ATLAS AMERICA PUBLIC #10 LTD. - FORM 10-K

ATLAS AMERICA PUBLIC #10 LTD. - FORM 10-K - April 1, 2013

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ATLAS AMERICA PUBLIC #10 LTD. Reports

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EX-23.1 - EX-23.1 - ATLAS AMERICA PUBLIC #10 LTD.	d512813dex231.htm
EX-31.2 - EX-31.2 - ATLAS AMERICA PUBLIC #10 LTD.	d512813dex312.htm
EX-99.1 - EX-99.1 - ATLAS AMERICA PUBLIC #10 LTD.	d512813dex991.htm
EXCEL - IDEA: XBRL DOCUMENT - ATLAS AMERICA PUBLIC #10 LTD.	Financial_Report.xls
EX-32.2 - EX-32.2 - ATLAS AMERICA PUBLIC #10 LTD.	d512813dex322.htm
EX-31.1 - EX-31.1 - ATLAS AMERICA PUBLIC #10 LTD.	d512813dex311.htm
EX-32.1 - EX-32.1 - ATLAS AMERICA PUBLIC #10 LTD.	d512813dex321.htm

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, 2012

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

For the transition period from to

Commission file number: 000-49777

ATLAS AMERICA PUBLIC #10 LTD.

(Exact name of registrant as specified in its charter)


Pennsylvania		25-1891457
(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):

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 #10 LTD.

INDEX TO ANNUAL REPORT

ON FORM 10-K

TABLE OF CONTENTS


	Page
PART I
Item 1: Business		4
Item 2: Properties		12
Item 3: Legal Proceedings		14
Item 4: Mine Safety Disclosures (Not Applicable)		14

PART II
Item 5: Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities		14
Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations		15
Item 8: Financial Statements and Supplementary Data		22
Item 9: Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		40
Item 9A: Controls and Procedures		40

PART III
Item 10: Directors, Executive Officers and Corporate Governance		41
Item 11: Executive Compensation		42
Item 12: Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		42
Item 13: Certain Relationships and Related Transactions		43
Item 14: Principal Accountant Fees and Services		43

PART IV
Item 15: Exhibits		44

SIGNATURES		45

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.

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 #10 LTD, (“we, “us”, or “the Partnership”) is a Pennsylvania limited partnership and was formed on July 5, 2001 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 $21,281,200, 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 $7,227,500. We have drilled 110 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.

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 $329 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, 2012 our MGP had not withheld any funds for this purpose.

Gas and Oil Production

Production Volumes

The following table presents our total net natural gas and oil production volumes for the years ended December 31, 2012 and 2011:


	Years Ended December 31,
	2012		2011
Production:⁽¹⁾
Natural gas (Mcf)		253,248		251,239
Oil (Bbl)		746		1,114

Total (Mcfe)		257,724		257,923

(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 utility companies, gas marketers, local distribution companies, industrial or other end-users, and companies generating electricity. 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 indexes are as follows: Appalachian Basin and Mississippi Lime (wells located in PA, TN, OH, OK, WV and NY), primarily the NYMEX spot market price; Barnett Shale and Marble Falls (wells located in TX), primarily the Waha spot market price; New Albany Shale and Antrim Shale (wells located in IN and MI), primarily the Texas Gas Zone SL and Chicago Hub spot market prices; and Niobrara formation (wells located in CO), primarily the Cheyenne Hub spot market price. Natural gas liquids are produced by the MGP’s natural gas processing plants, which extract the natural gas liquids from the natural gas production, enabling the remaining “dry” gas (low Btu content) to meet pipeline specifications for long-haul transport to end users. Our NGLs are generally priced using the Mont Belvieu (TX) regional processing hub.

Our production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas. 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, 2012, and 2011, along with our average production costs in each of the reported periods:


	Years Ended December 31,
	2012		2011
Production revenues (in thousands):
Nature gas revenue	$	736	$	1,341
Oil revenue		69		99

Total revenues	$	805	$	1,440

Average sales price: ⁽¹⁾
Natural gas (per Mcf) ⁽²⁾	$	3.44	$	5.53
Oil (per Bbl)	$	91.94	$	88.78
Production costs (per Mcfe)	$	2.15	$	2.45

(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 $136,000 and $49,100 for the years ended December 31, 2012 and 2011, respectively.

Drilling Activity

We received total cash subscriptions from investors of $21,281,200, 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 $7,227,500. We have drilled 110 development wells within the Clinton/Medina and Upper Devonian Sandstones geological formations in Pennsylvania and Ohio. 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		107		103.15
Dry hole		3		3

Total wells drilled		110		106.15

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.

Natural gas liquids. NGL’s are extracted from the natural gas stream by processing and fractionation plants enabling the remaining “dry” gas (low BTU content) 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) regional processing hub. 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, 2012 and 2011, 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:

•

require the acquisition of various permits before drilling commences;

•

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 two-year period ended December 31, 2012, 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 2013, 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:

Waste Handling. The Solid Waste Disposal Act, including the Resource Conservation and Recovery Act, or 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 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.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, or 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”s). These new regulations impose additional emissions control requirements and practices on our operations. Some of our 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, or 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.

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 for 2012 no later than April 1, 2013. 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.

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 our 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.

State Regulation. 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, Michigan imposes a 5% severance tax on natural gas and a 6.6% severance tax on oil, Tennessee imposes a 3% severance tax on natural gas and oil production and Ohio imposes a severance tax of $0.025 per Mcf of natural gas and $0.10 per Bbl of oil, Indiana imposes a severance tax of $0.03 per Mcf on natural gas and $0.24 per Bbl of oil, Colorado imposes a severance tax up to 5% of the value of oil and gas severed from earth, in addition to other applicable taxes, while West Virginia imposes a 5% severance tax on oil and gas. 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 2012, the impact fee for qualifying unconventional horizontal wells spudded during 2012 was $45,000 per well, while the impact fee for unconventional vertical wells was reduced to twenty percent of the horizontal well fee. 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 a horizontal well and 10 years for a 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. 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. Texas imposes a severance tax of 7.5% on the market value of gas produced and saved and 4.6% on the market value of condensate and oil produced.

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, EPA is conducting a study that evaluates any potential impacts of hydraulic fracturing on drinking water and ground water. 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.

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 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.

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 and Oil Reserves

The following tables summarize information regarding our estimated proved natural gas and oil reserves as of December 31, 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 and oil reserves and future net revenues of natural gas and oil 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, 2012 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 and oil 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 within the prior 12-month period, and are listed below as of the dates indicated:


	December 31,
	2012		2011
Natural gas (per Mcf)	$	2.76	$	4.12
Oil (per Bbl)	$	94.71	$	96.19

Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas and oil reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production and the timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

The preparation of our natural gas and oil reserve estimates 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 Ohio and Pennsylvania. The independent reserves engineer’s evaluation was based on more than 36 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 Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 14 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by our senior engineering staff and management, with final approval by our Executive Vice President.

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 and oil 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 and oil 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,
	2012		2011
Proved reserves:
Natural gas reserves (Mcf)		891,900		1,848,100
Oil reserves (Bbl):		4,900		8,100

Total proved developed reserves (Mcfe)		921,300		1,896,700

Standardized measure of discounted future cash flows	$	469,278	$	2,058,477

Standardized measure of discounted future cash flows per Limited Partner Unit ⁽¹⁾	$	149	$	656

Undiscounted future cash flows per Limited Partner Unit	$	188	$	995

(1)

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

The following table sets forth information regarding productive natural gas and oil wells in which we have a working interest as of December 31, 2012. 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.


	Number of productive wells
	Gross		Net
Gas and/or oil wells		106		102.15

Total wells		106		102.15

Developed Acreage

The following table sets forth information about our developed natural gas and oil acreage as of December 31, 2012.


	Developed acreage
	Gross		Net
Pennsylvania		2,847.20		2,784.21
Ohio		541.99		541.99

Total		3,389.19		3,326.20

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 Note 9 of “Notes to the Financial Statements”).

ITEM 4:

MINE SAFETY DISCLOSURES (Not applicable)

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, 2012 we had 778 unitholders.

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, 2012 and 2011 we distributed the following:


	Distributions
	2012		2011
Limited Partners	$	237,500	$	611,000
Managing General Partner		44,500		257,000

Total distributions	$	282,000	$	868,000

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 Supplemental 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 #10 LTD, (“we”, “us”, or “the Partnership”) is a Pennsylvania limited partnership and formed on July 5, 2001 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.

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, 2012 our MGP had not withheld any funds for this purpose.

MARKETS AND COMPETITION

The availability of a ready market for natural gas and oil produced by us, and the price obtained, depends on numerous factors beyond our control, including the extent of domestic production, imports of foreign natural gas and oil, political instability or terrorist acts in oil and gas producing countries and regions, market demand, competition from other energy sources, the effect of federal regulation on the sale of natural gas and oil in interstate commerce, other governmental regulation of the production and transportation of natural gas and oil and the proximity, availability and capacity of pipelines and other required facilities. Our MGP is responsible for selling our production. During 2012 and 2011, 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. We market 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. The production area and pricing indexes are as follows: Appalachian Basin and Mississippi Lime, primarily the NYMEX spot market price; Barnett Shale and Marble Falls, primarily the Waha spot market price; New Albany Shale and Antrim Shale, primarily the Texas Gas Zone SL and Chicago Hub spot market prices; and Niobrara formation, primarily the Cheyenne Hub spot market price.

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 (low BTU content) 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) regional processing hub. 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, 2012, Chevron Natural Gas, Interstate Gas Supply, Inc., and Energymark LLC accounted for approximately 29%, 28%, and 16%, respectively, of our total natural gas and oil production revenues with no other single customer accounting for more than 10% for this period.

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, oil and NGL 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 AND OIL 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,
	2012			2011
Production revenues (in thousands):
Gas	$	736		$	1,341
Oil		69			99

Total	$	805		$	1,440
Production volumes:
Gas (mcf/day)		692			688
Oil (bbls/day)		2			3

Total (mcfe/day)		704			706
Average sales price:⁽¹⁾
Gas (per mcf) ⁽²⁾	$	3.44		$	5.53
Oil (per bbl)	$	91.94		$	88.78
Production costs:
As a percent of revenues		69	%		44	%
Per mcfe	$	2.15		$	2.45
Depletion per mcfe	$	1.42		$	2.30

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

(2)

Natural Gas Revenues. Our natural gas revenues were $736,300 and $1,341,400 for the years ended December 31, 2012 and 2011, respectively, a decrease of $605,100 (45%). The $605,100 decrease in natural gas revenues for the year ended December 31, 2012 as compared to the prior year period was attributable to a $615,800 decrease in natural gas prices after the effect of financial hedges, which were driven by market conditions, partially offset by a $10,700 increase in production volumes. Our production volumes increased to 692 mcf per day for the year ended December 31, 2012 from 688 mcf per day for the year ended December 31, 2011, an increase of 4 (1%) 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.

Oil Revenues. We drill wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $68,600 and $98,900 for the years ended December 31, 2012 and 2011, respectively, a decrease of $30,300 (31%). The $30,300 decrease in oil revenues for the year ended December 31, 2012 as compared to the prior year period was attributable to a $32,600 decrease in production volumes, partially offset by a $2,300 increase in oil prices after the effect of financial hedges. Our production volumes decreased to 2 bbls per day for the year ended December 31, 2012 from 3 bbls per day for the year ended December 31, 2011, a decrease of 1 bbls per day (33%).

Costs and Expenses. Production expenses were $553,700 and $631,900 for the years ended December 31, 2012 and 2011, respectively, a decrease of $78,200 (12%). This decrease was primarily due to a combination of a decrease in water disposal charges and lower transportation expenses. The lower disposal costs were due to decreases in negotiated rates along with a decrease in the amount of water produced. The transportation charges were affected by a decrease in production volumes.

Depletion of our oil and gas properties as a percentage of oil and gas revenues was 45% and 41% for the years ended December 31, 2012 and 2011, 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 $135,300 and $139,700 for the years ended December 31, 2012 and 2011, respectively, a decrease of $4,400 (3%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP and vary from period to period due to the timing and billing of the costs and services provided to us.

There was no impairment of proved oil and gas properties recorded by us for the year ended December 31, 2012. Impairment of oil and gas properties for the year ended December 31, 2011 was $2,480,900, net of an offsetting gain from accumulated other comprehensive income of $188,800. 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 recognized for the year ended December 31, 2011. 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 decreased $532,400 for the year ended December 31, 2012 to $279,800 as compared to $812,200 the year ended December 31, 2011. This decrease was due to a decrease in net earnings before depletion, impairment, and accretion of $741,800, a decrease in the change in accounts receivable-affiliate of $61,000, and a decrease in the change in accrued liabilities of $4,800, partially offset by a non-cash gain on derivative value of $275,200.

Cash provided by investing activities was $2,500 during the year ended December 31, 2011 from the sale of a well.

Cash used in financing activities decreased $556,200 to $282,000 for the year ended December 31, 2012, from $838,200 for the year ended December 31, 2011. This decrease was due to a decrease in cash distributions to partners.

Our MGP may withhold funds for future plugging and abandonment costs. Through December 31, 2012, 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 the year ended December 31, 2012. During the year ended December 31, 2011, we recognized $2,480,900 of asset impairment related to gas and oil properties, net of an offsetting gain from accumulated other comprehensive income of $188,800. This impairment related to the carrying amount of these gas and oil properties being in excess of our estimate of their fair value at December 31, 2011. 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.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include 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 year ended December 31, 2012. During the year ended December 31, 2011, we recognized a $2,480,900 asset impairment within natural gas and oil properties on our balance sheet, net of an offsetting gain from accumulated other comprehensive income of $188,800. This impairment relates to the carrying amount of these gas and oil properties being in excess of our estimate of their fair value at December 31, 2011. 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.

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.

ITEM 8:

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Atlas America Public #10 LTD.

We have audited the accompanying balance sheets of Atlas America Public #10 LTD. (a Pennsylvania limited partnership) (the “Partnership”) as of December 31, 2012 and 2011, and the related statements of operations, comprehensive income, changes in partners’ capital, and cash flows for the years ended December 31, 2012 and 2011. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our 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 #10 LTD. as of December 31, 2012 and 2011, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

April 1, 2013

ATLAS AMERICA PUBLIC #10 LTD.

BALANCE SHEETS

DECEMBER 31,


	2012			2011
ASSETS
Current assets:
Cash and cash equivalents	$	27,600		$	29,800
Accounts receivable trade–affiliate		208,400			244,900
Accounts receivable monetized gains-affiliate		64,200			140,200
Current portion of derivative asset		3,300			—

Total current assets		303,500			414,900
Oil and gas properties, net		3,550,200			3,947,900
Long-term receivable monetized gains-affiliate		13,800			91,700

	$	3,867,500		$	4,454,500

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	300		$	8,400

Total current liabilities		300			8,400
Asset retirement obligations		1,635,200			1,586,600
Long-term put premium payable—affiliate		5,100			—
Commitments and contingencies		—			—
Partners’ capital:
Managing general partner’s interest		635,700			695,100
Limited partners’ interest (2,135 units)		1,602,900			2,155,900
Accumulated other comprehensive (loss) income		(11,700	)		8,500

Total partners’ capital		2,226,900			2,859,500

	$	3,867,500		$	4,454,500

See accompanying notes to financial statements.

ATLAS AMERICA PUBLIC #10 LTD.

STATEMENTS OF OPERATIONS

YEARS ENDED DECEMBER 31, 2012 AND 2011


	2012			2011
REVENUES
Gas and oil production	$	804,900		$	1,440,300
Interest		—			200

Total revenues		804,900			1,440,500
COST AND EXPENSES
Production		553,700			631,900
Depletion		365,500			594,400
Asset impairment		—			2,480,900
Accretion		80,800			83,800
General and administrative		135,300			139,700

Total expenses		1,135,300			3,930,700

Net loss	$	(330,400	)	$	(2,490,200	)

Allocation of net loss:
Managing general partner	$	(14,900	)	$	(210,000	)

Limited partners	$	(315,500	)	$	(2,280,200	)

Net loss per limited partnership unit	$	(148	)	$	(1,068	)

See accompanying notes to financial statements.

ATLAS AMERICA PUBLIC #10 LTD.

STATEMENTS OF COMPREHENSIVE LOSS

YEARS ENDED DECEMBER 31, 2012 AND 2011


	2012			2011
Net loss	$	(330,400	)	$	(2,490,200	)
Other comprehensive loss:
Changes in fair value of derivative instruments accounted for as cash flow hedges:
Unrealized holding (loss) gain on hedge contracts		(8,400	)		26,600
MGP portion of non-cash loss on hedge instruments		—			29,800
Difference in estimated hedge gains receivable		6,900			(235,300	)
Less: reclassification adjustment for realized gains in net loss		(18,700	)		(300,400	)

Total other comprehensive loss		(20,200	)		(479,300	)

Comprehensive loss	$	(350,600	)	$	(2,969,500	)

See accompanying notes to financial statements.

ATLAS AMERICA PUBLIC #10 LTD.

STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

YEARS ENDED DECEMBER 31, 2012 AND 2011


							Accumulated
	Managing						Other
	General			Limited			Comprehensive
	Partner			Partners			Income (Loss)			Total
Balance at December 31, 2010	$	1,162,100		$	5,047,100		$	487,800		$	6,697,000
Participation in revenue and costs and expenses:
Net production revenues		207,600			600,800			—			808,400
Interest income		100			100			—			200
Depletion		(80,800	)		(513,600	)		—			(594,400	)
Impairment of oil and gas properties		(265,300	)		(2,215,600	)		—			(2,480,900	)
Accretion		(26,900	)		(56,900	)		—			(83,800	)
General and administrative		(44,700	)		(95,000	)		—			(139,700	)

Net (loss) income		(210,000	)		(2,280,200	)		—			(2,490,200	)
Other comprehensive loss		—			—			(479,300	)		(479,300	)
Distributions to partners		(257,000	)		(611,000	)		—			(868,000	)

Balance at December 31, 2011	$	695,100		$	2,155,900		$	8,500		$	2,859,500
Participation in revenue and costs and expenses:
Net production revenues		86,800			164,400			—			251,200
Depletion		(32,500	)		(333,000	)		—			(365,500	)
Accretion		(25,900	)		(54,900	)		—			(80,800	)
General and administrative		(43,300	)		(92,000	)		—			(135,300	)

Net (loss) income		(14,900	)		(315,500	)		—			(330,400	)
Other comprehensive loss		—			—			(20,200	)		(20,200	)
Distributions to partners		(44,500	)		(237,500	)		—			(282,000	)

Balance at December 31, 2012	$	635,700		$	1,602,900		$	(11,700	)	$	2,226,900

See accompanying notes to financial statements.

ATLAS AMERICA PUBLIC #10 LTD.

STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2012 AND 2011


	2012			2011
Cash flows from operating activities:
Net loss	$	(330,400	)	$	(2,490,200	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion and amortization		365,500			594,400
Asset impairment		—			2,669,700
Non-cash loss on derivative value, net		135,500			(139,700	)
Accretion		80,800			83,800
Changes in operating assets and liabilities:
Decrease in accounts receivable		36,500			97,500
Decrease in accrued liabilities		(8,100	)		(3,300	)

Net cash provided by operating activities		279,800			812,200
Cash flows from investing activities:
Proceeds from sale of a well		—			2,500

Net cash provided by investing activities		—			2,500
Cash flows from financing activities:
Distributions to partners		(282,000	)		(838,200	)

Net cash used in financing activities		(282,000	)		(838,200	)

Net change in cash and cash equivalents		(2,200	)		(23,500	)
Cash and cash equivalents at beginning of period		29,800			53,300

Cash and cash equivalents at end of period	$	27,600		$	29,800

Supplemental schedule of non-cash investing and financing activities:
Asset retirement obligation revision	$	(32,200	)	$	106,100

Distribution to Managing General Partner	$	—		$	29,800

See accompanying notes to financial statements.

ATLAS AMERICA PUBLIC #10 LTD.

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2012 AND 2011

NOTE 1 — BASIS OF PRESENTATION

Atlas America Public #10 LTD (the “Partnership”) is a Pennsylvania limited partnership formed on July 5, 2001 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 Resources Partners (“ARP”) (NYSE: ARP) an independent developer and producer of natural gas, crude oil and natural gas liquids with operations in basins across the United States. The MGP sponsors and manages tax-advantaged investment partnerships, in which it coinvests, to finance a portion of its natural gas and oil production activities. ARP’s parent company is Atlas Energy, L.P. (“ATLS”), a publicly traded master-limited partnership (NYSE: ATLS). ARP was formed in October 2011 to own and operate substantially all of ATLS’ exploration and production assets, which were transferred to ARP on March 5, 2012.

On February 17, 2011, 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, 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”).

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 ultimate parent company, ATLS 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 third-party gas gathering systems. The Partnership does not plan to sell any of the 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.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

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 realizability 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, 2012 and 2011, the Partnership had recorded no allowance for uncollectible accounts receivable on its balance sheets.

Natural Gas and Oil Properties

Natural gas and oil properties are stated at cost. Maintenance and repairs which 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 which 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. Developments costs, whether successful or not, are capitalized. Oil and NGLs are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to 6 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 leasehold 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 costs of developed producing properties.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated 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 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 for 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 gas and oil properties recorded for the year ended December 31, 2012. During the year ended December 31, 2011, the Partnership recognized $2,480,900 of asset impairments related to gas and oil properties, net of an offsetting gain from accumulated other comprehensive income of $188,800. This impairment relates to the carrying amount of the gas and oil properties being in excess of the Partnership’s estimate of their fair value at December 31, 2011. 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, 2012 and 2011.

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 year ended December 31, 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, 2012, the Partnership had three customers that individually accounted for approximately 29%, 28%, and 16%, respectively, of the Partnership’s natural gas and oil combined revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2011, the Partnership had four customers that individually accounted for approximately 17%, 17%, 14%, and 13%, respectively, of the Partnership natural gas and oil 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 2 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, 2012 and 2011 of $158,300 and $176,900, respectively, which were included in accounts receivable 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 accounting principles generally accepted in the United States, 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 January 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“Update 2013-01”). Update 2013-1 clarifies that ordinary trade receivables and receivables are not in the scope of ASU No. 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 (“Codification”) or subject to a master netting arrangement or similar agreement. Entities are required to implement the amendments for interim and annual reporting periods beginning after January 1, 2013 and such amendments shall be applied retrospectively for any period presented that begins before the date of initial 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.

In August 2012, the FASB issued ASU 2012-03, Technical Amendments and Corrections to SEC Sections: Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 114, Technical Amendments Pursuant to SEC Release No. 33-9250, and Corrections Related to FASB Accounting Standards Update 2010-22 (SEC Update) (“Update 2012-03”). Update 2012-03 codified amendments and corrections to the ASC for various Securities and Exchange Commission (“SEC”) paragraphs pursuant or related to 1) the issuance of Staff Accounting Bulletin (“SAB”) 114; 2) the SEC’s Final Rule, Technical Amendments to Commission Rules and Forms Related to the FASB’s Accounting Standards Codification, Release No. 3350-9250, 34-65052, and IC-29748 August 8, 2011; 3) ASU 2010-22, Accounting for Various Topics—Technical Corrections to SEC Paragraphs (SEC Update); and 4) other various status sections. The Partnership adopted the requirements of Update 2012-03 on September 30, 2012, and it did not have a material impact on its financial position, results of operations or related disclosures.

In December 2011, the FASB issued ASU 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (“Update 2011-12”). The amendments in this update effectively defer the implementation of the changes made in Update 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income (“Update 2011-05”), related to the presentation of reclassification adjustments out of accumulated other comprehensive income. Under Update 2011-05 which was issued by the FASB in June 2011, entities are provided the option to present the total of comprehensive income, the components of net income and the components of other comprehensive income in either a single continuous statement of comprehensive income or in two separate but consecutive statements. Under each methodology, an entity is required to present each component of net income along with a total net income, each component of other comprehensive income and a total amount for comprehensive income. Update 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of changes in equity. As a result of Update 2011-12, entities are required to disclose reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect prior to Update 2011-05. All other requirements in Update 2011-05 are not affected by Update 2011-12. These requirements are effective for interim and annual reporting periods beginning after December 15, 2011. Accordingly, entities are not required to comply with presentation requirements of Update 2011-05 related to the disclosure of reclassifications out of accumulated other comprehensive income. The Partnership included statements of comprehensive income (loss) within its March 31, 2012 Form 10-Q upon the adoption of these ASUs on January 1, 2012. The adoption had no material impact on the Partnership’s financial condition or results of operations.

In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosure about Offsetting Assets and Liabilities (“Update 2011-11”). The amendments in this update require an entity to disclose both gross and net information about both financial and derivative instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the statement of financial position. An entity shall disclose at the end of a reporting period certain quantitative information separately for assets and liabilities that are within the scope of Update 2011-11, as well as provide a description of the rights of setoff associated with an entity’s recognized assets and recognized liabilities subject to an enforceable master netting arrangement or similar agreement. Entities are required to implement the amendments for interim and annual reporting periods beginning after January 1, 2013 and such amendments shall be applied retrospectively for any period presented that begins before the date of initial application. The Partnership elected to early adopt these requirements and updated its disclosures to meet these requirements effective January 1, 2012 (see Note 6). The adoption had no material impact on the Partnership’s financial position or results of operations.

In May 2011, the FASB issued ASU 2011-04, Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“Update 2011-04”). The amendments in Update 2011-04 revise the wording used to describe many of the requirements for measuring fair value and for disclosing information about fair value measurements in U.S. GAAP. For many of the amendments, the guidance is not necessarily intended to result in a change in the application of the requirements in Topic 820; rather it is intended to clarify the intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. As a result, Update 2011-04 aims to provide common fair value measurement and disclosure requirements in U.S. GAAP and International Financial Reporting Standards. These requirements are effective for interim and annual reporting periods beginning after December 15, 2011. The Partnership updated its disclosures to meet these requirements upon the adoption of Update 2011-04 on January 1, 2012 (see Note 7). The adoption had no material impact on the Partnership’s financial position or results of operations.

Recently Issued Accounting Standards

In February 2013, the FASB issued ASU No. 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 will apply the requirements of Update 2013-02 upon its effective date of January 1, 2013, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

NOTE 3 — PARTICIPATION IN REVENUES AND COSTS

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


	Managing
	General			Limited
	Partner			Partners
Organization and offering cost		100	%		0	%
Lease costs		100	%		0	%
Revenues ⁽¹⁾		32	%		68	%
Operating costs, administrative costs, direct and all other costs ⁽²⁾		32	%		68	%
Intangible drilling costs		0	%		100	%
Tangible equipment costs		66	%		34	%

(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,
	2012			2011
Proved properties:
Leasehold interests	$	335,300		$	335,300
Wells and related equipment		25,500,300			25,532,500

Total natural gas and oil properties		25,835,600			25,867,800

Less – accumulated depletion and impairment		(22,285,400	)		(21,919,900	)

Oil and gas properties, net	$	3,550,200		$	3,947,900

The Partnership recorded depletion expense on natural gas and oil properties of $365,500 and $594,400 for the years ended December 31, 2012 and 2011, 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 oil and gas properties recorded by us for the year ended December 31, 2012. During the year ended December 31, 2011, the Partnership recognized $2,669,700 of asset impairment related to oil and gas properties on its balance sheet. This impairment relates to the carrying amount of these oil and gas properties being in excess of the Partnership’s estimate of their fair value at December 31, 2011. 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.

NOTE 5 — ASSET RETIREMENT OBLIGATIONS

The Partnership recognized an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities. The Partnership also recognized a liability for its 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 estimated liability was based on the Partnership’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 was discounted using the 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. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its gas and oil properties, the Partnership determined that there were no other material retirement obligations associated with tangible long-lived assets.

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


	Years Ended December 31,
	2012			2011
Asset retirement obligations, beginning of year	$	1,586,600		$	1,396,700
Accretion expense		80,800			83,800
Revisions		(32,200	)		106,100

Asset retirement obligations, end of year	$	1,635,200		$	1,586,600

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 their 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 the Partnership’s hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity derivative contracts to the forecasted transactions. The MGP assesses, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the Partnership will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by management of the Partnership through the utilization of market data, will be recognized immediately 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, management recognized changes in fair value within gain 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 $17,100 at December 31, 2012, net of monetized gains receivable.

The following table summarizes the gross fair values of the Partnership’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Partnership’s balance sheets for the periods indicated:


	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheets			Net Amount of Assets Presented in the Balance Sheets
Offsetting Derivative Assets
As of December 31, 2012
Accounts receivable monetized gains-affiliate	$	70,500	$	(6,300	)	$	64,200
Long-term receivable monetized gains-affiliate		14,100		(14,100	)		—

Total derivative assets	$	84,600	$	(20,400	)	$	64,200

As of December 31, 2011
Accounts receivable monetized gains-affiliate	$	140,200	$	—		$	140,200
Long-term receivable monetized gains-affiliate		91,700		—			91,700

Total derivative assets	$	231,900	$	—		$	231,900


	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheets		Net Amount of Liabilities Presented in the Balance Sheets
Offsetting Derivative Liabilities
As of December 31, 2012
Put premiums payable-affiliate	$	(6,300	)	$	6,300	$	—
Long-term put premiums payable-affiliate		(19,200	)		14,100		(5,100	)

Total derivative liabilities	$	(25,500	)	$	20,400	$	(5,100	)

As of December 31, 2011
Put premiums payable-affiliate	$	—		$	—	$	—
Long-term put premiums payable-affiliate		—			—		—

Total derivative liabilities	$	—		$	—	$	—

The following table summarizes the gain or loss recognized in the Partnership’s statements of operations and statements of comprehensive loss for effective derivative instruments for the periods indicated:


	Years Ended December 31,
	2012			2011
(Loss) gain recognized in accumulated OCI	$	(8,400	)	$	26,600
Gain reclassified from accumulated OCI into loss	$	18,700		$	300,400

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 New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the 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.

The Partnership recognized gains of $18,700 and $300,400 for the years ended December 31, 2012 and 2011, respectively, on settled contracts covering commodity production. These gains were included within gas and oil production revenue in the Partnership’s statements of operations. As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the years ended December 31, 2012 and 2011 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

At December 31, 2012, the Partnership had the following commodity derivatives:

Natural Gas Put Options


Production Period Ending December 31,	Option Type	Volumes		Average Fixed Price		Fair Value Asset ⁽²⁾
		(MMBtu)⁽¹⁾		(per MMBtu)⁽¹⁾
2013	Puts purchased		13,400	$	3.45	$	3,400
2014	Puts purchased		11,100		3.80		4,200
2015	Puts purchased		8,900		4.00		4,200
2016	Puts purchased		8,900		4.15		5,300

						$	17,100

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

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

Prior to its merger with Chevron on February 17, 2011, 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 which were specifically related to the future natural gas and oil production of the Partnership. At December 31, 2012 and 2011, remaining hedge monetization cash proceeds of $70,500 and $140,200 related to the amounts hedged on behalf of the Partnerships’ limited partners were included within accounts receivable monetized gains-affiliate, respectively, and $14,100 and $91,700 in long term accounts receivable monetized gains-affiliate, respectively, on the Partnership’s balance sheet. The Partnership will allocate the monetization 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, 2012, the put premiums were recorded as short-term and long-term payables to affiliate of $6,300 and $19,200, respectively. Furthermore, the short-term put premium liabilities were included in accounts receivable monetized gains-affiliate and the long-term receivable monetized gains-affiliate were included in long-term liability affiliate on the Partnership’s balance sheet. The put premiums included on the Partnership’s balance sheet are allocable to the limited partners only.

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 sheet in accumulated other comprehensive loss of $11,700 as of December 31, 2012. Included in other comprehensive loss are unrealized losses of $74,700 and $13,200, net of the MGP interest, that were recognized into income as a result of oil and gas property impairments during the year ended December 31, 2011 and prior periods, respectively. In 2011, the MGP’s portion of the unrealized loss, $29,800, was written-off as part of the terms of the acquisition of the Transferred Business as a non-cash distribution to the MGP. Of the remaining $11,700 of net unrealized loss in accumulated other comprehensive loss, the Partnership will reclassify $5,800 of net losses to the Partnership’s statements of operations over the next twelve month period and the remaining $5,900 in later periods.

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.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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, 2012 and 2011 was as follows:


	Level 1		Level 2		Level 3		Total
As of December 31, 2012
Derivative assets, gross
Commodity puts	$	—	$	17,100	$	—	$	17,100

Total derivative assets, gross		—		17,100		—		17,100

Derivative liabilities, gross
Commodity puts		—		—		—		—

Total derivative liabilities, gross		—		—		—		—

Total derivatives, fair value, net	$	—	$	17,100	$	—	$	17,100

As of December 31, 2011
Derivative assets, gross
Commodity puts	$	—	$	—	$	—	$	—

Total derivative assets, gross		—		—		—		—

Derivative liabilities, gross
Commodity puts		—		—		—		—

Total derivative liabilities, gross		—		—		—		—

Total derivatives, fair value, net	$	—	$	—	$	—	$	—

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. Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the years ended December 31, 2012 and 2011 were as follows:


	Years Ended December 31,
	2012						2011
	Level 3			Total			Level 3		Total
Asset retirement obligations	$	(32,200	)	$	(32,200	)	$	106,100	$	106,100

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. For the year ended December 31, 2011, the Partnership recognized a $2,669,700 impairment of long-lived assets which was defined as a Level 3 fair value measurement (see Note 2 – Impairment of Long-Lived Assets). No impairments were recognized for the year ended December 31, 2012 (see Note 5).

NOTE 8 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

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

•

Administrative costs, which are included in general and administrative expenses in the Partnership’s statements of operations, are payable at $75 per well per month. Administrative costs incurred for the years ended December 31, 2012 and 2011 were $76,600 and $81,400, respectively.

•

Monthly well supervision fees, which are included in production expenses in the Partnership’s statements of operations, are payable at $329 per well per month for the operating and maintaining the wells. Well supervision fees incurred for the years ended December 31, 2012 and 2011 were $335,500 and $356,800, respectively.

•

Transportation fees, which are included in production expenses in the Partnership’s statements of operations, incurred for the years ended December 31, 2012 and 2011 were $107,400 and $169,300, respectively.

•

Direct costs, which are included in production and general administrative expenses in the Partnership’s statements of operations, are payable to the MGP and its affiliates as reimbursement for all costs expended on the Partnership’s behalf. Direct costs incurred for the years ended December 31, 2012 and 2011 were $169,500 and $164,100, respectively.

•

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

Subordination by Managing General Partner

•

Under the terms of the Partnership Agreement, the MGP may be required to subordinate up to 50% of its share of net production revenues so that the limited partners receive a return of at least 10% of their net subscriptions, determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution to the investor partners (April 2002) and expiring 60 months from that date.

NOTE 9 — COMMITMENTS AND CONTINGENCIES

General Commitments

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

Beginning one year after each of the Partnership’s wells has been placed into production, the MGP, as operator, may retain $200 per month per well to cover estimated future plugging and abandonment costs. As of December 31, 2012, the MGP has not withheld any such funds.

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.

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 its 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 #10 LTD. annual Form 10-K for the years ended December 31, 2012 and 2011 (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 Ohio and Pennsylvania. The independent reserves engineer’s evaluation was based on more than 35 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. The Partnership’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 Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 14 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by the Partnership’s senior engineering staff and management, with final approval by the Partnership’s Executive Vice President.

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, 2012, and 2011 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, 2012 and 2011 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, 2010		2,177,800			9,200
Revisions⁽¹⁾		(78,500	)		—
Production		(251,200	)		(1,100	)

Balance, December 31, 2011		1,848,100			8,100
Revisions ⁽²⁾		(703,000	)		(2,500	)
Production		(253,200	)		(700	)

Balance, December 31, 2012		891,900			4,900

(1)	The change in the 2011 natural gas reserves was due to actual production being less than engineering forecasts.

(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.

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,
	2012			2011
Natural gas and oil properties:
Leasehold interest	$	335,300		$	335,300
Wells and related equipment		25,500,300			25,532,500

Accumulated depletion, accretion and impairment⁽¹⁾		(22,285,400	)	$	(21,919,900	)

Net capitalized costs	$	3,550,200		$	3,947,900

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,
	2012			2011
Revenues	$	804,900		$	1,440,300
Production costs		(553,700	)		(631,900	)
Depletion and amortization		(365,500	)		(594,400	)
Long-lived asset impairment		—			(2,480,900	)

	$	(114,300	)	$	(2,266,900	)

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, 2012 and 2011, 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,
	2012			2011
Future cash inflows	$	3,141,200		$	9,119,200
Future production costs		(2,549,500	)		(5,994,900	)

Future net cash flows		591,700			3,124,300
Less 10% annual discount for estimated timing of cash flows		(122,400	)		(1,065,800	)

Standardized measure of discounted future net cash flows	$	469,300		$	2,058,500

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, 2012, 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 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 2012 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.

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.

The following table sets forth information as of February 15, 2013 with respect to those persons who serve as the officers of our general partner:


Name	Age	Position(s)
Sean P. McGrath	41	Chief Financial Officer
Freddie M. Kotek	57	Senior Vice President of Investment Partnership Division
Jeffrey C. Simmons	54	Senior Vice President of Operations
Jack Hollander	56	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.

Jeffrey C. Simmons has served as Senior Vice President of Operations of our general partner since March 2012. Mr. Simmons has been a Senior Vice President of Atlas Energy Management, Inc. since 2006. Mr. Simmons was a director of Atlas America, LLC from January 2002 until February 2004. Mr. Simmons was a Vice President of Resource America from April 2001 until May 2004. Mr. Simmons served as Vice President of Operations for Atlas Resources, LLC from July 1999 until December 2000 and for Atlas America, LLC from 1998 until December 2000. Mr. Simmons joined Resource America in 1986 as a senior petroleum engineer and has served in various executive positions with its energy subsidiaries since then.

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

Code of Business Conduct and Ethics

Because the Partnership does not directly employ any persons, the MGP has determined that he 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, 2012, we had 2,135 units outstanding. Mr. Jack Hollander, an officer of our MGP owns .50 units, which equals a partnership interest of .016%. No other officer or director of our MGP owns any units. Although, subject to certain conditions, investor partners may present their units to us beginning in 2014 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 32% 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 66% 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 $7,227,500. During the years ended December 31, 2012 and 2011, our MGP received $86,800 and $207,600, respectively, for our net production revenues.

Administrative Costs. Our MGP and its affiliates receive an unaccountable, fixed fee reimbursement for the administrative costs they incur on our behalf of $75 per well per month, which is proportionately reduced to the extent we acquired less than 100% of the working interest in a well. During the years ended December 31, 2012 and 2011, our MGP received $76,600 and $81,400, respectively, for administrative costs.

Direct Costs. Our MGP and its affiliates are reimbursed by us for all direct costs expended by them on our behalf. During the years ended December 31, 2012 and 2011, our MGP was reimbursed $169,500 and $164,100, respectively, for direct costs.

Well Charges. Our MGP, as operator of our wells, is reimbursed at actual cost for all direct expenses incurred on our behalf and receives well supervision fees for operating and maintaining the wells during producing operations in the amounts of $329 per well per month subject to an annual adjustment for inflation. The well supervision fees are proportionately reduced to the extent we acquire less than 100% of the working interest in a well. For the years ended December 31, 2012 and 2011, our MGP received $335,500 and $356,800, respectively, for well supervision fees.

Transportation Fees. We pay gathering fees to our MGP at a competitive rate for each mcf of our natural gas transported. For the years ended December 31, 2012 and 2011, $107,400 and $169,300, respectively, was paid to our MGP for gathering fees. In turn, our MGP remitted 100% of these amounts to Atlas Energy, who in turn paid LMM for the use of LMM’s gathering system in transporting a majority of our natural gas production.

Other Compensation. For the years ended December 31, 2012 and 2011, our MGP did not advance any funds to us, or did it provide us with any equipment, supplies or other services.

ITEM 14:

PRINCIPAL ACCOUNTANT FEES AND SERVICES

For the years ended December 31, 2012 and 2011, the accounting fees and services charged by Grant Thornton, LLP, our independent auditors, were as follows:


	Years Ended December 31,
	2012		2011
Audit fees	$	33,600	$	34,500

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 2012 and 2011.

PART IV

ITEM 15:

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

EXHIBIT INDEX


	Description	Location

4(a)	Certificate of Limited Partnership for Atlas America Public 10 LTD.	Previously filed in our Form SB-2/A on October 26, 2001

4(b)	Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public 10 LTD.	Previously filed in our Form SB-2/A on October 26, 2001

4(c)	Drilling and Operating Agreement for Atlas America Public 10 LTD.⁽¹⁾	Previously filed in our Form SB-2/A on October 26, 2001

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 August 14, 2001 in the Form S-1 Registration Statement dated August 14, 2001, File No. 333-67522

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: April 1, 2013				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.

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company