, “us”, or “the Partnership”) is a Delaware limited partnership and formed on June 5, 2002 with Atlas Resources, LLC serving as its managing general partner and operator (“Atlas Resources” or “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resources Partners, L.P. (“ARP”) (NYSE: ARP).

We have drilled and currently operate wells located in Pennsylvania and Ohio. We have no employees and rely on our MGP for management, which in turn, relies on its ultimate parent company, Atlas Energy (“Atlas Energy”) (NYSE: ATLS) for administrative services.

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The following discussion provides information to assist in understanding our financial condition and results of operations. Our operating cash flows are generated from our wells, which primarily produce natural gas, but also some oil. Our produced natural gas and oil is then delivered to market through affiliated or third-party gas gathering systems. Our ongoing operating and maintenance costs have been and are expected to be fulfilled through revenues from the sale of our natural gas and oil production. We pay our MGP, as operator, a monthly well supervision fee, which covers all normal and regularly recurring operating expenses for the production and sale of natural gas and oil such as:

— Well tending, routine maintenance and adjustment;

— Reading meters, recording production, pumping, maintaining appropriate books and records; and

— Preparation of reports for us and government agencies.

The well supervision fees, however, do not include costs and expenses related to the purchase of certain equipment, materials, and brine disposal. If these expenses are incurred, we pay cost for third-party services, materials, and a competitive charge for service performed directly by our MGP or its affiliates. Also, beginning one year after each of our wells has been placed into production, our MGP, as operator, may retain $200 per month per well to cover the estimated future plugging and abandonment costs of the well. As of December 31, 2013, our MGP had not withheld any funds for this purpose. The MGP is currently evaluating its right to exercise this option based on several factors such as commodity prices, the natural decline in well production, and current future plugging services and costs.

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 production. During 2013 and 2012, we experienced no problems in selling our natural gas and oil. Product availability and price are the principal means of competing in selling natural gas and oil production. While it is impossible to accurately determine our comparative position in the industry, we do not consider our operations to be a significant factor in the industry.

Natural Gas. The MGP markets the majority of our natural gas production to gas marketers directly or to third-party plant operators who process and market the gas. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The production area and pricing indices for the Appalachian Basin are the Dominion South Point, Tennessee Gas Pipeline, and Transco Leidy Line.

We do not hold firm transportation obligations on any pipeline that requires payment of transportation fees regardless of natural gas production volumes. As is customary in certain of our other operating areas, we occasionally commit a predictable portion of monthly production to the purchaser in order to maintain a gathering agreement.

Crude Oil. Crude oil produced from our wells flows directly into leasehold storage tanks where it is picked up by an oil company or a common carrier acting for an oil company. The crude oil is typically sold at the prevailing spot market price for each region, less appropriate trucking charges. We do not have delivery commitments for fixed and determinable quantities of crude oil in any future periods under existing contracts or agreements.

Natural Gas Liquids. NGL’s are extracted from the natural gas stream by processing and fractionation plants enabling the remaining “dry” gas to meet pipeline specifications for transport to end users or marketers operating on the receiving pipeline. The resulting dry natural gas is sold as mentioned above and our NGLs are generally priced using the Mont Belvieu (TX), or Conway (KS) regional processing indices. The cost to process and fractionate the NGLs from the gas stream is typically either a volumetric fee for the gas and liquids processed or a volumetric retention by the processing and fractionation facility. We do not have delivery commitments for fixed and determinable quantities of NGLs in any future periods under existing contracts or agreements.

For the year ended December 31, 2013, Chevron Natural Gas, Interstate Gas Supply, Inc., U.S. Energy Exploration Corporation, and Ergon Oil Purchasing, Inc. accounted for approximately 48%, 22%, 11%, and 10%, respectively, of our total natural gas, oil and NGL production revenues, with no other single customer accounting for more than 10% for this period.

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GENERAL TRENDS AND OUTLOOK

We expect our business to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

The areas in which we operate are experiencing a significant increase in natural gas, oil and NGL production related to new and increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques, including horizontal and multiple fracturing techniques. The increase in the supply of natural gas has put a downward pressure on domestic natural gas prices. While we anticipate continued high levels of exploration and production activities over the long-term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new natural gas and oil reserves.

Our future production, cash flow, and our ability to make distributions to our unitholders, including the MGP, depend on our success in producing our current reserves efficiently. We face the challenge of natural production declines and volatile natural gas and oil prices. As initial reservoir pressures are depleted, natural gas production from particular wells decreases.

RESULTS OF OPERATIONS

GAS, OIL AND NGL PRODUCTION: 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,
	2013			2012
Production revenues (in thousands):
Gas	$	900		$	826
Oil		155			96
Liquids		3			4
Total	$	1,058		$	926
Production volumes:
Gas (mcf/day)		659			779
Oil (bbls/day)		4			3
Liquids (bbls/day)		-			-
Total (mcfe/day)		683			797
Average sales price: (1)
Gas (per mcf) (2)	$	4.05		$	3.37
Oil (per bbl)	$	95.53		$	93.16
Liquids (per bbl)	$	47.79		$	37.57
Production costs:
As a percent of revenues		69	%		83	%
Per mcfe	$	2.89		$	2.62
Depletion per mcfe	$	2.09		$	1.38

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

(2) Average gas prices are calculated by including in total revenue derivative gains previously recognized into income in connection with prior period impairment charges and dividing by the total volume for the period. Previously recognized derivative gains were $73,000 and $134,800 for the years ended December 31, 2013 and 2012, respectively.

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Natural Gas Revenues. Our natural gas revenues were $900,400 and $825,600 for the years ended December 31, 2013 and 2012, respectively, an increase of $74,800 (9%). The $74,800 increase in natural gas revenues for the year ended December 31, 2013 as compared to the prior year was attributable to a $204,100 increase in natural gas prices after the effect of financial hedges, which were driven by market conditions, partially offset by a $129,300 decrease in production volumes. Our production volumes decreased to 659 mcf per day for the year ended December 31, 2013 from 779 mcf per day for the year ended December 31, 2012, a decrease of 120 (15%) mcf per day. The price we receive for our natural gas is primarily a result of the index driven agreements (See Item 1 “Business-Contractual Revenue Arrangements”). Thus, the price we receive for our natural gas may vary significantly each month as the underlying index changes in response to market conditions. The decrease in production volumes is mostly due to normal decline inherent in the life of the wells.

Oil Revenues. We drill wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $154,900 and $96,300 for the years ended December 31, 2013 and 2012, respectively, an increase of $58,600 (61%). The $58,600 increase in oil revenues for the year ended December 31, 2013 as compared to the prior year was attributable to a $3,800 increase in oil prices after the effect of financial hedges and a $54,800 increase in production volumes. Our production volumes increased to 4.55 bbls per day for the year ended December 31, 2013 from 2.82 bbls per day for the year ended December 31, 2012, an increase of 1.73 bbl per day (61%).

Natural Gas Liquids Revenue. The majority of our wells produce “dry gas”, which is composed primarily of methane and requires no additional processing before being transported and sold to the purchaser. Some wells, however, produce “wet gas”, which contains larger amounts of ethane and other associated hydrocarbons (i.e. “natural gas liquids”) that must be removed prior to transporting the gas. Once removed, these natural gas liquids are sold to various purchasers. Our natural gas liquids revenues were $3,000 and $3,600 for the years ended December 31, 2013 and 2012, respectively, a decrease of $600 (17%). The $600 decrease in liquid revenues for the year ended December 31, 2013 as compared to the prior year period was attributable to a $1,200 decrease in production volumes, partially offset by a $600 increase in liquid prices. Our production volumes were .17 and .26 bbls per day for the years ended December 31, 2013 and 2012, respectively, a decrease of .09 (35%) bbls per day.

Costs and Expenses. Production expenses were $725,300 and $764,900 for the years ended December 31, 2013 and 2012, respectively, a decrease of $39,600 (5%). This decrease was primarily due to a combination of a decrease in supervision fees and compressor station expenses.

Depletion of our oil and gas properties as a percentage of oil and gas revenues was 50% and 43% for the years ended December 31, 2013 and 2012, respectively. These percentage changes were directly attributable to changes in revenues, oil and gas reserve quantities, product prices, production volumes and changes in the cost basis of oil and gas properties.

General and administrative expenses were $160,300 and $169,100 for the years ended December 31, 2013 and 2012, respectively, a decrease of $8,800 (5%). 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 of costs and services provided to us.

There were no impairments of oil and gas properties for the years ended December 31, 2013 and 2012. 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. As a result of this assessment, an impairment charge was not recognized for the years ended December 31, 2013 and 2012. This charge is based on reserve quantities, future market prices and our carrying value. We cannot provide any assurance that similar charges may or may not be taken in future periods.

Liquidity and Capital Resources. Cash provided by operating activities increased $99,800 for the year ended December 31, 2013 to $277,500 as compared to $177,700 the year ended December 31, 2012. This increase was due to an increase in net earnings before depletion, and accretion of $181,200 and an increase in the change in accrued liabilities of $16,100, partially offset by a decrease in the change in accounts receivable trade-affiliate of $36,300 and a decrease in the non-cash loss on derivative value of $61,200 for the year ended December 31, 2013 compared to the year ended December 31, 2012.

Cash provided by investing activities was $8,200 during the year ended December 31, 2012 resulting from the sale of tangible equipment.

Cash used in financing activities decreased $18,000 to $250,700 for the year ended December 31, 2013, from $268,700 for the year ended December 31, 2012. This decrease was due to a decrease in cash distributions to partners.

19

Our MGP may withhold funds for future plugging and abandonment costs. The MGP is currently evaluating its right to exercise this option based on several factors such as commodity prices, the natural decline in well production, and current future plugging services and costs. Through December 31, 2013, our MGP had not withheld any funds for this purpose. Any additional funds, if required, will be obtained from production revenues or borrowings from our MGP or its affiliates, which are not contractually committed to make loans to us. The amount that we may borrow may not at any time exceed 5% of our total subscriptions, and we will not borrow from third-parties.

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

Asset Impairment

There were no impairments of proved gas and oil properties recorded by us for years ended December 31, 2013 and 2012. Asset impairment relates to the carrying amount of our gas and oil properties being in excess of our estimate of their fair value. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices.

ENVIRONMENTAL REGULATION

Our operations are subject to federal, state and local laws and regulations governing the release of regulated materials into the environment or otherwise relating to environmental protection or human health or safety (see “Item 1: Business —Environmental Matters and Regulations”). We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, imposition of remedial requirements, issuance of injunctions affecting our operations, or other measures. We have ongoing environmental compliance programs. However, risks of accidental leaks or spills are associated with our operations. There can be no assurance that we will not incur significant costs and liabilities relating to claims for damages to property, the environment, natural resources, or persons resulting from the operation of our business. Moreover, it is possible other developments, such as increasingly strict environmental laws and regulations and enforcement policies, could result in increased costs and liabilities to us.

Environmental laws and regulations have changed substantially and rapidly over the last 25 years, and we anticipate that there will be continuing changes. Trends in environmental regulation include increased reporting obligations and placing more restrictions and limitations on activities, such as emissions of greenhouse gases and other pollutants, generation and disposal of wastes, including wastes that may have naturally occurring radioactivity, and use, storage and handling of chemical substances that may impact human health, the environment and/or endangered species. Other increasingly stringent environmental restrictions and limitations have resulted in increased operating costs for us and other similar businesses throughout the United States. It is possible that the costs of compliance with environmental laws and regulations may continue to increase. We will attempt to anticipate future regulatory requirements that might be imposed and to plan accordingly, but there can be no assurance that we will identify and properly anticipate each such change, or that our efforts will prevent material costs, if any, from rising.

CHANGES IN PRICES AND INFLATION

Our revenues and the value of our assets have been and will continue to be affected by changes in natural gas and oil market prices. Natural gas and oil prices are subject to significant fluctuations that are beyond our ability to control or predict.

Inflation affects the operating expenses of our operations. Inflationary trends may occur if commodity prices were to increase, since such an increase may cause the demand for energy equipment and services to increase, thereby increasing the costs of acquiring or obtaining such equipment and services. While we anticipate that inflation will affect our future operating costs, we cannot predict the timing or amounts of any such effects.

20

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in conformity with U.S. GAAP 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 revenue and expense accruals, depletion and amortization, 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”) included in this report. The critical accounting policies and estimates we have identified are discussed below.

Depletion and Impairment of Long-Lived Assets

Long-Lived Assets. The cost of natural gas and oil properties, less estimated salvage value, is generally depleted on the units-of-production method.

Natural gas and oil properties are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. A long-lived asset is considered to be impaired when the undiscounted net cash flows expected to be generated by the asset are less than its carrying amount. The undiscounted net cash flows expected to be generated by the asset are based upon our estimates that rely on various assumptions, including natural gas and oil prices, production and operating expenses. Any significant variance in these assumptions could materially affect the estimated net cash flows expected to be generated by the asset. As discussed in General Trends and Outlook within this section, recent increases in natural gas drilling have driven an increase in the supply of natural gas and put a downward pressure on domestic prices. Further declines in natural gas prices may result in additional impairment charges in future periods.

There were no impairments of proved gas and oil properties recorded by us for the years ending December 31, 2013 and 2012. Asset impairments relates to the carrying amount of these gas and oil properties being in excess of our estimate of their fair value. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

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.

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 assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

We use a fair value methodology to value the assets and liabilities for our outstanding derivative contracts. Our 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.

Liabilities that are required to be measured at fair value on a nonrecurring basis include our asset retirement obligations (“ARO”) 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 MGP’s credit-adjusted risk-free rate and inflation rates.

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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 and availability of funds. The accuracy of these reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates. We engaged Wright and Company, Inc., an independent third-party reserve engineer, to prepare a report of our proved reserves (see “Item 2: Properties”).

Any significant variance in the assumptions utilized in the calculation of our reserve estimates 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, 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 our ability to pay distributions. In addition, our proved reserves may be subject to downward or upward revision based upon production history, prevailing natural gas and oil prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control. Our reserves and their relation to estimated future net cash flows impact the calculation of impairment and depletion of oil and gas properties. Generally, an increase or decrease in reserves without a corresponding change in capitalized costs will have a corresponding inverse impact to depletion expense.

Asset Retirement Obligations

We recognize and estimate the liability for the plugging and abandonment of our gas and oil wells. The associated asset retirement costs are capitalized as part of the carrying amount of the long lived asset.

The estimated liability is based on our 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 our MGP’s assumed credit-adjusted 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. We have no assets legally restricted for purposes of settling asset retirement obligations. Except for our gas and oil properties, we believe that there are no other material retirement obligations associated with tangible long lived assets.

Working Interest

Our Partnership Agreement establishes that revenues and expenses 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 the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expense 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 based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.

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ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Atlas America Public #11-2002 LTD.

We have audited the accompanying balance sheets of Atlas America Public #11-2002 LTD. (a Delaware limited partnership) (the “Partnership”) as of December 31, 2013 and 2012, and the related statements of operations, comprehensive loss, changes in partners’ capital, and cash flows for each of the two years in the period ended December 31, 2013. 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. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audits 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 Public #11-2002 LTD. as of December 31, 2013, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

March 31, 2014

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ATLAS AMERICA PUBLIC #11-2002 LTD.

BALANCE SHEETS

DECEMBER 31,

	2013			2012
ASSETS
Current assets:
Cash and cash equivalents	$	56,600		$	29,800
Accounts receivable trade–affiliate		170,500			193,800
Accounts receivable monetized gains-affiliate		9,700			41,800
Current portion of derivative assets		1,200			1,900
Total current assets		238,000			267,300
Oil and gas properties, net		2,665,300			3,435,100
Long-term derivative assets		6,100			7,900
	$	2,909,400		$	3,710,300
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	9,300		$	800
Total current liabilities		9,300			800
Asset retirement obligations		2,535,000			2,637,100
Long-term put premiums payable-affiliate		11,100			1,900
Commitments and contingencies		-			-
Partners’ capital:
Managing general partner’s interest		(5,500	)		243,500
Limited partners’ interest (3,126.55 units)		368,500			865,100
Accumulated other comprehensive loss		(9,000	)		(38,100	)
Total partners’ capital		354,000			1,070,500
	$	2,909,400		$	3,710,300

See accompanying notes to financial statements.

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ATLAS AMERICA PUBLIC #11-2002 LTD.

STATEMENTS OF OPERATIONS

YEARS ENDED DECEMBER 31, 2013 AND 2012

	2013			2012
REVENUES
Natural gas, oil and liquids	$	1,058,400		$	925,500
Interest income		-			100
Total revenues		1,058,400			925,600
COST AND EXPENSES
Production		725,300			764,900
Depletion		524,400			402,000
Accretion of asset retirement obligation		143,300			131,000
General and administrative		160,300			169,100
Total costs and expenses		1,553,300			1,467,000
Net loss	$	(494,900	)	$	(541,400	)
Allocation of net loss:
Managing general partner	$	(205,000	)	$	(213,000	)
Limited partners	$	(289,900	)	$	(328,400	)
Net loss per limited partnership unit	$	(93	)	$	(105	)

See accompanying notes to financial statements.

25

ATLAS AMERICA PUBLIC #11-2002 LTD.

STATEMENTS OF COMPREHENSIVE LOSS

YEARS ENDED DECEMBER 31, 2013 AND 2012

	2013			2012
Net loss	$	(494,900	)	$	(541,400	)
Other comprehensive income (loss):
Unrealized holding (loss) gain on cash flow hedging contracts		(9,200	)		(4,800	)
Difference in estimated hedge gains receivable		48,300			12,000
Reclassification adjustment for gains realized in net loss from cash flow hedges		(10,000	)		(45,300	)
Total other comprehensive income (loss)		29,100			(38,100	)
Comprehensive loss	$	(465,800	)	$	(579,500	)

See accompanying notes to financial statements.

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ATLAS AMERICA PUBLIC #11-2002 LTD.

STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

YEARS ENDED DECEMBER 31, 2013 AND 2012

	ManagingGeneralPartner			LimitedPartners			AccumulatedOtherComprehensiveIncome (Loss)			Total
Balance at December 31, 2011	$	501,200		$	1,417,500		$	-		$	1,918,700
Participation in revenue and costs and expenses:
Net production revenues		55,000			105,600			-			160,600
Interest income		-			100			-			100
Depletion		(163,000	)		(239,000	)		-			(402,000	)
Accretion of asset retirement obligation		(45,800	)		(85,200	)		-			(131,000	)
General and administrative		(59,200	)		(109,900	)		-			(169,100	)
Net loss		(213,000	)		(328,400	)		-			(541,400	)
Other comprehensive loss		-			-			(38,100	)		(38,100	)
Distributions to partners		(44,700	)		(224,000	)		-			(268,700	)
Balance at December 31, 2012	$	243,500		$	865,100		$	(38,100	)	$	1,070,500
Participation in revenue and costs and expenses:
Net production revenues		119,000			214,100						333,100
Depletion		(217,800	)		(306,600	)		-			(524,400	)
Accretion of asset retirement obligation		(50,100	)		(93,200	)		-			(143,300	)
General and administrative		(56,100	)		(104,200	)		-			(160,300	)
Net loss		(205,000	)		(289,900	)		-			(494,900	)
Other comprehensive income		-			-			29,100			29,100
Distributions to partners		(44,000	)		(206,700	)		-			(250,700	)
Balance at December 31, 2013	$	(5,500	)	$	368,500		$	(9,000	)	$	354,000

See accompanying notes to financial statements.

27

ATLAS AMERICA PUBLIC #11-2002 LTD.

STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

	2013			2012
Cash flows from operating activities:
Net loss	$	(494,900	)	$	(541,400	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion		524,400			402,000
Non-cash loss on derivative value, net		72,900			134,100
Accretion of asset retirement obligation		143,300			131,000
Changes in operating assets and liabilities:
Decrease in accounts receivable trade-affiliate		23,300			59,600
Increase (decrease) in accrued liabilities		8,500			(7,600	)
Net cash provided by operating activities		277,500			177,700
Cash flows from investing activities:
Proceeds from sale of tangible equipment		-			8,200
Net cash provided by investing activities		-			8,200
Cash flows from financing activities:
Distributions to partners		(250,700	)		(268,700	)
Net cash used in financing activities		(250,700	)		(268,700	)
Net change in cash and cash equivalents		26,800			(82,800	)
Cash and cash equivalents at beginning of year		29,800			112,600
Cash and cash equivalents at end of period	$	56,600		$	29,800
Supplemental schedule of non-cash investing and financing activities:
Asset retirement obligation revision	$	(245,400	)	$	(65,900	)

See accompanying notes to financial statements.

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ATLAS AMERICA PUBLIC #11-2002 LTD.

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

NOTE 1—BASIS OF PRESENTATION

Atlas America Public #11-2002 LTD. (the “Partnership”) is a Delaware limited partnership, formed on June 5, 2002 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP).

In March 2012, the MGP’s ultimate parent, Atlas Energy L.P. (“Atlas Energy”) (NYSE: ATLS), contributed to ARP, a newly-formed exploration and production master limited partnership, substantially all of Atlas Energy’s natural gas and oil development and production assets and its partnership management business, including ownership of the MGP.

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

The Partnership has drilled and currently operates wells located in Pennsylvania and Ohio. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy, for administrative services. The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through affiliated and or third-party gas gathering systems. The Partnership does not plan to sell any of its wells and intends to produce them until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. The Partnership expects that no other wells will be drilled and no additional funds will be required for drilling.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

Cash Equivalents

The carrying amounts of the Partnership’s cash equivalents approximate fair values because of the short maturities of these instruments. The Partnership considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents.

Receivables

Accounts receivable affiliate on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realization of its accounts receivable, 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 management’s review of the credit information. The Partnership extends credit on sales on an unsecured basis to many of their customers. At December 31, 2013 and 2012, the Partnership had recorded no allowance for uncollectible accounts receivable on its balance sheets.

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Oil and Gas Properties

Oil and gas properties are stated at cost. Maintenance and repairs that generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized.

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

The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties.

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

Impairment of Long-Lived Assets

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

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

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods.

There were no impairments of proved oil and gas properties recorded for the years ended December 31, 2013 and 2012. Asset impairment relates to the carrying amount of these gas and oil properties being in excess of the Partnership’s estimate of the fair value. The estimate of the fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

Derivative Instruments

The MGP enters into certain financial contracts to manage the Partnership’s exposure to movement in commodity prices (see Note 6). The derivative instruments recorded in the balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Partnership’s statements of operations unless specific hedge accounting criteria are met.

30

Asset Retirement Obligations

The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (see Note 5). The Partnership recognizes a liability for its future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset.

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.

The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. However, the Partnership has not recognized any potential interest or penalties in its financial statements as of December 31, 2013 and 2012.

The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2009. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2013.

Environmental Matters

The Partnership is subject to various federal, state, and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Partnership’s 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. The Partnership maintains insurance which may cover in whole or in part certain environmental expenditures. The Partnership had no environmental matters requiring specific disclosure or requiring the recognition of a liability for the years ended December 31, 2013 and 2012.

Concentration of Credit Risk

The Partnership sells natural gas, crude oil, and NGLs under contracts to various purchasers in the normal course of business. For the year ended December 31, 2013, the Partnership had four customers that individually accounted for approximately 48%, 22%, 11%, and 10%, respectively, of the Partnership’s natural gas, oil and NGL combined revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2012, the Partnership had three customers that individually accounted for approximately 53%, 22%, and 12%, respectively, of the Partnership natural gas, oil and NGL combined revenues, excluding the impact of all financial derivative activity.

Revenue Recognition

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

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The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “Use of Estimates” accounting policy for further description). The Partnership had unbilled revenues at December 31, 2013 and 2012 of $132,200 and $182,400, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.

Comprehensive Income (Loss)

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

Recently Adopted Accounting Standards

In February 2013, the FASB issued ASU 2013-02, Comprehensive Income (Topic 220) (“Update 2013-02”). Update 2013-02 requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present significant amounts reclassified out of accumulated other comprehensive income if the amount reclassified to net income in its entirety is in the same reporting period as incurred. For other amounts that are not required to be reclassified in their entirety to net income, an entity is required to reference to other disclosures that provide additional detail about those amounts. Entities are required to implement the amendments prospectively for reporting periods beginning after December 15, 2012, with early adoption being permitted. The Partnership adopted the requirements of Update 2013-02 upon its effective date of January 1, 2013, and it had no material impact on its financial position, results of operations or related disclosures.

In January 2013, the FASB issued ASU 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“Update 2013-01”). Update 2013-01 clarifies that ordinary trade receivables and payables are not in scope of ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. Specifically, ASU 2011-11 applies only to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with specific criteria contained in the FASB Accounting Standards Codification or subject to a master netting arrangement or similar agreement. The amendments are effective for interim and annual reporting periods beginning after January 1, 2013 and such amendments shall be applied retrospectively for any period presented that begins before the date of application. The Partnership adopted the requirements of Update 2013-01 on December 31, 2012, and it did not have a material impact on its financial position, results of operations or related disclosures.

Recently Issued Accounting Standards

In February 2013, the FASB issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements, for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements, for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership will apply the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

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NOTE 3—PARTICIPATION IN REVENUES AND COSTS

Working Interest

Our Partnership Agreement establishes that revenues and expenses 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 the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expense 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 based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.

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

	Managing General Partner		Limited Partners
Organization and offering cost		100%		0%
Lease costs		100%		0%
Revenues (1)		35%		65%
Operating costs, administrative costs, direct and all other costs (2)		35%		65%
Intangible drilling costs		8%		92%
Tangible equipment costs		67%		33%

(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.

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

NOTE 4—PROPERTY, PLANT AND EQUIPMENT

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

	December 31,
	2013			2012
Proved properties:
Leasehold interest	$	695,700		$	695,700
Wells and related equipment		40,673,100			40,918,500
Total natural gas and oil properties		41,368,800			41,614,200
Accumulated depletion and impairment		(38,703,500	)		(38,179,100	)
Oil and gas properties, net	$	2,665,300		$	3,435,100

The Partnership recorded depletion expense on natural gas and oil properties of $524,400 and $402,000 for the years ended December 31, 2013 and 2012, respectively. 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. Upon the sale of an entire interest where the property had been assessed for impairment, a gain or loss is recognized in the statements of operations.

There were no impairments of proved gas and oil properties recorded for the years ended December 31, 2013 and 2012. Asset impairment relates to the carrying amount of these oil and gas properties being in excess of the Partnership’s estimate of their fair value. The estimate of fair value of these oil and gas properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

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NOTE 5—ASSET RETIREMENT OBLIGATIONS

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

The MGP’s historical practice and continued intention is to retain distributions from the limited partners as the wells within the Partnership near the end of their useful life. On a partnership-by-partnership basis, the MGP assesses its right to withhold amounts related to plugging and abandonment costs based on several factors including commodity price trends, the natural decline in the production of the wells, and current and future costs. Generally, the MGP’s intention is to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approaches the fair value of the future plugging and abandonment cost. Upon the MGP’s decision to retain all future distributions to the limited partners of the Partnership, the MGP will assume the related asset retirement obligations of the limited partners.

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

	Years Ended December 31,
	2013			2012
Asset retirement obligations, beginning of year	$	2,637,100		$	2,572,000
Accretion of asset retirement obligation		143,300			131,000
Asset retirement obligation revision		(245,400	)		(65,900	)
Asset retirement obligations, end of period	$	2,535,000		$	2,637,100

NOTE 6—DERIVATIVE INSTRUMENTS

The MGP, on behalf of the Partnership, uses a number of different derivative instruments, principally swaps, collars and options, in connection with the Partnership’s commodity price risk management activities. Management enters into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under commodity-based swap agreements, the Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike price, and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged.

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 the MGP determines that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the MGP will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by management of the MGP through the utilization of market data, will be recognized immediately within gain (loss) on market-to-market derivatives in the Partnership’s statements of operations. For derivatives qualifying as hedges, the Partnership recognizes the effective portion of changes in fair value of derivative instruments as accumulated other comprehensive income and reclassifies the portion relating to commodity derivatives to gas and oil production revenues within the Partnership’s statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership recognizes changes in fair value within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations as they occur.

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The Partnership enters into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s balance sheets as the initial value of the options. The Partnership reflected net derivative assets on its balance sheets of $7,300 and $9,800 at December 31, 2013 and 2012, respectively.

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

At December 31, 2013, the Partnership had the following commodity derivatives:

Natural Gas Put Options

Production Period Ending December 31,	Volumes (MMBtu)(1)		Average Fixed Price (per MMBtu)(1)		Fair Value Asset (2)
2014		9,600	$	3.80	$	1,200
2015		7,700		4.00		2,600
2016		7,700		4.15		3,500
					$	7,300

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

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

Effects of Derivative Instruments on Statements of Operations:

The following table summarizes the gain or loss recognized in the statements of operations for effective derivative instruments for the years ended December 31, 2013 and 2012:

	Years Ended December 31,
	2013		2012
Gains from cash flow hedges reclassified from accumulated other comprehensive income (loss) into natural gas, oil and liquids revenues	$	10,000	$	45,300

As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the years ended December 31, 2013 and 2012, for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

Monetized Gains

Prior to February 17, 2011 (date of the Transferred Business), Atlas Energy Inc., (“AEI”) monetized its derivative instruments, including those related to the future natural gas and oil production of the Transferred Business. AEI also monetized derivative instruments that were specifically related to the future natural gas and oil production of the Partnership. At December 31, 2013 and 2012, remaining hedge monetization cash proceeds of $15,200 and $45,400, respectively, related to the amounts hedged on behalf of the Partnership’s limited partners were included within accounts receivable monetized gains-affiliate. There were no long-term monetized gains receivable-affiliate at December 31, 2013. At December 31, 2012, $9,100 of long-term monetized gains receivable-affiliate were included in long-term put premiums payable-affiliate on the Partnership’s balance sheet. The Partnership will allocate the monetized net proceeds to the limited partners based on the natural gas and oil production generated over the period of the original derivative contracts.

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During June 2012, the MGP used the undistributed monetized funds to purchase natural gas put options on behalf of the limited partners of the Partnership only. A premium (“put premium”) was paid to purchase the contracts and will be allocated to natural gas production revenues generated over the contractual term of the purchased hedging instruments. At December 31, 2013 and 2012, the put premiums were recorded as short-term payables to affiliate of $5,500 and $3,600, respectively, and long-term payables to affiliate of $11,100 and $11,000, respectively. Furthermore, the current portion of the put premium liability was included in accounts receivable monetized gains-affiliate and the long-term receivable monetized gains-affiliate was included in long term put premiums payable-affiliate in the Partnership’s balance sheets, presenting the impact of offsetting the related party assets and liabilities. The put premiums included on the Partnership’s balance sheets are allocable to the limited partners only.

The following table summarizes the gross and net fair values of the Partnership’s balances on the Partnership’s balance sheets for the periods indicated:

Offsetting Assets	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheets			Net Amount of Assets Presented in the Balance Sheets
As of December 31, 2013
Accounts receivable monetized gains-affiliate	$	15,200	$	(5,500	)	$	9,700
Long-term receivable monetized gains-affiliate		-		-			-
Total	$	15,200	$	(5,500	)	$	9,700
As of December 31, 2012
Accounts receivable monetized gains-affiliate	$	45,400	$	(3,600	)	$	41,800
Long-term receivable monetized gains-affiliate		9,100		(9,100	)		-
Total	$	54,500	$	(12,700	)	$	41,800

Offsetting Liabilities	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheets		Net Amount of Liabilities Presented in the Balance Sheets
As of December 31, 2013
Put premiums payable-affiliate	$	(5,500	)	$	5,500	$	-
Long-term put premiums payable-affiliate		(11,100	)		-		(11,100	)
Total	$	(16,600	)	$	5,500	$	(11,100	)
As of December 31, 2012
Put premiums payable-affiliate	$	(3,600	)	$	3,600	$	-
Long-term put premiums payable-affiliate		(11,000	)		9,100		(1,900	)
Total	$	(14,600	)	$	12,700	$	(1,900	)

Accumulated Other Comprehensive Income (Loss)

As a result of the monetization and the early settlement of natural gas and oil derivative instruments, the put options, and the unrealized gains recognized in income in prior periods due to natural gas and oil property impairments, the Partnership recorded a net deferred loss on its balance sheets in accumulated other comprehensive loss of $9,000 as of December 31, 2013. Included in accumulated other comprehensive loss are unrealized gains of $14,900, net of the MGP interest, that were recognized into income as a result of oil and gas property impairments prior periods. During the current year, $6,900 of net losses were recorded by the Partnership and allocated only to the limited partners. Of the remaining $9,000 of net unrealized loss in accumulated other comprehensive loss, the Partnership will reclassify $4,100 of net losses to the Partnership’s statements of operations over the next twelve month period and the remaining $4,900 in later periods.

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NOTE 7—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. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect the Partnership’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value:

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

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

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The carrying value of cash, accounts receivable, and accounts payable approximate their respective fair values due to the short-term maturities of such financial instruments. The Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 6). The Partnership manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty. The Partnership’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. These derivative instruments are calculated by utilizing commodity indices, quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument.

Information for assets and liabilities measured at fair value at December 31, 2013 and 2012 was as follows:

As of December 31, 2013	Level 1		Level 2		Level 3		Total
Derivative assets, gross
Commodity puts	$	-	$	7,300	$	-	$	7,300
Derivative liabilities, gross
Commodity puts		-		-		-		-
Total derivative, fair value, net	$	-	$	7,300	$	-	$	7,300
As of December 31, 2012
Derivative assets, gross
Commodity puts	$	-	$	9,800	$	-	$	9,800
Derivative liabilities, gross
Commodity puts		-		-		-		-
Total derivative, fair value, net	$	-	$	9,800	$	-	$	9,800

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

The Partnership’s other current assets and liabilities on its balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1.

The Partnership estimates the fair value of its asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates. There were no adjustments to retirement obligations measured at fair value on a nonrecurring basis for the years ended December 31, 2013 and 2012.

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The Partnership estimates the fair value of its long-lived assets in conjunction with the review of asset impairment or whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions, and judgments regarding such events or circumstances. There was no impairment recognized by us for the years ended December 31, 2013 and 2012 which were defined as a Level 3 fair value measurement (see Note 2 – Impairment of Long-Lived Assets).

NOTE 8—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The Partnership has entered into the following significant transactions with the MGP and its affiliates as provided under its Partnership Agreement. Administrative costs, which are included in general and administrative expenses in the Partnership’s statements of operations, are payable at $75 per well per month. Monthly well supervision fees, which are included in production expense in the Partnership’s statement of operations, are payable at $320 per well per month for operating and maintaining the wells. 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. Direct costs, which are included in production and general administrative expenses in the Partnership’s statements of operations, are payable to the MGP and its affiliates as reimbursement for all costs expended on the Partnership’s behalf.

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

	Years Ended December 31,
	2013		2012
Administrative	$	97,200	$	110,500
Supervision		415,000		471,700
Transportation		110,100		107,400
Direct Costs		263,300		244,400
Total	$	885,600	$	934,000

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

NOTE 9—COMMITMENTS AND CONTINGENCIES

General Commitments

Subject to certain conditions, investor partners may present their interests for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. The MGP is not obligated to purchase more than 5% of the 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, 2013, the MGP has not withheld any such funds. The MGP is currently evaluating its right to exercise this option based on several factors such as commodity prices, the natural decline in well production, and current and future plugging services and costs.

Legal Proceedings

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

NOTE 10—SUBSEQUENT EVENTS

Management has considered for disclosure any material subsequent events through the date the financial statements were issued.

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NOTE 11—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Gas Reserve Information. The preparation of the Partnership’s natural gas and oil reserve estimates was completed in accordance with our MGP’s prescribed internal control procedures by its reserve engineers. The accompanying reserve information included below is attributable to the reserves of the Partnership and was derived from the reserve reports prepared for Atlas America Public #11-2002 LTD. annual Form 10-K for the years ended December 31, 2013 and 2012 (see Note 2). For the periods presented, Wright and Company, Inc., an independent third-party reserve engineer, was retained to prepare a report of proved reserves related to the Partnership. The reserve information for the Partnership includes natural gas and oil reserves which are all located in the United States, primarily in Pennsylvania and Ohio. The independent reserves engineer’s evaluation was based on more than 37 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. The MGP’s internal control procedures include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our MGP’s Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 15 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by the MGP’s senior engineering staff and management, with final approval by the MGP’s Chief Operating Officer.

The reserve disclosures that follow reflect estimates of proved developed reserves net of royalty interests, of natural gas, crude oil, and natural gas liquids owned at year end. Proved developed reserves are those reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. In accordance with the prevailing accounting literature, the proved reserves quantities and future net cash flows as of December 31, 2013 and 2012 were estimated using an unweighted 12-month average pricing based on the prices on the first day of each month during the years ended December 31, 2013 and 2012 and including adjustments related to regional price differentials and energy content.

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 oil and gas reserves included within the Partnership 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 their effects have not been proved.

Reserve quantity information and a reconciliation of changes in proved reserve quantities included within the Partnership are as follows (unaudited):

	Gas (Mcf)			Oil (Bbls)
Balance, December 31, 2011		1,406,200			7,000
Revisions (1)		(790,400	)		(3,200	)
Production		(285,200	)		(1,000	)
Balance, December 31, 2012		330,600			2,800
Revisions (2)		958,200			4,100
Production		(240,500	)		(1,600	)
Balance, December 31, 2013		1,048,300			5,300

(1) The downward revision in natural gas volumes is primarily due to a decline in SEC base pricing from the prior year, a decrease in the positive gas price basis differentials and a decrease in economic lives resulting from increased expenses.

(2) The upward revision in natural gas and oil forecasts is primarily due to an increase in SEC base pricing from the prior year, resulting in longer economic life.

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Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to oil and gas producing activities of the Partnership during the periods indicated were as follows:

	Years Ended December 31,
	2013			2012
Natural gas and oil properties:
Leasehold interest	$	695,700		$	695,700
Wells and related equipment		40,673,100			40,918,500
Accumulated depletion, accretion and impairment		(38,703,500	)		(38,179,100	)
Net capitalized costs	$	2,665,300		$	3,435,100

Results of Operations from Oil and Gas Producing Activities. The results of operations related to the Partnership’s oil and gas producing activities during the periods indicated were as follows:

	Years Ended December 31,
	2013			2012
Revenues	$	1,058,400		$	925,500
Production costs		(725,300	)		(764,900	)
Depletion		(524,400	)		(402,000	)
	$	(191,300	)	$	(241,400	)

Standardized Measure of Discounted Future Cash Flows.The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the Partnership’s proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2013 and 2012, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations:

	Years Ended December 31,
	2013			2012
Future cash inflows	$	4,440,600		$	1,214,900
Future production costs		(3,423,800	)		(1,023,800	)
Future net cash flows		1,016,800			191,100
Less 10% annual discount for estimated timing of cash flows		(242,700	)		(24,000	)
Standardized measure of discounted future net cash flows	$	774,100		$	167,100

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

Under the supervision of our general partner’s Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report, Based upon that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2013, our disclosure controls and procedures were effective at the reasonable assurance level.

Management’s Report on Internal Control over Financial Reporting

The management of our general partner is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of management, including our general partner’s Chief Executive Officer 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 the 1992 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.

There have been no changes in our internal control over financial reporting during the fourth quarter of 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

This annual report does not include an attestation report by our registered public accounting firm regarding internal control of financial reporting because such a report is not required pursuant to the rules of the Securities and Exchange Commission.

41

PART III

ITEM 10: DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

Our general partner manages our activities. Unitholders do not directly or indirectly participate in our management or operation or have actual or apparent authority to enter into contracts on our behalf or to otherwise bind us.

As of December 31, 2013, the following table sets forth information with respect to those persons who serve as the officers of our general partner:

Name	Age	Position(s)
Sean P. McGrath	42	Chief Financial Officer
Freddie M. Kotek	58	Senior Vice President of Investment Partnership Division
Dave E. Leopold	50	Senior Vice President of Operations
Jack L. Hollander	57	Senior Vice President – Direct Participation Programs

Sean P. McGrath has served as Chief Financial Officer of our general partner since February 2012. Sean McGrath has served as Chief Financial Officer of Atlas Energy’s general partner since February 2011. Mr. McGrath was Chief Accounting Officer of Atlas Energy, Inc. and Chief Accounting Officer of Atlas Energy Resources, LLC from December 2008 until February 2011. Mr. McGrath served as Chief Accounting Officer of Atlas Energy GP, LLC (which is Atlas Energy’s general partner) from January 2006 until November 2009 and as Chief Accounting Officer of Atlas Pipeline Partners GP, LLC from May 2005 until November 2009. Mr. McGrath was Controller of Sunoco Logistics Partners L.P., a publicly-traded partnership that transports, terminals and stores refined products and crude oil, from 2002 until 2005. From 1998 until 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.

Freddie M. Kotek has served as Senior Vice President of our general partner since March 2012. Mr. Kotek has served as Senior Vice President of Atlas Energy’s general partner since February 2011. Mr. Kotek was an Executive Vice President of Atlas Energy, Inc. from February 2004 until February 2011 and served as a director of Atlas Energy, Inc. from September 2001 until February 2004. Mr. Kotek also was Chief Financial Officer of Atlas Energy, Inc. from February 2004 until March 2005. Mr. Kotek has been Chairman of Atlas Resources, LLC since September 2001 and Chief Executive Officer and President since January 2002. Mr. Kotek was a Senior Vice President of Resource America, Inc. from 1995 until May 2004 and President of Resource Leasing, Inc., a wholly owned subsidiary of Resource America, Inc., from 1995 until May 2004.

Dave E. Leopold has served as Senior Vice President of Operations of our general partner since December 2013. Mr. Leopold has been Regional Vice President Operations of ARP since March 2013. Prior to joining ARP, Mr. Leopold was the Operations Manager for Chesapeake Energy in Fort Worth, Texas where he led the Barnett Shale operations team to become the second largest producer in the play. From August 2000 to September 2006, Mr. Leopold held various management positions at Anadarko Petroleum Corporation, most recently serving as Production Engineering Manager over the Austin Chalk, Bossier Shale and what is now known as the Eagle Ford Shale. From 1991 to 2000, Mr. Leopold held various engineering and management roles with Union Pacific Resources in Fort Worth, Texas. From 1987 to 1991, he held drilling and reservoir engineering roles with Plains Petroleum Operating Company in Kansas and Colorado.

Jack L. Hollander has served as Senior Vice President – Direct Participation Programs since January 2002. Prior to 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 Energy, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.

42

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 that applies to the principal executive officer, principal financial officer, and principal accounting officer of our general partner, as well as to persons performing services for us generally. We will make a printed copy of our code of ethics available to any limited partner who so requests. Requests for print copies may be directed to us as follows: Atlas Resource Partners, L.P., Park Place Corporate Center One, 1000 Commerce Drive, 4^th Floor, Pittsburgh, Pennsylvania 15275-1011, Attention: Secretary. The code of business conduct is also posted, and any waivers we grant thereunder will be posted, on our website at www.atlasresourcepartners.com.

ITEM 11: EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Introduction

We do not directly employ any persons to manage or operate our businesses. Instead, all of the persons (including executive officers of our general partner and other personnel) necessary for the management of our business are employed and compensated by Atlas Energy. Pursuant to our partnership agreement, our general partner manages our operations and activities through and its affiliates’ employees (including employees of Atlas Energy and its general partner). No officer or director of our MGP receives any direct renumberation or other compensation from us. (see “Item 13: Certain Relationships and Related 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, 2013, we had 3,126.55 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 for purchase, the MGP is not obligated by the Partnership Agreement to purchase more than 5% of our total outstanding units in any calendar year. The MGP is owned 100% by Atlas Resource Partners, whose ultimate parent is Atlas Energy.

ITEM 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Our Relationship with Atlas Resource, LLC

Oil and Gas Revenues. Our MGP is allocated 35% of our oil and gas revenues in return for its payment and/or contribution of services towards our syndication and offering costs equal to 15% of our subscriptions, its payment of 67.13% 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 $13,295,200. During the years ended December 31, 2013 and 2012, our MGP received $119,000 and $55,000, respectively, for our net production revenues.

Administrative costs, which are included in general and administrative expenses in the Partnership’s statements of operations, are payable at $75 per well per month. Monthly well supervision fees, which are included in production expense in the Partnership’s statement of operations, are payable at $320 per well per month for operating and maintaining the wells. 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. Direct costs, which are included in production and general administrative expenses in the Partnership’s statements of operations, are payable to the MGP and its affiliates as reimbursement for all costs expended on the Partnership’s behalf.

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

	Years Ended December 31,
	2013		2012
Administrative	$	97,200	$	110,500
Supervision		415,000		471,700
Transportation		110,100		107,400
Direct Costs		263,300		244,400
Total	$	885,600	$	934,000

Other Compensation. For the years ended December 31, 2013 and 2012, our MGP did not advance any funds to us, or did it provide us with any equipment, supplies or other services.

43

ITEM 14: PRINCIPAL ACCOUNTANT FEES AND SERVICES

For the years ended December 31, 2013 and 2012, the accounting fees and services charged by Grant Thornton, LLP, our independent auditors, were as follows:

	Years Ended December 31,
	2013		2012
Audit fees	$	33,700	$	33,600

Audit Committee Pre-Approval Policies and Procedures

The audit committee of our general partner, on at least an annual basis, will review audit and non-audit services performed by Grant Thornton LLP as well as the fees charged by Grant Thornton LLP for such services. Our policy is that all audit and non-audit services must be pre-approved by the audit committee. All of such services and fees were pre-approved during 2013 and 2012.

44

PART IV

ITEM 15: EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

EXHIBIT INDEX

	Description	Location
4(a)	Certificate of Limited Partnership for Atlas America Public #11-2002 Ltd.	Previously filed in our Form S-1 on June 21, 2002
4(b)	Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #11-2002 Ltd.	Previously filed in our Form S-1 on June 21, 2002
4(c)	Drilling and Operating Agreement for Atlas America Public #11-2002 Ltd. (1)	Previously filed in our Form S-1 on June 21, 2002
23.1	Consent of Wright and Company, Inc.
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
101	Interactive Data File

(1) Filed on June 21, 2002 on the Form S-1 Registration Statement dated June 21, 2002, File No. 333-90980

45

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities of the Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	ATLAS RESOURCES PARTNERS L.P.
	BY: ATLAS RESOURCE PARTNERS GP, LLC, ITS GENERAL PARTNER
	ATLAS ENERGY L.P.
Date: March 31, 2014	By:	/s/ FREDDIE M. KOTEK
		Freddie M. Kotek, Chairman of the Board and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following person on behalf of the registrant and in the capacities and on the dates indicated.

Date: March 31, 2014	By:	/s/ SEAN P. MCGRATH
		Sean P. McGrath, Chief Financial Officer

46

EX-23

Exhibit 23.1

CONSENT OF INDEPENDENT PETROLEUM CONSULTANTS

Wright & Company, Inc. hereby consents to the use of our analysis relating to the evaluation titled Evaluation of Oil and Gas Reserves To the Interests of Certain Partnerships Managed by Atlas Resource Partners, L.P., Pursuant to the Requirements of the Securities and Exchange Commission, Effective January 1, 2014, Job 14.1586-A, dated March 10, 2014, for use in the Annual Report on Form 10-K for the year ended December 31, 2013, filed with the Securities and Exchange Commission, and to all references to Wright & Company, Inc., as having prepared such analysis and as an expert concerning such analysis.

Wright & Company, Inc.
TX Reg. No. F-12302
By:	/s/ D. Randall Wright
	D. Randall Wright
	President

Wright & Company, Inc.
Brentwood, Tennessee
March 10, 2014

EX-31

Exhibit 31.1

CERTIFICATION

I, Freddie M. Kotek, certify that:

1. I have reviewed this annual report on Form 10-K for the year ended December 31, 2013 of Atlas America Public #11-2002 LTD.;

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

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

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

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

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

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

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

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

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

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

/s/ FREDDIE M. KOTEK

Freddie M. Kotek

Chairman and Chief Executive Officer of the General Partner

March 31, 2014

EX-31

Exhibit 31.2

CERTIFICATION

I, Sean P. McGrath, certify that:

1. I have reviewed this annual report on Form 10-K for the year ended December 31, 2013 of Atlas America Public #11-2002 LTD.;

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

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

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

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

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

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

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

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

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

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

/s/ SEAN P. MCGRATH

Sean P. McGrath

Chief Financial Officer of the General Partner

March 31, 2014

EX-32

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Atlas America Public #11-2002 LTD. (the “Partnership”) on Form 10-K for the year ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Freddie M. Kotek, Chairman and Chief Executive Officer of the General Partner, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

/s/ FREDDIE M. KOTEK

Freddie M. Kotek

Chairman and Chief Executive Officer of the General Partner

March 31, 2014

EX-32

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Atlas America Public #11-2002 LTD. (the “Partnership”) on Form 10-K for the year ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Sean P. McGrath, Chief Financial Officer of the General Partner, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

/s/ SEAN P. MCGRATH

Sean P. McGrath

Chief Financial Officer of the General Partner

March 31, 2014

EX-99.1

Exhibit 99.1

March 10, 2014

Atlas Resource Partners, L.P.

1845 Walnut Street, 10^th Floor
Philadelphia, PA 19103

Attention: Mr. Matthew A. Jones

SUBJECT: Evaluation of Oil and Gas Reserves

To the Interests of Certain Partnerships

Managed by Atlas Resource Partners, L.P.

Pursuant to the Requirements of the

Securities and Exchange Commission

Effective January 1, 2014

Job 14.1586-A

At the request of Atlas Resource Partners, L.P. (Atlas), Wright & Company, Inc. (Wright) has performed an evaluation to estimate proved reserves and associated cash flow and economics from certain properties that are a part of various Atlas Partnerships (Partnerships). This evaluation was authorized by Mr. Mark Schumacher of Atlas, the Managing General Partner of the Partnerships. Projections of the reserves and cash flow to the evaluated interests were based on specified economic parameters, operating conditions, and government regulations considered applicable at the effective date. This reserves evaluation is pursuant to the financial reporting requirements of the Securities and Exchange Commission (SEC) as specified in Regulation S-X, Rule 4-10(a) and Regulation S-K, Rule 1202(a)(8). It is the understanding of Wright that the purpose of this evaluation is for inclusion in relevant registration statements or other filings to the SEC for the fiscal year ended December 31, 2013. The effective date of this report is January 1, 2014. This report was completed March 10, 2014. The attached Exhibit Acontains a list of the various Partnerships and provides a summary of the results of this report.

The properties evaluated in this report are located in the states of Colorado, Indiana, New York, Ohio, Pennsylvania, Tennessee, and West Virginia. According to Atlas, the total proved reserves included in this report represent 100 percent of the reported total proved reserves of each Partnership.

Proved oil and gas reserves are those quantities of oil and gas which can be estimated with reasonable certainty to be economically producible under existing economic conditions, operating methods, and government regulations. As specified by the SEC regulations, when calculating economic producibility, the base product price must be the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the prior 12-month period. The benchmark base prices used for this evaluation were $96.78 per barrel for West Texas Intermediate oil at Cushing, Oklahoma, and $3.670 per million British thermal units (MMBtu) for natural gas at Henry Hub, Louisiana. These benchmark base prices were adjusted for energy content, quality, and basis differential, as appropriate. The resultant average adjusted product prices for each Partnership can be found in the attached Exhibit A.The base product prices were held constant for the life of the properties.

Twelve Cadillac Drive  •  Suite 260

Brentwood, Tennessee 37027

(615) 370-0755         Fax (615) 370-0756

mail@wrightandcompany.com

Mr. Matthew A. Jones

Atlas Resource Partners, L.P.

March 10, 2014

Page 2

Oil and other liquid hydrocarbon volumes are expressed in thousands of United States (U.S.) barrels (Mbbl), one barrel equaling 42 U.S. gallons. Gas volumes are expressed in millions of standard cubic feet (MMcf) at 60 degrees Fahrenheit and at the legal pressure base that prevails in the state in which the reserves are located. No adjustment of the individual gas volumes to a common pressure base has been made.

Net income to the evaluated interests is the cash flow after consideration of royalty revenue payable to others, standard state and county taxes or fees, operating expenses, and investments, as applicable. The cash flow is before federal income tax (BTAX) and excludes consideration of any encumbrances against the properties if such exist. The Cash Flow (BTAX) was discounted at an annual rate of 10.00 percent (PCT) in accordance with the reporting requirements of the SEC.

The estimates of reserves contained in this report were determined by accepted industry methods, and the procedures used in this evaluation are appropriate for the purpose served by the report. Where sufficient production history and other data were available, reserves for producing properties were determined by extrapolation of historical production or sales trends. Analogy to similar producing properties was used for development projects and for those properties that lacked sufficient production history to yield a definitive estimate of reserves. When appropriate, Wright may have also utilized volumetric calculations and log correlations in the determination of estimated ultimate recovery (EUR). These calculations are often based upon limited log and/or core analysis data and incomplete formation fluid and rock data. Since these limited data must frequently be extrapolated over an assumed drainage area, subsequent production performance trends or material balance calculations may cause the need for significant revisions to the estimates of reserves. Wright used all methods and procedures it considered necessary under the circumstances to prepare this report.

Oil and gas reserves were evaluated for the proved developed producing (POP), proved developed nonproducing (PDNP), proved developed nonproducing shut-in (PDNP-SI), and proved developed nonproducing temporarily abandoned (PDNP-TA) reserves categories. The summary classification of total proved reserves combines all of the above categories. In preparing this evaluation, no attempt has been made to quantify the element of uncertainty associated with any category. Reserves were assigned to each category as warranted. Wright is not aware of any local, state, or federal regulations that would preclude Atlas from continuing to produce from currently active wells or to fully develop those properties included in this report.

There are significant uncertainties inherent in estimating reserves, future rates of production, and the timing and amount of future costs. The estimation of oil and gas reserves must be recognized as a subjective process that cannot be measured in an exact way, and estimates of others might differ materially from those of Wright. The accuracy of any reserves estimate is a function of the quantity and quality of available data and of subjective interpretations and judgments. It should be emphasized that production data subsequent to the date of these estimates or changes in the analogous properties may warrant revisions of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and gas that are ultimately recovered.

Mr. Matthew A. Jones

Atlas Resource Partners, L.P.

March 10, 2014

Page 3

All data utilized in the preparation of this report were provided by Atlas. No inspection of the properties was made as this was not considered to be within the scope of this evaluation. Wright has not independently verified the accuracy and completeness of information and data furnished by Atlas with respect to ownership interests, oil and gas production or sales, historical costs of operation and development, product prices, or agreements relating to current and future operations and sales of production. Wright requested and received detailed information allowing Wright to check and confirm any calculations provided by Atlas with regard to product pricing, appropriate adjustments, and lease operating expenses. Furthermore, if in the course of Wright's examination something came to our attention that brought into question the validity or sufficiency of any information or data, Wright did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or independently verified such information or data. In accordance with the requirements of the SEC, all operating costs were held constant for the life of the properties.

In accordance with the instructions of Atlas, abandonment costs net of salvage values were included where appropriate. In some areas, Atlas represented that the cost to abandon the property would be directly offset by the salvage value. Wright has not performed a detailed study of the abandonment costs nor the salvage values and offers no opinion as to Atlas's calculations and assumptions.

Wright is not aware of any potential environmental liabilities that may exist concerning the properties evaluated. There are no costs included in this evaluation for potential property restoration, liability, or clean up of damages, if any, that may be necessary due to past or future operating practices.

Wright is an independent petroleum consulting firm founded in 1988 and owns no interests in the oil and gas properties covered by this report. No employee, officer, or director of Wright is an employee, officer, or director of Atlas or the Partnerships, nor does Wright or any of its employees have direct financial interest in Atlas or the Partnerships. Neither the employment of nor the compensation received by Wright is contingent upon the values assigned or the opinions rendered regarding the properties covered by this report.

This report is prepared for the information of the Partnerships, their investors, and for the information and assistance of their independent public accountants in connection with their review of and report upon the financial statements of the Partnerships, and for reporting disclosures as required by the SEC. This report is also intended for public disclosure as an exhibit in filings made to the SEC by the Partnerships and Atlas.

Based on data and information provided by Atlas, and the specified economic parameters, operating conditions, and government regulations considered applicable at the effective date, it is Wright's conclusion that this report provides a fair and accurate representation of the oil and gas reserves to the interests of the Partnerships in those certain properties included in this report.

The professional qualifications of the petroleum consultants responsible for the evaluation of the reserves and economics information presented in this report meet the standards of Reserves Estimator as defined in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the Society of Petroleum Engineers.

Mr. Matthew A. Jones

Atlas Resource Partners, L.P.

March 10, 2014

Page 4

It has been a pleasure to serve you by preparing this evaluation.  All related data will be retained in our files and are available for your review.

Very truly yours,
Wright & Company, Inc.
TX Reg. No. F-12302
By:	/s/ D. Randall Wright
	D. Randall Wright President

EXHIBIT A

Job 14.1486-A

Partner ID No.	Partnership	Total Proved Net Reserves			Average Resultant Adjusted Product Prices			Cash Flow (BTAX), M$	10.00 PCT Cum. Disc. (BTAX), M$
		Oil, Mbbl	Gas, MMcf	NGL, Mbbl	Oil, Mbbl	Gas, MMcf	NGL, Mbbl
100918	ATLAS RESOURCES SERIES 28 2010 LP	0.000	54,550.023	0.000	0.00	3.734	0.00	128,101.133	58,479.676
100938	ATLAS RESOURCES PUBLIC #18-2009 (C) LP	0.000	62,632.777	0.000	0.00	3.784	0.00	157,949.766	71,518.375
100939	ATLAS RESOURCES PUBLIC #18-2009 (B) LP	17.853	18,717.969	48.696	94.64	3.834	45.00	42,741.973	20,829.410
100940	ATLAS RESOURCES PUBLIC #18-2008 (A) LP	33.996	11,020.303	95.240	94.59	3.777	45.00	18,830.764	10,833.998
100941	ATLAS RESOURCES PUBLIC #17-2008 (B) LP	95.345	12,795.718	4.124	89.51	3.797	45.00	23,987.135	14,099.771
100942	ATLAS RESOURCES PUBLIC #17-2007 (A)	37.660	9,423.312	0.000	89.91	3.775	0.00	14,361.373	9,122.230
100943	ATLAS AMERICA SERIES 27-2006 L.P.	8.815	3,665.892	0.000	92.64	3.771	0.00	5,487.789	3,422.286
100944	ATLAS AMERICA PUB #16-2007	57.010	11,385.620	0.000	90.33	3.737	0.00	19,042.777	11,525.208
100945	ATLAS AMERICA PUB #15-2006 (B)	11.548	9,011.628	0.000	92.12	3.714	0.00	13,212.599	8,039.866
100946	ATLAS AMERICA PUB #15-2005 (A)	9.472	1,724.584	0.000	91.30	3.812	0.00	2,541.186	1,743.093
100947	ATLAS AMERICA SERIES 26-2005	12.523	1,751.923	0.000	94.62	3.816	0.00	2,883.259	1,882.529
100948	ATLAS AMERICA PUB #14-2005 (A)	27.278	3,488.554	0.000	94.60	3.790	0.00	6,181.861	3,889.551
100949	ATLAS AMERICA PUB #14-2004 LTD	10.702	2,304.035	0.000	93.94	3.668	0.00	3,075.482	2,114.218
100959	ATLAS AMERICA SERIES 25-2004A	2.974	1,552.833	0.000	94.74	3.846	0.00	2,008.060	1,345.735
100976	ATLAS AMERICA PUB. #11-2002 LTD	5.290	1,048.287	0.000	94.74	3.758	0.00	1,016.841	774.123
100992	ATLAS AMERICA PUB #12-2003 LTD	0.218	1,421.382	0.000	94.74	3.812	0.00	1,515.462	1,058.339
100993	ATLAS AMERICA SERIES 25-2004B	2.936	1,588.453	0.000	93.47	3.835	0.00	2,357.928	1,457.244
100996	ATLAS AMERICA PUBLIC 9 LTD	6.931	979.181	0.000	94.74	3.919	0.00	1,160.832	846.496
100998	ATLAS AMERICA PUBLIC 10 LTD	5.730	1,628.365	0.000	94.74	3.876	0.00	2,005.614	1,373.664

Please note numbers in table may not add due to rounding techniques in the ARIES™ petroleum software program.

Professional Qualifications

D. Randall Wright

President

I, D. Randall Wright, am the primary technical person in charge of the estimates of reserves and associated cash flow and economics on behalf of Wright & Company, Inc. (Wright) for the results presented in this report to Atlas Resource Partners, L.P. I have a Master of Science degree in Mechanical Engineering from Tennessee Technological University.

I am a qualified Reserves Estimator as set forth in the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information" promulgated by the Society of Petroleum Engineers. This qualification is based on more than 40 years of practical experience in the estimation and evaluation of petroleum reserves with Texaco, Inc., First City National Bank of Houston, Sipes, Williamson & Associates, Inc., Williamson Petroleum Consultants, Inc., and Wright which I founded in 1988.

I am a registered Professional Engineer in the state of Texas (TBPE #43291), granted in 1978, a member of the Society of Petroleum Engineers (SPE) and a member of the Order of the Engineer.

/s/ D. Randall Wright, P.E.

D. Randall Wright, P.E.

DEFINITIONS OF OIL AND GAS RESERVES

Wright & Company, Inc. frequently prepares estimates of oil and gas reserves. Such reserves estimates usually include quantities which are represented as "proved" and, depending upon the data base and/or the desire of the client, may include additional reserves which are classified as "unproved". The scope of the analyses may also incorporate "contingent resources". These definitions as presented are an abridged version of the disclosure guidelines as set forth by the Securities and Exchange Commission (SEC) Rule 4-10(a) (l)-(32) of Regulation S-X and the Modernization of Oil and Gas Reporting, Final Rule dated January 14, 2009 in the Federal Register. The definitions of oil and gas reserves used by Wright & Company, Inc. are briefly set forth below.

RESERVES are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there is a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement project.

PROVED OIL AND GAS RESERVES are those quantities of oil and gas, which by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operating methods, and government regulation. The area of the reservoir considered as proved includes, but is not necessarily limited to, the area identified by drilling and limited by fluid contacts, if any, and adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons unless geoscience, engineering, or performance data and reliable technology establish a lower contact with reasonable certainty.

Reserves that can be produced economically through application of improved recovery techniques are included in the proved classification when both the following occur: (i) successful testing by a pilot in an area of the reservoir with properties no more favorable than in the reservoir as a whole, or the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program is based and, (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which the economic producibility of a reservoir is to be determined. The base product price shall be the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the prior 12-month period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

PROVED DEVELOPED OIL AND GAS RESERVES are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well or through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

PROVED UNDEVELOPED OIL AND GAS RESERVES are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

ANALOGOUS RESERVOIRS have similar rock and fluid properties, reservoir conditions and drive mechanisms, but one typically at a more advanced stage of development than the reservoir of interest and this may provide concepts to assist in the interpretation of more limited data and estimation recovery.

REASONABLE CERTAINTY means a higher degree of confidence that the quantities will be recovered. A high degree of confidence exists if the quantity is much more likely to be achieved than not and, as changes due to increased availability of geoscience (geological, geophysical, and geomechanical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

RELIABLE TECHNOLOGY is a grouping of one or more technologies (including computerized methods) that have been field tested and have demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

UNPROVED PROBABLE reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely to be recovered as not. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

UNPROVED POSSIBLE reserves are those additional reserves that are less certain to be recovered than probable reserves. Portions of the reservoir that do not meet the reasonable certainty criterion may be assigned probable and possible oil and gas reserves based on reservoir fluid properties and pressure gradient interpretations.

Wright & Company, Inc. may separate proved developed reserves into proved developed producing and proved developed non-producing reserves. This is to identify proved developed producing reserves as those to be recovered from actively producing wells. Proved developed nonproducing reserves are those to be recovered from wells or intervals within wells, which are completed but shut-in waiting on equipment or pipeline connections, or wells where a relatively minor expenditure is required for recompletion to another zone.

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Fair Value of Financial Instruments (Assets Measured at Fair Value on a Recurring Basis) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative, Fair Value, Total	$ 7,300	$ 9,800
Commodity Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross	7,300	9,800
Derivative liabilities, gross
Fair Value, Inputs, Level 1
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative, Fair Value, Total
Fair Value, Inputs, Level 1 | Commodity Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross
Derivative liabilities, gross
Fair Value, Inputs, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative, Fair Value, Total	7,300	9,800
Fair Value, Inputs, Level 2 | Commodity Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross	7,300	9,800
Derivative liabilities, gross
Fair Value, Inputs, Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative, Fair Value, Total
Fair Value, Inputs, Level 3 | Commodity Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross
Derivative liabilities, gross

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Supplemental Oil and Gas Information (Unaudited) (Results of Operations for Oil and Gas Producing Activities) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Natural Gas and Oil Producing Activities [Abstract]
Revenues	$ 1,058,400	$ 925,500
Production costs	(725,300)	(764,900)
Depletion and amortization	(524,400)	(402,000)
Total Results from Operations from Oil and Gas Producing Activities	$ (191,300)	$ (241,400)

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Participation in Revenues and Costs (Narrative) (Details) (Managing General Partner)	12 Months Ended
	Dec. 31, 2013
Managing General Partner
Capital Unit [Line Items]
Additional working interest	7.00%

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Certain Relationships and Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2013

Costs Incurred From Related Party Transactions

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

	Years Ended December 31,
	2013		2012
Administrative	$	97,200	$	110,500
Supervision		415,000		471,700
Transportation		110,100		107,400
Direct Costs		263,300		244,400
Total	$	885,600	$	934,000

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Certain Relationships and Related Party Transactions (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Administrative
Related Party Transaction [Line Items]
Monthly Administrative Costs Per Well	$ 75
Supervision
Related Party Transaction [Line Items]
Monthly Supervision Fees Per Well	$ 320
Transportation
Related Party Transaction [Line Items]
Transportation Fee Rate As Percentage Of Natural Gas Sales Price	13.00%

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Derivative Instruments (Offsetting Liabilities) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities	$ (16,600)	$ (14,600)
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets	5,500	12,700
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount of Liabilities Presented in the Balance Sheets	(11,100)	(1,900)
Put premiums payable-affiliate
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities	(5,500)	(3,600)
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets	5,500	3,600
Long-term put premiums payable-affiliate
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities	(11,100)	(11,000)
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets		9,100
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount of Liabilities Presented in the Balance Sheets	$ (11,100)	$ (1,900)

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Supplemental Oil and Gas Information (Unaudited) (Standardized Measure Of Future Cash Flows) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Natural Gas and Oil Producing Activities [Abstract]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Cash Inflows	$ 4,440,600	$ 1,214,900
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Production Costs	(3,423,800)	(1,023,800)
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Net Cash Flows, Total	1,016,800	191,100
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, 10 Percent Annual Discount for Estimated Timing of Cash Flows	(242,700)	(24,000)
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure, Total	$ 774,100	$ 167,100

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

Cash Equivalents

The carrying amounts of the Partnership’s cash equivalents approximate fair values because of the short maturities of these instruments. The Partnership considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents.

Receivables

Accounts receivable affiliate on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realization of its accounts receivable, 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 management’s review of the credit information. The Partnership extends credit on sales on an unsecured basis to many of their customers. At December 31, 2013 and 2012, the Partnership had recorded no allowance for uncollectible accounts receivable on its balance sheets.

Oil and Gas Properties

Oil and gas properties are stated at cost. Maintenance and repairs that generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized.

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

The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties.

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

Impairment of Long-Lived Assets

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

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

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods.

There were no impairments of proved oil and gas properties recorded for the years ended December 31, 2013 and 2012. Asset impairment relates to the carrying amount of these gas and oil properties being in excess of the Partnership’s estimate of the fair value. The estimate of the fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

Derivative Instruments

The MGP enters into certain financial contracts to manage the Partnership’s exposure to movement in commodity prices (see Note 6). The derivative instruments recorded in the balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Partnership’s statements of operations unless specific hedge accounting criteria are met.

Asset Retirement Obligations

The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (see Note 5). The Partnership recognizes a liability for its future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset.

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.

The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. However, the Partnership has not recognized any potential interest or penalties in its financial statements as of December 31, 2013 and 2012.

The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2009. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2013.

Environmental Matters

The Partnership is subject to various federal, state, and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Partnership’s 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. The Partnership maintains insurance which may cover in whole or in part certain environmental expenditures. The Partnership had no environmental matters requiring specific disclosure or requiring the recognition of a liability for the years ended December 31, 2013 and 2012.

Concentration of Credit Risk

The Partnership sells natural gas, crude oil, and NGLs under contracts to various purchasers in the normal course of business. For the year ended December 31, 2013, the Partnership had four customers that individually accounted for approximately 48%, 22%, 11%, and 10%, respectively, of the Partnership’s natural gas, oil and NGL combined revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2012, the Partnership had three customers that individually accounted for approximately 53%, 22%, and 12%, respectively, of the Partnership natural gas, oil and NGL combined revenues, excluding the impact of all financial derivative activity.

Revenue Recognition

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

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “Use of Estimates” accounting policy for further description). The Partnership had unbilled revenues at December 31, 2013 and 2012 of $132,200 and $182,400, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.

Comprehensive Income (Loss)

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

Recently Adopted Accounting Standards

In February 2013, the FASB issued ASU 2013-02, Comprehensive Income (Topic 220) (“Update 2013-02”). Update 2013-02 requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present significant amounts reclassified out of accumulated other comprehensive income if the amount reclassified to net income in its entirety is in the same reporting period as incurred. For other amounts that are not required to be reclassified in their entirety to net income, an entity is required to reference to other disclosures that provide additional detail about those amounts. Entities are required to implement the amendments prospectively for reporting periods beginning after December 15, 2012, with early adoption being permitted. The Partnership adopted the requirements of Update 2013-02 upon its effective date of January 1, 2013, and it had no material impact on its financial position, results of operations or related disclosures.

In January 2013, the FASB issued ASU 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“Update 2013-01”). Update 2013-01 clarifies that ordinary trade receivables and payables are not in scope of ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. Specifically, ASU 2011-11 applies only to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with specific criteria contained in the FASB Accounting Standards Codification or subject to a master netting arrangement or similar agreement. The amendments are effective for interim and annual reporting periods beginning after January 1, 2013 and such amendments shall be applied retrospectively for any period presented that begins before the date of application. The Partnership adopted the requirements of Update 2013-01 on December 31, 2012, and it did not have a material impact on its financial position, results of operations or related disclosures.

Recently Issued Accounting Standards

In February 2013, the FASB issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements, for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements, for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership will apply the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

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Commitments and Contingencies (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Disclosure Commitments And Contingencies Details [Line Items]
Investor Partners Ownership Interest Presented For Purchase By The MGP, Maximum Percentage	5.00%
Operator Fee Per Well To Cover Estimated Future Plugging And Abandonment Costs, Monthly	$ 200

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Participation in Revenues and Costs (Details)	12 Months Ended
	Dec. 31, 2013
Managing General Partner
Capital Unit [Line Items]
Additional partnership revenues to receive, Percentage	7.00%
Organization And Offering Cost | Managing General Partner
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	100.00%
Organization And Offering Cost | Limited Partners
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	0.00%
Lease Costs | Managing General Partner
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	100.00%
Lease Costs | Limited Partners
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	0.00%
Revenues | Managing General Partner
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	35.00%	[1]
Revenues | Limited Partners
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	65.00%	[1]
Operating Costs, Administrative Costs, Direct And All Other Costs | Managing General Partner
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	35.00%	[2]
Operating Costs, Administrative Costs, Direct And All Other Costs | Limited Partners
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	65.00%	[2]
Intangible Drilling Costs | Managing General Partner
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	8.00%
Intangible Drilling Costs | Limited Partners
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	92.00%
Tangible Equipment Costs | Managing General Partner
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	67.00%
Tangible Equipment Costs | Limited Partners
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	33.00%

[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.

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

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Summary of Significant Accounting Policies (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Allowance for Uncollectible Accounts Receivable	$ 0	$ 0
Asset Impairment Charges	0	0
Unbilled Revenues	$ 132,200	$ 182,400
Current Year Customer 1
Concentration Risk, Percentage	48.00%
Current Year Customer 2
Concentration Risk, Percentage	22.00%
Current Year Customer 3
Concentration Risk, Percentage	11.00%
Current Year Customer 4
Concentration Risk, Percentage	10.00%
Prior Year Customer 1
Concentration Risk, Percentage		53.00%
Prior Year Customer 2
Concentration Risk, Percentage		22.00%
Prior Year Customer3
Concentration Risk, Percentage		12.00%

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Supplemental Oil and Gas Information (Unaudited) (Changes In Proved Reserve Quantities) (Details)	12 Months Ended
	Dec. 31, 2013 Mcf		Dec. 31, 2012 Mcf
Gas (Mcf)
Reserve Quantities [Line Items]
Balance	330,600		1,406,200
Revisions	958,200	[1]	(790,400)	[2]
Production	(240,500)		(285,200)
Balance	1,048,300		330,600
Oil (Bbls)
Reserve Quantities [Line Items]
Balance	2,800		7,000
Revisions	4,100	[1]	(3,200)	[2]
Production	(1,600)		(1,000)
Balance	5,300		2,800

[1] The upward revision in natural gas and oil forecasts is primarily due to an increase in SEC base pricing from the prior year, resulting in longer economic life.

[2] The downward revision in natural gas volumes is primarily due to a decline in SEC base pricing from the prior year, a decrease in the positive gas price basis differentials and a decrease in economic lives resulting from increased expenses.

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Property, Plant and Equipment (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Property Plant And Equipment [Line Items]
Natural gas and oil properties	$ 41,368,800	$ 41,614,200
Accumulated depletion and impairment	(38,703,500)	(38,179,100)
Oil and gas properties, net	2,665,300	3,435,100
Leaseholds Interest
Property Plant And Equipment [Line Items]
Natural gas and oil properties	695,700	695,700
Wells and related equipment
Property Plant And Equipment [Line Items]
Natural gas and oil properties	$ 40,673,100	$ 40,918,500

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Property, Plant and Equipment (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Property Plant And Equipment [Line Items]
Depletion of Oil and Gas Properties	$ 524,400	$ 402,000
Impairment of Long-Lived Assets Held-for-use	$ 0	$ 0

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Basis of Presentation

12 Months Ended

Dec. 31, 2013

BASIS OF PRESENTATION

NOTE 1—BASIS OF PRESENTATION

Atlas America Public #11-2002 LTD. (the “Partnership”) is a Delaware limited partnership, formed on June 5, 2002 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP).

In March 2012, the MGP’s ultimate parent, Atlas Energy L.P. (“Atlas Energy”) (NYSE: ATLS), contributed to ARP, a newly-formed exploration and production master limited partnership, substantially all of Atlas Energy’s natural gas and oil development and production assets and its partnership management business, including ownership of the MGP.

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

The Partnership has drilled and currently operates wells located in Pennsylvania and Ohio. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy, for administrative services. The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through affiliated and or third-party gas gathering systems. The Partnership does not plan to sell any of its wells and intends to produce them until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. The Partnership expects that no other wells will be drilled and no additional funds will be required for drilling.

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Asset Retirement Obligations (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligations [Abstract]
Asset retirement obligations, beginning of year	$ 2,637,100	$ 2,572,000
Accretion of asset retirement obligation	143,300	131,000
Asset retirement obligation revision	(245,400)	(65,900)
Asset retirement obligations, end of period	$ 2,535,000	$ 2,637,100

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Fair Value of Financial Instruments (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of Long-Lived Assets Held-for-use	$ 0	$ 0
Asset Retirement Obligation
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Adjustment to retirement obligation	0	0
Fair Value, Inputs, Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of Long-Lived Assets Held-for-use	$ 0	$ 0

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BALANCE SHEETS (USD $)	Dec. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 56,600	$ 29,800
Accounts receivable trade–affiliate	170,500	193,800
Accounts receivable monetized gains-affiliate	9,700	41,800
Current portion of derivative assets	1,200	1,900
Total current assets	238,000	267,300
Oil and gas properties, net	2,665,300	3,435,100
Long-term derivative assets	6,100	7,900
TOTAL ASSETS	2,909,400	3,710,300
Current liabilities:
Accrued liabilities	9,300	800
Total current liabilities	9,300	800
Asset retirement obligations	2,535,000	2,637,100
Long-term put premiums payable-affiliate	11,100	1,900
Commitments and contingencies
Partners’ capital:
Managing general partner’s interest	(5,500)	243,500
Limited partners’ interest (3,126.55 units)	368,500	865,100
Accumulated other comprehensive loss	(9,000)	(38,100)
Total partners’ capital	354,000	1,070,500
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$ 2,909,400	$ 3,710,300

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Supplemental Oil and Gas Information (Unaudited) (Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Natural Gas and Oil Producing Activities [Abstract]
Natural gas and oil properties: Leasehold interest	$ 695,700	$ 695,700
Natural gas and oil properties: Wells and related equipment	40,673,100	40,918,500
Accumulated depletion, accretion and impairment	(38,703,500)	(38,179,100)
Net capitalized costs	$ 2,665,300	$ 3,435,100

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STATEMENTS OF CHANGES IN PARTNERS' CAPITAL (USD $)	Total	Managing General Partner	Limited Partners	Accumulated Other Comprehensive Income (Loss)
Balance at Dec. 31, 2011	$ 1,918,700	$ 501,200	$ 1,417,500
Participation in revenue and costs and expenses:
Net production revenues	160,600	55,000	105,600
Interest income	100		100
Depletion	(402,000)	(163,000)	(239,000)
Accretion of asset retirement obligation	(131,000)	(45,800)	(85,200)
General and administrative	(169,100)	(59,200)	(109,900)
Net loss	(541,400)	(213,000)	(328,400)
Other comprehensive income (loss)	(38,100)			(38,100)
Distributions to partners	(268,700)	(44,700)	(224,000)
Balance at Dec. 31, 2012	1,070,500	243,500	865,100	(38,100)
Participation in revenue and costs and expenses:
Net production revenues	333,100	119,000	214,100
Depletion	(524,400)	(217,800)	(306,600)
Accretion of asset retirement obligation	(143,300)	(50,100)	(93,200)
General and administrative	(160,300)	(56,100)	(104,200)
Net loss	(494,900)	(205,000)	(289,900)
Other comprehensive income (loss)	29,100			29,100
Distributions to partners	(250,700)	(44,000)	(206,700)
Balance at Dec. 31, 2013	$ 354,000	$ (5,500)	$ 368,500	$ (9,000)

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Derivative Instruments (Effects of Derivative Instruments on Statements of Operations) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Gains from cash flow hedges reclassified from accumulated other comprehensive income (loss) into natural gas, oil and liquids revenues	$ 10,000	$ 45,300

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Asset Retirement Obligations

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

	Years Ended December 31,
	2013			2012
Asset retirement obligations, beginning of year	$	2,637,100		$	2,572,000
Accretion of asset retirement obligation		143,300			131,000
Asset retirement obligation revision		(245,400	)		(65,900	)
Asset retirement obligations, end of period	$	2,535,000		$	2,637,100

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Derivative Instruments (Offsetting Assets) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	$ 15,200	$ 54,500
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset in the Balance Sheets	(5,500)	(12,700)
Affiliate Balances, Offsetting Derivative Assets, Net Amount of Assets Presented in the Balance Sheets	9,700	41,800
Accounts receivable monetized gains-affiliate
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	15,200	45,400
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset in the Balance Sheets	(5,500)	(3,600)
Affiliate Balances, Offsetting Derivative Assets, Net Amount of Assets Presented in the Balance Sheets	9,700	41,800
Long-term receivable monetized gains-affiliate
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets		9,100
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset in the Balance Sheets		$ (9,100)

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Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Fair Value Derivative Instruments

Information for assets and liabilities measured at fair value at December 31, 2013 and 2012 was as follows:

As of December 31, 2013	Level 1		Level 2		Level 3		Total
Derivative assets, gross
Commodity puts	$	-	$	7,300	$	-	$	7,300
Derivative liabilities, gross
Commodity puts		-		-		-		-
Total derivative, fair value, net	$	-	$	7,300	$	-	$	7,300
As of December 31, 2012
Derivative assets, gross
Commodity puts	$	-	$	9,800	$	-	$	9,800
Derivative liabilities, gross
Commodity puts		-		-		-		-
Total derivative, fair value, net	$	-	$	9,800	$	-	$	9,800

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STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:
Net loss	$ (494,900)	$ (541,400)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion	524,400	402,000
Non-cash loss on derivative value, net	72,900	134,100
Accretion of asset retirement obligation	143,300	131,000
Changes in operating assets and liabilities:
Decrease in accounts receivable trade-affiliate	23,300	59,600
Increase (decrease) in accrued liabilities	8,500	(7,600)
Net cash provided by operating activities	277,500	177,700
Cash flows from investing activities:
Proceeds from sale of tangible equipment		8,200
Net cash provided by investing activities		8,200
Cash flows from financing activities:
Distributions to partners	(250,700)	(268,700)
Net cash used in financing activities	(250,700)	(268,700)
Net change in cash and cash equivalents	26,800	(82,800)
Cash and cash equivalents at beginning of year	29,800	112,600
Cash and cash equivalents at end of period	56,600	29,800
Supplemental schedule of non-cash investing and financing activities:
Asset retirement obligation revision	$ (245,400)	$ (65,900)

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BALANCE SHEETS (Parenthetical)	Dec. 31, 2013
Limited partners' units	3,126.55

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Subsequent Events

12 Months Ended

Dec. 31, 2013

SUBSEQUENT EVENTS

NOTE 10—SUBSEQUENT EVENTS

Management has considered for disclosure any material subsequent events through the date the financial statements were issued.

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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013
Document Document And Entity Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Entity Registrant Name	ATLAS AMERICA Public #11-2002 LTD.
Entity Central Index Key	0001175028
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding	0
Entity Public Float	$ 0
Entity Current Reporting Status	Yes
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No

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Supplemental Oil and Gas Information (Unaudited)

12 Months Ended

Dec. 31, 2013

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

NOTE 11—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Gas Reserve Information. The preparation of the Partnership’s natural gas and oil reserve estimates was completed in accordance with our MGP’s prescribed internal control procedures by its reserve engineers. The accompanying reserve information included below is attributable to the reserves of the Partnership and was derived from the reserve reports prepared for Atlas America Public #11-2002 LTD. annual Form 10-K for the years ended December 31, 2013 and 2012 (see Note 2). For the periods presented, Wright and Company, Inc., an independent third-party reserve engineer, was retained to prepare a report of proved reserves related to the Partnership. The reserve information for the Partnership includes natural gas and oil reserves which are all located in the United States, primarily in Pennsylvania and Ohio. The independent reserves engineer’s evaluation was based on more than 37 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. The MGP’s internal control procedures include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our MGP’s Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 15 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by the MGP’s senior engineering staff and management, with final approval by the MGP’s Chief Operating Officer.

The reserve disclosures that follow reflect estimates of proved developed reserves net of royalty interests, of natural gas, crude oil, and natural gas liquids owned at year end. Proved developed reserves are those reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. In accordance with the prevailing accounting literature, the proved reserves quantities and future net cash flows as of December 31, 2013 and 2012 were estimated using an unweighted 12-month average pricing based on the prices on the first day of each month during the years ended December 31, 2013 and 2012 and including adjustments related to regional price differentials and energy content.

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 oil and gas reserves included within the Partnership 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 their effects have not been proved.

Reserve quantity information and a reconciliation of changes in proved reserve quantities included within the Partnership are as follows (unaudited):

	Gas (Mcf)			Oil (Bbls)
Balance, December 31, 2011		1,406,200			7,000
Revisions (1)		(790,400	)		(3,200	)
Production		(285,200	)		(1,000	)
Balance, December 31, 2012		330,600			2,800
Revisions (2)		958,200			4,100
Production		(240,500	)		(1,600	)
Balance, December 31, 2013		1,048,300			5,300

(1) The downward revision in natural gas volumes is primarily due to a decline in SEC base pricing from the prior year, a decrease in the positive gas price basis differentials and a decrease in economic lives resulting from increased expenses.

(2) The upward revision in natural gas and oil forecasts is primarily due to an increase in SEC base pricing from the prior year, resulting in longer economic life.

Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to oil and gas producing activities of the Partnership during the periods indicated were as follows:

	Years Ended December 31,
	2013			2012
Natural gas and oil properties:
Leasehold interest	$	695,700		$	695,700
Wells and related equipment		40,673,100			40,918,500
Accumulated depletion, accretion and impairment		(38,703,500	)		(38,179,100	)
Net capitalized costs	$	2,665,300		$	3,435,100

Results of Operations from Oil and Gas Producing Activities. The results of operations related to the Partnership’s oil and gas producing activities during the periods indicated were as follows:

	Years Ended December 31,
	2013			2012
Revenues	$	1,058,400		$	925,500
Production costs		(725,300	)		(764,900	)
Depletion		(524,400	)		(402,000	)
	$	(191,300	)	$	(241,400	)

Standardized Measure of Discounted Future Cash Flows.The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the Partnership’s proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2013 and 2012, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations:

	Years Ended December 31,
	2013			2012
Future cash inflows	$	4,440,600		$	1,214,900
Future production costs		(3,423,800	)		(1,023,800	)
Future net cash flows		1,016,800			191,100
Less 10% annual discount for estimated timing of cash flows		(242,700	)		(24,000	)
Standardized measure of discounted future net cash flows	$	774,100		$	167,100

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STATEMENTS OF OPERATIONS (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
REVENUES
Natural gas, oil and liquids	$ 1,058,400	$ 925,500
Interest income		100
Total revenues	1,058,400	925,600
COST AND EXPENSES
Production	725,300	764,900
Depletion	524,400	402,000
Accretion of asset retirement obligation	143,300	131,000
General and administrative	160,300	169,100
Total costs and expenses	1,553,300	1,467,000
Net loss	(494,900)	(541,400)
Allocation of net loss:
Managing general partner	(205,000)	(213,000)
Limited partners	$ (289,900)	$ (328,400)
Net loss per limited partnership unit	$ (93)	$ (105)

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2013

ASSET RETIREMENT OBLIGATIONS

NOTE 5—ASSET RETIREMENT OBLIGATIONS

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

The MGP’s historical practice and continued intention is to retain distributions from the limited partners as the wells within the Partnership near the end of their useful life. On a partnership-by-partnership basis, the MGP assesses its right to withhold amounts related to plugging and abandonment costs based on several factors including commodity price trends, the natural decline in the production of the wells, and current and future costs. Generally, the MGP’s intention is to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approaches the fair value of the future plugging and abandonment cost. Upon the MGP’s decision to retain all future distributions to the limited partners of the Partnership, the MGP will assume the related asset retirement obligations of the limited partners.

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

	Years Ended December 31,
	2013			2012
Asset retirement obligations, beginning of year	$	2,637,100		$	2,572,000
Accretion of asset retirement obligation		143,300			131,000
Asset retirement obligation revision		(245,400	)		(65,900	)
Asset retirement obligations, end of period	$	2,535,000		$	2,637,100

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2013

PROPERTY, PLANT AND EQUIPMENT

NOTE 4—PROPERTY, PLANT AND EQUIPMENT

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

	December 31,
	2013			2012
Proved properties:
Leasehold interest	$	695,700		$	695,700
Wells and related equipment		40,673,100			40,918,500
Total natural gas and oil properties		41,368,800			41,614,200
Accumulated depletion and impairment		(38,703,500	)		(38,179,100	)
Oil and gas properties, net	$	2,665,300		$	3,435,100

The Partnership recorded depletion expense on natural gas and oil properties of $524,400 and $402,000 for the years ended December 31, 2013 and 2012, respectively. 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. Upon the sale of an entire interest where the property had been assessed for impairment, a gain or loss is recognized in the statements of operations.

There were no impairments of proved gas and oil properties recorded for the years ended December 31, 2013 and 2012. Asset impairment relates to the carrying amount of these oil and gas properties being in excess of the Partnership’s estimate of their fair value. The estimate of fair value of these oil and gas properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

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Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2013

Effects of Derivative Instruments on Statements of Operations

Effects of Derivative Instruments on Statements of Operations:

The following table summarizes the gain or loss recognized in the statements of operations for effective derivative instruments for the years ended December 31, 2013 and 2012:

	Years Ended December 31,
	2013		2012
Gains from cash flow hedges reclassified from accumulated other comprehensive income (loss) into natural gas, oil and liquids revenues	$	10,000	$	45,300

Offsetting Assets

The following table summarizes the gross and net fair values of the Partnership’s balances on the Partnership’s balance sheets for the periods indicated:

Offsetting Assets	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheets			Net Amount of Assets Presented in the Balance Sheets
As of December 31, 2013
Accounts receivable monetized gains-affiliate	$	15,200	$	(5,500	)	$	9,700
Long-term receivable monetized gains-affiliate		-		-			-
Total	$	15,200	$	(5,500	)	$	9,700
As of December 31, 2012
Accounts receivable monetized gains-affiliate	$	45,400	$	(3,600	)	$	41,800
Long-term receivable monetized gains-affiliate		9,100		(9,100	)		-
Total	$	54,500	$	(12,700	)	$	41,800

Offsetting Liabilities

Offsetting Liabilities	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheets		Net Amount of Liabilities Presented in the Balance Sheets
As of December 31, 2013
Put premiums payable-affiliate	$	(5,500	)	$	5,500	$	-
Long-term put premiums payable-affiliate		(11,100	)		-		(11,100	)
Total	$	(16,600	)	$	5,500	$	(11,100	)
As of December 31, 2012
Put premiums payable-affiliate	$	(3,600	)	$	3,600	$	-
Long-term put premiums payable-affiliate		(11,000	)		9,100		(1,900	)
Total	$	(14,600	)	$	12,700	$	(1,900	)

Natural Gas Put Options

Commodity Derivatives

At December 31, 2013, the Partnership had the following commodity derivatives:

Natural Gas Put Options

Production Period Ending December 31,	Volumes (MMBtu)(1)		Average Fixed Price (per MMBtu)(1)		Fair Value Asset (2)
2014		9,600	$	3.80	$	1,200
2015		7,700		4.00		2,600
2016		7,700		4.15		3,500
					$	7,300

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

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

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Use of Estimates

Use of Estimates

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

Cash Equivalents

Cash Equivalents

The carrying amounts of the Partnership’s cash equivalents approximate fair values because of the short maturities of these instruments. The Partnership considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents.

Receivables

Receivables

Accounts receivable affiliate on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realization of its accounts receivable, 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 management’s review of the credit information. The Partnership extends credit on sales on an unsecured basis to many of their customers. At December 31, 2013 and 2012, the Partnership had recorded no allowance for uncollectible accounts receivable on its balance sheets.

Oil and Gas Properties

Oil and Gas Properties

Oil and gas properties are stated at cost. Maintenance and repairs that generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized.

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

The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties.

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

Impairment of Long-Lived Assets

Impairment of Long-Lived Assets

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

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

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods.

There were no impairments of proved oil and gas properties recorded for the years ended December 31, 2013 and 2012. Asset impairment relates to the carrying amount of these gas and oil properties being in excess of the Partnership’s estimate of the fair value. The estimate of the fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

Derivative Instruments

Derivative Instruments

The MGP enters into certain financial contracts to manage the Partnership’s exposure to movement in commodity prices (see Note 6). The derivative instruments recorded in the balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Partnership’s statements of operations unless specific hedge accounting criteria are met.

Asset Retirement Obligations

Asset Retirement Obligations

The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (see Note 5). The Partnership recognizes a liability for its future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset.

Income Taxes

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.

The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. However, the Partnership has not recognized any potential interest or penalties in its financial statements as of December 31, 2013 and 2012.

The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2009. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2013.

Environmental Matters

Environmental Matters

The Partnership is subject to various federal, state, and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Partnership’s 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. The Partnership maintains insurance which may cover in whole or in part certain environmental expenditures. The Partnership had no environmental matters requiring specific disclosure or requiring the recognition of a liability for the years ended December 31, 2013 and 2012.

Concentration of Credit Risk

Concentration of Credit Risk

The Partnership sells natural gas, crude oil, and NGLs under contracts to various purchasers in the normal course of business. For the year ended December 31, 2013, the Partnership had four customers that individually accounted for approximately 48%, 22%, 11%, and 10%, respectively, of the Partnership’s natural gas, oil and NGL combined revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2012, the Partnership had three customers that individually accounted for approximately 53%, 22%, and 12%, respectively, of the Partnership natural gas, oil and NGL combined revenues, excluding the impact of all financial derivative activity.

Revenue Recognition

Revenue Recognition

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

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “Use of Estimates” accounting policy for further description). The Partnership had unbilled revenues at December 31, 2013 and 2012 of $132,200 and $182,400, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.

Comprehensive Income (Loss)

Comprehensive Income (Loss)

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

Recently Adopted Accounting Standards

Recently Adopted Accounting Standards

In February 2013, the FASB issued ASU 2013-02, Comprehensive Income (Topic 220) (“Update 2013-02”). Update 2013-02 requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present significant amounts reclassified out of accumulated other comprehensive income if the amount reclassified to net income in its entirety is in the same reporting period as incurred. For other amounts that are not required to be reclassified in their entirety to net income, an entity is required to reference to other disclosures that provide additional detail about those amounts. Entities are required to implement the amendments prospectively for reporting periods beginning after December 15, 2012, with early adoption being permitted. The Partnership adopted the requirements of Update 2013-02 upon its effective date of January 1, 2013, and it had no material impact on its financial position, results of operations or related disclosures.

In January 2013, the FASB issued ASU 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“Update 2013-01”). Update 2013-01 clarifies that ordinary trade receivables and payables are not in scope of ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. Specifically, ASU 2011-11 applies only to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with specific criteria contained in the FASB Accounting Standards Codification or subject to a master netting arrangement or similar agreement. The amendments are effective for interim and annual reporting periods beginning after January 1, 2013 and such amendments shall be applied retrospectively for any period presented that begins before the date of application. The Partnership adopted the requirements of Update 2013-01 on December 31, 2012, and it did not have a material impact on its financial position, results of operations or related disclosures.

Recently Issued Accounting Standards

Recently Issued Accounting Standards

In February 2013, the FASB issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements, for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements, for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership will apply the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

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Certain Relationships and Related Party Transactions

12 Months Ended

Dec. 31, 2013

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

NOTE 8—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The Partnership has entered into the following significant transactions with the MGP and its affiliates as provided under its Partnership Agreement. Administrative costs, which are included in general and administrative expenses in the Partnership’s statements of operations, are payable at $75 per well per month. Monthly well supervision fees, which are included in production expense in the Partnership’s statement of operations, are payable at $320 per well per month for operating and maintaining the wells. 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. Direct costs, which are included in production and general administrative expenses in the Partnership’s statements of operations, are payable to the MGP and its affiliates as reimbursement for all costs expended on the Partnership’s behalf.

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

	Years Ended December 31,
	2013		2012
Administrative	$	97,200	$	110,500
Supervision		415,000		471,700
Transportation		110,100		107,400
Direct Costs		263,300		244,400
Total	$	885,600	$	934,000

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

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Derivative Instruments

12 Months Ended

Dec. 31, 2013

DERIVATIVE INSTRUMENTS

NOTE 6—DERIVATIVE INSTRUMENTS

The MGP, on behalf of the Partnership, uses a number of different derivative instruments, principally swaps, collars and options, in connection with the Partnership’s commodity price risk management activities. Management enters into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under commodity-based swap agreements, the Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike price, and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged.

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 the MGP determines that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the MGP will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by management of the MGP through the utilization of market data, will be recognized immediately within gain (loss) on market-to-market derivatives in the Partnership’s statements of operations. For derivatives qualifying as hedges, the Partnership recognizes the effective portion of changes in fair value of derivative instruments as accumulated other comprehensive income and reclassifies the portion relating to commodity derivatives to gas and oil production revenues within the Partnership’s statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership recognizes changes in fair value within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations as they occur.

The Partnership enters into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s balance sheets as the initial value of the options. The Partnership reflected net derivative assets on its balance sheets of $7,300 and $9,800 at December 31, 2013 and 2012, respectively.

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

At December 31, 2013, the Partnership had the following commodity derivatives:

Natural Gas Put Options

Production Period Ending December 31,	Volumes (MMBtu)(1)		Average Fixed Price (per MMBtu)(1)		Fair Value Asset (2)
2014		9,600	$	3.80	$	1,200
2015		7,700		4.00		2,600
2016		7,700		4.15		3,500
					$	7,300

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

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

Effects of Derivative Instruments on Statements of Operations:

The following table summarizes the gain or loss recognized in the statements of operations for effective derivative instruments for the years ended December 31, 2013 and 2012:

	Years Ended December 31,
	2013		2012
Gains from cash flow hedges reclassified from accumulated other comprehensive income (loss) into natural gas, oil and liquids revenues	$	10,000	$	45,300

As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the years ended December 31, 2013 and 2012, for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

Monetized Gains

Prior to February 17, 2011 (date of the Transferred Business), Atlas Energy Inc., (“AEI”) monetized its derivative instruments, including those related to the future natural gas and oil production of the Transferred Business. AEI also monetized derivative instruments that were specifically related to the future natural gas and oil production of the Partnership. At December 31, 2013 and 2012, remaining hedge monetization cash proceeds of $15,200 and $45,400, respectively, related to the amounts hedged on behalf of the Partnership’s limited partners were included within accounts receivable monetized gains-affiliate. There were no long-term monetized gains receivable-affiliate at December 31, 2013. At December 31, 2012, $9,100 of long-term monetized gains receivable-affiliate were included in long-term put premiums payable-affiliate on the Partnership’s balance sheet. The Partnership will allocate the monetized net proceeds to the limited partners based on the natural gas and oil production generated over the period of the original derivative contracts.

During June 2012, the MGP used the undistributed monetized funds to purchase natural gas put options on behalf of the limited partners of the Partnership only. A premium (“put premium”) was paid to purchase the contracts and will be allocated to natural gas production revenues generated over the contractual term of the purchased hedging instruments. At December 31, 2013 and 2012, the put premiums were recorded as short-term payables to affiliate of $5,500 and $3,600, respectively, and long-term payables to affiliate of $11,100 and $11,000, respectively. Furthermore, the current portion of the put premium liability was included in accounts receivable monetized gains-affiliate and the long-term receivable monetized gains-affiliate was included in long term put premiums payable-affiliate in the Partnership’s balance sheets, presenting the impact of offsetting the related party assets and liabilities. The put premiums included on the Partnership’s balance sheets are allocable to the limited partners only.

The following table summarizes the gross and net fair values of the Partnership’s balances on the Partnership’s balance sheets for the periods indicated:

Offsetting Assets	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheets			Net Amount of Assets Presented in the Balance Sheets
As of December 31, 2013
Accounts receivable monetized gains-affiliate	$	15,200	$	(5,500	)	$	9,700
Long-term receivable monetized gains-affiliate		-		-			-
Total	$	15,200	$	(5,500	)	$	9,700
As of December 31, 2012
Accounts receivable monetized gains-affiliate	$	45,400	$	(3,600	)	$	41,800
Long-term receivable monetized gains-affiliate		9,100		(9,100	)		-
Total	$	54,500	$	(12,700	)	$	41,800

Offsetting Liabilities	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheets		Net Amount of Liabilities Presented in the Balance Sheets
As of December 31, 2013
Put premiums payable-affiliate	$	(5,500	)	$	5,500	$	-
Long-term put premiums payable-affiliate		(11,100	)		-		(11,100	)
Total	$	(16,600	)	$	5,500	$	(11,100	)
As of December 31, 2012
Put premiums payable-affiliate	$	(3,600	)	$	3,600	$	-
Long-term put premiums payable-affiliate		(11,000	)		9,100		(1,900	)
Total	$	(14,600	)	$	12,700	$	(1,900	)

Accumulated Other Comprehensive Income (Loss)

As a result of the monetization and the early settlement of natural gas and oil derivative instruments, the put options, and the unrealized gains recognized in income in prior periods due to natural gas and oil property impairments, the Partnership recorded a net deferred loss on its balance sheets in accumulated other comprehensive loss of $9,000 as of December 31, 2013. Included in accumulated other comprehensive loss are unrealized gains of $14,900, net of the MGP interest, that were recognized into income as a result of oil and gas property impairments prior periods. During the current year, $6,900 of net losses were recorded by the Partnership and allocated only to the limited partners. Of the remaining $9,000 of net unrealized loss in accumulated other comprehensive loss, the Partnership will reclassify $4,100 of net losses to the Partnership’s statements of operations over the next twelve month period and the remaining $4,900 in later periods.

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Fair Value of Financial Instruments

12 Months Ended

Dec. 31, 2013

FAIR VALUE OF FINANCIAL INSTRUMENTS

NOTE 7—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. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect the Partnership’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value:

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

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

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The carrying value of cash, accounts receivable, and accounts payable approximate their respective fair values due to the short-term maturities of such financial instruments. The Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 6). The Partnership manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty. The Partnership’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. These derivative instruments are calculated by utilizing commodity indices, quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument.

Information for assets and liabilities measured at fair value at December 31, 2013 and 2012 was as follows:

As of December 31, 2013	Level 1		Level 2		Level 3		Total
Derivative assets, gross
Commodity puts	$	-	$	7,300	$	-	$	7,300
Derivative liabilities, gross
Commodity puts		-		-		-		-
Total derivative, fair value, net	$	-	$	7,300	$	-	$	7,300
As of December 31, 2012
Derivative assets, gross
Commodity puts	$	-	$	9,800	$	-	$	9,800
Derivative liabilities, gross
Commodity puts		-		-		-		-
Total derivative, fair value, net	$	-	$	9,800	$	-	$	9,800

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

The Partnership’s other current assets and liabilities on its balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1.

The Partnership estimates the fair value of its asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates. There were no adjustments to retirement obligations measured at fair value on a nonrecurring basis for the years ended December 31, 2013 and 2012.

The Partnership estimates the fair value of its long-lived assets in conjunction with the review of asset impairment or whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions, and judgments regarding such events or circumstances. There was no impairment recognized by us for the years ended December 31, 2013 and 2012 which were defined as a Level 3 fair value measurement (see Note 2 – Impairment of Long-Lived Assets).

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

COMMITMENTS AND CONTINGENCIES

NOTE 9—COMMITMENTS AND CONTINGENCIES

General Commitments

Subject to certain conditions, investor partners may present their interests for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. The MGP is not obligated to purchase more than 5% of the 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, 2013, the MGP has not withheld any such funds. The MGP is currently evaluating its right to exercise this option based on several factors such as commodity prices, the natural decline in well production, and current and future plugging services and costs.

Legal Proceedings

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

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Derivative Instruments (Commodity Derivatives) (Details) (USD $)					12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Natural Gas Put Options		Dec. 31, 2013 Natural Gas Put Options Production Period Ending December 31, 2014 MMBTU		Dec. 31, 2013 Natural Gas Put Options Production Period Ending December 31, 2015 MMBTU		Dec. 31, 2013 Natural Gas Put Options Production Period Ending December 31, 2016 MMBTU
Derivative [Line Items]
Volumes (MMBtu)					9,600	[1]	7,700	[1]	7,700	[1]
Average Fixed Price (per MMBtu)					3.80	[1]	4.00	[1]	4.15	[1]
Fair Value Asset	$ 7,300	$ 9,800	$ 7,300	[2]	$ 1,200	[2]	$ 2,600	[2]	$ 3,500	[2]

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

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

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment

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

	December 31,
	2013			2012
Proved properties:
Leasehold interest	$	695,700		$	695,700
Wells and related equipment		40,673,100			40,918,500
Total natural gas and oil properties		41,368,800			41,614,200
Accumulated depletion and impairment		(38,703,500	)		(38,179,100	)
Oil and gas properties, net	$	2,665,300		$	3,435,100

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Supplemental Oil and Gas Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Changes in Proved Reserve Quantities

Reserve quantity information and a reconciliation of changes in proved reserve quantities included within the Partnership are as follows (unaudited):

	Gas (Mcf)			Oil (Bbls)
Balance, December 31, 2011		1,406,200			7,000
Revisions (1)		(790,400	)		(3,200	)
Production		(285,200	)		(1,000	)
Balance, December 31, 2012		330,600			2,800
Revisions (2)		958,200			4,100
Production		(240,500	)		(1,600	)
Balance, December 31, 2013		1,048,300			5,300

(1) The downward revision in natural gas volumes is primarily due to a decline in SEC base pricing from the prior year, a decrease in the positive gas price basis differentials and a decrease in economic lives resulting from increased expenses.

(2) The upward revision in natural gas and oil forecasts is primarily due to an increase in SEC base pricing from the prior year, resulting in longer economic life.

Capitalized Costs Relating to Oil and Gas Producing Activities

Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to oil and gas producing activities of the Partnership during the periods indicated were as follows:

	Years Ended December 31,
	2013			2012
Natural gas and oil properties:
Leasehold interest	$	695,700		$	695,700
Wells and related equipment		40,673,100			40,918,500
Accumulated depletion, accretion and impairment		(38,703,500	)		(38,179,100	)
Net capitalized costs	$	2,665,300		$	3,435,100

Results of Operations for Oil and Gas Producing Activities

Results of Operations from Oil and Gas Producing Activities. The results of operations related to the Partnership’s oil and gas producing activities during the periods indicated were as follows:

	Years Ended December 31,
	2013			2012
Revenues	$	1,058,400		$	925,500
Production costs		(725,300	)		(764,900	)
Depletion		(524,400	)		(402,000	)
	$	(191,300	)	$	(241,400	)

Standardized Measure of Discounted Future Cash Flows

Standardized Measure of Discounted Future Cash Flows.The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the Partnership’s proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2013 and 2012, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations:

	Years Ended December 31,
	2013			2012
Future cash inflows	$	4,440,600		$	1,214,900
Future production costs		(3,423,800	)		(1,023,800	)
Future net cash flows		1,016,800			191,100
Less 10% annual discount for estimated timing of cash flows		(242,700	)		(24,000	)
Standardized measure of discounted future net cash flows	$	774,100		$	167,100

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Certain Relationships and Related Party Transactions (Schedule of Related Party Transactions) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 885,600	$ 934,000
Administrative
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	97,200	110,500
Supervision
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	415,000	471,700
Transportation
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	110,100	107,400
Direct Costs
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 263,300	$ 244,400

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STATEMENTS OF COMPREHENSIVE LOSS (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Net loss	$ (494,900)	$ (541,400)
Other comprehensive income (loss):
Unrealized holding (loss) gain on cash flow hedging contracts	(9,200)	(4,800)
Difference in estimated hedge gains receivable	48,300	12,000
Reclassification adjustment for gains realized in net loss from cash flow hedges	(10,000)	(45,300)
Total other comprehensive income (loss)	29,100	(38,100)
Comprehensive loss	$ (465,800)	$ (579,500)

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Participation in Revenues and Costs

12 Months Ended

Dec. 31, 2013

PARTICIPATION IN REVENUES AND COSTS

NOTE 3—PARTICIPATION IN REVENUES AND COSTS

Working Interest

Our Partnership Agreement establishes that revenues and expenses 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 the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expense 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 based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.

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

	Managing General Partner		Limited Partners
Organization and offering cost		100%		0%
Lease costs		100%		0%
Revenues (1)		35%		65%
Operating costs, administrative costs, direct and all other costs (2)		35%		65%
Intangible drilling costs		8%		92%
Tangible equipment costs		67%		33%

(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.

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

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Basis of Presentation (Details)	12 Months Ended
	Dec. 31, 2013
Atlas America Public #11-2002 LTD. Formation Date	Jun. 05, 2002

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Derivative Instruments (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]
Fair Value Asset/(Liability)	$ 7,300	$ 9,800
Gain (Loss) on Fair Value Hedge Ineffectiveness, Net	0	0
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	15,200	54,500
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	16,600	14,600
Accumulated other comprehensive (loss) income	(9,000)	(38,100)
Unrealized gains (losses) due to natural gas and oil property impairments
Derivative [Line Items]
Accumulated other comprehensive (loss) income	(9,000)
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	(4,100)
Net Deferred Gain (Loss) To Be Reclassified Into Net Income In Later Periods	(4,900)
Other Comprehensive Income (Loss)
Derivative [Line Items]
Unrealized gains (losses) due to natural gas and oil property impairments	14,900
Allocation To Limited Partner Only | Other Comprehensive Income (Loss)
Derivative [Line Items]
Net Derivative Gains (Losses) Limited Partner	(6,900)
Accounts receivable monetized gains-affiliate
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	15,200	45,400
Accounts receivable monetized gains-affiliate | Allocation To Limited Partner Only
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	15,200	45,400
Long-term receivable monetized gains-affiliate
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets		9,100
Long-term receivable monetized gains-affiliate | Allocation To Limited Partner Only
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	0	9,100
Put premiums payable-affiliate
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	5,500	3,600
Put premiums payable-affiliate | Allocation To Limited Partner Only
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	5,500	3,600
Long-term put premiums payable-affiliate
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	11,100	11,000
Long-term put premiums payable-affiliate | Allocation To Limited Partner Only
Derivative [Line Items]
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	$ 11,100	$ 11,000

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Participation in Revenues and Costs (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Participation In Revenues And Costs, Allocation

Working Interest

Our Partnership Agreement establishes that revenues and expenses 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 the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expense 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 based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.

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

	Managing General Partner		Limited Partners
Organization and offering cost		100%		0%
Lease costs		100%		0%
Revenues (1)		35%		65%
Operating costs, administrative costs, direct and all other costs (2)		35%		65%
Intangible drilling costs		8%		92%
Tangible equipment costs		67%		33%

(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.

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