Atlas Resources Series 28-2010 10-12G Registration of securities

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10

GENERAL FORM FOR REGISTRATION OF SECURITIES

Pursuant to Section 12(b) or (g) of the Securities Exchange Act of 1934

ATLAS RESOURCES SERIES 28-2010 L.P.

(Exact Name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization) 27-2101952
(I.R.S. Employer
Identification Number)

Westpointe Corporate Center One
1550 Coraopolis Heights Road, Suite 300
Moon Township, Pennsylvania	15108
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code:
(412) 262-2830

Securities to be registered pursuant to Section 12(b) of the Act:
None

Securities to be registered pursuant to Section 12(g) of the Act:
Units⁽¹⁾
(Title of Class)

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

Large Accelerated Filero	Accelerated Filero	Non-Accelerated Filero	Smaller Reporting Companyþ
		(Do not check if a smaller reporting company)

⁽¹⁾ Units means limited partner Units, converted limited partner Units and investor general partner Units, which will be automatically converted into the converted limited partner Units by our managing general partner once all of our wells are drilled and completed.

Item 1 Business	1
General	1
Employees	1
Our Offering	1
Investment Objectives	3
Oil and Natural Gas Properties	4
Production	5
Sale of Natural Gas and Oil Production	5
Major Customers	9
Competition	9
Markets	9
Governmental Regulation	9
Regulation of Production	9
Regulation of Transportation and Sale of Natural Gas	10
Crude Oil Regulation	10
State Regulation	11
Environmental Regulation	11
Dismantlement, Restoration, Reclamation and Abandonment Costs	12
Item 1A Risk Factors	12
Risks Relating to Our Business	12
Natural Gas and Oil Prices are Volatile and a Substantial Decrease in Prices, Particularly Natural Gas Prices, Would Decrease Our Revenues, Our Cash Distributions and the Value of Our Properties and Could Reduce Our Managing General Partner’s Ability to Loan Us Funds; Meet Its Ongoing Obligations to Indemnify Our Investor General Partners and Purchase Units Under Our Presentment Feature	12
Estimates of Our Natural Gas and Oil Reserves are Based on Many Assumptions that May Prove to be Inaccurate. Any Material Inaccuracies in these Underlying Assumptions Will Materially Affect the Quantities and Present Value of Our Reserves	14
Our Managing General Partner Has Limited Experience in Drilling Horizontal Wells to the Marcellus Shale and Horizontal Wells are More Expensive and Difficult to Drill and Complete Than Vertical Wells	15
Drilling Our Wells Requires Adequate Sources of Water to Facilitate the Fracturing Process and Our Production Operations Result in Removing Water from Our Wells that We Must Dispose Of. If We are Unable to Dispose of the Water We Remove from a Well at a Reasonable Cost and Within Applicable Environmental Rules, Our Ability to Produce Natural Gas from the Well Could Be Impaired	15
Drilling Wells is Highly Speculative and Some of Our Wells Are Nonproductive or May Be Productive, But Fail to Return the Costs of Drilling and Operating Them	15
The Drilling of Some of Our Wells Could Be Curtailed, Delayed or Cancelled If Unexpected Events Occur	16
If Third-Parties Participating in Drilling Some of Our Wells Fail to Pay Their Share of the Well Costs, We Would Have to Pay Those Costs in Order to Get the Wells Drilled, and If We Are Not Reimbursed the Increased Costs Would Reduce Our Cash Flow and Possibly Could Reduce the Number of Wells We Can Drill	17

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Risks Related to an Investment in Us	17
Our Managing General Partner’s Management Obligations to Us Are Not Exclusive, and if It Does Not Devote the Necessary Time to Our Management There Could Be Delays in Providing Timely Reports and Distributions to Our Participants, and Our Managing General Partner, Serving as Operator of Our Wells, May Not Supervise the Wells Closely Enough	17
Current Conditions May Change and Reduce Our Proved Reserves, Which Could Reduce Our Revenues	17
Government Regulation of the Oil and Natural Gas Industry is Stringent and Could Cause Us to Incur Substantial Unanticipated Costs for Regulatory Compliance, Environmental Remediation of Our Well Sites (Which May Not Be Fully Insured) and Penalties, and Could Delay or Limit Our Drilling Operations	18
Our Natural Gas and Oil Activities Are Subject to Drilling and Operating Hazards Which Could Result in Substantial Losses to Us	20
Our Total Annual Cash Distributions During Our First Five Years May be Less than $10,000 Per Unit, Even With Subordination	20
Our Limited Operating History Creates Greater Uncertainty Regarding Our Ability to Operate Profitably	20
Competition May Reduce Our Revenues from the Sale of Our Natural Gas	21
We May Have to Replace Our Natural Gas Purchasers and Receive a Lower Price for Our Natural Gas	21
We Could Incur Delays in Receiving Payment, or Substantial Losses if Payment is Not Made, for Natural Gas We Previously Delivered to a Purchaser, Which Could Delay or Reduce Our Revenues and Cash Distributions	21
We Intend to Produce Natural Gas and/or Oil from Our Wells Until They Are Depleted, Regardless of Any Changes in Current Conditions, Which Could Result in Lower Returns to Our Participants as Compared With Other Types of Investments Which Can Adapt to Future Changes Affecting Their Portfolios	22
Since Our Managing General Partner Is Not Contractually Obligated to Loan Funds to Us, We Could Have to Curtail Operations or Sell Properties if We Need Additional Funds and Our Managing General Partner Does Not Make a Loan to Us	22
Future Hedging Activities We Anticipate Undertaking May Adversely Affect Our Financial Situation and Results of Operations	22
Increases in Prices for Natural Gas and Oil Could Result in Non-Cash Balance Sheet Reductions Due to the Accounting Treatment of Derivative Contracts We Expect to Enter Into in the Future	23
A Decrease in Natural Gas Prices Could Subject Our and Our Managing General Partner’s Oil and Gas Properties to an Impairment Loss under Generally Accepted Accounting Principles	23
Federal Income Tax Risks	24
Changes in the Law May Reduce Our Participant’s Tax Benefits From an Investment in Us	24
Our Participants’ Deduction for Intangible Drilling Costs May be Limited for Purposes of the Alternative Minimum Tax	24
Our Limited Partners Need Passive Income to Use Their Deduction for Intangible Drilling Costs	24
Our Participants May Owe Taxes in Excess of Their Cash Distributions from Us	24
Investment Interest Deductions of Investor General Partners May be Limited	25
Our Participants’ Tax Benefits from an Investment in Us Are Not Contractually Protected	25

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An IRS Audit of Us May Result in an IRS Audit of the Personal Federal Income Tax Returns of Our Participants	25
Our Deductions May be Challenged by the IRS	25
Item 2 Financial Information	26
Selected Financial Data	26
Forward Looking Statements	27
Results of Operations	28
Liquidity and Capital Resources	28
Critical Accounting Policies	29
Use of Estimates	29
Reserve Estimates	29
Impairment of Oil and Gas Properties	29
Dismantlement, Restoration, Reclamation and Abandonment Costs	30
Commodity Price Risk	30
Item 3 Properties	31
Drilling Activity	31
Summary of Productive Wells	31
Production	32
Natural Gas and Oil Reserve Information	32
Title to Properties	34
Acreage	34
Item 4 Security Ownership of Certain Beneficial Owners and Management	35
Item 5 Directors and Executive Officers	35
Managing General Partner	35
Organizational Diagram and Security Ownership of Beneficial Owners	38
Officers and Directors of Managing General Partner	40
Atlas Energy, L.P. (“Atlas Energy”), a Delaware Limited Partnership	43
Atlas Energy Holdings Operating Company, LLC (“Atlas Energy Holdings”), a Delaware Limited Liability Company	45
Remuneration of Officers and Directors	45
Code of Business Conduct and Ethics	45
Transactions with Management and Affiliates	45
Item 6 Executive Compensation (Omitted)
Item 7 Certain Relationships and Related Transactions	46
Oil and Gas Revenues	47
Financial	47
Leases	47
Administrative Costs	47
Direct Costs	47

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Drilling Contracts	47
Per Well Charges	48
Gathering Fees	48
Dealer-Manager Fees	48
Organization and Offering Costs	48
Other Compensation	48
Item 8 Legal Proceedings	48
Item 9 Market Price of and Dividends on the Registrant’s Common Equity and Related Stockholder Matters	49
Item 10 Recent Sales of Unregistered Securities	49
Item 11 Description of Registrant’s Securities to be Registered	50
General	50
Liability of Participants for Further Calls and Conversion	50
Distributions and Subordination	51
Participant Allocations	52
Term, Dissolution and Distributions on Liquidation	52
Transferability	53
Presentment Feature	54
Voting Rights and Amendments	55
Books and Records	56
Restrictions on Roll-Up Transactions	56
Withdrawal of the Managing General Partner	58
Item 12 Indemnification of Directors and Officers	58
Item 13 Financial Statements and Supplementary Data	59
Item 14 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	80
Item 15 Financial Statements and Exhibits	80
Exhibit 4.1
Exhibit 4.2
Exhibit 10.1
Exhibit 10.2
Exhibit 10.3
Exhibit 10.4
Exhibit 10.5
Exhibit 10.6
Exhibit 10.7
Exhibit 10.8
Exhibit 10.9

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ITEM 1. BUSINESS.

The following discussion contains forward-looking statements regarding events and financial trends that may affect our future operating results and financial position. These statements are subject to risks and uncertainties that could cause our actual results and financial position to differ materially from the results anticipated in those statements. These risks include risks associated with drilling and operating our wells, marketing natural gas and oil production from the wells, and fluctuations in market prices for the natural gas and oil produced from the wells. For a more complete discussion of the risks and uncertainties to which we are subject, See “Risk Factors” in Item 1A. The terms “we,” “our,” and “us” used in this Form 10 are used as references to Atlas Resources Series 28-2010 L.P.

General

We were formed as a Delaware limited partnership on March 12, 2010, with Atlas Resources, LLC, a Pennsylvania limited liability company, as our managing general partner. We are filing this General Form for Registration of Securities on Form 10 to register our Units pursuant to Section 12(g) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). We are subject to the registration requirements of Section 12(g) because at the end of our first fiscal year on December 31, 2010, the aggregate value of our assets exceeded the applicable threshold of $10 million and our Units of record were held by more than 500 persons. Because of our obligation to register our Units with the Securities and Exchange Commission (the “SEC”) under the Exchange Act, we will be subject to the requirements of the Exchange Act rules and we intend to file:

• quarterly reports on Form 10-Q;

• annual reports on Form 10-K;

• current reports on Form 8-K; and

otherwise comply with the disclosure obligations of the Exchange Act applicable to issuers filing registration statements pursuant to Section 12(g) of the Exchange Act.

Employees. We have no employees. Instead, we rely on our managing general partner for management services, and our managing general partner relies on its indirect parent company, Atlas Energy, L.P. (“Atlas Energy”), and its affiliates for management and administrative services and financing for capital expenditures. See Item 5 “Directors and Executive Officers.”

Our Offering. Our offering was conducted in reliance on the exemption from registration provided by Rule 506 under Regulation D and Section 4(2) of the Securities Act. All of our participants were reasonably believed by our managing general partner to be accredited investors at the time of sale. We broke escrow and had our first closing on May 14, 2010. When we had our final closing on September 20, 2010, we had 2,273 investors who purchased our Units (our “participants”). “Units” means our limited partner Units, our converted limited partner Units and our investor general partner Units that will automatically be converted by our managing general partner into the converted limited partner Units once all of our wells are drilled and completed. In accordance with the terms of our offering, 7,312 Units were sold at $20,000 per Unit, and 188 Units were sold at discounted prices to selling agents and their registered representatives and principals and clients of registered investment advisors, and investors who bought Units through the officers and directors of our managing general partner. No Units were sold to our managing general partner, and its officers, directors and affiliates.

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Our participants contributed a total of $149,724,600 in subscription proceeds to us, which we paid to our managing general partner serving as our operator and general drilling contractor under our drilling and operating agreement. We used all of our subscription proceeds to drill and complete wells located primarily in western Pennsylvania, central Indiana, northern Colorado and northern Michigan. Under our partnership agreement, all of the subscription proceeds of our participants were used to pay the intangible drilling costs of our wells and a portion of the tangible costs. “Intangible drilling costs” generally means those costs of drilling and completing a well that are currently deductible, as compared with lease costs, which must be recovered through the depletion allowance, and equipment costs, which must be recovered through depreciation deductions. “Tangible costs” generally means the equipment costs of drilling and completing a well that are not currently deductible as intangible drilling costs and are not lease costs. Our managing general partner was required to contribute all of the leases on which our wells are situated, pay and/or contribute services towards our organization and offering costs up to an amount equal to 15% of our participants’ subscription proceeds and pay all of our equipment costs to drill and complete our wells that were not paid with our participants’ subscription proceeds. As of December 31, 2010, the aggregate amount of these contributions by our managing general partner was $33,909,100. A tabular presentation of the respective capital contributions to us of the participants and our managing general partner as of December 31, 2010 is set forth below.

Capital Contributions to Us As of 12/31/10(1)

Participants	$	149,724,600
Managing General Partner	$	33,909,100	(2)

(1)	Our cash distributions are allocated between our managing general partner and our participants in the same percentages as their respective capital contributions bear to our total capital contributions, except that our managing general partner receives an additional 10% of our distributions regardless of the amount of its capital contribution.
(2)	Our managing general partner’s capital contributions to us increased from $33,909,100 as of December 31, 2010 to $37,891,600 as of March 31, 2011 (unaudited) and are expected to increase further as our drilling activities are completed. Currently, our managing general partner anticipates that its total capital contributions to us eventually will be approximately $46,632,000.

2

Investment Objectives. Our investment objectives are to:

• Provide monthly cash distributions to our participants from the wells drilled with our subscription proceeds until the wells are depleted, with a minimum annual return of capital of 12% during the first 12-month subordination period, 10% during the next three 12-month subordination periods, and 8% during the fifth 12-month subordination period based on $20,000 per Unit regardless of the actual subscription price paid, beginning when natural gas or oil is being sold from at least 75% of our wells. These distributions during the 60-month aggregate subordination period are not guaranteed, but are subject to our managing general partner’s subordination obligation as described in Item 11 “Description of Registrant’s Securities to be Registered — Distributions and Subordination.”

Under current conditions, and based in part on the drilling results of the 51.58 net wells which we drilled in 2010 (approximately 43% of our estimated total of 118.69 net wells to be drilled), we believe that our participants will receive the minimum aggregate distributions described above each year during this 60-month aggregate subordination period. See Item 3 “Properties” and the “Notes to Financial Statements — Note 10” in Item 13 “Financial Statements and Supplementary Data.” However, we do not yet know the drilling results of all of the 67.11 net wells which we prepaid in 2010 (approximately 57% of our estimated total of 118.69 net wells to be drilled), since we were still in the process of drilling 35.11 of our net wells on March 31, 2011. Therefore, a participant should not rely on the results of the wells we drilled in 2010 as being indicative of the results of the wells drilled in 2011. Also, current conditions, such as prices for natural gas and our costs for operating our wells, will change during the 60-month aggregate subordination period. See Item 1A “Risk Factors.”

• Obtain federal income tax deductions in 2010 from intangible drilling costs in an amount guaranteed to equal not less than 85% of each participant’s subscription price for his or her Units. These deductions for intangible drilling costs may be used to offset a portion of the participant’s taxable income subject to any objections by the IRS, each participant’s individual tax circumstances, and the passive activity rules if the participant invested in us as a limited partner. For example, if a participant paid $20,000 for a Unit the investment would produce a 2010 tax deduction of not less than $17,000 per unit, 85%, against:

• ordinary income, or capital gain in some situations, if the participant invested as an investor general partner; and

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• passive income if the participant invested as a limited partner.

In the first quarter of 2011, our IRS Schedule K-1’s to our participants reported a deduction for intangible drilling costs in 2010 in an amount equal to 85% of the subscription price paid by each participant. However, we do not guarantee the IRS’ treatment of our participants’ deductions for intangible drilling costs. If the IRS were to decrease the amount of the deduction, or defer part of the deduction to 2011 for wells we prepaid in 2010, for example, our participants would not be entitled to any reimbursement from us for any increase in taxes owed, penalties or interest or any other lost tax benefits.

• Offset a portion of any gross production income generated by us with tax deductions from percentage depletion.

• Provide each of our participants with tax deductions, in an aggregate amount guaranteed to equal up to the remaining 15% of the participant’s initial investment in us that was not used to pay intangible drilling costs, through annual depreciation deductions over a seven-year cost recovery period, subject to:

• a 50% write-off in 2010 for the costs of qualified equipment acquired before September 8, 2010 and used in wells placed in service for the production of natural gas production in 2010; or

• a 100% write-off in 2010 for the costs of qualified equipment acquired after September 8, 2010 and used in wells placed in service for the production of natural gas in either 2010 or 2011.

The tax benefits of these depreciation deductions to our participants are subject to any objections by the IRS, each participant’s individual tax circumstances, and the passive activity rules if the participant invested as a limited partner or is a converted limited partner. Also, we do not guarantee the IRS’ treatment of our participants’ depreciation deductions for our equipment costs. If the IRS were to decrease the amount of the deductions, for example, our participants would not be entitled to any reimbursement from us for any increase in taxes owed, penalties or interest or any other lost tax benefits.

Oil and Natural Gas Properties. As of December 31, 2010, we had drilled 51.58 net development wells, and as of March 31, 2011 we had drilled an additional 32.00 net development wells and had begun drilling approximately 35.11 more net development wells. Because all of our wells have not yet been drilled and completed, our investor general partner Units have not yet been converted to limited partner Units. We will not drill any wells except the wells funded with our subscription proceeds and our managing general partner’s capital contributions to us as described above. For further information concerning our natural gas and oil properties, including the status of our drilling activities, our leasing practices and our reserve and acreage information, see Item 3 “Properties.” We believe that our ongoing operating and maintenance costs for our productive wells will be paid through revenues we receive from the sale of our natural gas and oil production as discussed in Item 2 “Financial Information.” Thus, the subscription proceeds from the offering of our Units in 2010 and our ongoing natural gas and oil production revenues from our wells will satisfy all of our cash requirements and we will not seek to raise additional funds from either our participants or new investors.

4

We pay our managing general partner a monthly well supervision fee of $975 per well per month in the Marcellus Shale primary area in western Pennsylvania, $1,500 per well per month in the New Albany Shale primary area in central Indiana, and $600 per well per month in the Antrim Shale primary area in northern Michigan, for serving as the operator of our wells. This well supervision fee covers all normal and regularly recurring operating expenses for the production and sale of natural gas and to a lesser extent oil, such as:

• well tending, routine maintenance and adjustment;

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

• preparing reports to us and to government agencies.

The well supervision fees, however, do not include costs and expenses related to the purchase of certain equipment, materials, rebuilding of access roads, water hauling, or certain other goods or services provided by our managing general partner’s affiliates at competitive rates in the area or by third-parties. In this regard, our managing general partner will determine competitive industry rates for equipment, supplies and other services by conducting a survey of the interest and/or fees charged by unaffiliated third-parties engaged in similar businesses in the same geographic areas. If possible, our managing general partner will contact at least two unaffiliated third-parties; however, our managing general partner will have sole discretion in determining the amount to be charged us, subject to the foregoing.

Production. All of our wells are expected to produce natural gas, and some of our wells are currently producing natural gas and to a far lesser extent oil, which are our only products. We do not plan to sell any of our wells and intend to continue to produce them until they are depleted, at which time they will be plugged and abandoned. See Item 3 “Properties” for information concerning:

• our natural gas and oil production quantities;

• average sales prices; and

• average production costs.

Sale of Natural Gas and Oil Production. Our managing general partner is responsible for selling our natural gas and oil production. In the geographic areas where our wells are situated, our managing general partner is a party to natural gas contracts with various natural gas purchasers, each of which is paying a different price for our natural gas. Our managing general partner is also responsible for gathering and transporting the natural gas produced by us to interstate pipeline systems, local distribution companies, and/or end-users in the area (the “gathering services”), and we pay our managing general partner a competitive gathering fee for this service. In providing the gathering services our managing general partner may use gathering systems owned by its affiliates or independent third-parties.

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We will pay a gathering fee directly to our managing general partner at competitive rates for the gathering services. The gathering fee paid by us to our managing general partner may be increased from time-to-time by our managing general partner, in its sole discretion, but may not be increased beyond competitive rates as determined by our managing general partner. Currently, our managing general partner has determined that the competitive rates in our primary areas are as follows:

• in the Marcellus Shale primary area, an amount equal to 16% of the gross sales price received by us for our natural gas, and for this purpose gross sales price means the price that is actually received, adjusted to take into account proceeds received or payments made pursuant to hedging arrangements;

• in the New Albany Shale (Indiana) primary area, a gathering fee of $0.005 (1/2 of one cent) per mcf per mile the natural gas is transported, plus a processing fee of $1.00 per mcf if the natural gas is processed through a processing plant in Indiana in which an affiliate of our managing general partner owns an interest; and

• in the Antrim Shale primary area in Michigan, an average gathering fee of approximately $.30 per mcf transported.

The payment of a competitive fee to our managing general partner for its gathering services is subject to the following conditions:

• If a third-party gathering system is used by us, then our managing general partner’s gathering fee with respect to our natural gas will be the actual transportation and compression fees charged by the third-party gathering system and our managing general partner will pay all of the gathering fee it receives from us to the third-party gathering the natural gas.

• If both a third-party gathering system and a gas gathering system owned by an affiliate of our managing general partner are used by us, then our managing general partner will receive an amount equal to a competitive fee as described above for the natural gas transported by the segment provided by the gathering system owned by an affiliate of our managing general partner, plus the amount charged by the third-party gathering system for the natural gas transported by the segment provided by the third-party.

Our managing general partner will determine competitive industry rates for its gathering services by conducting a survey of gathering fees charged by unaffiliated third-parties in the same geographic areas. If possible, our managing general partner will contact at least two unaffiliated third-parties; however, our managing general partner will have sole discretion in determining the amount to be charged us, subject to the foregoing.

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Our managing general partner considers a drilling area to be a primary drilling area if 10% or more of our subscription proceeds are used to drill wells in the area. In this regard, our managing general partner anticipates that:

• The natural gas produced from the Marcellus Shale primary area in Pennsylvania will be sold primarily to UGI Energy Services, Colonial Energy, Inc., South Jersey Resources Group, ConocoPhillips Company, Dominion Field Services, Inc., EQT Energy LLC, Equitable Gas Company, Sequent Energy Management, L.P., and NJR Energy Services pursuant to various contracts.

• The natural gas produced from the New Albany Shale primary area in Indiana will be sold primarily to Atmos Energy pursuant to contracts which end March 31, 2014.

• The natural gas produced from the Antrim Shale primary area in Michigan will be sold primarily to DTE Energy Company, BP Canada, Conoco Phillips, Sequent Energy, Nexen, and Total Gas & Power pursuant to various contracts or on the spot market.

All of the natural gas contracts described above are between the natural gas purchaser and our managing general partner or its affiliates. Either our managing general partner or its affiliates will receive the sales proceeds from the natural gas purchasers and then distribute the sales proceeds to us based on the volume of natural gas produced by us. Until the sales proceeds are distributed to us, they will be subject to the claims of our managing general partner’s or its affiliates’ creditors.

The pricing and delivery arrangements with the vast majority of the natural gas purchasers described above are tied to the settlement of the New York Mercantile Exchange Commission (“NYMEX”) monthly futures contracts price, which is reported daily in the Wall Street Journal, with an additional premium, which is referred to as the basis, paid for natural gas production in the Appalachian Basin because of the relatively close location of the natural gas in relation to the natural gas market. These arrangements do not include our natural gas production from the New Albany Shale primary area in Indiana or the Antrim Shale primary area in Michigan since these areas are not situated in the Appalachian Basin.

Pricing for natural gas and oil production has been volatile and unpredictable for many years. Currently, none of our natural gas production is subject to hedging arrangements. Instead, our production is sold at contract prices in the month produced or at spot market prices. The prices under most of our gas sales contracts are negotiated on an annual basis and are index-based. However, to limit our exposure if natural gas prices fall, we have used hedges in the past, and expect to do so again in the future, to lock in a range of pricing for a significant portion of our production during the periods covered by the hedges. In this regard, in conjunction with the “Asset Acquisition” and the “Chevron Merger” described in Item 5 “Directors and Executive Officers — Managing General Partner,” all of the previous derivative contracts related to the natural gas and oil production of the partnerships sponsored by our managing general partner, including us, were monetized and we and the other partnerships will share in the total available hedge gains based on each partnership’s actual production volumes during the period of the original derivative contracts, some which would have extended into 2014.

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With respect to future hedging arrangements, our managing general partner and its affiliates may enter into financial hedges through contracts such as NYMEX futures and options contracts and over-the-counter futures contracts through banking counterparties on behalf of us and the other partnerships sponsored by our managing general partner, including future partnerships. They may also use physical hedges through their natural gas purchasers as discussed below. These futures contracts are commitments to purchase or sell natural gas at future dates and generally have covered one-month periods for up to 60 months in the future. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, our managing general partner has established a risk management committee to assure that all financial trading is done in compliance with our managing general partner’s hedging policies and procedures. Our managing general partner does not intend to contract for positions that it cannot offset with actual production. Any physical hedges require firm delivery of natural gas and, therefore, are considered normal sales of natural gas, rather than hedges, for accounting purposes. Additionally, we may enter into our own agreements and financial instruments relating to hedging our natural gas and oil and the pledging of up to 100% of our assets and reserves in connection therewith.

The percentages of our natural gas that may hedged in the future through either financial hedges, physical hedges or not hedged at all will change from time to time in the discretion of our managing general partner and its affiliates and are not limited. If the hedges are with our managing general partner or its affiliates, rather than us, it is difficult to project what portion of these hedges will be allocated to us by our managing general partner because of uncertainty about the quantity, timing, and delivery locations of natural gas that may be produced by us. However, the allocations must be based on actual production in accordance with past practice.

Although hedging will provide us some protection against falling prices, these activities also could reduce the potential benefits of price increases and we could incur liability on the financial hedges. See Item 1A “Risk Factors — Risks Related to an Investment in Us — Future Hedging Activities We Anticipate Undertaking May Adversely Affect Our Financial Situation and Results of Operations.” We and the other partnerships sponsored by our managing general partner and its affiliates will be severally liable for our respective allocated share of the liabilities under any future hedging agreements, but will not be jointly and severally liable for the entire amount of the liabilities under the hedging agreements.

Crude oil produced from our wells will flow directly into storage tanks where it will be picked up by the oil company, a common carrier, or pipeline companies acting for the oil company which is purchasing the crude oil. Unlike natural gas, crude oil does not present any transportation problem. Our managing general partner anticipates selling any oil produced by our wells to regional oil refining companies at the prevailing spot market price for Appalachian crude oil in spot sales.

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Subject to our managing general partner’s and its affiliates’ interest in their natural gas contracts, hedging arrangements, and pipelines and gathering systems, all benefits and liabilities from marketing and any other relationships affecting the property of our managing general partner or its affiliates or us must be fairly and equitably apportioned according to the interests of each in the property, consistent with past practice.

Major Customers. Our natural gas and oil is sold to various purchasers. For the period ended March 31, 2011, sales to Atmos Energy Marketing, LLC accounted for 87% of our total revenues. For the period ended December 31, 2010, sales to Atmos Energy Marketing, LLC accounted for 98% of our total revenues. No other customer accounted for more than 10% of our total revenues for the periods ended March 31, 2011 and December 31, 2010, respectively. As of March 31, 2011 and December 31, 2010, only 66% and 39%, respectively, of the total 110.14 net wells we currently expect to drill and complete were online and producing natural gas. Thus, the percentages of sales to our customers as set forth above should not be considered to be representative of our sales and customers after all of our wells are online and producing.

Competition. The energy industry is intensely competitive in all of its aspects. Competition arises not only from numerous domestic and foreign sources of natural gas and oil, but also from other industries that supply alternative sources of energy. In selling our natural gas and oil, product availability and price are our principal means of competition. We may also encounter competition in obtaining drilling and operating services from third-party providers. Any competition we encounter could delay the drilling and/or operating of our wells, and thus delay the distribution of our revenues to our participants. While it is impossible for us to accurately determine our comparative position in the natural gas and oil industry, we do not consider our operations to be a significant factor in the industry.

Markets. The availability of a ready market for natural gas and oil, and the price obtained, depend on numerous factors beyond our control as described below in Item 1A “Risk Factors — Risks Relating to Our Business.” During fiscal years 2008, 2009, and 2010 our managing general partner did not experience problems in selling its and its affiliates’ natural gas and oil, although prices varied significantly during those periods.

Governmental Regulation

Regulation of Production. The production of natural gas and oil is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations, such as requirements for permits for drilling operations, drilling bonds and reports concerning operations. Also, each state in which we drill a well has regulations governing conservation matters, including the regulation of well spacing. The effect of these regulations is to limit the number of wells, or the locations where we can drill wells, although we can apply for exemptions to the regulations to reduce the well spacing. The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

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Regulation of Transportation and Sale of Natural Gas. Governmental agencies regulate the production and transportation of natural gas. Generally, the regulatory agency in the state where a producing natural gas well is located supervises production activities and the transportation of natural gas sold into intrastate markets, and the Federal Energy Regulatory Commission (“FERC”) regulates the interstate transportation of natural gas.

Natural gas prices have not been regulated since 1993, and the price of natural gas is subject to the supply and demand for natural gas along with factors such as the natural gas’ BTU content and where the wells are located. Since 1985 FERC has sought to promote greater competition in natural gas markets in the United States. Traditionally, natural gas was sold by producers to interstate pipeline companies that served as wholesalers and resold the natural gas to local distribution companies for resale to end-users. FERC changed this market structure by requiring interstate pipeline companies to transport natural gas for third-parties. In 1992 FERC issued Order 636 and a series of related orders that required pipeline companies to, among other things, separate their sales services from their transportation services and provide an open access transportation service that is comparable in quality for all natural gas producers or suppliers. The premise behind FERC Order 636 was that the interstate pipeline companies had an unfair advantage over other natural gas producers or suppliers because they could bundle their sales and transportation services together. FERC Order 636 is designed to ensure that no natural gas seller has a competitive advantage over another natural gas seller because it also provides transportation services.

In 2000 FERC issued Order 637 and subsequent orders to enhance competition by removing price ceilings on short-term capacity release transactions. It also enacted other regulatory policies that were intended to enhance competition in the natural gas market and increase the flexibility of interstate natural gas transportation. FERC has further required pipeline companies to develop electronic bulletin boards to provide standardized access to information concerning capacity and prices.

Crude Oil Regulation. Oil prices are not regulated, and the price is subject to the supply and demand for oil, along with qualitative factors such as the gravity of the crude oil and sulfur content differentials.

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State Regulation. Each state where we drill a well imposes a comprehensive statutory and regulatory scheme for natural gas and oil operations, including supervising the production activities and the transportation of natural gas sold in intrastate markets, which creates additional financial and operational burdens. For example, in our primary areas our oil and gas operations are regulated by the Department of Environmental Resources in Pennsylvania, the Department of Natural Resources in Indiana and the Department of Natural Resources and Environment in Michigan. Among other things, the regulations involve:

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

• landowner notification requirements;

• certain bonding or other security measures;

• minimum well spacing requirements;

• restrictions on well locations and underground gas storage;

• certain well site restoration, groundwater protection including water disposal plans, and safety measures;

• discharge permits for drilling operations;

• various reporting requirements; and

• well plugging standards and procedures.

Environmental Regulation. Our drilling and producing operations are subject to various federal, state, and local laws covering the discharge of materials into the environment, or otherwise relating to the protection of the environment. The Environmental Protection Agency and state and local agencies will require us to obtain permits and take other measures with respect to:

• the discharge of pollutants into navigable waters;

• disposal of wastewater; and

• air pollutant emissions, which may include CO² emissions from natural gas and oil wells.

If these requirements or permits are violated, there can be substantial civil and criminal penalties that will increase if there was willful negligence or misconduct. In addition, we may be subject to fines, penalties and unlimited liability for cleanup costs under various federal laws such as the Federal Clean Water Act, the Clean Air Act, the Resource Conservation and Recovery Act, the Oil Pollution Act of 1990, the Toxic Substance Control Act, and the Comprehensive Environmental Response, Compensation and Liability Act of 1980 for oil and/or hazardous substance contamination or other pollution caused by our drilling activities or our wells and our production activities.

Additionally, our liability can extend to pollution that occurred on our leases before we acquired the leases. Also, each state where we drill a well has either adopted federal standards or promulgated its own environmental requirements consistent with the federal regulations.

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We believe we have complied in all material respects with applicable federal and state regulations and do not expect that these regulations will have a material adverse impact on our operations. Although compliance may cause delays in drilling our wells, which we do not anticipate, or increase our costs, currently we do not believe these costs will be substantial. However, we cannot predict the ultimate costs of complying with present and future environmental laws and regulations because these laws and regulations are frequently changed, and ultimately they may have a material impact on our operations or costs to remain in compliance. Additionally, we cannot obtain insurance to protect against many types of environmental claims, including remediation costs.

Dismantlement, Restoration, Reclamation and Abandonment Costs. When we determine that a well is no longer capable of producing natural gas or oil in economic quantities, we must dismantle the well and restore and reclaim the surrounding area before we can abandon the well. We contract these operations to independent service providers to which we pay a fee. The contractor will also salvage the equipment on the well, which we then sell in the used equipment market.

ITEM 1A. RISK FACTORS

Statements made by us that are not strictly historical facts are “forward-looking” statements that are based on current expectations about our business and assumptions made by our managing general partner. These statements are subject to risks and uncertainties that exist in our operations and business environment that could result in actual outcomes and results that are materially different than those predicted.

Risks Relating to Our Business

Natural Gas and Oil Prices are Volatile and a Substantial Decrease in Prices, Particularly Natural Gas Prices, Would Decrease Our Revenues, Our Cash Distributions and the Value of Our Properties and Could Reduce Our Managing General Partner’s Ability to Loan Us Funds; Meet Its Ongoing Obligations to Indemnify Our Investor General Partners and Purchase Units Under Our Presentment Feature. A substantial decrease in natural gas and oil prices, particularly natural gas prices, would decrease our revenues and the value of our natural gas and oil properties. Our future financial condition and results of operations, and the value of our natural gas and oil properties, will depend on market prices for natural gas and, to a much lesser extent, oil. Further, if natural gas and oil prices decrease during the first years of production from our wells, which is when the wells typically achieve their greatest level of production, there would be a greater adverse effect on our distributions to our participants than price decreases in later years when the wells have a lower level of production. Also, our participants’ return level will decrease during our term, even if there are rising natural gas prices, because of reduced production volumes from our wells.

Prices for natural gas and oil are dictated by supply and demand factors and prices may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas or oil, and market uncertainty. For example, reduced natural gas demand and/or excess natural gas supplies will result in lower prices. Other factors affecting the price and/or marketing of natural gas and oil production, which are beyond our control and cannot be accurately predicted, are the following:

• the cost, proximity, availability, and capacity of pipelines and other transportation facilities;

• the price and availability of other energy sources such as coal, nuclear energy, solar and wind;

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• the price and availability of alternative fuels, including when large consumers of natural gas are able to convert to alternative fuel use systems;

• local, state, and federal regulations regarding production, conservation, water disposal, and transportation;

• overall domestic and global economic conditions;

• the impact of the U.S. dollar exchange rates on natural gas and oil prices;

• technological advances affecting energy consumption;

• domestic and foreign governmental relations, regulations and taxation;

• the impact of energy conservation efforts;

• the general level of supply and market demand for natural gas and oil on a regional, national and worldwide basis;

• weather conditions and fluctuating seasonal supply and demand for natural gas and oil because of various factors such as home heating requirements in the winter months;

• economic and political instability, including war or terrorist acts in natural gas and oil producing countries, including those of the Middle East, Africa and South America;

• the amount of domestic production of natural gas and oil; and

• the amount and price of imports of natural gas and oil from foreign sources, including the actions of the members of the Organization of Petroleum Exporting Countries (“OPEC”), which include production quotas for petroleum products from time to time with the intent of increasing, maintaining, or decreasing price levels.

These factors make it extremely difficult to predict natural gas and oil price movements with any certainty. Price decreases would reduce the amount of our cash flow available for distribution to our participants and could make some of our reserves uneconomic to produce which would reduce our reserves and cash flow. Additionally, price decreases may cause the lenders under Atlas Energy, L.P.’s credit facility to reduce its borrowing base because of lower revenues or reserve values, which would indirectly reduce our managing general partner’s liquidity, and could possibly, require mandatory loan repayments from our managing general partner if Atlas Energy, L.P. and its other affiliates called on our managing general partner to do so. This would reduce our managing general partner’s ability to loan us money or to meet its ongoing partnership obligations, such as indemnification of our investor general partners for liabilities in excess of their pro rata share of our assets and insurance proceeds and purchasing Units presented by our participants.

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Estimates of Our Natural Gas and Oil Reserves are Based on Many Assumptions that May Prove to be Inaccurate. Any Material Inaccuracies in these Underlying Assumptions Will Materially Affect the Quantities and Present Value of Our Reserves. Underground accumulations of natural gas and oil cannot be measured in an exact way. Natural gas and oil reserve engineering requires subjective estimates of underground accumulations of natural gas and oil and assumptions concerning future natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate as discussed in Item 3 “Properties — Natural Gas and Oil Reserve Information.” Any significant variance from these assumptions by actual figures could greatly affect estimates of reserves, the economically recoverable quantities of natural gas and oil, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, will likely result in the actual quantities of natural gas and oil we ultimately recover being different from our reserve estimates.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on historical prices and costs. However, the actual future net cash flows we derive from such properties also will be affected by factors such as:

• actual prices we receive for natural gas;

• the amount and timing of actual production;

• the amount and timing of our capital expenditures;

• supply of and demand for natural gas; and

• changes in governmental regulations or taxation.

The timing of both our production and incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

Any significant variance in our assumptions could materially affect the quantity and value of our reserves, the amount of PV-10 and standardized measure, and our financial condition and results of operations. In addition, our reserves or PV-10 and standardized measure may be revised downward or upward based upon production history, prevailing natural gas and oil prices and other factors. A material decline in prices paid for our production can reduce the estimated volumes of our reserves because the economic life of our wells could end sooner. Similarly, a decline in market prices for natural gas or oil may reduce our PV-10 and standardized measure.

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Our Managing General Partner Has Limited Experience in Drilling Horizontal Wells to the Marcellus Shale and Horizontal Wells are More Expensive and Difficult to Drill and Complete Than Vertical Wells. As of March 31, 2011, our managing general partner had participated in drilling and served as operator on 96 horizontal wells in the Marcellus Shale, which does not include the 11 horizontal Marcellus Shale wells it is drilling on our behalf. In addition, horizontal wells in the Marcellus Shale are more expensive to drill and complete than vertical wells, because of increased costs associated with the drilling rigs needed to drill a horizontal well, including fracing the wells, and casing for the wells. For example, in the Marcellus Shale, a horizontal well may cost three times the amount of a vertical well and this increased cost to us may not result in greater recoverable reserves. Also, horizontal wells will be more susceptible to mechanical problems associated with completing the wells, such as casing collapse and lost equipment in the wellbore, than vertical wells. Further, fracing the formation in a horizontal well is more complicated than fracing the same geological formation in a vertical well. Thus, there is a greater risk of loss of the well or cost overruns associated with horizontal drilling as compared with vertical drilling.

Drilling Our Wells Requires Adequate Sources of Water to Facilitate the Fracturing Process and Our Production Operations Result in Removing Water from Our Wells that We Must Dispose Of. If We are Unable to Dispose of the Water We Remove from a Well at a Reasonable Cost and Within Applicable Environmental Rules, Our Ability to Produce Natural Gas from the Well Could Be Impaired. Our natural gas wells in the Marcellus Shale primary area use a process called hydraulic fracturing, which requires large amounts of water to frac the wells and also results in water discharges that must be treated and disposed of. Environmental regulations governing the injection, withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing may increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial performance. Our ability to remove and dispose of water will affect our production, and the cost of water treatment and disposal may affect our profitability. Also, new environmental regulations could be imposed that would include restrict our ability to conduct hydraulic fracturing or dispose of water, drilling fluids and other substances associated with the exploration, development and production of natural gas and oil.

Drilling Wells is Highly Speculative and Some of Our Wells Are Nonproductive or May Be Productive, But Fail to Return the Costs of Drilling and Operating Them. The amount of recoverable natural gas and oil reserves may vary significantly from well to well. We have drilled some wells that are nonproductive (i.e. “dry holes”), and we may drill more nonproductive wells or wells that may be profitable on an operating basis, but do not produce sufficient net revenues to return a profit after drilling, operating and other costs are taken into account. The geologic data and technologies available do not allow us to know conclusively before drilling a well whether or not natural gas or oil is present or can be produced economically.

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The cost of drilling, completing and operating a well is often uncertain. For example, the increase in natural gas and oil prices over the last several years has increased the demand for drilling rigs and other related equipment, and the costs of drilling and completing natural gas and oil wells also have increased. This has increased our well costs since our wells are drilled by our managing general partner, serving as our general drilling contractor, on a modified cost plus basis, and are not drilled on a turnkey basis for a fixed price that would shift the risk of cost overruns to our managing general partner as drilling contractor. Thus, any cost overruns in drilling and completing our wells could reduce or delay distributions to our participants.

The Drilling of Some of Our Wells Could Be Curtailed, Delayed or Cancelled If Unexpected Events Occur. Some of our drilling operations may be curtailed, delayed or cancelled as a result of many factors, including:

• title problems;

• environmental or other regulatory concerns;

• costs of, or shortages or delays in the availability of, oil field services and equipment;

• unexpected drilling conditions;

• unexpected geological conditions;

• adverse weather conditions;

• equipment failures or accidents;

• limitations on or disruptions in gathering or transmission capacity;

• environmental accidents such as gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment or oil leaks, including groundwater contamination;

• fires, blowouts, craterings and explosions; and

• uncontrollable flows of natural gas or well fluids.

As discussed in Item 3 “Properties,” all of our wells are not yet completed and online. Any one or more of the factors discussed above could reduce or delay our receipt of a portion, which could be significant, of our natural gas and oil production revenues, thereby reducing or delaying our revenues and our distributions to our participants. In addition, any of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties.

Although we maintain insurance against various losses and liabilities arising from our operations, insurance against all operational risks will not be available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could reduce our results of operations.

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If Third-Parties Participating in Drilling Some of Our Wells Fail to Pay Their Share of the Well Costs, We Would Have to Pay Those Costs in Order to Get the Wells Drilled, and If We Are Not Reimbursed the Increased Costs Would Reduce Our Cash Flow and Possibly Could Reduce the Number of Wells We Can Drill. Third-parties have participated with us in drilling some of our wells. Financial risks exist when the cost of drilling, equipping, completing, and operating wells is shared by more than one person. If we pay our share of the costs, but the other interest owner does not pay its share of the costs, then we would have to pay the costs of the defaulting party. In this event, we would receive the defaulting party’s revenues from the well, if any, under penalty arrangements set forth in the operating agreement, which may, or may not, be sufficient to cover the additional costs we paid. If it is insufficient to cover the additional costs, the increased costs would reduce our cash flow and the number of wells we can drill unless we borrow funds to cover the additional costs or the costs of drilling our other wells is less than expected and those excess funds are used to pay the additional costs.

Risks Related to an Investment In Us

Our Managing General Partner’s Management Obligations to Us Are Not Exclusive, and if It Does Not Devote the Necessary Time to Our Management There Could Be Delays in Providing Timely Reports and Distributions to Our Participants, and Our Managing General Partner, Serving as Operator of Our Wells, May Not Supervise the Wells Closely Enough. We do not have any officers, directors or employees. Instead, we rely totally on our managing general partner and its affiliates for our management. Our managing general partner is required to devote to us the time and attention that it considers necessary for the proper management of our activities. However, our managing general partner and its affiliates currently are, and will continue to be, engaged in other natural gas and oil activities, including other partnerships and unrelated business ventures for their own account or for the account of others, during our term. This creates a continuing conflict of interest in allocating management time, services, and other activities among us and its other activities. If our managing general partner does not devote the necessary time to our management, there could be delays in providing timely annual and semi-annual reports, tax information and cash distributions to our participants. Also, if our managing general partner, serving as the operator of our wells, does not supervise the wells closely enough, for example, there could be delays in undertaking remedial operations on a well, if necessary to increase the production of natural gas from the well.

Current Conditions May Change and Reduce Our Proved Reserves, Which Could Reduce Our Revenues.A participant will be able to recover his investment in us only through our distribution of our net sales proceeds from the production of natural gas and oil from our productive wells. The quantity of natural gas and oil in a well, which is referred to as its reserves, decreases over time as the natural gas and oil is produced until the well is no longer economical to operate. Our proved reserves will decline as they are produced from our wells, and once all of our wells are online our distributions to our participants generally will decrease each year until our wells are depleted.

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Our proved reserves at December 31, 2010 from the wells we drilled, completed and placed online for production in 2010 are set forth in Item 3 “Properties — Natural Gas and Oil Reserve Information.” However, there is an element of uncertainty in all estimates of proved reserves, and current conditions, such as natural gas and oil prices and the costs of operating our wells and transporting our natural gas, will change in the future and could reduce the amount of our current proved reserves. Also, our estimated proved reserves and revenues from the sale of our natural gas and oil production once all of our wells have been drilled and placed online for production will vary significantly from our expectations associated with the estimated proved reserves of only the wells we drilled, completed and placed online for production in 2010 as presented in Item 3 “Properties — Natural Gas and Oil Reserve Information.”

We base our estimates of proved natural gas and oil reserves and future net revenues from those reserves on various assumptions, including those required by the SEC, such as natural gas and oil prices, taxes, development expenses, capital expenses, operating expenses and availability of funds. Any significant variance in the future in these assumptions based on actual production, natural gas and oil prices, taxes, development expenses, operating expenses, availability of funds, would materially affect the estimated quantity of our reserves as discussed in Item 3 “Properties.”

Our properties also may be susceptible to hydrocarbon drainage from wells on adjacent properties in which we do not have an interest. In addition, our proved reserves may be revised downward in the future based on the following:

• the actual production history of our wells;

• results of future exploration and development in the area;

• decreases in natural gas and oil prices;

• governmental regulation; and

• other changes in current conditions, many of which are beyond our control.

Government Regulation of the Oil and Natural Gas Industry is Stringent and Could Cause Us to Incur Substantial Unanticipated Costs for Regulatory Compliance, Environmental Remediation of Our Well Sites (Which May Not Be Fully Insured) and Penalties, and Could Delay or Limit Our Drilling Operations.We are subject to complex laws that can affect the cost, manner or feasibility of doing business. Exploration, development, production and sales of natural gas and oil are subject to extensive federal, state and local regulations. We discuss our regulatory environment in more detail in Item 1 “Business — Governmental Regulation.” We may be required to make large expenditures to comply with these regulations. Failure to comply with these regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Also, governmental regulations could change in ways that substantially increase our costs, thereby reducing our return on invested capital, revenues and net income.

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In addition, our operations may cause us to incur substantial liabilities to comply with environmental laws and regulations. Our natural gas and oil operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations:

• require the acquisition of a permit before drilling begins;

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

• limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas; and

• impose substantial liabilities for pollution resulting from our operations.

These laws include, for example:

• the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions;

• the federal Clean Water Act and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water;

• the Resource Conservation and Recovery Act (“RCRA”) and comparable state laws that impose requirements for the handling and disposal of waste, including waste water produced from our wells; and

• the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and comparable state laws that regulate the cleanup of hazardous substances produced from our wells.

Failure to comply with these laws and regulations may result in the following:

• assessment of administrative, civil, and criminal penalties;

• incurrence of investigatory or remedial obligations; or

• imposition of injunctive relief.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transporting, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance or could restrict our methods or times of operation. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed. Pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not covered, or not fully covered, by insurance could reduce our revenues and the value of our assets.

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Our Natural Gas and Oil Activities Are Subject to Drilling and Operating Hazards Which Could Result in Substantial Losses to Us. Well blowouts, cratering, explosions, uncontrollable flows of natural gas, oil or well fluids, fires, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks are inherent drilling and operating hazards for us. The occurrence of any of those hazards could result in substantial losses to us, including liabilities to third-parties or governmental entities for damages resulting from the occurrence of any of those hazards and substantial investigation, litigation and remediation costs.

Our Total Annual Cash Distributions During Our First Five Years May be Less Than $10,000 Per Unit, Even With Subordination. If our participants’ cash distributions from us are less than 12% of capital ($2,400 per $20,000 unit) in the first 12-month subordination period, 10% of capital ($2,000 per $20,000 unit) in each of the next three 12- month subordination periods, and 8% of capital ($1,600 per $20,000 unit) in the fifth 12-month subordination period based on a $20,000 Unit regardless of the actual price paid) for the 60-month aggregate subordination period beginning when natural gas or oil is being sold from at least 75% of our wells, then our managing general partner has agreed to subordinate a portion of its share of our net production revenues. However, if our wells produce only small natural gas and oil volumes, and/or natural gas and oil prices decrease, then even with subordination our participants may not receive the return of capital in each of the five 12-month subordination periods described above. Also, at any time during the 60-month aggregate subordination period our managing general partner is entitled to an additional share of our revenues to recoup previous subordination distributions to the extent our participants’ cash distributions from us would exceed the return of capital described above. A more detailed discussion of our managing general partner’s subordination obligation is set forth in Item 11 “Description of Registrant’s Securities to be Registered — Distributions and Subordination.”

Our Limited Operating History Creates Greater Uncertainty Regarding Our Ability to Operate Profitably. Our limited history of operating our wells may not indicate the results that we may achieve in the future. Our success depends on generating sufficient revenues by producing sufficient quantities of natural gas and oil from our wells and then marketing that natural gas and oil at sufficient prices to pay the operating costs of our wells and our administrative costs of conducting business as a partnership, and still provide a reasonable rate of return on our participants’ investment in us. If we are unable to pay our costs, then we may need to:

• borrow funds from our managing general partner, which is not contractually obligated to make any loans to us;

• shut-in or curtail production from some of our wells; or

• attempt to sell some of our wells, which we may not be able to do on terms that are acceptable to us.

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Also, the events set forth below could decrease our revenues from our wells and/or increase our expenses of operating our wells:

• decreases in the price of natural gas and oil, which are volatile;

• changes in the oil and gas industry, including changes in environmental regulations, which could increase our costs of operating our wells in compliance with any new environmental regulations;

• an increase in third-party costs for equipment or services, or an increase in gathering and compression fees for transporting our natural gas production; and

• problems with one or more of our wells, which could require repairing or performing other remedial work on a well or providing additional equipment for the well.

Competition May Reduce Our Revenues from the Sale of Our Natural Gas. Competition arises from numerous domestic and foreign sources of natural gas and oil, including other natural gas producers and marketers in the Appalachian Basin, Indiana, and Michigan as well as competition from other industries that supply alternative sources of energy. Competition will make it more difficult to market our natural gas. Product availability and price are the principal means of competition in selling natural gas and oil. Many of our competitors possess greater financial or other resources than we do, which may enable them to offer their natural gas to natural gas purchasers on terms, such as lower prices or a greater volume of natural gas that can be delivered to the purchaser that we cannot match. Also, other energy sources such as coal may be available to the purchasers at a lower price. As a result, we may have to seek other natural gas purchasers and we may receive lower prices for our natural gas and incur higher transportation and compression fees if we sell our natural gas to these other natural gas purchasers. In this event, our revenues from the sale of our natural gas would be reduced.

We May Have to Replace Our Natural Gas Purchasers and Receive a Lower Price for Our Natural Gas. We will depend on a limited number of natural gas purchasers to purchase the majority of our natural gas production and we will not be guaranteed a specific natural gas price, unless we engage in hedging in the future. Thus, if our current purchasers were to pay a lower price for our natural gas in the future, our revenues would decrease. Also, if our current purchasers began buying a reduced percentage of our natural gas, or stopped buying any of our natural gas, the sale of our natural gas would be delayed until we found other purchasers, and the substitute purchasers we found may pay lower prices for our natural gas, which would reduce our revenues.

We Could Incur Delays in Receiving Payment, or Substantial Losses if Payment is Not Made, for Natural Gas We Previously Delivered to a Purchaser, Which Could Delay or Reduce Our Revenues and Cash Distributions. There is a credit risk associated with a natural gas purchaser’s ability to pay. We may not be paid or may experience delays in receiving payment for natural gas that has already been delivered. In this event, our revenues and cash distributions to our participants also would be delayed or reduced. In accordance with industry practice, we typically will deliver natural gas to a purchaser for a period of up to 60 to 90 days before we receive payment. Thus, it is possible that we may not be paid for natural gas that already has been delivered if the natural gas purchaser fails to pay for any reason, including bankruptcy. This ongoing credit risk also may delay or interrupt the sale of our natural gas.

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We Intend to Produce Natural Gas and/or Oil from Our Wells Until They Are Depleted, Regardless of Any Changes in Current Conditions, Which Could Result in Lower Returns to Our Participants as Compared With Other Types of Investments Which Can Adapt to Future Changes Affecting Their Portfolios. Our natural gas and oil properties are relatively illiquid because there is no public market for working interests in natural gas and oil wells. In addition, one of our investment objectives is to continue to produce natural gas and oil from our wells until the wells are depleted. Thus, unlike mutual funds, for example, which can vary their portfolios in response to changes in future conditions, we do not intend, and in all likelihood we would be unable, to vary our portfolio of wells in response to future changes in economic and other conditions such as decreases or increases in natural gas or oil prices, or increased operating costs of our wells.

Since Our Managing General Partner Is Not Contractually Obligated to Loan Funds to Us, We Could Have to Curtail Operations or Sell Properties if We Need Additional Funds and Our Managing General Partner Does Not Make a Loan to Us. Our revenues from the sale of our natural gas and oil production may be insufficient to pay all of our ongoing expenses, such as our operating and maintenance costs for our productive wells or our costs associated with repairing or performing other remedial work on a well. If this were to occur, we expect that we would borrow the necessary funds from our managing general partner or its affiliates, although they are not contractually committed to make a loan. Also, under our partnership agreement the amount we may borrow may not at any time exceed 5% of our total subscriptions and no borrowings are permitted from third-parties. If, for any reason, our managing general partner did not loan us the funds needed to repair or perform other remedial work on a well, then we might have to curtail operations on the well or attempt to sell the well, although we may not be able to do so on terms that are acceptable to us.

Future Hedging Activities We Anticipate Undertaking May Adversely Affect Our Financial Situation and Results of Operations. Because the majority of our proved reserves are currently natural gas reserves, we are more susceptible to movements in natural gas prices. Although currently none of our natural gas is hedged to protect against a decrease in natural gas prices, we expect to engage in hedging activities in the future, as we have done in the past, to help protect us if natural gas prices fall in the future. However, our future hedging activities could reduce the potential benefits of price increases and we could incur liability on financial hedges. For example, we would be exposed to the risk of a financial loss if any of the following occurred:

• our production is substantially less than expected;

• the counterparties to the futures contracts fail to perform under the contracts; or

• there is a sudden, unexpected event materially impacting natural gas prices.

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Increases in Prices for Natural Gas and Oil Could Result in Non-Cash Balance Sheet Reductions Due to the Accounting Treatment of Derivative Contracts We Expect to Enter Into in the Future. In conjunction with the “Asset Acquisition” and “Chevron Merger” described in Item 5 “Directors and Executive Officers — Managing General Partner,” Atlas Energy, Inc. monetized all of its derivative contracts related to natural gas and oil production. We and the other partnerships sponsored by our managing general partner, including future partnerships, will share in the total available hedge gains based on each partnership’s actual production volumes during the period of the original derivative contracts, some of which extended into 2014. In addition, we anticipate that in the future we will enter into natural gas derivative contracts, either through Atlas Energy or an affiliate or directly for our own account, and we will account for these derivative contracts by applying the provisions of Accounting Standards Codification 815, “Derivatives and Hedging.” Due to the mark-to-market accounting treatment for these contracts, we could recognize incremental hedge liabilities between reporting periods resulting from increases in reference prices for natural gas and oil, which could result in us recognizing a non-cash loss in our accumulated other comprehensive income (loss) and a consequent non-cash decrease in our partners’ equity between reporting periods. Any such decrease could be substantial.

A Decrease in Natural Gas Prices Could Subject Our and Our Managing General Partner’s Oil and Gas Properties to an Impairment Loss under Generally Accepted Accounting Principles. Generally accepted accounting principles require oil and gas properties and other long-lived assets to be reviewed for impairment whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. We and our managing general partner will test our respective oil and gas properties on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on our or our managing general partner’s own economic interests and our respective plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. We and our managing general partner estimate prices based on current contracts in place at the impairment testing date, adjusted for basis differentials and market related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. Accordingly, declines in the price of natural gas have caused the carrying values of properties in many of our managing general partner’s previous partnerships to exceed the expected future cash flow. Future declines in the price of natural gas may cause the carrying value of our, our managing general partner’s or its other partnerships’ oil and gas properties to exceed the expected future cash flows, and require an impairment loss to be recognized.

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Federal Income Tax Risks.

Changes in the Law May Reduce Our Participants’ Tax Benefits From an Investment in Us. Our participants’ tax benefits from their investment in us may be affected by changes in the tax laws. For example, President Obama’s administration has proposed, among other tax changes, the repeal of certain oil and gas tax benefits, beginning in 2012, including the repeal of the percentage depletion allowance. This proposal may or may not be enacted into law. The repeal of the percentage depletion allowance, if it happens, however, would result in a decrease in our participants’ future tax benefits from their investment in us.

Our Participants’ Deduction for Intangible Drilling Costs May Be Limited for Purposes of the Alternative Minimum Tax. Under current tax law, our participants’ alternative minimum taxable income in 2010 cannot be reduced by more than 40% by their respective shares of our deduction for intangible drilling costs without creating a tax preference item under the alternative minimum tax rules.

Our Limited Partners Need Passive Income to Use Their Deduction for Intangible Drilling Costs. If a participant invested in us as a limited partner (except as discussed below), his or her share of our deduction for intangible drilling costs in 2010 will be a passive loss that cannot be used to offset “active” income, such as salary and bonuses, or portfolio income, such as dividends and interest income. Thus, a limited partner may not have enough passive income from us or net passive income from his or her other passive activities, if any, in 2010 to offset a portion or all of the limited partner’s passive deduction for intangible drilling costs in 2010. However, any unused passive loss from intangible drilling costs may be carried forward indefinitely to offset passive income in subsequent taxable years. Also, except as described below, the passive activity limitations do not apply to a limited partner that is a C corporation which:

• is not a personal service corporation or a closely held corporation;

• is a personal service corporation in which employee-owners hold 10% (by value) or less of the stock, but is not a closely held corporation; or

• is a closely held corporation (i.e., five or fewer individuals own more than 50% (by value) of the stock), but is not a personal service corporation in which employee-owners own more than 10% (by value) of the stock, in which case passive losses may be used to offset net active income (calculated without regard to passive activity income and losses or portfolio income and losses).

Our Participants May Owe Taxes in Excess of Their Cash Distributions from Us. Our participants may become subject to income tax liability for their respective shares of our income in any taxable year in an amount that is greater than the cash they receive from us in that taxable year. For example:

• if we borrow money, our participants’ share of our revenues used to pay principal on the loan will be included in their share of our income and will not be deductible;

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• income from sales of natural gas and oil may be included in our participants’ income from us in one tax year, even though payment is not actually received by us and, thus, cannot be distributed to our participants until the next tax year;

• if there is a deficit in a participant’s capital account, we may allocate income or gain to the participant even though the participant does not receive a corresponding distribution of our revenues;

• our revenues may be expended by our managing general partner for nondeductible costs or retained in us to establish a reserve for future estimated costs, including a reserve for the estimated costs of eventually plugging and abandoning our wells, which will reduce our participants’ cash distributions from us without a corresponding tax deduction; and

• the taxable disposition of our property or our participants’ Units may result in income tax liability to our participants in excess of the cash they receive from the transaction.

Investment Interest Deductions of Investor General Partners May Be Limited. If a participant invested in us as an investor general partner, his or her share of our deduction for intangible drilling costs in 2010 will reduce the participant’s investment income and may limit the amount of the participant’s deductible investment interest expense, if any.

Our Participants’ Tax Benefits from an Investment in Us Are Not Contractually Protected. An investment in us does not give our participants any contractual protection against the possibility that part or all of the intended tax benefits of their investment will be disallowed by the IRS. No one provides any insurance, tax indemnity or similar agreement for the tax treatment of our participants’ investment in us. Our participants have no right to rescind their investment in us or to receive a refund of any of their investment in us if a portion or all of the intended tax consequences of their investment in us is ultimately disallowed by the IRS or the courts. Also, none of the fees paid by us to our managing general partner, its affiliates or independent third-parties (including special counsel which issued the tax opinion letter) are refundable or contingent on whether the intended tax consequences of their investment in us are ultimately sustained if challenged by the IRS.

An IRS Audit of Us May Result in an IRS Audit of the Personal Federal Income Tax Returns of Our Participants. The IRS may audit our annual federal information income tax returns, particularly since our participants will be eligible to claim a deduction for intangible drilling costs in 2010. If we are audited, the IRS also may audit the personal federal income tax returns of a portion or all of our participants, including prior years’ returns and items that are unrelated to us.

Our Deductions May be Challenged by the IRS. If the IRS audits us, it may challenge the amount of our deductions and the taxable year in which the deductions were claimed, including the deductions for intangible drilling costs and depreciation. Any adjustments made by the IRS to our federal information income tax returns could lead to adjustments on the personal federal income tax returns of our participants and could reduce the amount of their deductions from us in 2010 and subsequent tax years. The IRS also could seek to recharacterize a portion of our intangible drilling costs for drilling and completing our wells as some other type of expense, such as lease costs or equipment costs, which would reduce or defer our participants’ share of our deductions for those costs.

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ITEM 2. FINANCIAL INFORMATION.

Selected Financial Data. The following table sets forth selected financial data for the period ended December 31, 2010, that we derived from our financial statements, which were audited by Grant Thornton LLP, independent registered public accountants, and are included in this Form 10.

	For the period April 1, 2010
	(commencement of operations)
	through December 31, 2010
Income statement data:
Revenues:
Gas and oil production	$	2,159,900
Total revenues	$	2,159,900
Costs and expenses:
Gas and oil production	$	1,000,600
Dry hole costs		1,279,000
General and administration		40,500
Depletion		1,549,400
Total costs and expenses	$	3,869,500
Net loss		(1,709,600	)
Basic and diluted net loss per limited partnership unit	$	(205	)

	For the period April 1, 2010
	(commencement of operations)
	through December 31, 2010
Operating data:
Net annual production volumes:
Natural gas (mmcf)(1)		457,100
Oil (mbbls)		—
Total (mmcfs)		457,100
Average sales price:
Natural gas (per mcf)	$	4.72
Oil (per bbl)	$	—
Other financial information:
Net cash used in operating activities	$	—
Capital expenditures	$	149,724,600
EBITDA(2)	$	(160,200	)

	December 31, 2010
Balance sheet data:
Total assets	$	170,091,100
Total liabilities	$	1,609,300
Partners’ capital	$	168,481,800

(1) Excludes sales of residual gas and sales to landowners.

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(2) We define EBITDA as earnings before interest, taxes, depreciation, depletion and amortization. EBITDA is not a measure of performance calculated in accordance with accounting principles generally accepted in the United States of America or GAAP. Although not prescribed under GAAP, we believe the presentation of EBITDA is relevant and useful because it helps our participants to understand our operating performance and makes it easier to compare our results with other companies that have different financing and capital structures or tax rates. EBITDA should not be considered in isolation from, or as a substitute for, our net income as an indicator of operating performance or cash flows from operating activities as a measure of liquidity. EBITDA, as we calculate it, may not be comparable to EBITDA measures reported by other companies. In addition, EBITDA does not represent funds available for discretionary use. The following reconciles EBITDA to our income from continuing operations for the periods indicated.

	For the period April 1, 2010
	(commencement of operations)
	through December 31, 2010
Loss from continuing operations	$	(1,709,600	)
Plus depletion		1,549,400
EBITDA	$	(160,200	)

Forward-Looking Statements. When used in this Form 10, the words “believes,” “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements. These statements are subject to certain risks and uncertainties more particularly described in Item 1A “Risk Factors” of this Form 10. These risks and uncertainties could cause our actual results to differ materially from those that we anticipate. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this Form 10. We undertake no obligation to publicly release the results of any revisions to forward-looking statements that we may make to reflect events or circumstances after the date of this Form 10 or to reflect the occurrence of unanticipated events.

This Item 2 “Financial Information” section should be read in conjunction with Item 13 “Financial Statements and Supplementary Data — Notes to Financial Statements.”

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Results of Operations. The following table sets forth information for the period April 1, 2010 (commencement of operations) through December 31, 2010 relating to revenues recognized and costs and expenses incurred, daily production volumes, average sales prices and production cost per equivalent unit during the period indicated:

	For the Period April 1, 2010
	(commencement of operations)
	through December 31, 2010
Revenues (in thousands):
Gas(1)	$	2,160
Oil	$	—
Production volumes:
Gas (thousands of cubic feet (mcf)/day)		2,177
Oil (barrels (bbls)/day)		—
Average sales price:
Gas (per mcf)	$	4.72
Oil (per bbl)	$	—
Production costs:
As a percent of sales		46	%
Per equivalent mcf	$	2.19
Depletion per mcfe	$	4.90

(1) Excludes sales of residual gas and sales to landowners.

Liquidity and Capital Resources. Cash used in investing activities was $149,724,600 for the period ended December 31, 2010, which was paid to our managing general partner, serving as general drilling contractor, pursuant to our drilling and operating agreement. Cash provided by financing activities was $149,724,600 which came from capital contributions for the period ended December 31, 2010.

Our managing general partner believes that we have adequate capital to develop approximately 127 gross wells under our drilling and operating agreement. Our wells will be drilled primarily in western Pennsylvania, central Indiana, and northern Michigan. Funds contributed by our participants and our managing general partner after our formation will be the only funds available to us for drilling activities. Although we estimate that 127 gross development wells will be drilled, we cannot guarantee that all of our proposed wells will be drilled or completed since there may be cost overruns in drilling and completing the wells. Each of our proposed wells is unique and the ultimate costs incurred may be more or less than our current estimates.

Our ongoing operating and maintenance costs for the next 12-month period are expected by our managing general partner to be fulfilled through revenues from the sale of our gas and oil production. Natural gas prices are volatile and, for example, can be affected by weather conditions and fluctuating seasonal supply and demand for natural gas and oil. Also, our managing general partner has not experienced any problems with selling natural gas in the past three fiscal years as discussed in Item 1 “Business — General — Markets.” Although we do not anticipate that there will be a shortfall in our revenues that we use to pay for our ongoing expenses, if one were to occur, we expect that we would borrow the necessary funds from our managing general partner or its affiliates, which are not contractually committed to make a loan. The amount we may borrow may not at any time exceed 5% of our total subscriptions and no borrowings will be obtained from third-parties.

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We have not and will not devote any funds to research and development activities and no new products or services will be introduced. We do not plan to sell any of our wells and intend to continue to produce them until they are depleted at which time they will be plugged and abandoned. We have no employees and rely on our managing general partner and its affiliates for management.

Critical Accounting Policies. The discussion and analysis of our financial condition and results of operations are based on our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of our assets, liabilities, revenues and costs and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, we evaluate our estimates, including those related to oil and gas reserves and certain accrued liabilities. We base our estimates on our managing general partner’s historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

We have identified the following policies as critical to our business operations and understanding the results of our operations. For a detailed discussion on the application of these and other accounting policies, see Note 2 in Item 13 “Financial Statements and Supplementary Data — Notes to Financial Statements.”

Use of Estimates. Preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and costs and expenses during the reporting period. Actual results could differ from these estimates.

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

Impairment of Oil and Gas Properties. We will review our producing oil and gas properties for impairment on an annual basis and whenever events and circumstances indicate a decline in the recoverability of their carrying values. We will estimate the expected future cash flows from our oil and gas properties and compare the future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable.

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If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to their fair value in the current period. The factors used to determine fair value include, but are not limited to, estimates of reserves, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that will require us to record an impairment of our oil and gas properties and impairments may be required in the future.

Dismantlement, Restoration, Reclamation and Abandonment Costs. On a periodic basis, we estimate the costs of future dismantlement, restoration, reclamation and abandonment of our natural gas and oil-producing properties. We also estimate the salvage value of equipment recoverable on abandonment as discussed in Note 5 to our financial statements in Item 13 “Financial Statements and Supplementary Data — Notes to Financial Statements.” To cover any shortfall between our participants’ share of the salvage value of the equipment in a well and their share of the plugging and abandoning costs of the well, our managing general partner has the right, beginning one year after each well begins producing, to retain up to $200 per month of our revenues in partnership reserves to cover future plugging and abandonment costs of the well. This $200 also includes our managing general partner’s share of revenues to cover its share of the plugging and abandonment costs of the well. As of December 31, 2010, no reserve for this purpose had been established. A decrease in salvage values or an increase in dismantlement, restoration, reclamation and abandonment costs could reduce our gross profit from energy operations.

Commodity Price Risk. Our major market risk exposure in commodities is fluctuations in the pricing of our natural gas and oil production. Realized pricing is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas production. Pricing for natural gas and oil production has been volatile and unpredictable for many years. Currently, none of our natural gas production is subject to hedging arrangements. Instead, our production is being sold at contract prices in the month produced or at spot market prices. In this regard, the prices under most of our natural gas sales contracts are negotiated on an annual basis and are index-based. Also, in conjunction with the “Asset Acquisition” and the “Chevron Merger” described in Item 5 “Directors and Executive Officers — Managing General Partner,” Atlas Energy, Inc. monetized all derivative contracts related to natural gas and oil production, and we and the other partnerships sponsored by our managing general partner will share in the total available hedge gains based on each of each partnership’s actual production volumes during the period of the original derivative contracts.

To limit our exposure to a decrease in natural gas prices, we have used hedges in the past, and we expect to do so again in the future to lock in a range of pricing for a significant portion or all of our production during the periods covered by the hedges.

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ITEM 3. PROPERTIES.

Drilling Activity. As of December 31, 2010 we had drilled and completed 52 gross wells, which is 45.03 net wells that were online for the sale of production as shown in the following table. All of the wells we drilled were “development wells,” which means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. In addition to the wells we drilled during 2010, our participants’ share of our estimated drilling and equipment costs of 68 gross wells, which is 67.11 net wells, were prepaid by us in 2010 for wells to be drilled in 2011. The drilling of each of the wells we prepaid in 2010 began on or before March 31, 2011, and was not delayed by any shortages of drilling rigs, equipment, supplies or personnel. Those prepaid wells are not included in the following table.

	Development Wells
	Productive (1)				Dry (2)
	Gross (3)		Net (4)		Gross (3)		Net (4)
Period Ending December 31, 2010		52.00		45.03		7.00		6.55

(1)	A “productive well” generally means a well that is not a dry hole.
(2)	A “dry hole” generally means a well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well. The term “completion” refers to the installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, to the reporting of abandonment to the appropriate agency.
(3)	A “gross” well is a well in which we own a working interest.
(4)	A “net” well equals the actual working interest we own in one gross well divided by one hundred. For example, a 50% working interest in a well is one gross well, but a .50 net well.

Summary of Productive Wells. The table below shows the location by state and the number of productive gross and net wells in which we owned a working interest at December 31, 2010. All of our wells are classified as natural gas wells.

Location	Gross		Net
Colorado		6		6.00
Indiana		41		34.26
Michigan		5		4.77
Total		52		45.03

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

	Production				Average Sales Price				Average Production
			Gas						Cost (Lifting Cost)
	Oil (bbls)		(mcf)		per bbl		per mcf (1)		per mcfe (1)(2)
Period from First Production to December 31, 2010		—		457,100	$	—	$	4.72	$	2.19

(1)	“Mcf” means one thousand cubic feet of natural gas. “Mcfe” means one thousand cubic feet equivalent.
	“Bbl” means one barrel of oil. Oil production is converted to mcfe at the rate of six mcf per barrel (“bbl”).
(2)	Production costs include labor to operate the wells and related equipment, repairs and maintenance, materials and supplies, property taxes, severance taxes, insurance, gathering charges and production overhead.

Natural Gas and Oil Reserve Information. As of December 31, 2010 we had drilled and completed for the sale of production 45.03 net wells. Under current conditions, our managing general partner is reasonably certain that the proved reserves as shown in the table below will be produced over the life of our wells. All of the wells we drilled were “development wells,” which means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. In addition to the wells we drilled during 2010, our participants’ share of our estimated drilling and equipment costs of approximately 67.11 net wells were prepaid by us in 2010. The drilling of each of the wells we prepaid in 2010 began on or before March 31, 2011, and those prepaid wells are not included in the table below. Thus, the reserve information set forth below is not representative of our reserves after all of our wells are drilled and completed. All of our reserves are located in the United States. The basic information required for reserve estimation on our proved natural gas and oil reserves was provided by our managing general partner and verified for reasonableness by Wright & Company, Inc., independent energy consultants, in accordance with SEC guidelines.

Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas and oil reserves, of necessity, are projections based on engineering and other data. There are inherent uncertainties 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.

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The price of the estimated future production was calculated as the 12-month unweighted arithmetic average price based on the first-day-of-the-month price for each month within the prior 12-month period, which was $4.38 per million British thermal units (MMBtu) for natural gas. In arriving at the estimated future cash flows, operating costs, development costs, and production-related and ad valorem taxes when applicable. Future prices received from the sale of natural gas may be different from those we estimated. The amounts and timing of future operating, development and abandonment costs may also differ from those used. Thus, the reserves set forth in the following table ultimately may not be produced and the proved reserves may not be produced within the periods anticipated. You should not construe the estimated PV-10 values as representative of the fair market value of our proved natural gas properties. PV-10 values are based on projected cash inflows, which do not provide for changes in natural gas and oil prices or for escalation of expenses and capital costs. The meaningfulness of these estimates depends on the accuracy of the assumptions on which they were based.

The following table summarizes information regarding our estimated proved natural gas and oil reserves as of the date indicated.

	December 31, 2010
Natural gas reserves — Proved Reserves (Mcf)(1)(4):
Total proved reserves of natural gas		24,651,600
Oil reserves — Proved Reserves (Bbl)(1)(4)
Total proved reserves of oil		0
Total proved reserves (Mcfe)		24,651,600
PV-10 estimate of cash flows of proved reserves (3)(4):
Total PV-10 estimate	$	25,459,900

(1)	“Proved Reserves” generally means those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government 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.
(2)	“Developed reserves” generally means reserves of any category 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.
(3)	The present value of estimated future net cash flows is calculated by discounting estimated future net cash flows by 10% annually.
(4)	Please see Rule 4-10 of SEC Regulation S-X for complete definitions of each reserve category, including undeveloped reserves.

We have not filed any estimates of our natural gas and oil reserves with, nor were the estimates included in any reports to, any Federal or foreign governmental agency within the 12 months before the date of this filing. For additional information concerning our natural gas reserves and activities, see Item 13 “Financial Statements and Supplementary Data — Notes to Financial Statements.”

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Title to Properties. We believe that we hold good and indefeasible title or operating rights to our properties in accordance with standards generally accepted in the natural gas and oil 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 and oil industry, we conduct only a perfunctory title examination at the time we acquire a property. Before we begin drilling operations, however, we conduct an extensive title examination and perform curative work on any defects that we deem significant. We 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 in favor of third-parties customary in the industry, such as free gas to the landowner-lessor for home heating requirements, etc. Our properties are also subject to burdens such as:

• liens incident to operating agreements;

• taxes;

• development obligations under natural gas and oil leases;

• farm-out arrangements; and

• other encumbrances, easements and restrictions.

We do not believe that any of these burdens will materially interfere with our use of our properties.

Acreage. The table below shows the estimated acres of developed and undeveloped natural gas and oil acreage in which we have an interest, separated by state, at December 31, 2010.

	Developed Acreage				Undeveloped Acreage (3)
Location	Gross (1)		Net (2)		Gross (1)		Net (2)
Pennsylvania		13.27		13.27		—		—
Indiana		9,120.00		7,995.20		1,280		1,222.40
Michigan		560.00		542.40		160		160.00
Colorado		1,720.00		1,720.00		—		—
Total		11,413.27		10,270.87		1,440		1,382.40

(1)	A “gross” acre is an acre in which we own a working interest.
(2)	A “net” acre equals the actual working interest we own in one gross acre divided by one hundred. For example, a 50% working interest in an acre is one gross acre, but a .50 net acre.
(3)	“Undeveloped acreage” means those lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether or not the acreage contains proved reserves.

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ITEM 4. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.

As of December 31, 2010, we had issued 7,500 Units to 2,273 participants, and we will not issue any additional Units. The following table, as of December 31, 2010, sets forth the number and percentage of Units owned and held by:

• beneficial owners of 5% or more of our Units;

• our managing general partner’s executive officers and directors; and

• all of the executive officers and directors of our managing general partner as a group.

The address for each director and executive officer of our managing general partner is Westpointe Corporate Center One, 1550 Coraopolis Heights Road, Suite 300, Moon Township, Pennsylvania 15108.

	Units
	Amount and Nature
	of Beneficial
Beneficial Owner	Ownership		Percent of Class
DIRECTORS AND EXECUTIVE OFFICERS
Freddie M. Kotek		0		0	%
Jeffrey C. Simmons		0		0	%
NON-DIRECTOR EXECUTIVE OFFICERS
Jack L. Hollander		0		0	%
Matthew A. Jones		0		0	%
Sean P. McGrath		0		0	%
Marci F. Bleichmar		0		0	%
Karen A. Black		0		0	%
Justin T. Atkinson		0		0	%
All executive officers and directors as a group		0		0	%
OTHER OWNERS OF MORE THAN 5% OF OUTSTANDING UNITS
None		0		0	%

We are not aware of any arrangements which may, at a subsequent date, result in a change in our control.

ITEM 5. DIRECTORS AND EXECUTIVE OFFICERS

Managing General Partner. We have no officers, directors or employees. Instead, Atlas Resources, LLC, a Pennsylvania limited liability company, serves as our managing general partner and it intends to allocate its management time, services and other functions on an as-needed basis consistent with its fiduciary duties among us and its other activities so that our administration as a partnership and our natural gas and oil operations are managed properly. Our managing general partner’s indirect parent company is Atlas Energy (NYSE: AHD). In this regard, Atlas Energy has announced that beginning on April 28, 2011 its ticker symbol will change from “AHD” to “ATLS.” Our managing general partner depends on Atlas Energy and its affiliates for all management and administrative

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functions and financing for capital expenditures. Atlas Energy and its affiliates employ more than 375 persons. In this regard, our managing general partner pays a management fee of 7% of subscription funds raised, and reimburses management and administrative expenses incurred on its behalf, to Atlas Energy or an affiliate based on an allocation of total revenues. Atlas Energy, formerly known as Atlas Pipeline Holdings, L.P. as discussed below, is a publicly-traded Delaware limited partnership. Atlas Energy’s general partner is Atlas Energy GP, LLC. Atlas Energy’s wholly-owned subsidiary, Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP”), a Delaware limited liability company, is the general partner of Atlas Pipeline Partners, L.P., a publicly-traded Delaware limited partnership (NYSE: APL).

Atlas Energy is headquartered at Westpointe Corporate Center One, 1550 Coraopolis Heights Road, Suite 300, Moon Township, Pennsylvania 15108, near the Pittsburgh International Airport, which is also our managing general partner’s primary office. Since 1985 our managing general partner has sponsored 22 public and 38 private partnerships to conduct natural gas drilling and development activities. Currently, our managing general partner and its affiliates operate more than 8,000 natural gas and oil wells located primarily in the Appalachian Basin.

On February 17, 2011, Atlas Energy completed the transactions, which we refer to as the “Asset Acquisition,” contemplated by Atlas Energy’s transaction agreement (the “Atlas Energy Transaction Agreement”), dated November 8, 2010, with Atlas Energy, Inc. and Atlas Energy Resources, LLC (“ATN”), a wholly-owned subsidiary of Atlas Energy, Inc., which are former indirect parent companies of our managing general partner, pursuant to which Atlas Energy purchased from Atlas Energy, Inc.: (1) its investment partnership business, including the operations of its investment partnerships, including us, in Michigan, Pennsylvania, Tennessee, Indiana and Colorado; (2) 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 (3) its ownership and management of investments in Lightfoot Capital Partners, L.P. and related entities. The assets Atlas Energy purchased included certain Atlas Energy, Inc. subsidiaries. In connection with the Asset Acquisition, Atlas Energy, Inc. contributed Atlas Energy’s general partner, Atlas Energy GP, LLC to Atlas Energy, and Atlas Energy GP, LLC became Atlas Energy’s wholly-owned subsidiary. All of these transactions, along with the Asset Acquisition are referred to collectively as the “Atlas Energy Transactions.”

Concurrently with Atlas Energy’s completion of the Asset Acquisition, APL completed its sale to ATN of its 49% non-controlling interest in Laurel Mountain Midstream, LLC (the “Laurel Mountain Sale”) for $413.5 million in cash, including adjustments based on certain capital contributions APL made to and distributions it received from Laurel Mountain after January 1, 2011. APL retained the preferred distribution rights under the limited liability company agreement of Laurel Mountain entitling APL Laurel Mountain LLC to receive all payments made under a note issued to Laurel Mountain by Williams Laurel Mountain, LLC in connection with the formation of Laurel Mountain.

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Concurrently with Atlas Energy’s completion of the Asset Acquisition and APL’s completion of the Laurel Mountain Sale, Atlas Energy, Inc. completed its merger transaction with Chevron Corporation (“Chevron”), pursuant to which, among other things, Atlas Energy, Inc. became a wholly-owned subsidiary of Chevron (the “Chevron Merger”). The APL common Units and 12% cumulative Class C preferred Units held directly by Atlas Energy, Inc. were acquired by Chevron as part of the Chevron Merger.

On February 18, 2011, subsequent to the Asset Acquisition and the Chevron Merger, Atlas Energy changed its name to Atlas Energy, L.P.

At March 31, 2011, Atlas Energy had a credit facility with a syndicate of banks that matures in March 2016. The maximum lender commitments under the credit facility are $300 million, with an initial borrowing base of $125 million. As of March 31, 2011, Atlas Energy had no outstanding borrowings under the credit facility. The borrowing base under the credit agreement will be redetermined semi-annually, with the first such redetermination to occur on May 1, 2011. Atlas Energy and the administrative agent, at the direction of the super majority lenders (as defined in the credit agreement), each also have the right to initiate one interim redetermination during each six month period, and Atlas Energy may further initiate an interim redetermination in connection with specified transactions including the acquisition of oil and gas properties with values above a threshold specified in the credit agreement. In connection with each redetermination of the borrowing base, the administrative agent will propose a new borrowing base based upon, among other things, reserve reports and such other information as the administrative agent deems appropriate in its reasonable discretion and consistent with its normal oil and gas lending criteria as they exist at the particular time. The borrowing base is automatically reduced by 25% of the stated principal of any senior unsecured notes issued by Atlas Energy. Up to $50 million of the credit facility may be in the form of standby letters of credit, of which no amount was outstanding at March 31, 2011. The facility is secured by substantially all of Atlas Energy’s assets and is guaranteed by each of its material subsidiaries. This includes a guaranty by our managing general partner and a pledge of our managing general partner’s interests in its partnerships, including our managing general partner’s interest in us, but does not include our participants’ Units in us. At Atlas Energy’s election, interest on borrowings under the credit facility is determined by reference to either LIBOR plus an applicable margin between 2.00% and 3.25% per annum or the base rate (which is the higher of the Wells Fargo prime rate, the Federal funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 1.00% and 2.25% per annum. These margins will fluctuate based on the utilization of the facility.

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The events which constitute an event of default for Atlas Energy’s credit facility are customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against Atlas Energy in excess of a specified amount and a change of control. In addition, the agreement limits sales, leases or transfers of assets and the incurrence of additional indebtedness. Atlas Energy was in compliance with these covenants as of March 31, 2011. The credit facility also requires Atlas Energy to maintain a ratio of current assets (as defined in the credit facility) to current liabilities (as defined in the credit facility) of not less than 1.0 to 1.0, a ratio of total funded debt (as defined in the credit facility) to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”, as defined in the credit facility) of not more than 3.75 to 1.0, and a ratio of EBITDA to consolidated interest expense (as defined in the credit facility) of not less than 2.5 to 1.0.

If Atlas Energy were to default under its credit facility, the lenders could proceed against the collateral granted to them to secure that indebtedness and if they accelerate the repayment of the borrowings, Atlas Energy may not have sufficient assets to repay its credit facility and its other indebtedness. Also, Atlas Energy’s borrowings under its credit facility are, and are expected to continue to be, at variable rates of interest and expose it to interest rate risk. If interest rates increase, Atlas Energy’s debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and its net income would decrease.

Organizational Diagram and Security Ownership of Beneficial Owners

Set forth below is a current organizational chart of Atlas Energy and its subsidiaries after the Atlas Energy Transactions described in “— Managing General Partner,” above.

After the Atlas Energy Transactions, our managing general partner became a wholly-owned subsidiary of Atlas Energy Holdings Operating Company, LLC (“Atlas Energy Holdings”), which is a wholly-owned subsidiary of Atlas Energy. The officers and directors of Atlas Energy and Atlas Energy Holdings are set forth following the organizational chart.

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ORGANIZATIONAL DIAGRAM

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Officers and Directors of Managing General Partner

The officers and directors of the managing general partner will serve until their successors are elected. The officers and directors of our managing general partner are as follows:

NAME	AGE		POSITION OR OFFICE
Freddie M. Kotek		55	Chairman of the Board of Directors, Chief Executive Officer and President
Jeffrey C. Simmons		52	Executive Vice President — Operations and a Director
Jack L. Hollander		55	Senior Vice President — Direct Participation Programs
Matthew A. Jones		49	Senior Vice President
Sean P. McGrath		39	Chief Financial Officer
Marci F. Bleichmar		40	Senior Vice President of Marketing
Karen A. Black		50	Vice President — Partnership Administration
Justin T. Atkinson		38	Vice President

With respect to the biographical information set forth below, the approximate amount of an individual’s professional time devoted to the business and affairs of the managing general partner and Atlas Energy have been aggregated.

Freddie M. Kotek.President and Chief Executive Officer since January 2002 and Chairman of the Board of Directors of the managing general partner since September 2001. Mr. Kotek also serves as Senior Vice President — Syndication Business of Atlas Energy’s general partner, Atlas Energy GP, LLC, since the Chevron Merger on February 17, 2011. Mr. Kotek also served as an Executive Vice President of Atlas Energy, Inc., formerly known as Atlas America, Inc., from February 2004 and Executive Vice President of ATN from October 2009 until the Chevron Merger on February 17, 2011. Mr. Kotek has been a registered representative and principal of Anthem Securities since May 2000. Mr. Kotek will devote approximately 95% of his professional time to the business and affairs of the managing general partner and Atlas Energy, and the remainder of his professional time to the business and affairs of the managing general partner’s other affiliates.

Jeffrey C. Simmons.Executive Vice President — Operations and a Director of the managing general partner since January, 2001. Mr. Simmons also served as Vice President of Operations for the managing general partner from July 1999 until December 2000. Mr. Simmons served as a Senior Vice President of ATN from April 2007 until the Chevron Merger on February 17, 2011. Mr. Simmons was an Executive Vice President of Atlas America, Inc. from January 2001 until the ATN merger in September 2009, a Director of Atlas America, Inc. from January 2002 until February 2004 and Vice President of Operations for Atlas America, Inc. from 1998 until December 2000. Mr. Simmons was a Senior Vice President of Atlas Energy Management, Inc. from June 2006 until the Chevron Merger on February 17, 2011. Mr. Simmons received his Bachelor of Science degree with honors in Petroleum Engineering from Marietta College in 1981 and his Masters degree in Business Administration from Ashland University in 1992. Mr. Simmons devotes approximately 90% of his professional time to the business and affairs of the managing general partner and Atlas Energy, and the remainder of his professional time to the business and affairs of the managing general partner’s other affiliates.

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Jack L. Hollander.Senior Vice President — Direct Participation Programs of the managing general partner since January 2002 and before that he served as Vice President — Direct Participation Programs from January 2001 until December 2001. Mr. Hollander served as the Senior Vice President — Direct Participation Programs of ATN from September 2009 until the Chevron Merger on February 17, 2011. Mr. Hollander also served as Senior Vice President — Direct Participation Programs of Atlas America, Inc. from January 2002 until the ATN merger in September 2009. 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 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 has been a registered representative of Anthem Securities since November 2004. Mr. Hollander devotes approximately 100% of his professional time to the business and affairs of the managing general partner and Atlas Energy.

Matthew A. Jones.Senior Vice President of the managing general partner since the Chevron Merger on February 17, 2011. He formerly served as Chief Financial Officer of the managing general partner from March 2006 until the Chevron Merger on February 17, 2011. Mr. Jones also serves as the Senior Vice President and Chief Operating Officer of Exploration and Production of Atlas Energy’s general partner, Atlas Energy GP, LLC, since the Chevron Merger on February 17, 2011. Mr. Jones served as the Chief Financial Officer of Atlas Energy, Inc., formerly known as Atlas America, Inc., from March 2005 and as an Executive Vice President from October 2009 until the Chevron Merger on February 17, 2011. Mr. Jones served as the Chief Financial Officer of ATN from June 2006, the Chief Financial Officer of Atlas Energy’s general partner, Atlas Energy GP, LLC, from January 2006, and the Chief Financial Officer of Atlas Pipeline Partners GP, LLC from March 2005 until the ATN merger in September 2009. Mr. Jones served as a director of Atlas Energy GP, LLC from February 2006 until February 17, 2011. Mr. Jones also served as a director and the Chief Financial Officer of Atlas Energy Management, Inc. from June 2006 until the Chevron Merger on February 17, 2011. From 1996 to 2005, Mr. Jones worked in the Investment Banking Group at Friedman Billings Ramsey, concluding as Managing Director. Mr. Jones worked in Friedman Billings Ramsey’s Energy Investment Banking Group from 1999 to 2005, and in Friedman Billings Ramsey’s Specialty Finance and Real Estate Group from 1996 to 1999. Mr. Jones devotes approximately 100% of his professional time to the business and affairs of the managing general partner and Atlas Energy.

Sean P. McGrath.Chief Financial Officer of the managing general partner since the Chevron Merger on February 17, 2011. He formerly served as Chief Accounting Officer of the managing general partner from December, 2008 until the Chevron Merger on February 17, 2011. Mr. McGrath also serves as Chief Financial Officer of Atlas Energy’s general partner, Atlas Energy GP, LLC, since the Chevron Merger on February 17, 2011. Mr. McGrath formerly served as the Chief Accounting Officer of Atlas Energy, Inc., formerly known as Atlas America, Inc. from December 2008 until the Chevron Merger on February 17, 2011. Mr. McGrath served as the Chief Accounting Officer of Atlas Pipeline Partners GP, LLC from May 2005 and Chief Accounting Officer of Atlas Energy GP, LLC from January 2006 until November 2009. Mr. McGrath was the Controller of Sunoco Logistics Partners L.P., a publicly-traded partnership that transports, terminals and stores refined products and crude oil from 2002 to 2005. Mr. McGrath devotes approximately 100% of his professional time to the business and affairs of the managing general partner and Atlas Energy.

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Marci F. Bleichmar.Senior Vice President of Marketing of the managing general partner since May 2008 and before that, Vice President of Marketing from February 2001 through May 2008. Ms. Bleichmar served as the Senior Vice President of Marketing of ATN from October 2009 until the Chevron Merger on February 17, 2011. Ms. Bleichmar also served as Senior Vice President of Marketing for Atlas America, Inc. from February 2001 until the ATN merger in September 2009. From March 2000 until February 2001, Ms. Bleichmar served as Director of Marketing for Jacob Asset Management (a mutual fund manager), and from March 1998 until March 2000, she was an account executive at Bloomberg Financial Services LP. From November 1994 until 1998, Ms. Bleichmar was an Associate on the Derivatives Trading Desk of JP Morgan. Ms. Bleichmar has been a registered representative of Anthem Securities since October 2001. Ms. Bleichmar received a Bachelor of Arts degree from the University of Wisconsin in 1992. Ms. Bleichmar devotes approximately 100% of her professional time to the business and affairs of the managing general partner and Atlas Energy.

Karen A. Black.Vice President — Partnership Administration of the managing general partner since February 2003. Ms. Black is also Vice President and Financial and Operations Principal of Anthem Securities since October 2002. Ms. Black joined the managing general partner and Atlas Energy, Inc. in July 2000 and served as manager of production, revenue and partnership accounting from July 2000 through October 2001, after which she served as manager and financial analyst until her appointment as Vice President — Partnership Administration. Before joining the managing general partner in 2000, Ms. Black was associated with Texas Keystone, Inc. as controller from April 1997 through June 2000. Ms. Black was employed as a tax accountant for Sobol Bosco & Associates, Inc. from May 1996 through March 1997. Ms. Black devotes approximately 50% of her professional time to the business and affairs of the managing general partner and Atlas Energy, and the remainder of her professional time to the business and affairs of Anthem Securities, with which she has been affiliated since April 2002.

Justin T. Atkinson. Vice President of the managing general partner since March 2009. Before that Mr. Atkinson was Director of Due Diligence of the managing general partner from February 2003 until March 2009. Mr. Atkinson also serves as President of Anthem Securities since February 2004 and as Chief Compliance Officer since October 2002. Before that Mr. Atkinson served as assistant compliance officer of Anthem Securities from December 2001 until October 2002 and Vice President from October 2002 until February 2004. Before his employment with the managing general partner, Mr. Atkinson was a manager of investor and broker/dealer relations with Viking Resources Corporation from 1996 until November 2001. Mr. Atkinson devotes approximately 25% of his professional time to the business and affairs of the managing general partner and Atlas Energy, and the remainder of his professional time to the business and affairs of Anthem Securities, with which he has been affiliated since April 2001.

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Atlas Energy, L.P. (“Atlas Energy”) a Delaware Limited Partnership. Atlas Energy is the indirect parent company of our managing general partner and the parent company of Atlas Energy Holdings Operating Company, LLC, which is the direct parent of our managing general partner. (See “— Organizational Diagram and Security Ownership of Beneficial Owners,” above.) Our managing general partner and its affiliates, including us, must depend on Atlas Energy and its affiliates to provide all corporate staff and support services. (See “— Transactions with Management and Affiliates,” below.) As a limited partnership, Atlas Energy does not have officers or directors. Instead, its affairs are managed by its general partner, Atlas Energy GP, LLC. As of February 17, 2011, the executive officers and directors for Atlas Energy GP, LLC include the following:

NAME	AGE		POSITION
Edward E. Cohen		72	Chief Executive Officer, President and Director
Jonathan Z. Cohen		40	Chairman of the Board
Sean P. McGrath		39	Chief Financial Officer
Matthew A. Jones		49	Senior Vice President, and President and Chief Operating Officer of Exploration and Production Division
Carlton M. Arrendell		49	Director
Mark C. Biderman		65	Director
Dennis A. Holtz		70	Director
Ellen F. Warren		54	Director
William G. Karis		63	Director
Harvey G. Magarick		71	Director

See “— Officers and Directors of Managing General Partner,” above, for biographical information on Messrs. Jones and McGrath. Biographical information on the other executive officers and directors is set forth below.

Edward E. Cohenhas been the Chief Executive Officer and President of Atlas Energy GP, LLC since the Chevron Merger on February 17, 2011. Previously, he was the Chairman of the Board of Atlas Energy GP, LLC from its formation in January 2006 until February 2011. Mr, Cohen also has been the Chairman of the Managing Board of Atlas Pipeline Partners GP, LLC, the general partner of APL, since its formation in 1999, and served as its Chief Executive Officer from 1999 until January 2009. He also served as the Chairman of the Board of Directors and Chief Executive Officer of Atlas Energy, Inc., formerly known as Atlas America, Inc., from September 2000 until the Chevron Merger on February 17, 2011, and also served as its President from September 2000 until October 2009. Mr. Cohen was the Chairman of the Board and Chief Executive Officer of ATN and its manager, Atlas Energy Management, Inc., from their formation in June 2006 until the Chevron Merger on February 17, 2011. In addition, Mr. Cohen has been Chairman of the Board of Directors of Resource America, Inc., a publicly-traded specialized asset management company, since 1990, and was its Chief Executive Officer from 1988 until 2004, and President from 2000 until 2003; Chairman of the Board of Resource Capital Corp., a publicly-traded real estate investment trust, since its formation in September 2005 until November 2009 and still serves on its board; a director of TRM Corporation, a publicly-traded consumer services company, from 1998 to July 2007; and Chairman of the Board of Brandywine Construction & Management, Inc., a property management company, since 1994. Mr. Cohen is the father of Jonathan Z. Cohen.

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Jonathan Z. Cohenhas been Chairman of the Board of Directors of Atlas Energy GP, LLC since the Chevron Merger on February 17, 2011. He previously served as Vice Chairman of the Board of Directors of Atlas Energy GP, LLC from January 2006 until February 17, 2011. Mr. Cohen served as Vice Chairman of Atlas Energy, Inc., formerly known as Atlas America, Inc., from its formation in 2000 until the Chevron Merger on February 17, 2011. Mr. Cohen also served as the Vice Chairman of the Board of ATN and Atlas Energy Management, Inc. from their formation in June 2006 until the Chevron Merger on February 17, 2011. Mr. Cohen has been Vice Chairman of the Managing Board of Atlas Pipeline Partners GP, LLC since its formation in 1999. Mr. Cohen has been a senior officer of Resource America since 1998, serving as the Chief Executive Officer since 2004, President since 2003 and a director since 2002. Mr. Cohen has been Chief Executive Officer, President and a director of Resource Capital Corp. since its formation in 2005, and was the trustee and secretary of RAIT Financial Trust (a publicly-traded real estate investment trust) from 1997, and its Vice Chairman from 2003, until December 2006. Mr. Cohen is a son of Edward E. Cohen.

Carlton M. Arrendellhas been a Director of Atlas Energy since the Chevron Merger on February 17, 2011. Previously he served as a Director of Atlas Energy, Inc. from February 2004 until February 17, 2011. Mr. Arrendell has been the Chief Investment Officer and a Vice President of Full Spectrum of NY LLC since the May 2007. Before joining Full Spectrum, Mr. Arrendell was a special real estate consultant to the AFL-CIO Investment Trust Corporation following six years of service as Investment Trust Corporation’s Chief Investment Officer.

Mark C. Bidermanhas been a Director of Atlas Energy since the Chevron Merger on February 17, 2011. Previously he served as a Director of Atlas Energy, Inc. from July 2009 until February 17, 2011. Mr. Biderman was Vice Chairman of National Financial Partners Corp., a publicly-traded financial services company, from September 2008 to December 2008. Before that, from November 1999 to September 2008, he was National Financial’s Executive Vice President and Chief Financial Officer. From May 1987 to October 1999, Mr. Biderman served as Managing Director and Head of the Financial Institutions Group at CIBC World Markets Group, an investment banking firm, and its predecessor, Oppenheimer & Co., Inc. Mr. Biderman serves as a director and chairman of the audit committee of Full Circle Capital Corporation, a publicly traded investment company, since August 2010 and as a director, chairman of the compensation committee, and member of the audit committee of Apollo Commercial Real Estate Finance, Inc., a publicly-traded commercial real estate finance company, since November 2010.

Dennis A. Holtzhas been a Director of Atlas Energy since the Chevron Merger on February 17, 2011. Previously he served as a Director of Atlas Energy, Inc. from February 2004 until February 17, 2011. Mr. Holtz maintained a corporate and real estate law practice in Philadelphia and New Jersey from 1988 until his retirement in January 2008.

Ellen F. Warrenhas been a Director of Atlas Energy since the Chevron Merger on February 17, 2011. Previously she served as Director of Atlas Energy, Inc. from September 2009 until February 17, 2011. Ms. Warren is founder and President of OutSource Communications, a marketing communications firm that services corporate and nonprofit clients. Prior to founding OutSource Communications in August 2005, she was President of Levy Warren Marketing Media, a public relations and marketing firm she co-founded in March 1998. Before that, she was Vice President of Marketing/Communications for Jefferson Bank, a Philadelphia-based financial institution from September 1992 to February 1998. Ms. Warren served as a Director of ATN from December 2006 until September 2009.

William G. Karishas been a Director of Atlas Energy since the Chevron Merger on February 17, 2011. He also has been the principal of Karis and Associates, LLC, a consulting company that provides financial and consulting services to the coal industry, since 1997. Prior to that, Mr. Karis was President and CEO of CONSOL Inc. (now CONSOL Energy Company). Mr. Karis is a member of the Boards of Directors and is Chairman of the Audit and Finance Committees of Blue Danube Inc., and Greenbriar Minerals, LLC.

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Harvey G. Magarickhas been a Director of Atlas Energy since the Chevron Merger on February 17, 2011. He also has maintained his own consulting practice since June 2004. From 1997 to 2004, Mr. Magarick was a partner at BDO Seidman. Mr. Magarick is a member of the Board of Trustees of the Hirtle Callaghan Trust, an investment fund, and has been the Chairman of its audit committee since 2004.

Atlas Energy Holdings Operating Company, LLC (“Atlas Energy Holdings”), a Delaware Limited Liability Company. Atlas Energy Holdings is a wholly-owned subsidiary of Atlas Energy and the direct parent company of the managing general partner. (See “— Organizational Diagram and Security Ownership of Beneficial Owners,” above.) Our managing general partner and we must depend on Atlas Energy Holdings and its affiliates, including Atlas Energy, to provide all corporate staff and support services. (See “— Transactions with Management and Affiliates,” below.) Since Atlas Energy Holdings is managed by its members, it has no directors. As of February 17, 2011, the executive officers of Atlas Energy Holdings include the following:

NAME	AGE		POSITION
Jonathan Z. Cohen		40	Chief Executive Officer
Sean P. McGrath		39	Chief Financial Officer

See “— Officers and Directors of Managing General Partner” for biographical information on Mr. McGrath and “— Atlas Energy, L.P. (“Atlas Energy”), a Delaware Limited Partnership,” above, for biographical information on Mr. Jonathan Z. Cohen.

Remuneration of Officers and Directors. No officer or director of our managing general partner will receive any remuneration or other compensation from us. These persons will receive compensation solely from an affiliated company of our managing general partner.

Code of Business Conduct and Ethics. Because we do not employ any persons, our managing general partner has determined that we will rely on a Code of Business Conduct and Ethics adopted by Atlas Energy that applies to the principal executive officer, principal financial officer and principal accounting officer of our managing general partner, as well as to persons performing services for our managing general partner generally. You may obtain a copy of this Code of Business Conduct and Ethics by a request to our managing general partner at Atlas Resources, LLC, Westpointe Corporate Center One, 1550 Coraopolis Heights Road, Suite 300, Moon Township, Pennsylvania 15108.

Transactions with Management and Affiliates. Our managing general partner depends on its indirect parent company, Atlas Energy, L.P., and its affiliates, for all management and administrative functions. Our managing general partner paid a management fee of 7% of subscription funds raised and reimbursed expenses to its indirect parent company, Atlas Energy Resources, LLC, for management and administrative services and expenses incurred on its behalf based on an allocation of total revenues, which amounted to $104.5 million, $132.4 million and $102.1 million for 2008, 2009 and 2010, respectively, of which $234,400 was attributable to services provided to us in 2010. Beginning with the 2011 calendar year, and after the Atlas Energy Transactions discussed in “— Managing General Partner,” above, the management fee of 7% of subscription funds raised will be paid by our managing general partner to Atlas Energy or its affiliates.

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ITEM 7. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

Our policies, procedures and standards for the review, approval, or ratification of related party transactions are set forth in our partnership agreement. These related party transactions primarily involve services, such as drilling and operating our wells, and gathering, transporting and marketing our natural gas and oil production and other transactions as set forth below, provided to us by our managing general partner or its affiliates, for which we pay them reasonable and competitive compensation. Section 4.03(d), “Transactions with the Managing General Partner,” of our partnership agreement deals with transactions between us and our managing general partner and its affiliates. Those include the following:

• the transfer of leases from our managing general partner to us concerning the amount of acreage that must be transferred in the prospect to us;

• the possible payment of compensation by another investment partnership sponsored by our managing general partner to us if our managing general partner determines that there is encroachment on one of our horizontal wells by a horizontal well drilled by the other investment partnership and the result is drainage from our well, and the possible payment of compensation by us to the another investment partnership sponsored by our managing general partner if our managing general partner determines that there is encroachment on the previous investment partnership’s horizontal well by one of our horizontal wells and the result is drainage from the other partnership’s well;

• the transfer to us of less than our managing general partner’s and its affiliates’ entire interest in the prospect;

• the limitations on sale of undeveloped and developed leases by us to our managing general partner;

• the requirement that property transactions between us and our managing general partner must be fair and reasonable;

• the transfer of leases between affiliated limited partnerships;

• the sale of all or substantially all of our assets;

• the providing of services to us by our managing general partner and its affiliates at competitive rates;

• loans from our managing general partner to us and no loans from us to our managing general partner or its affiliates;

• farmouts to and from our managing general partner and us;

• commitments of our future production;

• sharing in gas marketing arrangements;

• advance payments from us to our managing general partner;

• our participation in other partnerships;

• roll-up limitations; and

• the compensation and reimbursement of expenses to be paid by us to our managing general partner and its affiliates.

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Also, the officers of our managing general partner are responsible for applying the policies and procedures set forth in our partnership agreement to our related party transactions, such as determining that the amount of compensation paid by us to related parties is reasonable and competitive in light of the services that they provide to us. The various officers of our managing general partner are assigned to oversee particular transactions by Mr. Freddie Kotek, who is our managing general partner’s chief executive officer and president. See Item 5 “Directors and Executive Officers.”

Oil and Gas Revenues. Our managing general partner’s revenue share will be in the same percentage as its capital contribution bears to our total capital contributions plus an additional 10% of our natural gas and oil revenues. As of March 31, 2011, our managing general partner was allocated 33.75% of our natural gas and oil revenues in return for paying and contributing services towards our organization and offering costs estimated to be 10.86% of our subscriptions, paying an estimated 46% of the tangible costs of our wells and contributing all of the leases covering each of our prospects on which one well is situated. As of March 31, 2011 our managing general partner had contributed $37,891,600 (unaudited) to us and it estimates that its total capital contributions to us will be $46,632,000 after all of our drilling activities are completed.

Financial. During the period ended December 31, 2010, we did not pay any cash distributions to our managing general partner or our participants. During the quarter ended March 31, 2011, we distributed $367,700 to our participants and $187,300 to our managing general partner.

Leases. During the periods ended March 31, 2011 and December 31, 2010, our managing general partner contributed undeveloped prospects (leases) to us to drill 20 net wells and 98.69 net wells, respectively, and received a credit to its capital account in us in the amount of $1,155,100 (unaudited) and $5,053,800, respectively. Our managing general partner does not anticipate contributing any further leases to us.

Administrative Costs. Our managing general partner and its affiliates receive an unaccountable, fixed payment reimbursement from us for their administrative costs of $75 per well per month, which will be proportionately reduced if we acquire less than 100% of the working interest in a well. Our managing general partner received $12,100 in these fees for the period ended December 31, 2010, and $13,600 (unaudited) for the period ended March 31, 2011.

Direct Costs. Our managing general partner and its affiliates will be reimbursed by us for all direct costs expended by them on our behalf, whether our managing general partner is acting as our managing general partner or as the operator of our wells. For the periods ended March 31, 2011 and December 31, 2010, we reimbursed our managing general partner $670,800 (unaudited) and $250,200, respectively, for these direct costs.

Drilling Contracts. We entered into a drilling and operating agreement with our managing general partner, acting as our general drilling contractor, after our initial and final closing dates to drill and complete 118.69 net wells. The total amount received by our managing general partner from our subscription proceeds was $149,724,600. This amount was paid by our participants for their share of the costs of drilling and completing the wells, including the wells that were prepaid in 2010, but the drilling of which began on or before March 31, 2011. We have not entered into any other drilling transactions to the date of this filing, and none are anticipated by us for future periods.

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Per Well Charges. Our managing general partner, serving as operator of our wells, is reimbursed at actual cost for all direct expenses incurred on our behalf as set forth above in “— Direct Costs” and receives well supervision fees for operating and maintaining our wells during producing operations in the amount of $975 per well per month in the Marcellus Shale primary area in Pennsylvania, $1,500 per well per month in the New Albany Shale primary area in Indiana, $600 per well per month in the Antrim Shale primary area in Michigan and at competitive rates in our secondary drilling areas, subject to annual adjustments for inflation. During the periods ended March 31, 2011 and December 31, 2010, our managing general partner received $201,800 (unaudited) and $222,300, respectively, for well supervision fees.

Gathering Fees. We pay a gathering fee to our managing general partner at a competitive rate for each mcf transported. For the periods ended March 31, 2011 and December 31, 2010, the amounts paid were $27,500 (unaudited) and $15,800, respectively, of which $9,500 and $0, respectively, were paid by our managing general partner to Laurel Mountain Midstream, LLC for natural gas we transported through its gathering system before Atlas Energy, Inc.’s merger with Chevron as described in Item 5 “Directors and Executive Officers,” when an affiliate of our managing general partner owned a 49% equity interest in Laurel Mountain Midstream, LLC.

Dealer-Manager Fees. As part of the offering of our Units, in 2010 our managing general partner’s affiliate, Anthem Securities, Inc., serving as dealer-manager of the offering, received a 2.5% dealer-manager fee and a 7% sales commission in the aggregate amount of $13,985,430. The dealer-manager will receive no further compensation from us. Of this amount, $13,968,465 was paid by Anthem Securities to third-party broker/dealers who participated in the offering of our Units.

Organization and Offering Costs. During the period ended December 31, 2010, our managing general partner paid and contributed services for our organization and offering costs in the amount of $16,267,000, including the compensation paid to the dealer-manager, which did not exceed 15% of our subscription proceeds.

All of the related party transactions set forth above were reviewed, approved or ratified by the officers of our managing general partner as discussed above.

Other Compensation. If our managing general partner makes a loan to us it may receive a competitive rate of interest. If our managing general partner provides equipment, supplies and other services to us, then it may do so at competitive industry rates as described in Item 1 “Business — Oil and Natural Gas Properties.” For the periods ended December 31, 2010 and March 31, 2011, no advances were made to us by our managing general partner and we did not enter into any contracts with our managing general partner for equipment, supplies and other services to us other than our partnership agreement and our drilling and operating agreement.

ITEM 8. LEGAL PROCEEDINGS.

None

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ITEM 9. MARKET PRICE OF AND DIVIDENDS ON THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

There is no established public trading market for our Units.

As of March 31, 2011 and December 31, 2010, there were no outstanding options or warrants to purchase, or securities convertible into, our Units. In addition, as of March 31, 2011 and December 31, 2010, there were no Units that could be sold pursuant to Rule 144 under the Securities Act or that we had agreed to register under the Securities Act of 1933 for sale by our participants and there were no Units that were being, or were publicly proposed to be, publicly offered by us.

As of March 31, 2011, there were 2,273 holders of record of our Units.

Our managing general partner reviews our accounts monthly to determine whether cash distributions are appropriate and the amount to be distributed to our managing general partner and our participants, if any. Cash distributions to our managing general partner may only be made in conjunction with distributions to our participants and only out of funds properly allocated to our managing general partner’s account. We distribute those funds which our managing general partner determines are not necessary for us to retain, taking into account our managing general partner’s subordination obligation as described in Item 11 “Description of Registrant’s Securities to be Registered — Distributions and Subordination.” We will not advance or borrow funds for purposes of distributions to our participants if the amount of the distributions would exceed our accrued and received revenues for the previous four quarters, less paid and accrued operating costs with respect to the revenues. Distributions may be reduced or deferred to the extent our revenues are used for any of the following:

• repayment of borrowings;

• cost overruns;

• remedial work to improve a well’s producing capability, including additional fracs in the Marcellus Shale;

• direct costs and our general and administrative expenses;

• reserves, including a reserve for the estimated costs of eventually plugging and abandoning our wells; or

• indemnification of our managing general partner and its affiliates for losses or liabilities incurred in connection with our activities.

The determination of our revenues and costs will be made in accordance with generally accepted accounting principles, consistently applied. During the period ended December 31, 2010, we did not pay any cash distributions to our managing general partner or our participants. During the period ended March 31, 2011, we distributed $367,700 to our participants and $187,300 to our managing general partner.

ITEM 10. RECENT SALES OF UNREGISTERED SECURITIES.

We sold 7,500 Units to 2,273 investors in a private placement offering of our Units beginning April 19, 2010 and ending September 20, 2010. Anthem Securities, Inc., an affiliate of our managing general partner, served as the dealer-manager of the offering and received the compensation set forth in Item 7 “Certain Relationships and Related Transactions — Dealer-Manager Fees.” Our net proceeds from the sale of our Units were $149,724,600.

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We relied on the exemption from registration provided by Rule 506 under Regulation D and Section 4(2) of the Securities Act in connection with the offering. Our Units were offered and sold to a limited number of persons who had the sophistication to understand the merits and risks of the investment, who had the financial ability to bear those risks, and who were “accredited investors,” as that term is defined in Regulation D (17 CFR 230.501(a)). All of our participants were reasonably believed by our managing general partner to be accredited investors at the time of sale.

ITEM 11. DESCRIPTION OF REGISTRANT’S SECURITIES TO BE REGISTERED.

General. The rights and obligations of the holders of our Units (i.e., our participants) are governed by our partnership agreement. “Units” means limited partner Units, investor general partner Units and the converted limited partner Units into which the investor general partner Units will be automatically converted by our managing general partner after all of our wells have been drilled and completed. The following discussion is a summary of the material provisions of our partnership agreement that are not described elsewhere in this Form 10 and is qualified in its entirety by the full text of the partnership agreement.

We were formed under the Delaware Revised Uniform Limited Partnership Act and are qualified to transact business in the jurisdictions where our wells are located. Our managing general partner is Atlas Resources, LLC, which has exclusive management control over all aspects of our business. In the course of its management, our managing general partner may, in its sole discretion, employ any persons, including its affiliates, as it deems necessary for our efficient operation.

Liability of Participants for Further Calls and Conversion.We are governed by the Delaware Revised Uniform Limited Partnership Act. If a participant invested in us as a limited partner, then generally the participant will not be liable to third-parties for our obligations unless the participant:

• also invested in us as an investor general partner;

• takes part in the control of our business in addition to the exercise of a participant’s rights and powers as a limited partner; or

• fails to make a required capital contribution to the extent of the required capital contribution.

In addition, a limited partner participant may be required to return any distribution received if the participant knew at the time the distribution was made that it was improper because it rendered us insolvent.

If the participant invested in us as an investor general partner for the tax benefits instead of as a limited partner, then his Units will be automatically converted by our managing general partner to limited partner Units after all of our wells have been drilled and completed. See Item 1 “Business.” Currently, the conversion has not occurred, because we have not yet drilled and completed all of our wells.

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After the investor general partner Units are converted to limited partner Units, which is a nontaxable event, the participant will have the lesser liability of a limited partner under Delaware law for our obligations and liabilities that arise after the conversion, subject to the exceptions described above. However, an investor general partner will continue to have the responsibilities of a general partner for liabilities and obligations that we incurred before the effective date of the conversion. For example, an investor general partner might become liable for any liabilities we incurred in excess of his subscription amount during the time we engaged in drilling activities and for environmental claims that arose during drilling activities, but were not discovered until after conversion. This could result in the former investor general partner being required to make payments, in addition to his original investment, in amounts that are impossible to predict because of their uncertain nature.

Distributions and Subordination. Our managing general partner will review our accounts at least monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any. Subject to our managing general partner’s subordination obligation as described below, our managing general partner and our participants share in all of our production revenues in the same percentage as their respective capital contribution bears to our total capital contributions, except that our managing general partner receives an additional 10% of our natural gas and oil revenues. As of December 31, 2010, our managing general partner received 33.75% of our production revenues and our participants received 66.25% of our production revenues. Subject to the foregoing, these sharing percentages will be adjusted based on the final amount of our managing general partner’s capital contributions to us after all of our wells have been drilled and completed. See our partnership agreement for special allocations between our managing general partner and our participants of equipment proceeds, lease proceeds and interest income.

Our partnership agreement is structured to provide our participants with cash distributions equal to at least 12% of capital ($2,400 per $20,000 unit) in the first 12-month subordination period, 10% of capital ($2,000 per $20,000 unit) in each of the next three 12-month subordination periods, and 8% of capital ($1,600 per $20,000 unit) in the fifth 12-month subordination period, based on a subscription price of $20,000 per Unit regardless of the actual subscription price paid by any participant for a Unit, beginning when our managing general partner determines that natural gas or oil is being sold from at least 75% of our wells, excluding any wells drilled that were nonproductive. To help achieve this investment feature, under our partnership agreement our managing general partner will subordinate up to 50% of its share of our partnership net production revenues during this subordination period. The term “partnership net production revenues” means our gross revenues from the sale of our natural gas and oil production from our wells after deduction of the related operating costs, direct costs, administrative costs, and all other costs not specifically allocated in the partnership agreement. However, if our wells produce only small natural gas and oil volumes, and/or natural gas and oil prices decrease, then even with subordination a participant may not receive the return of capital for each of the first five years as described above, or a return of all of his capital during our term, because the subordination is not a guarantee.

Subordination distributions will be determined by debiting or crediting our current period revenues to our managing general partner as may be necessary to provide the distributions to our participants. At any time during the 60- month aggregate subordination period our managing general partner is entitled to an additional share of our revenues to recoup previous subordination distributions to the extent cash distributions from us to our participants would exceed the return of capital described above. The specific formula is set forth in Section 5.01(b)(4)(a) of our partnership agreement.

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Participant Allocations. Our participants’ share as a group of our revenues, gains, income, costs, expenses, losses, and other charges and liabilities generally are charged and credited among our participants in accordance with their respective number of Units, based on $20,000 per Unit regardless of the actual subscription price paid by any participant for a Unit. These allocations also take into account any investor general partner’s status as a defaulting investor general partner.

Certain participants, however, paid a reduced amount to acquire their Units. Thus, our intangible drilling costs and our participants’ share of our equipment costs to drill and complete our wells are charged among our participants in accordance with the respective subscription price they paid for their Units, rather than their respective number of Units.

Term, Dissolution and Distributions on Liquidation. We will continue in existence for 50 years unless we are terminated earlier by a final terminating event as described below, or by an event which causes the dissolution of a limited partnership under the Delaware Revised Uniform Limited Partnership Act. However, if an event which causes our dissolution under state law is not a final terminating event, then a successor limited partnership will automatically be formed. Thus, only on a final terminating event will we be liquidated. A final terminating event is any of the following:

• the election to terminate us by our managing general partner or the affirmative vote of our participants whose Units equal a majority of our total Units;

• our termination under Section 708(b)(1)(A) of the Internal Revenue Code because no part of our business is being carried on; or

• we cease to be a going concern.

On our liquidation a participant will receive his capital interest in us. Generally, this means an undivided interest in our assets, after payments to our creditors, in the ratio the participant’s capital account bears to all of the capital accounts in us until all capital accounts have been reduced to zero. Thereafter, the participant’s capital interest in our remaining assets will equal the participant’s interest in our related revenues.

Any in-kind property distributions to a participant from us must be made to a liquidating trust or similar entity, unless the participant affirmatively consents to receive an in-kind property distribution after being told the risks associated with the direct ownership of our natural gas and oil properties or there are alternative arrangements in place which assure that the participant will not be responsible for the operation or disposition of our natural gas and oil properties. If our managing general partner has not received a participant’s written consent to the in-kind distribution within 30 days after it is mailed, then it will be presumed that the participant did not consent. Our managing general partner may then sell the asset at the best price reasonably obtainable from an independent third-party, or to itself or its affiliates at fair market value as determined by an independent expert selected by our managing general partner. Also, if we are liquidated our managing general partner will be repaid for any debts owed it by us before there are any distributions to our participants.

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Transferability. Our Units may not be sold, assigned or otherwise transferred unless certain conditions set forth in our partnership agreement are satisfied, including:

• an opinion of counsel acceptable to our managing general partner that the transfer of the Unit does not require registration and qualification under the Securities Act of 1933 and applicable state securities laws, unless this requirement is waived by our managing general partner; and

• a determination under the tax laws that a transfer of the Unit would not, in the opinion of our counsel, result in our termination for tax purposes or our being treated as a “publicly-traded” partnership for tax purposes.

Also, under the partnership agreement transfers are subject to the following limitations:

• except as provided by operation of law, we will recognize the transfer of only one or more whole Units unless the participant making the transfer owns less than a whole Unit, in which case the entire fractional interest in the Unit must be transferred;

• the costs and expenses associated with the transfer must be paid by the participant transferring the Unit;

• the form of transfer must be in a form satisfactory to our managing general partner; and

• the terms of the transfer must not contravene those of our partnership agreement.

A transfer of a participant’s Unit will not relieve the participant of responsibility for any obligations related to his Unit under the partnership agreement. Also, the transfer of a Unit does not grant rights under the partnership agreement, as among the transferees, to more than one party unanimously designated by the transferees to our managing general partner. Further, the transfer of a Unit does not require an accounting by our managing general partner.

Finally, a sale of a participant’s Units could create adverse tax and economic consequences for the participant. The sale or exchange of Units held for more than 12 months generally will result in recognition of long-term capital gain or loss. However, previous deductions by the participant for depreciation, depletion and intangible drilling costs may be recaptured as ordinary income rather than capital gain, regardless of how long the participant owned the Units. If the Units are held for 12 months or less, then the gain or loss generally will be short-term gain or loss. The participant’s pro rata share of our liabilities, if any, as of the date of the sale or exchange must be included in the amount realized by the participant. Thus, the gain recognized by the participant may result in a tax liability greater than the cash proceeds, if any, received by the participant from the sale or other taxable disposition of his Units.

Under our partnership agreement, an assignee (transferee) of a Unit may become a substituted partner only on meeting certain further conditions. The conditions to become a substituted partner are as follows:

• the assignor (transferor) gives the assignee the right;

• our managing general partner consents to the substitution;

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

• the assignee executes and delivers, in a form acceptable to our managing general partner, the instruments necessary to establish that a legal transfer has taken place and to confirm his or her agreement to be bound by all terms and provisions of the partnership agreement.

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A substituted partner is entitled to all of the rights of full ownership of the assigned Units, including the right to vote. We will amend our records at least once each calendar quarter to effect the substitution of substituted partners.

Presentment Feature. Beginning in 2015 a participant may present his Units to our managing general partner for purchase. However, a participant is not required to offer his Units to our managing general partner, and may receive a greater return if the Units are retained.

Our managing general partner has no obligation to establish a reserve to satisfy the presentment obligation, and it does not intend to do so. Our managing general partner may immediately suspend its purchase obligation by notice to our participants if it determines, in its sole discretion, that it does not have the necessary cash flow or cannot arrange financing or other consideration for this purpose on terms it deems reasonable.

Our managing general partner will not purchase less than one Unit unless the fractional Unit represents the participant’s entire interest in us, nor more than 5% of our total Units in any calendar year. If fewer than all of the Units presented at any time are to be purchased, then the Units to be purchased will be selected by lot. Our managing general partner may not waive the limit on its purchasing more than 5% of our total Units in any calendar year.

Our managing general partner’s obligation to purchase the Units presented by our participants may be discharged for its benefit by a third-party or an affiliate of our managing general partner. The Unit will be transferred to the party who pays for it, along with the delivery of an executed assignment. The presentment must be within 120 days of our reserve report discussed below and, in accordance with Treas. Reg. §1.7704-1(f), the purchase may not be made by our managing general partner until at least 60 calendar days after written notice of the participant’s intent to present the Unit was made.

The amount of the presentment price will be the greater of the following amounts:

• three times the amount of our total distributions to a participant during the previous twelve months; or

• the amount that is generally attributable to the participant’s share of our natural gas and oil reserves, as discussed below.

The amount of the presentment price attributable to our natural gas and oil reserves will be determined based on our last reserve report. Beginning in 2012, and every year thereafter, our managing general partner will prepare an annual reserve report of our natural gas and oil proved reserves which will be reviewed by an independent expert. The presentment price to a participant will be based on his share of our net assets and liabilities as described below, based on the ratio that his number of Units bears to the total number of our Units. The presentment price will include the participant’s share of the sum of the following partnership items:

• an amount based on 70% of the present worth of future net revenues from our proved reserves as described our most recent reserve report as described above;

• cash on hand;

• prepaid expenses and accounts receivable, less a reasonable amount for doubtful accounts; and

• the estimated market value of all assets not separately specified above, determined in accordance with standard industry valuation procedures.

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There will be deducted from the foregoing sum the following items:

• an amount equal to the participant’s share of all debts, obligations, and other liabilities, including accrued expenses; and

• any distributions made to the participant between the date of the request and the actual payment. However, if any cash distributed was derived from the sale, after the presentment request, of oil, natural gas, or a producing property, for purposes of determining the reduction of the presentment price the distributions will be discounted at the same rate used to take into account the risk factors employed to determine the present worth of our proved reserves.

The amount may be further adjusted by our managing general partner for estimated changes from the date of the reserve report to the date of payment of the presentment price because of various considerations described in our partnership agreement.

Voting Rights and Amendments. Other than as set forth below, a participant generally will not be entitled to vote on any of our partnership matters at any meeting. However, at any time participants whose Units equal 10% or more of our total Units may call a meeting to vote, or vote without a meeting, on the matters set forth below without the concurrence of our managing general partner. On the matters being voted on a participant is entitled to one vote per Unit or, if the participant owns a fractional Unit, that fraction of one vote equal to the fractional interest in the Unit. Participants whose Units equal a majority of our total Units may vote to:

• dissolve us;

• remove our managing general partner and elect a new managing general partner;

• elect a new managing general partner if our managing general partner elects to withdraw from the partnership;

• remove the operator and elect a new operator;

• approve or disapprove the sale of all or substantially all of our assets;

• cancel any contract for services with our managing general partner, the operator, or their affiliates, which is not otherwise described in the private placement memorandum for the offering of our Units or our partnership agreement without penalty on 60 days notice; and

• amend our partnership agreement; provided however, any amendment may not:

• without the approval of our participants or our managing general partner, increase the duties or liabilities of the participants or our managing general partner or increase or decrease the profits or losses or required capital contribution of our participants or our managing general partner; or

• without the unanimous approval of our participants, affect the classification of our income and loss for federal income tax purposes.

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Although our managing general partner and its officers, directors, and affiliates could have voted on certain issues as a participant if they had purchased Units, they did not purchase any Units. In addition to amendments by our participants as described above, amendments to our partnership agreement may be proposed in writing by our managing general partner and adopted with the consent of participants whose Units equal a majority of our total Units. Our partnership agreement may also be amended by our managing general partner without the consent of our participants for certain limited purposes set forth in our partnership agreement.

Books and Records. Our managing general partner is required to keep books and records of all of our financial activities in accordance with generally accepted accounting principles. A participant may inspect and copy any of the records, including a list of our participants subject to the conditions described below, at any reasonable time after giving adequate notice to our managing general partner. Access to the list of our participants is subject to the following conditions:

• an alphabetical list of the names, addresses, and business telephone numbers of our participants along with the number of Units held by each of them (the “Participant List”) must be maintained as a part of our books and records and be available for inspection by any participant or his designated agent at our home office on the participant’s request;

• the Participant List must be updated at least quarterly to reflect changes in the information contained in the Participant List;

• a copy of the Participant List must be mailed to any participant requesting the Participant List within 10 days of the written request;

• the purposes for which a participant may request a copy of the Participant List include, without limitation, matters relating to the participant’s voting rights under our partnership agreement and the exercise of participant’s rights under the federal proxy laws; and

• our managing general partner may refuse to exhibit, produce, or mail a copy of the Participant List as requested if our managing general partner believes that the actual purpose and reason for the request for inspection or for a copy of the Participant List is to secure the list or other information for the purpose of selling the list or information or copies of the list, or of using the same for a commercial purpose other than in the interest of the applicant as a participant relative to our affairs. Our managing general partner will require the participant requesting the Participant List to represent in writing that the list was not requested for a commercial purpose unrelated to the participant’s interest in us.

Also, our managing general partner may keep logs, well reports, and other drilling and operating data confidential for reasonable periods of time.

Restrictions on Roll-Up Transactions. In connection with any proposed transaction which is considered a “Roll-up Transaction” involving us and the issuance of securities of an entity (a “Roll-up Entity”) that would be created or would survive after the successful completion of the Roll-up Transaction, an appraisal of all of our natural gas and oil properties must be obtained from a competent independent appraiser. Our properties must be appraised on a consistent basis, and the appraisal must be based on the evaluation of all relevant information and must indicate the value of our properties as of a date immediately before the announcement of the

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proposed Roll-up Transaction. The appraisal must assume an orderly liquidation of our properties over a 12-month period. The terms of the engagement of the independent appraiser must clearly state that the engagement is for the benefit of us and our participants. A summary of the appraisal, indicating all of the material assumptions underlying the appraisal, must be included in a report to our participants in connection with the proposed Roll-up Transaction. A “Roll-up Transaction” is transaction involving our acquisition, merger, conversion or consolidation, directly or indirectly, and the issuance of securities of a Roll-up Entity. This term does not include:

• a transaction involving our securities that have been listed on a national securities exchange or included for quotation on Nasdaq National Market System for at least 12 months; or

• a transaction involving only our conversion to corporate, trust, or association form if, as a consequence of the transaction, there will be no significant adverse change in any of the following: voting rights; the term of our existence; compensation to our managing general partner; or our investment objectives.

In connection with a proposed Roll-up Transaction, the person sponsoring the Roll-up Transaction must offer to our participants who vote “no” on the proposal the choice of:

• accepting the securities of the Roll-up Entity offered in the proposed Roll-up Transaction; or

• one of the following:

• remaining as participants in us and preserving their interests in us on the same terms and conditions as existed previously, or

• receiving cash in an amount equal to each participant’s pro rata share of the appraised value of our net assets.

We are prohibited from participating in any proposed Roll-Up Transaction:

• which would result in the diminishment of any participant’s voting rights under the Roll-up Entity’s chartering agreement or limit the ability of a participant to exercise the voting rights of its securities of the Roll-up Entity on the basis of the number of our Units held by the participant;

• in which the democracy rights of our participants in the Roll-up Entity would be less than those provided for under §§4.03(c)(1) and 4.03(c)(2) of our partnership agreement or, if the Roll-up Entity is a corporation, then the democracy rights of our participants must correspond to the democracy rights provided for our participants in our partnership agreement to the greatest extent possible;

• which includes provisions that would operate to materially impede or frustrate the accumulation of shares by any purchaser of the securities of the Roll-up Entity, except to the minimum extent necessary to preserve the tax status of the Roll-up Entity;

• in which our participants’ rights of access to the records of the Roll-up Entity would be less than those provided for under §§4.03(b)(5), 4.03(b)(6) and 4.03(b)(7) of our partnership agreement;

• in which any of the costs of the transaction would be borne by us if our participants whose Units equal a majority of our total Units do not vote to approve the proposed Roll-Up Transaction; and

• unless the Roll-up Transaction is approved by our participants whose Units equal a majority of our total Units.

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We currently have no plans to enter into a Roll-Up Transaction.

Withdrawal of Managing General Partner. After 10 years our managing general partner may voluntarily withdraw as our managing general partner for whatever reason by giving 120 days’ written notice to our participants. Although our withdrawing managing general partner is not required to provide a substitute managing general partner, a new managing general partner may be substituted by the affirmative vote of our participants whose Units equal a majority of our total Units. If our participants, however, choose to terminate our existence and do not select a substitute managing general partner, then we would terminate and dissolve which could result in adverse tax and other consequences to our participants.

Also, our managing general partner may assign its general partner interest in us to its affiliates and it may withdraw a property interest from us in the form of a working interest in our wells equal to or less than its revenue interest in us without the consent of our participants.

ITEM 12. INDEMNIFICATION OF DIRECTORS AND OFFICERS.

Under the terms of our partnership agreement, our managing general partner, the operator, and their affiliates have limited their liability to us and our participants for any loss suffered by us or the participants which arises out of any action or inaction on their part if:

• they determined in good faith that the course of conduct was in our best interest;

• they were acting on our behalf or performing services for us; and

• their course of conduct did not constitute negligence or misconduct.

In addition, our partnership agreement provides for our indemnification of our managing general partner, the operator, and their affiliates against any losses, judgments, liabilities, expenses, and amounts paid in settlement of any claims sustained by them in connection with us provided that they meet the standards set forth above. However, there is a more restrictive standard for indemnification for losses arising from or out of an alleged violation of federal or state securities laws. Also, to the extent that any indemnification provision in our partnership agreement purports to include indemnification for liabilities arising under the Securities Act of 1933, as amended, in the SEC’s opinion this indemnification is contrary to public policy and therefore unenforceable.

Payments arising from the indemnification or agreement to hold harmless described above are recoverable only out of our tangible net assets, including our revenues, and any insurance proceeds. Still, the use of our funds or assets for indemnification of our managing general partner, the operator or an affiliate would reduce amounts available for our operations or for distribution to our participants.

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Under our partnership agreement, we are not allowed to pay the cost of the portion of any insurance that insures our managing general partner, the operator, or an affiliate against any liability for which they cannot be indemnified as described above. However, our funds can be advanced to them for legal expenses and other costs incurred in any legal action for which indemnification is being sought if we have adequate funds available and certain conditions in our partnership agreement are met.

ITEM 13. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Index to Financial Statements

ATLAS RESOURCES SERIES 28-2010 L.P.

	Page
Report of Independent Registered Public Accounting Firm		60
Balance Sheet as of December 31, 2010		61
Statement of Operations for the Period April 1, 2010 (commencement of operations) through December 31, 2010		62
Statement of Comprehensive Income for the Period April 1, 2010 (commencement of operations) through December 31, 2010		63
Statement of Changes in Partners’ Capital for the Period April 1, 2010 (commencement of operations) through December 31, 2010		64
Statement of Cash Flows for the Period April 1, 2010 (commencement of operations) through December 31, 2010		65
Notes to Financial Statements December 31, 2010		66

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of
Atlas Resources Series #28-2010 L.P.

We have audited the accompanying balance sheet of Atlas Resources Series #28-2010 L.P. (a Delaware Limited Partnership) as of December 31, 2010, and the related statement of operations, comprehensive income, changes in partners’ capital, and cash flows for the period April 1, 2010 (commencement of operations) through December 31, 2010. 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 audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides 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 Resources Series #28-2010 L.P. as of December 31, 2010, and the results of its operations and its cash flows for the period April 1, 2010 (commencement of operations) through December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Cleveland, Ohio
April 29, 2011

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ATLAS RESOURCES SERIES 28-2010 L.P.

BALANCE SHEET
DECEMBER 31,

	2010
ASSETS
Current assets:
Cash and cash equivalents	$	—
Accounts receivable-affiliate		1,153,700
Short-term hedge receivable due from affiliate		1,325,500
Total current assets		2,479,200
Oil and gas properties, net		100,874,300
Construction in progress		65,071,800
Long-term hedge receivable due from affiliate		1,665,800
	$	170,091,100
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	34,900
Short-term hedge liability due to affiliate		4,300
Total current liabilities		39,200
Asset retirement obligations		1,407,800
Long-term hedge liability due to affiliate		162,300
Partners’ capital:
Managing general partner		17,468,800
Limited partners (7,500 units)		148,188,300
Accumulated other comprehensive income		2,824,700
Total partners’ capital		168,481,800
	$	170,091,100

See accompanying notes to financial statements.

61

ATLAS RESOURCES SERIES 28-2010 L.P.

STATEMENT OF OPERATIONS
FOR THE PERIOD APRIL 1, 2010 (commencement of operations)

THROUGH DECEMBER 31, 2010

	2010
REVENUES
Natural gas	$	2,159,900
Total revenues		2,159,900
COST AND EXPENSES
Production		1,000,600
Depletion		1,549,400
Dry hole costs		1,279,000
General and administrative		40,500
Total expenses		3,869,500
Net loss	$	(1,709,600	)
Allocation of net loss:
Managing general partner	$	(173,300	)
Limited partners	$	(1,536,300	)
Net loss per investor partnership unit	$	(205	)

See accompanying notes to financial statements.

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ATLAS RESOURCES SERIES 28-2010 L.P.

STATEMENT OF COMPREHENSIVE INCOME
FOR THE PERIOD APRIL 1, 2010 (commencement of operations)

THROUGH DECEMBER 31, 2010

	2010
Net loss	$	(1,709,600	)
Other comprehensive income:
Unrealized holding gain on hedging contracts		3,013,200
Less: reclassification adjustment for gains realized in net loss		(188,500	)
Total other comprehensive income		2,824,700
Comprehensive income	$	1,115,100

See accompanying notes to financial statements.

63

ATLAS RESOURCES SERIES 28-2010 L.P.

STATEMENT OF CHANGES IN PARTNERS’ CAPITAL
FOR THE PERIOD APRIL 1, 2010 (commencement of operations) THROUGH DECEMBER 31, 2010

							Accumulated
	Managing						Other
	General			Limited			Comprehensive
	Partner			Partners			Income		Total
Balance at April 1, 2010	$	100		$	—		$	—	$	100
Partners’ capital contributions:
Capital contribution		—			149,724,600			—		149,724,600
Syndication and offering costs		16,267,000			—			—		16,267,000
Tangible equipment/leasehold costs		17,642,100			—			—		17,642,100
Total contributions		33,909,100			149,724,600			—		183,633,700
Syndication and offering costs, immediately charged to capital		(16,267,000	)		—			—		(16,267,000	)
		17,642,100			149,724,600			—		167,366,700
Participation in revenue and costs and expenses:
Net production revenues		391,300			768,000			—		1,159,300
Depletion		(408,300	)		(1,141,100	)		—		(1,549,400	)
Dry hole costs		(142,600	)		(1,136,400	)		—		(1,279,000	)
General and administrative		(13,700	)		(26,800	)		—		(40,500	)
Net loss		(173,300	)		(1,536,300	)		—		(1,709,600	)
Other comprehensive income		—			—			2,824,700		2,824,700
Initial capital contribution returned		(100	)		—			—		(100	)
Balance at December 31, 2010	$	17,468,800		$	148,188,300		$	2,824,700	$	168,481,800

See accompanying notes to financial statements.

64

ATLAS RESOURCES SERIES 28-2010 L.P.

STATEMENT OF CASH FLOWS
FOR THE PERIOD APRIL 1, 2010 (commencement of operations)

THROUGH DECEMBER 31, 2010

	2010
Cash flows from operating activities:
Net loss	$	(1,709,600	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depletion		1,549,400
Dry hole costs		1,279,000
Increase in accounts receivable-affiliate		(1,153,700	)
Increase in accrued liabilities		34,900
Net cash provided by operating activities		—
Cash flows from investing activities:
Oil and gas well drilling contracts paid to MGP		(149,724,600	)
Net cash used in investing activities		(149,724,600	)
Cash flows from financing activities:
Partners’ capital contributions		149,724,600
Net cash provided by financing activities		149,724,600
Net increase in cash and cash equivalents		—
Cash and cash equivalents at beginning of period		—
Cash and cash equivalents at end of period	$	—
Supplemental Schedule of non-cash investing and financing activities:
Assets contributed by the managing general partner:
Tangible equipment	$	12,588,300
Lease costs		5,053,800
Syndication and offering costs		16,267,000
	$	33,909,100
Asset retirement obligation	$	1,407,800

See accompanying notes to financial statements.

65

ATLAS RESOURCES SERIES 28-2010 L.P.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2010

NOTE 1 — DESCRIPTION OF BUSINESS

Atlas Resources Series 28-2010 L.P. (the “Partnership”) is a Delaware limited partnership, which commenced operations on April 1, 2010 and had production begin in June 2010, with Atlas Resources, LLC serving as its Managing General Partner and Operator (Atlas Resources or “MGP”). Atlas Resources, LLC is an indirect subsidiary of Atlas Energy, Inc., (“Atlas Energy”) (NASDAQ: ATLS). Atlas Energy’s focus is on the development and/or production of natural gas and oil in the Appalachian, Michigan, Illinois, and/or Colorado basin regions of the United States of America. Atlas Energy is also a leading sponsor of and manages tax-advantaged direct investment partnerships, in which it co-invests to finance the exploitation and development of its acreage. Atlas Energy Resource Services, Inc. provides Atlas Energy with the personnel necessary to manage its assets and raise capital.

On February 17, 2011, Atlas Pipeline Holdings, L.P. (“AHD”) (NYSE: AHD), a then-majority owned subsidiary of Atlas Energy and general partner to Atlas Pipeline Partners, L.P. (“APL”) (NYSE: APL), completed an acquisition of assets from Atlas Energy, which included its investment management business, proved reserves located in the Appalachian Basin, New Albany Shale, Antrim Shale, Chattanooga Shale and Niobrara formations, and other assets. Subsequent to the transaction, AHD changed its name to Atlas Energy, L.P. and assumed control of Atlas Resources.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

Use of Estimates

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

The natural gas industry principally conducts its business by processing actual transactions as much as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the period ended December 31, 2010 represent actual results in all material respects (see “Revenue Recognition” accounting policy for further description).

Accounts Receivable and Allowance for Possible Losses

In evaluating the need for an allowance for possible losses, the MGP performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness as determined by review of its customers’ credit information. Credit is extended on an unsecured basis to many of its energy customers. At December 31, 2010 the Partnership’s MGP’s credit evaluation indicated that the Partnership had no need for an allowance for possible losses.

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ATLAS RESOURCES SERIES 28-2010 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Fair Value of Financial Instruments

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

Supplemental Cash Flow Information

The Partnership considers temporary investments with a maturity at the date of acquisition of 90 days or less to be cash equivalents. No cash was paid by the Partnership for interest or income taxes for the period ended December 31, 2010.

Oil and Gas Properties

Oil and gas properties are stated at cost. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized. The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Oil is converted to gas equivalent basis (“Mcfe”) at the rate of one barrel equals 6 Mcf.

The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of developed producing properties. Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the cost from the property accounts and the resultant gain or loss is reclassified to the Partnership’s statement of operations. The Partnership recorded $1,279,000 of dry hole costs for the period ended December 31, 2010 from oil and gas properties to the statement of operations from the retirement of Tennessee producing activities. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its balance sheet. As a result of retirements, the Partnership reclassified $704,700 for the period ended December 31, 2010, from oil and gas properties to accumulated depletion. At December 31, 2010, construction in progress was $65,071,800, which represented Limited Partner funds paid to the MGP for the completion of natural gas and oil wells.

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.

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ATLAS RESOURCES SERIES 28-2010 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Impairment of Long-Lived Assets (Continued)

The review of the Partnership’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce proved reserves. Expected future cash flow from the sale of 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. During the period ended December 31, 2010, the Partnership did not recognize an asset impairment related to oil and gas properties.

Working Interest

The Partnership Agreement establishes that revenues and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). The MGP is also provided an additional working interest of 10% as provided in the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expenses until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues and expenses based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.

Revenue Recognition

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

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ATLAS RESOURCES SERIES 28-2010 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue Recognition (Continued)

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas 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 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, 2010 of $856,100, which are included in accounts receivable — affiliate within the Partnership’s balance sheet.

Asset Retirement Obligation

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

Environmental Matters

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

Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. Atlas Energy maintains insurance that may cover in whole or in part, certain environmental expenditures. For the period ended December 31, 2010, the Partnership had no environmental matters requiring specific disclosure or the recording of a liability.

Comprehensive Income

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

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ATLAS RESOURCES SERIES 28-2010 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Recently Adopted Accounting Standards

In April 2010, the FASB issued Accounting Standards Update 2010-14, “Accounting for Extractive Industries — Oil & Gas: Amendments to Paragraph 932-10-S99-1” (“Update 2010-14”). Update 2010-14 provides amendments to add the SEC’s Regulation S-X Rule 4-10, “Financial Accounting and Reporting for Oil and Gas Producing Activities Pursuant to the Federal Securities Laws and the Energy Policy and Conservation Act of 1975” (“S-X Rule 4-10”) to Accounting Standards Codification (“ASC”) Topic 932 “Extractive Activities — Oil and Gas”. S-X Rule 4-10 was included in the SEC’s Final Rule, “Modernization of Oil and Gas Reporting, which became effective January 1, 2010. As Update 2010-14 only served to align the FASB’s ASC Topic 932 with the SEC’s S-X Rule 4-10, its adoption did not have a material impact on the Partnership’s financial position, results of operations or related disclosures.

In February 2010, the FASB issued Accounting Standards Update 2010-09, “Subsequent Events (Topic 855): Amendments to Certain Recognition and Disclosure Requirements” (“Update 2010-09”). Update 2010-09 removes the requirement for an SEC filer to disclose a date through which subsequent events have been evaluated in both issued and revised financial statements. Revised financial statements include financial statements revised as a result of either correction of an error or retrospective application of U.S. generally accepted accounting standards. The requirements of Update 2010-09 were effective upon its issuance on February 24, 2010. The requirements of Update 2010-09 were applied upon its adoption, and it did not have an impact on the Partnership financial position, results of operations or related disclosures.

In January 2010, the FASB issued Accounting Standards Update 2010-06, “Fair Value Measurement and Disclosures (Topic (820) — Improving Disclosures about Fair Value Measurement” (“Update 2010-06”). Update 2010-06 clarifies and requires new disclosures about the transfer of amounts between Level 1 and Level 2, as well as significant transfers in and out of Level 3. In addition, for Level 2 and Level 3 measurements, Update 2010-06 requires additional disclosure about the valuation technique used or any changes in technique. Update 2010-06 also clarifies that entities must disclose fair value measurements by classes of assets and liabilities, based on the nature and risks of the assets and liabilities. The requirements of Update 2010-06 are effective at the start of a reporting entity’s first fiscal year beginning after December 15, 2009 (January 1, 2010 for the Partnership). The requirements of Update 2010-06 were applied upon its adoption on April 1, 2010 and it did not have a material impact on the Partnership’s financial position, results of operations or related disclosures.

Major Customers

The Partnership’s natural gas is sold under contract to various purchasers. For the period ended December 31, 2010, sales to Atmos Energy Marketing, LLC accounted for 98%, of total revenues. No other customers accounted for 10% or more of total revenues for the period ended December 31, 2010.

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ATLAS RESOURCES SERIES 28-2010 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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.

NOTE 3 — PARTICIPATION IN REVENUES AND COSTS

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

	Managing
	General			Limited
	Partner			Partners
Organization and offering costs		100	%		0	%
Lease costs		100	%		0	%
Revenues (1)		33.75	%		66.25	%
Operating costs, administrative costs, direct costs and all other operating costs (2)		33.75	%		66.25	%
Intangible drilling costs		0	%		100	%
Tangible equipment costs		46	%		54	%

(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 10% 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 — OIL AND GAS PROPERTIES

The following is a summary of oil and gas properties:

	December 31,
	2010
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	4,812,700
Wells and related equipment		96,906,300
		101,719,000
Accumulated depletion		(844,700	)
	$	100,874,300

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ATLAS RESOURCES SERIES 28-2010 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010

NOTE 5 — ASSET RETIREMENT OBLIGATION

The Partnership recognizes an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. It also recognizes a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depletion.

The estimated liability is based on the MGP’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed 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 oil and gas properties, the Partnership has determined that there are no other material retirement obligations associated with tangible long-lived assets.

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

	Period
	Ended
	December 31,
	2010
Asset retirement obligation at beginning of period	$	—
Liabilities incurred from drilling wells		1,407,800
Asset retirement obligations at end of year	$	1,407,800

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 its commodity price risk management activities. The MGP enters into financial instruments to hedge its forecasted natural gas and crude oil sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas and crude oil is sold. Under swap agreements, the MGP receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not obligation, to purchase or sell natural gas and crude oil at a fixed price for the relevant contract period.

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ATLAS RESOURCES SERIES 28-2010 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010

NOTE 6 — DERIVATIVE INSTRUMENTS (Continued)

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

Derivatives are recorded on the Partnership’s balance sheet as assets or liabilities at fair value. The Partnership reflected a net derivative asset on its balance sheet of $2,824,700 at December 31, 2010. Of the $2,824,700 net unrealized gain in accumulated other comprehensive income at December 31, 2010, if the fair values of the instruments remain at current market values, the Partnership will reclassify $1,321,200 of gains to the Partnership’s statement of operations over the next twelve month period as these contracts expire. Aggregate gains of $1,503,500 will be reclassified to the Partnership’s statement of operations in later periods as these remaining contracts expire. Actual amounts that will be reclassified will vary as a result of future price changes.

The following table summarizes the fair value of the Partnership’s derivative instruments as of December 31, 2010, as well as the gain or loss recognized in the statement of operations for effective derivative instruments for the period ended December 31, 2010:

Fair Value of Derivative Instruments:

		Asset Derivatives			Liability Derivatives
Derivatives in		Fair Value			Fair Value
Cash Flow	Balance Sheet	December 31,		Balance Sheet	December 31,
Hedging Relationships	Location	2010		Location	2010
Commodity contracts:	Current assets	$	1,325,500	Current liabilities	$	(4,300	)
	Long-term assets		1,665,800	Long-term liabilities		(162,300	)
Total derivatives		$	2,991,300		$	(166,600	)

Effects of Derivative Instruments on Statement of Operations:

	Gain			Gain
	Recognized in OCI			Reclassified from OCI
	on Derivative		Location of Gain	into Net Loss
	(Effective Portion)		Reclassified from	(Effective Portion)
Derivatives in	Period Ended		Accumulated	Period Ended
Cash Flow	December 31,		OCI into Loss	December 31,
Hedging Relationships	2010		(Effective Portion)	2010
Commodity contracts	$	3,013,200	Natural gas and oil revenue	$	188,500

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ATLAS RESOURCES SERIES 28-2010 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010

NOTE 6 — DERIVATIVE INSTRUMENTS (Continued)

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

In December 2010, the MGP, on behalf of the Partnership, allocated approximately $2,500 in net proceeds from the early settlement of natural gas derivative positions for production periods during 2012. The gain realized upon the early terminations of these derivative positions is reported in accumulated other comprehensive income and will be reclassified to the Partnership’s statement of operations in the same periods in which the hedged production revenues would have been recognized in earnings. The $2,500 in net proceeds is recorded in the hedge receivable balance on the Partnership’s balance sheet at December 31, 2010.

As of December 31, 2010, Atlas Energy had allocated to the Partnership the following natural gas volumes hedged:

Natural Gas Fixed Price Swaps

Production			Average
Period Ending	Volumes		Fixed Price		Fair Value
December 31,	(MMbtu)(1)		(per MMbtu)(1)		Asset (2)
2011		302,200	$	6.978	$	813,600
2012		318,300		7.478		739,200
2013		295,600		6.831		474,800
2014		34,200		5.941		11,800
					$	2,039,400

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ATLAS RESOURCES SERIES 28-2010 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010

NOTE 6 — DERIVATIVE INSTRUMENTS (Continued)

Natural Gas Costless Collars

Production				Average
Period Ending	Option	Volumes		Floor & Cap		Fair Value
December 31,	Type	(MMbtu)(1)		(per MMbtu)(1)		Asset/(Liability) (2)
2011	Puts purchased		237,200	$	6.544	$	511,900
2011	Calls sold		237,200		7.662		(4,300	)
2012	Puts purchased		88,300		6.117		149,600
2012	Calls sold		88,300		7.343		(18,600	)
2013	Puts purchased		137,200		5.862		197,900
2013	Calls sold		137,200		7.045		(88,300	)
2014	Puts purchased		58,000		5.712		87,000
2014	Calls sold		58,000		6.819		(52,400	)
						$	782,800
				Total Net Asset		$	2,822,200

(1)	MMBTU represents million British Thermal Units.
(2)	Fair value based on forward NYMEX natural gas prices, as applicable.

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. The hierarchy defines three levels of inputs that may be used to measure fair value.

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

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

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Partnership uses a fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 6). 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 fair value measurements.

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ATLAS RESOURCES SERIES 28-2010 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010

NOTE 7 — FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)

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

The Partnership estimates the fair value of asset retirement obligations using Level 3 inputs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements; the credit-adjusted risk-free rate of the Partnership; and estimated inflation rates (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:

• Drilling contracts to drill and complete wells for the Partnership are charged at cost plus 18%. The cost of the wells includes reimbursement to the Partnership’s MGP of its general and administrative overhead cost. The Partnership paid $149,724,600 to its MGP for the period ended December 31, 2010.

• The Partnership’s MGP contributed undeveloped leases necessary to cover each of the Partnership’s prospects and as of December 31, 2010 received a credit to its capital account in the Partnership of $5,053,800.

• Administrative costs which are included in general and administrative expenses in the Partnership’s statement of operations are payable at $75 per well per month. Administrative costs incurred during the period ended December 31, 2010 were $12,100.

• Monthly well supervision fees which are included in production expenses in the Partnership’s statement of operations are payable at $975 per well per month for Marcellus wells, $1,500 per well per month for New Albany wells, $600 per well per month for horizontal Antrim Shale wells, and for Colorado wells, a fee of $400 is charged per well per month for operating and maintaining the wells. Well supervision fees incurred during the period ended December 31, 2010 were $222,300.

• Transportation fees, which are included in production expenses in the Partnership’s statement of operations, incurred during the period ended December 31, 2010 were $15,800.

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ATLAS RESOURCES SERIES 28-2010 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010

NOTE 8 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS (Continued)

• Assets contributed from the MGP, which are disclosed on the Partnership’s statement of cash flows as non-cash investing and financing activities, for the period ended December 31, 2010, were $17,642,100.

• The MGP received a credit to its capital account of $16,267,000 for the period ended December 31, 2010 for fees, commissions and reimbursement costs to organize the Partnership.

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 sheet represents the net production revenues due from the MGP.

Subordination by Managing General Partner

Under the terms of the Partnership Agreement, the MGP may be required to subordinate up to 50% of its share of net production revenues of the Partnership to the benefit of the limited partners for an amount equal to at least 12% of their net subscriptions in the first 12-month subordination period, 10% of their net subscriptions in each of the next three 12-month subordination periods, and 8% of their net subscriptions in the fifth 12-month subordination period determined on a cumulative basis, in each of the first five years of Partnership operations, commencing when the MGP determines natural gas or oil is being sold from at least 75% of the partnership’s wells, excluding any wells drilled that were non-productive and expiring 60 months from that date.

NOTE 9 — COMMITMENTS AND CONTINGENCIES

Subject to certain conditions, investor partners may present their interests beginning in 2015 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, 2010, the MGP has not withheld any such funds.

Legal Proceedings

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

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

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ATLAS RESOURCES SERIES 28-2010 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010

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

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

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

	December 31,
	2010
Mineral interest in proved properties:	$	4,812,700
Wells and related equipment		96,906,300
Accumulated depletion		(844,700	)
Net capitalized cost	$	100,874,300

(2) Oil and Gas Reserve Information

The preparation of the Partnership’s natural gas and oil reserve estimates were completed in accordance with its prescribed internal control procedures, which include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review. For the period ended December 31, 2010, the Partnership retained Wright & Company, independent, third-party reserves engineers, to prepare a report of proved reserves. The reserves report included a detailed review of our properties. Wright & Company’s evaluation was based on more than 35 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations applicable as of December 31, 2010. The Wright & Company report was prepared in accordance with generally accepted petroleum engineering and evaluation principles.

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

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

	Natural Gas
	(Mcf)
Proved developed reserves:
Beginning of period		—
Extensions, discoveries and other additions		25,108,700
Production		(457,100	)
Balance at December 31, 2010		24,651,600

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ATLAS RESOURCES SERIES 28-2010 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010

NOTE 11 — SUBSEQUENT EVENTS

Atlas Energy, Inc. Asset Acquisition

On February 17, 2011, Atlas Pipeline Holdings, L.P. (“AHD”) (NYSE: AHD), a then-majority owned subsidiary of Atlas Energy and parent of the general partner to Atlas Pipeline Partners, L.P. (“APL”) (NYSE: APL), completed an acquisition of assets from Atlas Energy, which included its investment management business, proved reserves located in the Appalachian Basin, New Albany Shale, Antrim Shale, Chattanooga Shale and Niobrara formations, and other assets (“Asset Acquisition”). As part of the transaction, Atlas Resources, LLC became an indirect subsidiary of AHD. Concurrent with the Asset Acquisition, Atlas Energy and its subsidiaries completed a merger transaction with Chevron Corporation (“Chevron”), whereby each share of Atlas Energy was converted into the right to receive $38.25 in cash as well as a pro rata distribution of all AHD common units owned by Atlas Energy, and Atlas Energy became a wholly-owned subsidiary of Chevron (“Merger”). Subsequent to the Merger, AHD changed its name to Atlas Energy, L.P.

Laurel Mountain Sale

Concurrently with the completion of the Asset Acquisition, APL, an affiliate of the MGP, completed its sale to Atlas Energy Resources, LLC of its 49% non-controlling interest in the Laurel Mountain joint venture.

Hedge Monetization

In conjunction with the “Asset Acquisition,” Atlas Energy monetized all derivative contracts related to natural gas and oil production. The Partnership will share in the total available hedge gains with all other Partnerships sponsored by the MGP. Each Partnership will participate in the monetized funds based on its production volumes during the period of the original derivative contracts.

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ITEM 14. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

ITEM 15. FINANCIAL STATEMENTS AND EXHIBITS

(a) The following documents are filed as part of this Form 10:

1.	Financial Statements
	The financial statements of Atlas Resources Series 28-2010 L.P. as of December 31, 2010 are set forth in Item 13 “Financial Statements and Supplementary Data.”

2. Exhibits

Exhibit No.		Description
	4.1	Certificate of Limited Partnership for Atlas Resources Series 28-2010 L.P.
	4.2	Amended and Restated Certificate and Agreement of Limited Partnership for Atlas Resources Series 28-2010 L.P.
	10.1	Drilling and Operating Agreement for Atlas Resources Series 28-2010 L.P.
	10.2	Gas Gathering Agreement for Natural Gas on the Legacy Appalachian System dated as of June 1, 2009 between Laurel Mountain Midstream, LLC and Atlas America, LLC, Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble LLC, Resource Energy, LLC, Viking Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.
	10.3	Gas Gathering Agreement for Natural Gas on the Expansion Gathering System dated as of June 1, 2009 between Laurel Mountain Midstream, LLC and Atlas America, LLC, Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble LLC, Resource Energy, LLC, Viking Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.
	10.4	Pennsylvania Operating Services Agreement dated as of February 17, 2011 between Atlas Energy, Inc., Atlas Pipeline Holdings, L.P. and Atlas Resources, LLC. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.
	10.5	Petro-Technical Services Agreement, dated as of February 17, 2011 between Atlas Energy, Inc. and Atlas Pipeline Holdings, L.P. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.
	10.6	Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.
	10.7	Amendment No. 1 to the Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC, dated as of January 6, 2011. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.
	10.8	Amendment No. 2 to the Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC, dated as of February 2, 2011. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.
	10.9	Transaction Confirmation, Supply Contract No. 0001, under Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC, dated February 17, 2011. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.

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SIGNATURES

Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized.

	ATLAS RESOURCES SERIES 28-2010 L.P.
	(Registrant)
	By:	Atlas Resources, LLC
		Managing General Partner
Date: April 29, 2011	By:	/s/ Freddie Kotek
		Freddie Kotek, Chairman of the Board of Directors, Chief Executive Officer and President

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EXHIBIT INDEX

Exhibit No.		Description
	4.1	Certificate of Limited Partnership for Atlas Resources Series 28-2010 L.P.
	4.2	Amended and Restated Certificate and Agreement of Limited Partnership for Atlas Resources Series 28-2010 L.P.
	10.1	Drilling and Operating Agreement for Atlas Resources Series 28-2010 L.P.
	10.2	Gas Gathering Agreement for Natural Gas on the Legacy Appalachian System dated as of June 1, 2009 between Laurel Mountain Midstream, LLC and Atlas America, LLC, Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble LLC, Resource Energy, LLC, Viking Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.
	10.3	Gas Gathering Agreement for Natural Gas on the Expansion Gathering System dated as of June 1, 2009 between Laurel Mountain Midstream, LLC and Atlas America, LLC, Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble LLC, Resource Energy, LLC, Viking Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.
	10.4	Pennsylvania Operating Services Agreement dated as of February 17, 2011 between Atlas Energy, Inc., Atlas Pipeline Holdings, L.P. and Atlas Resources, LLC. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.
	10.5	Petro-Technical Services Agreement, dated as of February 17, 2011 between Atlas Energy, Inc. and Atlas Pipeline Holdings, L.P. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.
	10.6	Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.
	10.7	Amendment No. 1 to the Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC, dated as of January 6, 2011. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.
	10.8	Amendment No. 2 to the Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC, dated as of February 2, 2011. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.
	10.9	Transaction Confirmation, Supply Contract No. 0001, under Base Contract for Sale and Purchase of Natural Gas dated as of November 8, 2010 between Chevron Natural Gas, a division of Chevron U.S.A. Inc. and Atlas Resources, LLC, Viking Resources, LLC, and Resource Energy, LLC, dated February 17, 2011. Specific terms in this exhibit have been redacted, as marked by three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.

82