10-K 1 v105743_10k.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2007
OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _________ to __________

Commission file number: 1-33193

ATLAS ENERGY RESOURCES, LLC
(Exact name of registrant as specified in its charter)

Delaware
75-3218520
(State or other jurisdiction or
(I.R.S. Employer
incorporation or organization)
Identification No.)
   
Westpointe Corporate Center One
 
1550 Coraopolis Heights Road
 
Moon Township, PA
15108
(Address of principal executive offices)
Zip Code
   
Registrant’s telephone number, including area code:
412-262-2830
   
Securities registered pursuant to Section 12(b) of the Act:
 

Title of each class
Name of each exchange on which registered
Common units representing Class B
New York Stock Exchange
limited liability company interests
 

Securities registered pursuant to Section 12(g) of the Act: None
Title of class

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

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

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

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

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

Large accelerated filer ¨
Accelerated filer x
Non-accelerated filer ¨

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

The aggregate market value of common units held by non-affiliates of the registrant on June 30, 2007 was approximately $500.7 million.

DOCUMENTS INCORPORATED BY REFERENCE: None
 


ATLAS ENERGY RESOURCES, LLC AND SUBSIDIARIES
INDEX TO ANNUAL REPORT
ON FORM 10-K

     
Page
PART I
Item 1:
Business
4
 
Item 1A:
Risk Factors
20
 
Item 1B:
Unresolved Staff Comments
33
 
Item 2:
Properties
33
 
Item 3:
Legal Proceedings
37
 
Item 4:
Submission of Matters to a Vote of Security Holders
37
       
       
PART II
Item 5:
Market for Registrant's Common Equity and Related Shareholder Matters and Issuer Purchases of Equity Securities 
38
 
Item 6:
Selected Financial Data
39
 
Item 7:
Management’s Discussion and Analysis of Financial Condition and Results of Operations 
42
 
Item 7A:
Quantitative and Qualitative Disclosures about Market Risk 
62
 
Item 8:
Financial Statements and Supplementary Data 
65
 
Item 9:
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
102
 
Item 9A:
Controls and Procedures 
102
 
Item 9B:
Other Information 
104
       
       
PART III
Item 10:
Directors and Executive Officers of the Registrant 
104
 
Item 11:
Executive Compensation 
107
 
Item 12:
Security Ownership of Certain Beneficial Owners and Management 
117
 
Item 13:
Certain Relationships and Related Transactions 
119
 
Item 14:
Principal Accounting Fees and Services 
120
       
       
PART IV
Item 15:
Exhibits and Financial Statement Schedules 
121
       
SIGNATURES 
123
 
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The matters discussed within this report include forward-looking statements. These statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “should,” or “will,” or the negative thereof or other variations thereon or comparable terminology. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this report are forward-looking statements. We have based these forward-looking statements on our current expectations, assumptions, estimates, and projections. While we believe these expectations, assumptions, estimates, and projections are reasonable, such forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control. These and other important factors may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements.

Factors that could cause actual results to differ from those implied by the forward-looking statements in this report are more fully described under Item 1A, “Risk Factors” in this report. Given these risks and uncertainties, you are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this report are made only as of the date hereof. We do not undertake and specifically decline any obligation to update any such statements or to publicly announce the results of any revisions to any of these statements to reflect future events or developments.

We commenced operations in December 2006. References in this report to operations before that date are to our predecessor, Atlas America E&P Operations. In June 2006, Atlas America E&P Operations changed its fiscal year end from September 30 to December 31 and, therefore, information is included in this report for the year ended September 30, 2005, the three-month transition period ended December 31, 2005, and the years ended December 31, 2006 and 2007.

PART I

ITEM 1: BUSINESS

General

We are an independent developer and producer of natural gas and oil, with operations in northern Michigan’s Antrim Shale and the Appalachian Basin. We are a leading sponsor and manager of tax-advantaged direct investment natural gas and oil partnerships in the United States. We believe we have established a strong track record of growing our reserves, production and cash flows through a balanced mix of natural gas and oil exploitation and development and sponsorship of investment partnerships. As of December 31, 2007, our estimated proved reserves were 896.7 Bcfe, including the reserves net to our equity interest in our investment partnerships. Of our reserves, approximately 68% are proved developed and approximately 99% are natural gas. For the year ended December 31, 2007, our average daily production was approximately 89.5 Mmcfe per day and we generated revenues of $577.9 million and net income of $117.5 million.
 
In Michigan, as of December 31, 2007 we had reserves of approximately 666.8 Bcfe and our average daily production for the year ended December 31, 2007 was approximately 59.8 Mmcfe per day.

Since 2003, we have grown our Appalachian reserves and production at compound annual growth rates of approximately 8%. In Appalachia, as of December 31, 2007, we had proved reserves of approximately 229.9 Bcfe and our average daily production for the year ended December 31, 2007 was approximately 29.7 Mmcfe per day. We have experienced drilling success rates of approximately 99% over the last four years. We fund our Appalachian operations through sponsoring and managing investment partnerships. We generate both upfront and ongoing fees from the drilling, production, servicing, and administration of our Appalachian wells in these partnerships.

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We were formed in June 2006 to own and operate substantially all of the natural gas and oil assets and the investment partnership management business of Atlas America, Inc. (Nasdaq: ATLS). Atlas America has been involved in the energy industry since 1968, expanding its operations in 1998 when it acquired The Atlas Group, Inc. and in 1999 when it acquired Viking Resources Corporation, both engaged in the development and production of natural gas and oil and the sponsorship of investment partnerships. We are managed by Atlas Energy Management, Inc., a wholly-owned subsidiary of Atlas America. On June 29, 2007, we acquired DTE Gas & Oil Company from DTE Energy Company (NYSE: DTE), which we refer to as DTE, for $1.273 billion in cash.
 
As of and for the year ended December 31, 2007, we had the following key assets:
 
In our Appalachia gas and oil operations:
 
·  
proved reserves of 229.9 Bcfe including the reserves net to our equity interest in our investment partnerships and our direct interests in producing wells;
 
·  
direct and indirect working interests in approximately 7,722 gross producing gas and oil wells;
 
·  
overriding royalty interests in approximately 627 gross producing gas and oil wells;
 
·  
net daily production of 29.7 Mmcfe per day;
 
·  
approximately 797,800 gross (697,300 net) acres, of which approximately 508,600 gross (501,400 net) acres, are undeveloped; and
 
·  
an interest in a joint venture that gave us the right to drill up to 77 additional net wells before March 31, 2008 on approximately 212,000 acres in Tennessee.
 
In our Michigan gas and oil operations:
 
·  
proved reserves of 666.8 Bcfe
 
·  
direct and indirect working interests in approximately 2,292 gross producing gas and oil wells;
 
·  
overriding royalty interests in approximately 78 gross producing gas and oil wells;
 
·  
net daily production of 59.8 Mmcfe per day; and
 
·  
approximately 357,000 gross (285,100 net) acres, of which approximately 63,000 gross (53,300 net) acres, are undeveloped.
 
In our partnership management business:
 
·  
our investment partnership business, which includes equity interests in 92 investment partnerships and a registered broker-dealer which acts as the dealer-manager of our investment partnership offerings; and
 
·  
managed total proved reserves of 503.7 Bcfe.
 
For the year ended December 31, 2007, we produced 89.5 Mcfe/d, which includes the proportionate share of production from our investment partnerships as well as our direct interests in producing wells.

Acquisition of DTE Antrim assets. On June 29, 2007, we acquired DTE Gas & Oil, now known as Atlas Gas & Oil Company, or AGO, from DTE Energy Company (“DTE” -NYSE:DTE) for $1.3 billion in cash. The assets acquired, which consisted principally of interests in natural gas wells in the Antrim Shale, are the basis for the formation of our gas and oil operations. We funded the purchase price from borrowings under a new credit facility with an initial borrowing base of $850.0 million that matures in June 2012. We intend to continue to expand our business through strategice acquisitions and internal growth projects that increase distributable cash flow.

Private equity offering. We financed a portion of the purchase price for the DTE Gas & Oil acquisition with the proceeds of a private offering, completed on June 29, 2007. We raised net proceeds of $597.5 million through the sale of 7,298,181 Class B common units and 16,702,828 Class D units at a weighted average price of $25.00. On November 10, 2007, the Class D units automatically converted to common units on a one-for-one basis. On February 20, 2008, a registration statement with the Securities and Exchange Commission covering the resale of these units went effective.
 
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New credit facility. Upon the closing of the DTE Gas & Oil acquisition, we replaced our credit facility with a new 5-year, credit facility with an initial borrowing base of $850.0 million. The credit facility has a current borrowing base of $672.5 million, which will be redetermined semi-annually based on changes in our oil and gas reserves. The facility is secured by our assets and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR rate plus the applicable margin, elected at our option. The base rate for any day equals the higher of the federal funds rate plus 0.50% of the JPMorgan prime rate. Adjusted LIBOR is LIBOR divided by 1.00 minus the percentage prescribed by the Federal Reserve Board for determining the reserve requirement for Eurocurrency liabilities. The applicable margin ranges from 0.0% to 1.25% for base rate loans and 1.00% to 2.25% for LIBOR loans. At December 31, 2007, the weighted average interest rate on outstanding borrowings was 7.2%.

Recent Developments

Private debt offering. In January 2008, we issued $250.0 million of 10-year, 10.75% senior unsecured notes due 2018. We used the proceeds of the note offering to reduce the balance outstanding on our senior secured credit facility. Interest on the senior notes is payable semi-annually in arrears on February 1 and August 1 of each year. The senior notes are redeemable at any time at certain redemption prices, together with accrued and unpaid interest to the date of redemption. In addition, before February 1, 2011, we may redeem up to 35% of the aggregate principal amount of the senior notes with the proceeds of certain equity offerings at a stated redemption price. The senior notes are also subject to repurchase by us at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if we do not reinvest the net proceeds within 360 days. The senior notes are junior in right of payment to our secured debt, including our obligations under our credit facility. The indenture governing the senior notes contains covenants, including limitations of our ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets.

New interest rate swap. In January 2008, we entered into an interest rate swap contract for $150 million, swapping the floating rate incurred on a portion of our existing senior secured credit facility for a fixed rate of approximately 4.36%, which includes an initial margin of 1.25% over the three year fixed swap rate of 3.11%. The interest rate swap contract will mature in January 2011. Combining the 4.36% interest rate on the new swap and the 10.75% interest rate on the new senior notes, we have fixed $400 million of our outstanding debt at a weighted average interest rate of approximately 8.35%.
 
Antrim Shale Overview

The Antrim Shale formation is a shallow late Devonian shale that occupies about 33,000 square miles under the northern half of Michigan’s Lower Peninsula. Most of the Michigan wells originally targeted oil and gas bearing reservoirs below the shale. While the Antrim Shale has produced oil and gas since the 1940s, it was not until the 1980s that it Antrim was purposely targeted for production on a large scale. The Antrim Shale is a low risk, organically rich black shale formation that is naturally fractured and primarily contains biogenic methane and water. Antrim production rates vary according to the intensity of the fracturing in the area immediately surrounding individual wells. The fractures provide the conduits for free gas and associated water to flow to the borehole through the black shale which otherwise has low permeability. Moreover, the fractures assist in the release of gas adsorbed on the shale surface.

Antrim Shale wells produce substantial volumes of water, especially during the early production stages, which must be removed from the formation to initiate gas production. The gas is transported from the well to a centrally located separation, compression and dehydration facility, where water is separated from it and disposed of, usually in a dedicated salt water disposal well to minimize water disposal costs.
 
Appalachian Basin Overview

The Appalachian Basin includes the states of Kentucky, Maryland, New York, Ohio, Pennsylvania, Virginia, West Virginia and Tennessee. It is the most mature oil and gas producing region in the United States, having established the first oil production in 1860. Because the Appalachian Basin is located near the energy-consuming regions of the mid-Atlantic and northeastern United States, Appalachian producers have historically sold their natural gas at a premium to the benchmark price for natural gas on the NYMEX. For the twelve months ended December 31, 2007, the average premium over NYMEX for natural gas delivered to our primary delivery points in the Appalachian Basin was $.337 per MMBtu.
 
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During the first several years of production, Appalachian Basin wells generally experience higher initial production rates and decline rates, which are followed by an extended period of significantly lower production rates and decline rates.

Shallow reserves in the Appalachian Basin are typically in blanket formations and have a high degree of step-out development success; that is, as development progresses, reserves from newly completed wells are reclassified from the proved undeveloped to the proved developed category and additional adjacent locations are added to proved undeveloped reserves. As a result, the cumulative amount of total proved reserves tends to increase as development progresses. Wells in the Appalachian Basin generally produce little or no water, contributing to a low cost of operation. In addition, most wells produce dry natural gas, which does not require processing.

Gas and Oil Production

At December 31, 2007, we owned interests in approximately 10,719 gross wells, of which we operated approximately 8,829. During the year ended December 31, 2007, we drilled 1,232 gross wells, 99% of which were successful in producing natural gas in commercial quantities.
 
Appalachia

In Appalachia, as of December 31, 2007, we owned interests in approximately 8,349 gross wells, of which we operated approximately 7,091. During the year ended December 31, 2007, average daily production from our wells was approximately 29.7 Mmcfe/d. During the year ended December 31, 2007, we drilled 1,117 gross (381.6 net) wells, 99% of which were successful in producing natural gas in commercial quantities. As of December 31, 2007, we had approximately 797,800 gross (697,300 net) acres, of which approximately 508,600 gross (501,400 net) acres are undeveloped. In September 2004, we expanded operations into Tennessee through a joint venture with Knox Energy, LLC that gave us an exclusive right to drill wells through December 31, 2007 on approximately 212,000 acres owned by Knox Energy. This agreement was extended through March 31, 2008; we are currently negotiating terms of a further joint venture agreement with Knox. As of December 31, 2007, we had drilled 321.0 net wells under this agreement. In addition, as of that date we had identified over 580 proved undeveloped drilling locations and approximately 2,600 additional potential drilling locations on our Appalachia acreage and the Tennessee joint venture acreage.

In the fourth quarter of 2006, we and our investment partnerships began drilling wells to multiple pay zones, including the Marcellus Shale of Western Pennsylvania. The Marcellus Shale is a black, organic rich shale formation located at depths between 6,000 and 8,500 feet and ranges in thickness from 75 to 150 feet on our acreage in Western Pennsylvania. As of February 20, 2008, we control approximately 483,000 Marcellus Shale acres in Pennsylvania, New York and West Virginia, and we continue to expand our position. As of that date, we had drilled 27 vertical wells and are currently producing 21 wells into a pipeline. The remaining 6 wells are scheduled to be completed and turned into line shortly. We are currently focused on our approximately 224,000 existing Marcellus acres in southwestern Pennsylvania, where we have drilled all but one of our Marcellus wells and have now, through this drilling, largely delineated our acreage. Almost all of this acreage in southwestern Pennsylvania has ample pipeline capacity that is controlled by our affiliate, Atlas Pipeline Partners, L.P. (NYSE: APL). Wright & Company, Inc., our independent petroleum engineering consultants, has evaluated our first 14 southwestern Pennsylvania Marcellus wells and assigned proved reserves that averaged 961 million cubic feet ("Mmcf") per well. These wells included five initial wells where we utilized. For the nine subsequent wells where we implemented our advanced drilling, completion and production techniques, Wright & Company assigned reserves that averaged 1.3 billion cubic feet ("Bcf") per well and were as high as 1.8 Bcf. Since implementing the advanced drilling, completion and production techniques, our initial daily rates (24 hours) into a pipeline have averaged 1.3 Mmcf per day in southwestern Pennsylvania. We plan to drill and complete at least 150 vertical Marcellus Shale wells over the next 18 months.

Michigan

In Michigan, as of December 31, 2007, we owned interests in approximately 2,370 gross wells, of which we operated approximately 1,738. During the six months ended December 31, 2007, average daily production from our wells was approximately 59.8 Mmcfe/d. During the six months ended December 31, 2007, we have drilled 102 gross (88.6 net) wells, 100% of which were successful in producing natural gas in commercial quantities. As of December 31, 2007, we had approximately 357,000 gross (285,100 net) acres, of which approximately 63,000 gross (53,300 net) acres are undeveloped.
 
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For information concerning our natural gas and oil production, see Item 2: ‘‘Properties.” 

Investment Partnerships

We generally fund our drilling activities, other than those of our Michigan business unit, through sponsorship of tax-advantaged investment partnerships. Accordingly, the amount of development activities we undertake depends in part upon our ability to obtain investor subscriptions to the partnerships. We raised $363.3 million in the year ended December 31, 2007 and $218.5 million in fiscal 2006. During the year ended December 31, 2007, our investment partnerships invested $423.1 million in drilling and completing wells, of which we contributed $137.6 million. During fiscal 2006, our investment partnerships invested $272.2 million in drilling and completing wells, of which we contributed $73.6 million.

We generally structure our investment partnerships so that, upon formation of a partnership, we coinvest in and contribute leasehold acreage to it, enter into drilling and well operating agreements with it and become its managing general partner. In addition to providing capital for our drilling activities, our investment partnerships are a source of fee-based revenues, which are not directly dependent on natural gas and oil prices. We receive an interest in our investment partnerships proportionate to the amount of capital and the value of the leasehold acreage we contribute, typically 27% to 30% of the overall capitalization in a particular partnership. We also receive an additional interest in each partnership, typically 7%, for which we do not make any additional capital contribution.

As managing general partner of our investment partnerships, we receive the following fees:

·  
Well construction and completion. For each well that is drilled by an investment partnership, we receive a 15% mark-up on those costs incurred to drill and complete the well.

·  
Administration and oversight. For each well drilled by an investment partnership, we receive a fixed fee of approximately $15,000 ($45,000 for Marcellus wells). Additionally, the partnership pays us a monthly per well administrative fee of $75 for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well.

·  
Well services. Each partnership pays us a monthly per well operating fee, currently $100 to $477, for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well.

·  
Gathering. Historically, each partnership paid us a gathering fee which was typically insufficient to cover all of the gathering fees due to Atlas Pipeline. Since the completion of our initial public offering in December 2006, pursuant to the terms of our contribution agreement with Atlas America, our gathering revenues and costs within our partnership management segment net to $0. Please read “− Other Agreements with Atlas America and Its Affiliates − Contribution Agreement.” We also pay our proportionate share of gathering fees based on our percentage interest in the well, which are included in gas and oil production expense.

We generally agree to subordinate up to 50% of our share of production revenues to specified returns to the investor partners, typically 10% per year for the first five years of distributions. We have not subordinated our share of revenues from any of our investment partnerships since March 2005, but did subordinate $91,000 in fiscal 2005, $335,000 in fiscal 2004 and $362,000 in fiscal 2003. We do not believe any amounts which may be subordinated in the future will be material to our operations.

Our investment partnerships provide tax advantages to their investors because an investor’s share of the partnership’s intangible drilling cost deduction may be used to offset ordinary income. Intangible drilling costs include items that do not have salvage value, such as labor, fuel, repairs, supplies and hauling. Historically, under our partnership agreements, approximately 90% of the subscription proceeds received by each partnership have been used to pay 100% of the partnership’s intangible drilling costs. For example, an investment of $10,000 has generally permitted the investor to deduct approximately $9,000 in the year in which the investor invests.
 
8

 
Natural Gas Sales

Appalachia

In Appalachia, we have a natural gas supply agreement with Hess Corporation, which is valid through March 31, 2009. Subject to certain exceptions, Hess Corporation has a last right of refusal to buy all of the natural gas produced and delivered by us and our affiliates, including our investment partnerships, at certain delivery points with the facilities of:
 
 
·  
East Ohio Gas Company, National Fuel Gas Distribution, Columbia of Ohio, and Peoples Natural Gas Company, which are local distribution companies; and
 
·  
National Fuel Gas Supply, Columbia Gas Transmission Corporation, Tennessee Gas Pipeline Company, and Texas Eastern Transmission Company, which are interstate pipelines.
 
A portion of our and our investment partnerships’ natural gas is subject to the agreement with Hess Corporation, with the following exceptions:
 
·  
natural gas we sell to Warren Consolidated, an industrial end-user and direct delivery customer;
 
·  
natural gas that at the time of the agreement was already dedicated for the life of the well to another buyer;
 
·  
natural gas that is produced by a company which was not an affiliate of ours at the time of the agreement;
 
·  
natural gas sold through interconnects established subsequent to the agreement;
 
·  
natural gas that is delivered to interstate pipelines or local distribution companies other than those described above; and
 
·  
natural gas that is produced from wells operated by a third party or subject to an agreement under which a third party was to arrange for the gathering and sale of the natural gas.
 
Based on the most recent monthly production data available to us as of December 31, 2007, we anticipate that we and our affiliates, including our investment partnerships, will sell approximately 18% of our Appalachian natural gas production during the year ending December 31, 2008 under the Hess Corporation agreement. The agreement requires the parties to negotiate a new pricing arrangement at each annual delivery point. If, at the end of any applicable period, the parties cannot agree to a new price for any delivery point, then we may solicit offers from third parties to buy the natural gas for that delivery point. If Hess Corporation does not match this price, then we may sell the natural gas to the third party. We market the remainder of our natural gas, which is principally located in the Fayette County, PA area, primarily to Colonial Energy, Inc., UGI Energy Services, and others. See “—Major Customers.” During the year ended December 31, 2007, we received an average of $8.91 per Mcf of natural gas, compared to $8.83 per Mcf in fiscal 2006 and $8.34 per Mcf in fiscal 2005.
 
We expect that natural gas produced from our wells drilled in areas of the Appalachian Basin other than those described above will be primarily tied to the spot market price and supplied to:
 
·  
gas marketers;
 
·  
local distribution companies;
 
·  
industrial or other end-users; and/or
 
·  
companies generating electricity.

Michigan

In Michigan, we have natural gas sales agreements with DTE, which are valid through December 31, 2012. DTE has the obligation to purchase all of the natural gas produced and delivered by us and our affiliates from specific projects at certain delivery points with the facilities of:
 
9

 
·  
Merit Plant/Michigan Consolidated Gas Company (MCGC) Kalkaska;
 
·  
MCGC Jordan 4, Chestonia 17, Mancelona 19, Saginaw Bay and Woolfolk; and
 
·  
Consumers Energy Goose Creek and Wilderness Plant,
 
Based on the most recent monthly production data available to us as of December 31, 2007, we anticipate that we and our affiliates will sell approximately 50% of our Michigan natural gas production during the year ending December 31, 2008 under the DTE agreements in most cases at NYMEX pricing. During the six months ended December 31, 2007, AGO received an average of $8.44 per Mcf of natural gas.
 
Crude Oil Sales

Crude oil produced from our wells flows directly into storage tanks where it is picked up by the oil company, a common carrier, or pipeline companies acting for the oil company, which is purchasing the crude oil. We sell any oil produced by our Appalachian wells to regional oil refining companies at the prevailing spot market price for Appalachian crude oil. In Michigan, the property operator typically markets the oil produced.
 
Asset Retirement Obligations
 
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 whom we pay a fee. The contractor will also salvage the equipment on the well, which we then sell in the used equipment market. Under the partnership agreements of our investment partnerships, which own the majority of our Appalachia wells, we are allocated abandonment costs in proportion to our partnership interest (generally between 27% and 35%) and are allocated between 65% and 100% of the salvage proceeds. As a consequence, we generally receive proceeds from salvaged equipment at least equal to, and typically exceeding, our share of the related costs.
 
Natural Gas Hedging
 
We seek to provide greater stability in our cash flows through our use of financial hedges and physical hedges. The financial hedges may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. The futures contracts are commitments to purchase or sell natural gas at future dates and generally cover one-month periods for up to six years in the future. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, we have a management committee to assure that all financial trading is done in compliance with our hedging policies and procedures. We do not intend to contract for positions that we cannot offset with actual production. As of December 31, 2007, we had financial hedges and physical hedges in place for approximately 65% of our expected Appalachian production and for approximately 87% of our Michigan production for the twelve months ending December 31, 2008.
 
Hess Corporation and other third-party marketers to which we sell gas, such as Colonial Energy, Inc. and UGI Energy Services, also use NYMEX-based financial instruments to hedge their pricing exposure and make price hedging opportunities available to us through physical hedge transactions. These transactions are not deemed hedges for accounting purposes because they require firm delivery of natural gas and are considered normal sales of natural gas. We generally limit these arrangements to much smaller quantities than those projected to be available at any delivery point. The price paid by these third-party marketers for volumes of natural gas sold under these sales agreements may be significantly different from the underlying monthly spot market value.
 
Natural Gas Gathering
 
Appalachia
 
We conduct our natural gas transportation and processing operations through Atlas America’s affiliate, Atlas Pipeline Partners. Atlas Pipeline owns approximately 1,600 miles of gathering systems located in eastern Ohio, western New York and western Pennsylvania serving approximately 6,600 wells.
 
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In connection with the completion of our initial public offering, and the contribution by Atlas America of its natural gas and oil development and production assets to us, we entered into the following agreements with Atlas Pipeline.

Omnibus Agreement
 
Under the omnibus agreement, Atlas America and its affiliates agreed to add wells to Atlas Pipeline's gathering systems and provide consulting services when Atlas Pipeline constructs new gathering systems or extends existing systems. We joined the omnibus agreement as an obligor (except for the provisions of the omnibus agreement imposing conditions upon the disposition of the general partner interest of Atlas Pipeline's general partner), and Atlas America became secondarily liable as a guarantor of our performance. The omnibus agreement is a continuing obligation, having no specified term or provisions regarding termination except for a provision terminating the agreement if Atlas Pipeline's general partner is removed without cause.

 
Well connections. We are required to construct, at our sole cost and expense, up to 2,500 feet of small diameter (two inches or less) sales or flow lines from the wellhead of any well we drill and operate to a point of connection to Atlas Pipeline’s gathering systems. Where we have extended sales and flow lines to within 1,000 feet of one of Atlas Pipeline’s gathering systems, we may require Atlas Pipeline to extend its system to connect to that well. With respect to other wells that are more than 2,500 feet from Atlas Pipeline’s gathering systems, Atlas Pipeline has the right, at its cost and expense, to extend its gathering system to within 2,500 feet of the well and to require us, at our cost and expense, to construct up to 2,500 feet of flow line to connect to the gathering system extension. If Atlas Pipeline elects not to exercise its right to extend its gathering systems, we may connect a well to a natural gas gathering system owned by a third party or to any other delivery point; however, Atlas Pipeline will have the right to assume the cost of construction of the necessary flow lines, which then become its property and part of its gathering systems.
 
Consulting services. The omnibus agreement requires us to assist Atlas Pipeline in identifying existing gathering systems for possible acquisition and to provide consulting services to Atlas Pipeline in evaluating and making a bid for these systems. We must give Atlas Pipeline notice of identification by us or any of our affiliates of any gathering system as a potential acquisition candidate, and must provide Atlas Pipeline with information about the gathering system, its seller and the proposed sales price, as well as any other information or analyses we compile with respect to the gathering system. Atlas Pipeline must determine, within a time period specified by our notice to it, which must be a reasonable time under the circumstances, whether it wants to acquire the identified system and advise us of its intent. If Atlas Pipeline advises us that it does not intend to make the acquisition, does not complete the acquisition within a reasonable time period, or advises us that it does not intend to acquire the system, then we may do so.
 
Gathering system construction. We will provide Atlas Pipeline with construction management services if Atlas Pipeline determines to expand one or more of its gathering systems. We are entitled to reimbursement for our costs, including an allocable portion of employee salaries, in connection with our construction management services.

Natural Gas Gathering Agreements

Under our master natural gas gathering agreement with Atlas Pipeline, we pay gathering fees as follows:

·  
for natural gas from our well interests, other than those of our investment partnerships, that were connected to Atlas Pipeline’s gathering systems at February 2, 2000, the greater of $0.40 per thousand cubic feet, or Mcf, 16% of the gross sales price of the natural gas transported;
 
·  
for (i) natural gas from well interests allocable to our investment partnerships that drilled or drill wells on or after December 1, 1999 that are connected to the gathering systems (ii) natural gas from our well interests, other than those of our investment partnerships, that are connected to the gathering systems after February 2, 2000, and (iii) well interests allocable to third parties in wells connected to the gathering systems at February 2, 2000, the greater of $0.35 per Mcf or 16% of the gross sales price of the natural gas transported; and
 
·  
for natural gas from well interests we operate and drilled after December 1, 1999 that are connected to a gathering system that is not owned by Atlas Pipeline and for which Atlas Pipeline assumes the cost of constructing the connection to that gathering system, an amount equal to the greater of $0.35 per Mcf or 16% of the gross sales price of the natural gas transported, less the gathering fee charged by the other gathering system.
 
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We receive gathering fees from contracts or other arrangements with the owners of well interests connected to Atlas Pipeline’s gathering systems. Pursuant to the contribution agreement described below under "—Other Agreements with Atlas America and its Affiliates—Contribution Agreement,” Atlas America agreed to assume our obligation to pay gathering fees to Atlas Pipeline. We, in turn, assigned to Atlas America the gathering fees we receive from our investment partnerships and gathering fees attributable to our production interest. The gathering fees payable to Atlas Pipeline generally exceed the amount we receive from our investment partnerships for gathering services. If Atlas America fails to pay gathering fees to Atlas Pipeline as required by its assumption agreement with us, we will have to pay to Atlas Pipeline the difference between the gathering fee payable and the amount we receive from our investment partnerships for gathering services out of our own resources.

The master natural gas gathering agreement is a continuing obligation and, accordingly, has no specified term or provisions regarding termination. However, if Atlas Pipeline’s general partner is removed as the general partner of Atlas Pipeline without cause, then no gathering fees will be due under the agreement with respect to new wells drilled by us.

In addition to the master natural gas gathering agreement, we are party to three other gas gathering agreements with Atlas Pipeline:

·  
Under two agreements, relating to wells located in southeastern Ohio, which were originally acquired from Kingston Oil Corporation, and wells located Fayette County, Pennsylvania, which were originally acquired from American Refining and Exploration Company, we pay Atlas Pipeline gathering fees of $0.80 per Mcf. These wells are owned directly by our subsidiaries, and Atlas America has not assumed any part of our obligation to pay the gathering fees to Atlas Pipeline under these agreements.
 
·  
Under another agreement, which covers wells owned by third parties unrelated to our investment partnerships and us, we pay Atlas Pipeline gathering fees that range between $0.20 and $0.29 per Mcf or between 10% to 16% of the weighted average sales price. The gathering fees payable under this agreement are a direct pass-through of the gathering fees we receive from the third party wells. Accordingly, Atlas America has not assumed any part of our obligation to pay the gathering fees to Atlas Pipeline under this agreement, and has been removed as an obligor under it.

Michigan

We transport our natural gas from our Michigan wells through our 1,157 miles of polypropylene flow lines to centrally located separation, compression and dehydration facilities, which we refer to as CPFs, where water is separated from the natural gas and disposed of. We own interests in 81 CPFs, of which we operate 61. The wells generally produce natural gas and water for 3 to 12 months, after which they produce only gas.

We then transport the compressed and dehydrated gas stream from CPFs via our 181 miles of sales lines to the northern Michigan high pressure gathering system, which is composed of a number of gathering systems owned by third party transporters that deliver gas to delivery points. Compressed and dehydrated gas exiting the CPF typically has carbon dioxide (CO2) levels in excess of the 2% pipeline specifications required at the delivery point. Therefore, it is treated at CO2 processing plants located along the northern Michigan high pressure gathering system before delivery to the delivery points. The CO2 plants utilize either an amine or membrane treating process. We currently own and operate one amine processing plant and operate on behalf of DTE four other amine plants and one membrane plant. We pay third parties an average of $0.30/Mcfe on a net basis for these transportation and treating services.

Other Agreements with Atlas America and Its Affiliates

Contribution Agreement

Contribution of assets by Atlas America. The substantial majority of the Appalachian assets we own were held, directly or indirectly, by subsidiaries of Atlas America. In connection with our initial public offering, Atlas America entered into a contribution agreement pursuant to which it contributed to us all of the stock of its natural gas and oil development and production subsidiaries as well as the development and production assets owned by it. As consideration for this contribution, we distributed to Atlas America the net proceeds we received from that offering, as well as 29,352,996 of our common units, the Class A units and the management incentive interests. As part of the contribution agreement, Atlas America has agreed to indemnify us for losses attributable to title defects to our oil and gas property interests for three years after the closing of the offering, and indefinitely for losses attributable to retained liabilities and income taxes attributable to pre-closing operations and formation transactions. Furthermore, we have agreed to indemnify Atlas America for all losses attributable to the post-closing operations of the assets contributed to us, to the extent not subject to its indemnification obligations.

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Atlas America’s assumption of obligations under the master natural gas gathering agreement with Atlas Pipeline. Upon completion of our initial public offering, we became a party to an existing master natural gas gathering agreement between Atlas America and Atlas Pipeline pursuant to which Atlas Pipeline gathers substantially all of the natural gas from wells operated by us. Pursuant to the contribution agreement, Atlas America has agreed to assume our obligation to pay gathering fees to Atlas Pipeline under the master natural gas gathering agreement; we have agreed to pay Atlas America the gathering fees we receive from our investment partnerships and fees associated with production to our interest.

Management Agreement

Upon completion of our initial public offering, we entered into a management agreement with Atlas Energy Management, a subsidiary of Atlas America, pursuant to which Atlas Energy Management will manage our business affairs under the supervision of our board of directors. Atlas Energy Management will provide us with all services necessary or appropriate for the conduct of our business. In exercising its powers and discharging its duties under the management agreement, Atlas Energy Management must act in good faith.

Before making any distribution on our common units, we will reimburse Atlas Energy Management for all expenses that it incurs on our behalf pursuant to the management agreement. These expenses will include costs for providing corporate staff and support services to us. Atlas Energy Management will charge on a fully allocated cost basis for services provided to us. This fully allocated cost basis is based on the percentage of time spent by personnel of Atlas Energy Management and its affiliates on our matters and includes the compensation paid by Atlas Energy Management and its affiliates to such persons and their allocated overhead. The allocation of compensation expense for such persons will be determined based on a good faith estimate of the value of each such person’s services performed on our business and affairs, subject to the periodic review and approval of our audit or conflicts committee.

Atlas Energy Management, its stockholders, directors, officers, employees and affiliates will not be liable to us, our directors or unit holders for acts or omissions performed in good faith and in accordance with and pursuant to the management agreement, except because of acts constituting gross negligence, bad faith, willful misconduct, fraud or a knowing violation of criminal law. We will indemnify Atlas Energy Management, its stockholders, directors, officers, employees and affiliates with respect to all expenses, losses, damages, liabilities, demands, charges and claims arising from acts of Atlas Energy Management, its stockholders, directors, officers, employees and affiliates not constituting gross negligence, bad faith, willful misconduct, fraud or a knowing violation of criminal law performed in good faith in accordance with and pursuant to the management agreement. Atlas Energy Management and its affiliates will indemnify us and our directors and officers with respect to all expenses, losses, damages, liabilities, demands, charges and claims arising from acts of Atlas Energy Management or its affiliates constituting gross negligence, bad faith, willful misconduct, fraud or a knowing violation of criminal law or any claims by employees of Atlas Energy Management or its affiliates relating to the terms and conditions of their employment. Atlas Energy Management and/or Atlas America will carry errors, omissions, and other customary insurance.

The management agreement may not be amended without the prior approval of our conflicts committee if the proposed amendment will, in the reasonable discretion of our board, adversely affect our common unit holders.

The management agreement does not have a specific term; however, Atlas Energy Management may not terminate the agreement before December 18, 2016. We may terminate the management agreement only upon the affirmative vote of holders of at least two-thirds of our outstanding common units, including units held by Atlas America. In the event we terminate the management agreement, Atlas Energy Management will have the option to require the successor manager, if any, to purchase its membership interests and management incentive interests for their fair market value as determined by agreement between the departing manager and the successor manager.

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Anthem Securities, Inc.

Anthem Securities is our registered broker-dealer subsidiary, which acts as the dealer-manager for our investment partnership offerings. Anthem Securities is registered as a broker-dealer solely involved in direct participation programs such as our investment partnerships, and does not maintain customer accounts or custody of securities. Anthem Securities has been a member of FINRA, formerly known as the National Association of Securities Dealers, Inc., since 1997.
 
Availability of Oil Field Services
 
We contract for drilling rigs and purchase goods and services necessary for the drilling and completion of wells from a number of drillers and suppliers, none of which supplies a significant portion of our annual needs. During fiscal 2007, we faced no shortage of these goods and services. We cannot predict the duration or stability of the current level of supply and demand for drilling rigs and other goods and services required for our operations with any certainty due to numerous factors affecting the energy industry, including the demand for natural gas and oil.

Major Customers

Our natural gas sold under contract to various purchasers. For the year ended September 30, 2005 and the years ended December 31, 2006 and 2007, gas sales to Hess Corporation (formerly First Energy Solutions Corp.) accounted for 12%, 10% and 18%, respectively, of our total Appalachian gas and oil production revenues. For the six months, ended December 31, 2007, sales to DTE accounted for 46% of our Michigan oil and gas production revenues. No other single customer accounted for more than 10% of our total revenues during these periods.

Competition

The energy industry is intensely competitive in all of its aspects. We operate in a highly competitive environment for acquiring properties and other natural gas and oil companies, attracting capital through our investment partnerships, contracting for drilling equipment and securing trained personnel. We also compete with the exploration and production divisions of public utility companies for natural gas and oil property acquisitions. Competition is intense for the acquisition of leases considered favorable for the development of natural gas and oil in commercial quantities. Our competitors may be able to pay more for natural gas and oil properties and to evaluate, bid for and purchase a greater number of properties than our financial or personnel resources permit. Furthermore, 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. Product availability and price are the principal means of competition in selling natural gas and oil.

Many of our competitors possess greater financial and other resources than ours, which may enable them to identify and acquire desirable properties and market their natural gas and oil production more effectively than we do.

Moreover, we also compete with a number of other companies that offer interests in investment partnerships. As a result, competition for investment capital to fund investment partnerships is intense.

Markets

The availability of a ready market for natural gas and oil and the price obtained, depends upon numerous factors beyond our control, as described in “Risk factors” Product availability and price are the principal means of competition in selling natural gas and oil. During the year ended December 31, 2007, we did not experience problems in selling our natural gas and oil, although prices have varied significantly during this period.

Natural Gas and Oil Leases

The typical natural gas and oil lease agreement provides for the payment of royalties to the mineral owner for all natural gas and oil produced from any well(s) drilled on the leased premises. In the Appalachian Basin this amount is typically 1/8th (12.5%) resulting in a 87.5% net revenue interest to us, and in Michigan this amount is typically 1/6th (16.67%) resulting in an 83.3% net revenue interest to us, for most leases directly acquired by us. In certain instances, this royalty amount may increase to 1/6th in the Appalachian Basin and to 3/16th (18.75%) in Michigan when leases are taken from larger landowners or mineral owners such as coal and timber companies.

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Because the acquisition of natural gas and oil leases is a very competitive process, and involves certain geological and business risks to identify productive areas, prospective leases are often held by other natural gas and oil operators. In order to gain the right to drill these leases we may elect to farm-in leases and/or purchase leases from other natural gas and oil operators. Typically the assignor of such leases will reserve an overriding royalty interest, ranging in the Appalachian Basin from 1/32nd to 1/16th (3.125% to 6.25%), which further reduces the net revenue interest available to us to between 84.375% and 81.25% and in Michigan from 3.33% to 5.33%, which further reduces the net revenue interest available to us to between 80.0% and 78.0%.

Sometimes these third party owners of natural gas and oil leases retain the option to participate in the drilling of wells on leases farmed out or assigned to us. Normally the retained interest is a 25% working interest. In this event, our working interest ownership will be reduced by the amount retained by the third party operator. In all other instances we anticipate owning a 100% working interest in newly drilled wells.

In almost all of the areas we operate in the Appalachian Basin and Michigan, the surface owner is normally the natural gas and oil owner allowing us to deal with a single owner. This simplifies the research process required to identify the proper owners of the natural gas and oil rights and reduces the per acre lease acquisition cost and the time required to successfully acquire the desired leases.

Seasonal Nature of Business

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in certain areas of the Appalachian region and Michigan. These seasonal anomalies may pose challenges for meeting our well construction objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay our operations. In the past, we have drilled a greater number of wells during the winter months because we have typically received the majority of funds from our investment partnerships during the fourth calendar quarter. Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

Environmental Matters and Regulation

General

Our operations are subject to comprehensive and stringent federal, state and local laws and regulations governing, among other things, where and how we install wells, how we handle wastes from our operations and the discharge of materials into the environment. Our operations will be subject to the same environmental laws and regulations as other companies in the natural gas and oil industry. Among other requirements and restrictions, these laws and regulations:
 
·  
require the acquisition of various permits before drilling commences;
 
·  
require the installation of expensive pollution control equipment;
 
·  
restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;
 
·  
limit or prohibit drilling activities on lands lying within or, in some cases, adjoining wilderness, wetlands and other protected areas;
 
·  
require remedial measures to reduce, mitigate or respond to releases of pollutants or hazardous substances from former operations, such as pit closure and plugging of abandoned wells;
 
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·  
impose substantial liabilities for pollution resulting from our operations; and
 
·  
with respect to operations affecting federal lands or leases, require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement.
 
These laws, rules and regulations may also restrict the rate of natural gas and oil production below the rate that would otherwise be possible. The regulatory burden on the natural gas and oil industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently enact new, and revise existing, environmental laws and regulations, and any new laws or changes to existing laws that result in more stringent and costly waste handling, disposal and clean-up requirements for the natural gas and oil industry could have a significant impact on our operating costs. We believe that our operations overall substantially comply with all currently applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict how environmental laws and regulations that may take effect in the future may affect our properties or operations. For the years ended December 31, 2006 and 2007, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. We are not aware of any environmental issues or claims that will require material capital expenditures during 2008, or that will otherwise have a material impact on our financial position or results of operations.
 
Environmental laws and regulations that could have a material impact on the natural gas and oil exploration and production industry include the following:

National Environmental Policy Act

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

Waste Handling

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

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

The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “Superfund” law, imposes joint and several liability, without regard to fault or legality of conduct, on persons who are considered under the statute to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
 
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Our operations are, in many cases, conducted at properties that have been used for natural gas and oil exploitation and production for many years. Although we believe Atlas America utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges

The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other natural gas and oil wastes, into navigable waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or the relevant state. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The Clean Water Act also requires specified facilities to maintain and implement spill prevention, control and countermeasure plans and to take measures to minimize the risks of petroleum spills. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for failure to obtain or non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. We believe our operations on the whole are in substantial compliance with the requirements of the Clean Water Act.

Air Emissions

The Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through permits and other requirements. In addition, EPA has developed, and continues to develop, stringent regulations governing emissions of toxic and other air pollutants at specified sources. Some of our new facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to comply with new emission limitations. These regulations may increase the costs of compliance for some facilities, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance. These laws and regulations also apply to entities that use natural gas as fuel, and may increase the costs of compliance of our customers to the point where demand for natural gas is affected. We believe that our operations are in substantial compliance with the requirements of the Clean Air Act.

OSHA and Other Regulations

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

Other Laws and Regulation

The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol, and Congress has resisted recent proposed legislation directed at reducing greenhouse gas emissions. However, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The natural gas and oil industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could affect our future operations. Our operations are not adversely impacted by current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would affect our business.
 
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Other Regulation of the Natural Gas and Oil Industry

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

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including natural gas and oil facilities.

Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Drilling and Production

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

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

Natural Gas Regulation

The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The Federal Energy Regulatory Commission’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.
 
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Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.

State Regulation

The various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Michigan imposes a 5.6% severance tax on natural gas and a 7.3% severance tax on oil, Tennessee imposes a 3% severance tax on natural gas and oil production and Ohio imposes a severance tax of $0.25 per Mcf of natural gas and $0.10 per Bbl of oil. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.

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

Employees

We do not have any employees. To carry out our operations, our manager and its affiliates employed approximately 467 persons as of December 31, 2007.

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Available Information
 
We make our periodic reports under the Securities Exchange Act of 1934, including our annual report on Form 10-K, our quarterly reports on Form 10-Q and our current reports on Form 8-K, available through our website at www.atlasenergyresources.com. To view these reports, click on “Investor Relations”, then “SEC Filings”. You may also receive, without charge, a paper copy of any such filings by request to us at 1550 Coraopolis Heights Road, Moon Township, Pennsylvania 15108, telephone number (412) 262-2830. A complete list of our filings is available on the Securities and Exchange Commission’s website at www.sec.gov. Any of our filings are also available at the Securities and Exchange Commission’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. The Public Reference Room may be contacted at telephone number (800) 732-0330 for further information.

The NYSE requires the chief executive officer of each listed company to certify annually that he is not aware of any violation by the company of the NYSE corporate governance listing standards as of the date of the certification, qualifying the certification to the extent necessary. The Chief Executive Officer of our general partner provided such certification to the NYSE in 2007 without qualification. In addition, the certifications of the Chief Executive Officer and Chief Financial Officer of our general partner required by Sections 302 and 906 of the Sarbanes-Oxley Act have been included as exhibits to this report.

ITEM 1A: RISK FACTORS

We may not have sufficient cash flow from operations to pay the initial quarterly distribution, or IQD, following the establishment of cash reserves and payment of fees and expenses, including payments to our manager. We may not have sufficient cash flow from operations each quarter to pay the IQD. Under the terms of our limited liability company agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses and the amount of any cash reserve amounts that our board of directors establishes to provide for future operations, future capital expenditures, future debt service requirements and future cash distributions to our unit holders and the holders of the management incentive interests. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

·  
the amount of natural gas and oil we produce;
 
·  
the price at which we sell our natural gas and oil;
 
·  
the level of our operating costs;
 
·  
our ability to acquire, locate and produce new reserves;
 
·  
results of our hedging activities;
 
·  
the level of our interest expense, which depends on the amount of our indebtedness and the interest payable on it; and
 
·  
the level of our capital expenditures.

The actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

·  
our ability to make working capital borrowings to pay distributions;
 
·  
the cost of acquisitions, if any;
 
·  
fluctuations in our working capital needs;
 
·  
timing and collectability of receivables;
 
·  
restrictions on distributions imposed by lenders;
 
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·  
payments to our manager;
 
·  
the amount of our estimated maintenance capital expenditures;
 
·  
prevailing economic conditions; and
 
·  
the amount of cash reserves established by our board of directors for the proper conduct of our business.

As a result of these factors, the amount of cash we distribute in any quarter to our unit holders may fluctuate significantly from quarter to quarter and may be significantly less than the IQD amount that we expect to distribute.

If commodity prices decline significantly, our cash flow from operations will decline. Our revenue, profitability and cash flow substantially depend upon the prices and demand for natural gas and oil. The natural gas and oil markets are very volatile and a drop in prices can significantly affect our financial results and impede our growth. Changes in natural gas and oil prices will have a significant impact on the value of our reserves and on our cash flow. Prices for natural gas and oil may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas or oil, market uncertainty and a variety of additional factors that are beyond our control, such as:
 
·  
the level of the domestic and foreign supply and demand;
 
·  
the price and level of foreign imports;
 
·  
the level of consumer product demand;
 
·  
weather conditions and fluctuating and seasonal demand;
 
·  
overall domestic and global economic conditions;
 
·  
political and economic conditions in natural gas and oil producing countries, including those in the Middle East and South America;
 
·  
the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
 
·  
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 cost, proximity and capacity of natural gas pipelines and other transportation facilities; and
 
·  
the price and availability of alternative fuels.
 
In the past, the prices of natural gas and oil have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2007, the NYMEX Henry Hub natural gas index price ranged from a high of $7.59 per MMBtu to a low of $5.43 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $95.10 per Bbl to a low of $51.13 per Bbl.

Unless we replace our reserves, our reserves and production will decline, which would reduce our cash flow from operations and impair our ability to make payments on our debt. Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Based on our December 31, 2007 reserve reports, our average annual decline rate for proved developed producing reserves is approximately 8% during the first five years, approximately 5% in the next five years and less than 5% thereafter. Because total estimated proved reserves include proved undeveloped reserves at December 31, 2007, production will decline at this rate even if those proved undeveloped reserves are developed and the wells produce as expected. This rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change when we drill additional wells, make acquisitions and under other circumstances. Thus, our future natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. Our ability to find and acquire additional recoverable reserves to replace current and future production at acceptable costs depends on our generating sufficient cash flow from operations and other sources of capital, including our investment partnerships, all of which are subject to the risks discussed elsewhere in this section.
 
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Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or 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. Our independent petroleum engineers prepare estimates of our proved reserves. Over time, our internal engineers may make material changes to reserve estimates taking into account the results of actual drilling and production. Some of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, we make certain assumptions regarding future natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions by actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas and oil attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. For example, if natural gas prices decline by $1.00 per Mcf, then the PV-10 value of our proved reserves as of December 31, 2007 would decrease from $1.5 billion to $1.2 billion. Our PV-10 is calculated using natural gas prices that include our physical hedges but not our financial hedges. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often 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 prices and costs in effect on the day of estimate. However, actual future net cash flows from our natural gas 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 our 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 reserves, the amount of PV-10 described in this report, and our financial condition and results of operations. In addition, our reserves or PV-10 may be revised downward or upward based upon production history, results of future exploitation and development activities, 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.

 
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·  
changes in our reserves;
 
·  
changes in natural gas prices;
 
·  
changes in labor and drilling costs;
 
·  
our ability to acquire, locate and produce reserves;
 
·  
changes in leasehold acquisition costs; and
 
·  
government regulations relating to safety and the environment.

Our significant maintenance capital expenditures will reduce the amount of cash we have available for distribution to our unit holders. Additionally, our actual maintenance capital expenditures will vary from quarter to quarter. Our limited liability company agreement requires us to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus will be subject to review and approval by our board of directors, including a majority of our conflicts committee, at least once a year. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unit holders will be lower than if we deducted actual maintenance capital expenditures from operating surplus. If we underestimate the appropriate level of estimated maintenance capital expenditures, we may have less cash available for distribution in future periods when actual capital expenditures begin to exceed our previous estimates. Over time, if we do not set aside sufficient cash reserves or have available sufficient sources of financing and make sufficient expenditures to maintain our capital asset base, we will be unable to pay distributions at the anticipated level and may have to reduce our distributions.

The scope and costs of the risks involved in making acquisitions may prove greater than estimated at the time of the acquisition. Any acquisition involves potential risks, including, among other things:
 
·  
mistaken assumptions about revenues and costs, including synergies;
 
·  
significant increases in our indebtedness and working capital requirements;
 
·  
an inability to integrate successfully or timely the businesses we acquire;
 
·  
the assumption of unknown liabilities;
 
·  
limitations on rights to indemnity from the seller;
 
·  
the diversion of management’s attention from other business concerns;
 
·  
increased demands on existing personnel;
 
·  
customer or key employee losses at the acquired businesses; and
 
·  
the failure to realize expected growth or profitability.
 
The scope and cost of these risks may ultimately be materially greater than estimated at the time of the acquisition.  Further, our future acquisition costs may be higher than those we have achieved historically.  Any of these factors could adversely affect our future growth and our ability to increase distributions.
 
We may be unsuccessful in integrating the operations from our recent acquisition or any future acquisitions with our operations and in realizing all of the anticipated benefits of these acquisitions. We acquired DTE Gas & Oil in June 2007 and are currently in the process of integrating its operations with ours. We also have an active, on-going program to identify other potential acquisitions. The integration of previously independent operations with ours can be a complex, costly and time-consuming process. The difficulties of combining these systems, as well as any operations we may acquire in the future, with us include, among other things:

·  
operating a significantly larger combined entity;
 
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·  
the necessity of coordinating geographically disparate organizations, systems and facilities;
 
·  
integrating personnel with diverse business backgrounds and organizational cultures;
 
·  
consolidating operational and administrative functions;
 
·  
integrating internal controls, compliance under Sarbanes-Oxley Act of 2002 and other corporate governance matters;
 
·  
the diversion of management’s attention from other business concerns;
 
·  
customer or key employee loss from the acquired businesses;
 
·  
a significant increase in our indebtedness; and
 
·  
potential environmental or regulatory liabilities and title problems.
 
We acquired DTE Gas & Oil with the expectation that combining it with our existing operations will result in benefits, including, among other things, increased geographic diversification and reserve life. There can be no assurance that we will realize any of these benefits or that the acquisition will not result in the deterioration or loss of our business. Costs incurred and liabilities assumed in connection with an acquisition and increased capital expenditures and overhead costs incurred to expand our operations could harm our business or future prospects, and result in significant decreases in our gross margin and cash flows.

The DTE Gas & Oil acquisition has substantially changed our business, making it difficult to evaluate our business based upon our historical financial information. The DTE Gas & Oil acquisition has significantly increased our size, redefined our business plan, expanded our geographic market and resulted in large changes to our revenues and expenses. As a result of this acquisition, and our continued plan to acquire and integrate additional companies that we believe present attractive opportunities, our financial results for any period or changes in our results across periods may continue to dramatically change. Our historical financial results, therefore, should not be relied upon to accurately predict our future operating results, thereby making the evaluation of our business more difficult.

We have limited experience in drilling wells to the Marcellus Shale, less information regarding reserves and decline rates in the Marcellus Shale than in other areas of our Appalachian operations and wells drilled to the Marcellus Shale will be deeper, more expensive and more susceptible to mechanical problems in drilling and completing than wells in the other areas. We have limited experience in drilling development wells to the Marcellus Shale. As of December 31, 2007, we have drilled 19 wells to the Marcellus Shale, 15 of which have been turned on-line, but those wells have been producing for only a short period of time. Other operators in the Appalachian Basin also have limited experience in drilling wells to the Marcellus Shale. Thus, we have much less information with respect to the ultimate recoverable reserves and the production decline rate in the Marcellus Shale than we have in our other areas of operation. In addition, the wells to be drilled in the Marcellus Shale will be drilled deeper than in our other primary areas, which makes the Marcellus Shale wells more expensive to drill and complete. The wells will also be more susceptible to mechanical problems associated with the drilling and completion of the wells, such as casing collapse and lost equipment in the wellbore. In addition, the fracturing of the Marcellus Shale will be more extensive and complicated than fracturing the geological formations in our other areas of operation.

Changes in tax laws may impair our ability to obtain capital funds through investment partnerships .Under current federal tax laws, there are tax benefits to investing in investment partnerships such as those we sponsor, including deductions for intangible drilling costs and depletion deductions. Changes to federal tax law that reduce or eliminate these benefits may make investment in our investment partnerships less attractive and, thus, reduce our ability to obtain funding from this significant source of capital funds.

We have a substantial amount of indebtedness which could adversely affect our financial position. We currently have a substantial amount of indebtedness. As of February 20, 2008, we had total debt of approximately $770.1 million, consisting of $250.0 million of senior notes, $520.0 million of borrowings under our credit facility, and $0.1 million of other debt. We may also incur significant additional indebtedness in the future. Our substantial indebtedness may:

make it difficult for us to satisfy our financial obligations, including making scheduled principal and interest payments on the senior notes and our other indebtedness;
 
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limit our ability to borrow additional funds for working capital, capital expenditures, acquisitions or other general business purposes;

limit our ability to use our cash flow or obtain additional financing for future working capital, capital expenditures, acquisitions or other general business purposes;

require us to use a substantial portion of our cash flow from operations to make debt service payments;

limit our flexibility to plan for, or react to, changes in our business and industry;

place us at a competitive disadvantage compared to our less leveraged competitors; and

increase our vulnerability to the impact of adverse economic and industry conditions.

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to affect any of these remedies on satisfactory terms or at all.

Covenants in our debt agreements restrict our business in many ways. The indenture governing our senior notes and our credit facility contain various covenants that limit our ability and/or our subsidiaries’ ability to, among other things:

incur or assume liens or additional debt or provide guarantees in respect of obligations of other persons;

issue redeemable stock and preferred stock;

pay dividends or distributions or redeem or repurchase capital stock;

prepay, redeem or repurchase debt;

make loans, investments and capital expenditures;

enter into agreements that restrict distributions from our subsidiaries;

sell assets and capital stock of our subsidiaries;

enter into certain transactions with affiliates; and

consolidate or merge with or into, or sell substantially all of our assets to, another person.

In addition, our credit facility contains restrictive covenants and requires us to maintain specified financial ratios. Our ability to meet those financial ratios can be affected by events beyond our control, and we may be unable to meet those tests. A breach of any of these covenants could result in a default under our credit facility and/or the senior notes. Upon the occurrence of an event of default under our credit facility, the lenders could elect to declare all amounts outstanding under our credit facility to be immediately due and payable and terminate all commitments to extend further credit. If we were unable to repay those amounts, the lenders could proceed against the collateral granted to them to secure that indebtedness. We have pledged a significant portion of our assets as collateral under our credit facility. If the lenders under our credit facility accelerate the repayment of borrowings, we may not have sufficient assets to repay our credit facility and our other indebtedness, including the notes. Our borrowings under our credit facility are, and are expected to continue to be, at variable rates of interest and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income would decrease.
 
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Changes in tax laws may impair our ability to obtain capital funds through investment partnerships. Under current federal tax laws, there are tax benefits to investing in investment partnerships such as those we sponsor, including deductions for intangible drilling costs and depletion deductions. Changes to federal tax law that reduce or eliminate these benefits may make investment in our investment partnerships less attractive and, thus, reduce our ability to obtain funding from this significant source of capital funds.

We may not be able to continue to raise funds through our investment partnerships at the levels we have recently experienced, which may in turn restrict our ability to maintain our drilling activity at the levels recently experienced. We have sponsored limited and general partnerships to raise funds from investors to finance our development drilling activities in Appalachia. Accordingly, the amount of development activities we undertake there depends in large part upon our ability to obtain investor subscriptions to invest in these partnerships. During the past three years we have raised successively larger amounts of funds through these investment partnerships, raising $148.7 million in fiscal 2005, and $52.2 million in the three months ended December 31, 2005 and $218.5 million and $363.3 million in calendar 2006 and 2007, respectively. In the future, we may not be successful in raising funds through these investment partnerships at the same levels we have recently experienced, and we also may not be successful in increasing the amount of funds we raise as we have done in recent years. Our ability to raise funds through our investment partnerships depends in large part upon the perception of investors of their potential return on their investment and their tax benefits from investing in them, which perception is influenced significantly by our historical track record of generating returns and tax benefits to the investors in our existing partnerships.

In the event that our investment partnerships do not achieve satisfactory returns on investment or the anticipated tax benefits, we may have difficulty in continuing to increase the amount of funds we raise through these partnerships or in maintaining the level of funds we have recently raised through these partnerships. In this event, we may need to obtain financing for our drilling activities on a less attractive basis than the financing we realize through these partnerships or we may determine to reduce our drilling activity.

Our fee-based revenues may decline if we are unsuccessful in continuing to sponsor investment partnerships, and our fee-based revenue may not increase at the same rate as recently experienced if we are unable to raise funds at the same or higher levels as we have recently experienced. Our fee-based revenues are based on the number of investment partnerships we sponsor and the number of partnerships and wells we manage or operate. If we are unsuccessful in sponsoring future investment partnerships, our fee-based revenues may decline. Additionally, our fee-based revenue may not increase at the same rate as recently experienced if we are unable to raise funds at the same or higher levels as we have recently experienced.

Our revenues may decrease if investors in our investment partnerships do not receive a minimum return.
We have agreed to subordinate up to 50% of our share of production revenues to specified returns to the investor partners in our investment partnerships, typically 10% per year for the first five years of distributions. Thus, our revenues from a particular partnership will decrease if it does not achieve the specified minimum return and our ability to make distributions to unit holders may be impaired. We have not subordinated our share of revenues from any of our investment partnerships since March 2005, but did subordinate $91,000 in 2005 and $335,000 in 2004.

Competition in the natural gas and oil industry is intense, which may hinder our ability to acquire gas and oil properties and companies and to obtain capital, contract for drilling equipment and secure trained personnel. We operate in a highly competitive environment for acquiring properties and other natural gas and oil companies, attracting capital through our investment partnerships, contracting for drilling equipment and securing trained personnel. We will also compete with the exploration and production divisions of public utility companies for natural gas and oil property acquisitions. Our competitors may be able to pay more for natural gas and oil properties and drilling equipment and to evaluate, bid for and purchase a greater number of properties than our financial or personnel resources permit. Moreover, our competitors for investment capital may have better track records in their programs, lower costs or better connections in the securities industry segment that markets oil and gas investment programs than we do. All of these challenges could make it more difficult for us to execute our growth strategy. We may not be able to compete successfully in the future in acquiring leasehold acreage or prospective reserves or in raising additional capital.

Furthermore, 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. Competition is intense for the acquisition of leases considered favorable for the development of natural gas and oil in commercial quantities. Product availability and price are the principal means of competition in selling natural gas and oil. Many of our competitors possess greater financial and other resources than ours, which may enable them to identify and acquire desirable properties and market their natural gas and oil production more effectively than we do.
 
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We depend on certain key customers for sales of our natural gas. To the extent these customers reduce the volumes of natural gas they purchase from us, our revenues and cash available for distribution could decline. In Appalachia, our natural gas is sold under contracts with various purchasers. Under a natural gas supply agreement with Hess Corporation, which expires on March 31, 2009, Hess Corporation has a last right of refusal to buy all of the natural gas produced and delivered by our affiliates, and us including our investment partnerships. During fiscal 2007, natural gas sales to Hess Corporation accounted for approximately 18% of our total Appalachian oil and gas revenues. In Michigan, during the six months ended December 31, 2007, gas under contracts to a former affiliate of Atlas Gas & Oil, which expire at various dates through 2012, accounted for approximately 62% of our total Michigan oil and gas revenues. To the extent these and other key customers reduce the amount of natural gas they purchase from us, our revenues and cash available for distributions to unitholders could temporarily decline in the event we are unable to sell to additional purchasers.

Our Appalachia business depends on the gathering and transportation facilities of Atlas Pipeline. Any limitation in the availability of those facilities would interfere with our ability to market the natural gas we produce and could reduce our revenues and cash available for distribution Atlas Pipeline gathers more than 90% of our current Appalachia production and approximately 50% of our total production. The marketability of our natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems owned by Atlas Pipeline and other third parties. The amount of natural gas that can be produced and sold is subject to curtailment in circumstances such as pipeline interruptions due to scheduled and unscheduled maintenance or excessive pressure or physical damage to the gathering or transportation system. The curtailments arising from these and similar circumstances may last from a few days to several months.

If Atlas America fails to pay gathering fees to Atlas Pipeline as required by its assumption agreement with us, we will have to pay to Atlas Pipeline the difference between the gathering fee payable and the amount we receive from our investment partnerships for gathering services out of our own resources. We are a party to master gas gathering agreements with Atlas Pipeline, which requires, among other things, paying Atlas Pipeline gathering fees for gathering our gas. The gathering agreement is a continuing obligation and not terminable by us, except that if Atlas Pipeline’s general partner is removed without cause, then no gathering fees will be due under the agreement with respect to new wells drilled by us. Atlas America assumed our obligation to pay these gathering fees pursuant to the contribution agreement entered into at the completion of our initial public offering, and we agreed to pay Atlas America the gathering fees we receive from our investment partnerships and fees associated with production to our interest. The gathering fees payable to Atlas Pipeline generally exceed the amount we receive from our investment partnerships for gathering services. For the year ended December 31, 2007, this excess amount was approximately $11.9 million. If Atlas America defaulted on its obligation to us under the assumption agreement to pay gathering fees to Atlas Pipeline, we would be liable to Atlas Pipeline for the payment of the fees, which would reduce our income and cash available for payments on the notes.

Shortages of drilling rigs, equipment and crews could delay our operations. Higher natural gas and oil prices generally increase the demand for drilling rigs, equipment and crews and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Over the past three years, we and other natural gas and oil companies have experienced higher drilling and operating costs. Shortages of, or increasing costs for, experienced drilling crews and oil field equipment and services could restrict our ability to drill the wells and conduct the operations which we currently have planned. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues.

Because we handle natural gas and oil, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment. The operations of our wells and other facilities are subject to stringent and complex federal, state and local environmental laws and regulations. These 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;
 
27

 
·  
RCRA and comparable state laws that impose requirements for the handling and disposal of waste from our facilities; and
 
·  
CERCLA and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which we have sent waste for disposal.
 
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including the RCRA, CERCLA, the federal Oil Pollution Act and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

There is an inherent risk that we may incur environmental costs and liabilities due to the nature of our business and the substances we handle. For example, an accidental release from one of our wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies may be enacted or adopted and could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover remediation costs under our insurance policies.

Many of our leases are in areas that have been partially depleted or drained by offset wells. Our key project areas are located in active drilling areas in the Appalachian Basin. As a result, many of our leases are in areas that have already been partially depleted or drained by earlier offset drilling. This may inhibit our ability to find economically recoverable quantities of natural gas in these areas.

Our identified drilling location inventories are susceptible to uncertainties that could materially alter the occurrence or timing of our drilling activities, which may result in lower cash from operations. Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. As of December 31, 2007, we had identified over 3,950 potential drilling locations. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, natural gas prices, costs and drilling results. In addition, our independent petroleum engineering consultants have not assigned any proved reserves to the over 2,650 unproved potential drilling locations we have identified and therefore there may exist greater uncertainty with respect to the success of drilling wells at these drilling locations. Our final determination on whether to drill any of these drilling locations will be dependent upon the factors described above as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, we do not know if the numerous drilling locations we have identified will be drilled within our expected timeframe or will ever be drilled or if we will be able to produce natural gas and oil from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from our anticipated drilling activities.

Some of our undeveloped leasehold acreage is subject to leases that may expire in the near future. Leases covering approximately 44,900 of our 1,037,300 net acres, or 4%, are scheduled to expire on or before December 31, 2008. If we are unable to renew these leases or any leases scheduled for expiration beyond December 31, 2008, on favorable terms, we will lose the right to develop the acreage that is covered by an expired lease and our production would decline, which would reduce our cash flows from operations and could impair our ability to make payments on the notes.

Drilling for and producing natural gas are high-risk activities with many uncertainties. Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for natural gas can be uneconomic, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:
 
28

 
·  
the high cost, shortages or delivery delays of equipment and services;
 
·  
unexpected operational events and drilling conditions;
 
·  
adverse weather conditions;
 
·  
facility or equipment malfunctions;
 
·  
title problems;
 
·  
pipeline ruptures or spills;
 
·  
compliance with environmental and other governmental requirements;
 
·  
unusual or unexpected geological formations;
 
·  
formations with abnormal pressures;
 
·  
injury or loss of life;
 
·  
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.
 
Any one or more of the factors discussed above could reduce or delay our receipt of drilling and production revenues, thereby reducing our earnings, and could reduce revenues in one or more of our investment partnerships, which may make it more difficult to finance our drilling operations through sponsorship of future partnerships. 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 will maintain insurance against various losses and liabilities arising from our operations, insurance against all operational risks is not 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.

Properties that we buy may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities. One of our growth strategies is to capitalize on opportunistic acquisitions of natural gas reserves. However, our reviews of acquired properties are inherently incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well we acquire. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when we inspect a well. Any unidentified problems could result in material liabilities and costs that negatively affect our financial condition and results of operations.

Even if we are able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnity against all or part of these problems. Even if a seller agrees to provide indemnity, the indemnity may not be fully enforceable and may be limited by floors and caps on such indemnity.

Hedging transactions may limit our potential gains or cause us to lose money. Pricing for natural gas has been volatile and unpredictable for many years. To limit exposure to changing natural gas prices, we use financial and physical hedges for our natural gas production. Physical hedges are not deemed hedges for accounting purposes because they require firm delivery of natural gas and are considered normal sales of natural gas. We generally limit these arrangements to smaller quantities than those projected to be available at any delivery point. In addition, we may enter into financial hedges, which may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. The futures contracts are commitments to purchase or sell natural gas at future dates and generally cover one-month periods for up to six years in the future. By removing the price volatility from a significant portion of our natural gas production, we have reduced, but not eliminated, the potential effects of changing natural gas prices on our cash flow from operations for those periods. Furthermore, while intended to help reduce the effects of volatile natural gas prices, such transactions, depending on the hedging instrument used, may limit our potential gains if natural gas prices were to rise substantially over the price established by the hedge. Under circumstances in which, among other things, production is substantially less than expected, the counterparties to our futures contracts fail to perform under the contracts or a sudden, unexpected event materially impacts natural gas prices, we may be exposed to the risk of financial loss.
 
29

 
We may be exposed to financial and other liabilities as the managing general partner in investment partnerships. We serve as the managing general partner of 92 investment partnerships and will be the managing general partner of new investment partnerships that we sponsor. As a general partner, we are contingently liable for the obligations of these partnerships to the extent that partnership assets or insurance proceeds are insufficient. We have agreed to indemnify each investor partner in our investment partnerships from any liability that exceeds such partner’s share of the investment partnership’s assets.

We are subject to comprehensive federal, state, local and other laws and regulations that could increase the cost and alter the manner or feasibility of our doing business. Our operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon natural gas and oil wells. Under these laws and regulations, we could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.

Part of the regulatory environment in which we operate includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our activities are subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of natural gas we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could inhibit our ability to develop our properties. Additionally, the natural gas and oil regulatory environment could change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, reduce our profitability. Furthermore, we may be put at a competitive disadvantage to larger companies in our industry who can spread these additional costs over a greater number of wells and larger operating staff. Please read “Business—Environmental Matters and Regulation” and “Business—Other Regulation of the Natural Gas and Oil Industry” for a description of the laws and regulations that affect us.

Our limited liability company agreement limits and modifies our directors’ and officers’ fiduciary duties. Our limited liability company agreement contains provisions that modify and limit our directors’ and officers’ fiduciary duties to our unit holders and us. For example, our limited liability company agreement provides that:

·  
our directors and officers will not have any liability to us or our unit holders for decisions made in good faith, which is defined so as to require that they believed the decision was in our best interests; and
 
·  
our directors and officers will not be liable for monetary damages to us or our unit holders for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the directors or officers acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that such conduct was unlawful.

Members of our board of directors and Atlas America and its affiliates, including our manager, may have conflicts of interest with us. Conflicts of interest may arise between us and our unit holders and members of our board of directors and Atlas America and its affiliates, including our manager. These potential conflicts may relate to the divergent interests of these parties. Situations in which the interests of members of our board of directors and Atlas America and its affiliates, may differ from interests of owners of common units include, among others, the following situations:
 
30


·  
Our limited liability company agreement gives our board of directors broad discretion in establishing cash reserves for the proper conduct of our business, which will affect the amount of cash available for distribution. For example, our board of directors will use its reasonable discretion to establish and maintain cash reserves sufficient to maintain our asset base.
 
·  
Our manager will recommend to our board of directors the timing and extent of our drilling program and related capital expenditures, asset purchases and sales, and financing alternatives and reserve adjustments, all of which will affect the amount of cash that we distribute to our unit holders.
 
·  
In some instances our board of directors may cause us to borrow funds in order to permit us to pay cash distributions to our unit holders, even if the purpose or effect of the borrowing is to make management incentive distributions.
 
·  
Except as provided in our omnibus agreement with Atlas America, members of our board of directors and Atlas America and its affiliates, including our manager, are not prohibited from investing or engaging in other businesses or activities that compete with us.
 
·  
We do not have any employees and rely solely on employees of our manager and its affiliates. Our officers and the officers of our manager who provide services to us are not required to work full time on our affairs. These officers may devote significant time to the affairs of our manager’s affiliates. There may be significant conflicts between us and our affiliates regarding the availability of these officers to manage us.

Our limited liability company agreement provides for a limited call right that may require unit holders to sell their common units at an undesirable time or price. If, at any time, any person owns more than 87.5% of the common units then outstanding, such person has the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units then outstanding at a price not less than the then-current market price of the common units. As a result, our unit holders may be required to sell their common units at an undesirable time or price and therefore may receive a lower or no return on their investment. Unit holders may also incur tax liability upon a sale of their units.

Our manager may transfer its interests in us to a third party without common unitholder consent. Our manager may transfer its Class A units and management incentive interests to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our common unit holders. Furthermore, Atlas America is not restricted from transferring its equity interest in our manager.

Atlas America may sell common units in the future, which could reduce the market price of our outstanding units. Atlas America owns 29,352,996 common units. In addition, our manager has the right to convert its Class A units and management incentive interests into common units if we terminate the management agreement, and its Class A units will automatically convert into common units, and it will have the option of converting its management incentive interests, if the common unit holders vote to eliminate the special voting rights of our Class A units. We have agreed to register for sale common units held by Atlas America and its affiliates. These registration rights allow Atlas America, our manager and their affiliates to request registration of their common units and to include any of those units in a registration of other securities by us. If Atlas America and its affiliates were to sell a substantial portion of their units, it could reduce the market price of our outstanding common units.

We depend on our manager and Atlas America, and may not find suitable replacements if the management agreement terminates. We have no employees. Our support personnel are employees of Atlas America. We have no separate facilities and completely rely on our manager and, because our manager has no direct employees, Atlas America. If our management agreement terminates, we may be unable to find a suitable replacement for them.

Our management agreement was not negotiated at arm’s-length and, as a result, may not be as favorable to us as if it had been negotiated with a third party. Our officers and four of our directors, Edward E. Cohen, Jonathan Z. Cohen, Richard D. Weber and Matthew A. Jones, are officers or directors of our manager, and Messrs. Cohen are directors of Atlas America. As a consequence, our management agreement was not the result of arm’s-length negotiations and its terms may not be as favorable to us as if it had been negotiated with an unaffiliated third party.
 
31


Expense reimbursements due to our manager under our management agreement will reduce cash available for distribution to our unit holders. Before making any distribution on our common units, we will reimburse our manager for all expenses that it incurs on our behalf pursuant to the management agreement. These expenses will include all costs incurred on our behalf, including costs for providing corporate staff and support services to us. Our manager will charge on a fully allocated cost basis for services provided to us. This fully allocated cost basis is based on the percentage of time spent by personnel of our manager and its affiliates on our matters and includes the compensation paid by our manager and its affiliates to such persons and their allocated overhead. The allocation of compensation expense for such persons will be determined based on a good faith estimate of the value of each such person’s services performed on our business and affairs, subject to the periodic review and approval of our audit or conflicts committee.

Termination of the management agreement by us is difficult. Termination of our management agreement is difficult: we may terminate the management agreement only upon the affirmative vote of at least two-thirds of our outstanding common units, including units owned by Atlas America and its affiliates. Upon any termination, our manager will have the right to convert its Class A units into common units on a one-for-one basis and convert its management incentive interests into common units based on their fair market value if the successor manager does not purchase them. Atlas America will be able to prevent the removal of our manager so long as it owns at least two-thirds of our common units.

Our manager’s liability is limited under the management agreement, and we have agreed to indemnify our manager against certain liabilities. Our manager will not assume any responsibility under the management agreement other than to render the services called for under it, and will not be responsible for any action of our board of directors in following or declining to follow its advice or recommendations. Our manager, its directors, officers, employees and affiliates will not be liable to us, any subsidiary of ours, our directors or our unit holders for acts performed in good faith and in accordance with the management agreement, except by reason of acts constituting bad faith, willful misconduct, fraud or criminal conduct. We have agreed to indemnify the parties for all damages and claims arising from acts not constituting bad faith, willful misconduct, fraud or criminal conduct and performed in good faith in accordance with and pursuant to the management agreement.

Our limited liability company agreement restricts the voting rights of unit holders owning 20% or more of our common units. Our limited liability company agreement restricts the voting rights of common unit holders by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than Atlas America, our manager, their affiliates or transferees and persons who acquire such units with the prior approval of our board of directors, cannot vote on any matter. Our limited liability company agreement also contains provisions limiting the ability of common unit holders to call meetings or to acquire information about our operations, as well as other provisions limiting common unit holders’ ability to influence the manner or direction of management.

If the holders of our common units vote to eliminate the special voting rights of the holders of our Class A units, the Class A units will automatically convert into common units on a one-for-one basis and our manager will have the option of converting the management incentive interests into common units at their fair market value, which may be dilutive to you. The holders of our Class A units have the right to vote as a separate class on extraordinary transactions submitted to a unitholder vote such as a merger or sale of all or substantially all of our assets. This right can be eliminated upon a vote of the holders of not less than two-thirds of our outstanding common units. If such elimination is so approved, the Class A units will automatically convert into common units on a one-for-one basis and our manager will have the right to convert its management incentive interests into common units based on their then fair market value, which may be dilutive to you.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for distribution. The anticipated after-tax benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us.If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed as corporate distributions, and no income, gain, loss, deduction or credit would flow through to you. Because a tax may be imposed on us as a corporation, our cash available for distribution to our unit holders could be reduced. Therefore, our treatment as a corporation could result in a material reduction in the anticipated cash flow and after-tax return to our unit holders and therefore result in a substantial reduction in the value of our common units. Current law or our business may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced. Our limited liability company agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the IQD amount and the incentive distribution amounts will be adjusted to reflect the impact of that law on us.
 
32

 
We will be considered to have terminated for tax purposes due to a sale or exchange of 50% or more of our interests within a twelve-month period. We will be considered to have terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. A constructive termination results in the closing of our taxable year for all unit holders and in the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, may result in more than 12 months of our taxable income or loss being includable in taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns, and unit holders receiving two Schedule K-1s, for one fiscal year and the cost of the preparation of these returns will be borne by all unit holders.


None

ITEM 2: PROPERTIES

Office Properties

We lease a 27,000 square foot office building in Moon Township, Pennsylvania. We own a 17,000 square foot field office and warehouse facility in Jackson Center, Pennsylvania, a 24,000 square foot office in Fayette County, Pennsylvania and an office in Deerfield, Ohio. We lease a 13,800 square foot office building in Traverse City, Michigan under a lease expiring in 2012. We lease a 1,400 square foot field office in Ohio under a lease expiring in 2009. We also rent 17,200 square feet of office space in Uniontown, Ohio under a lease expiring in August 2008. We also lease other field offices in Ohio and New York on a month-to-month basis.

Natural Gas and Oil Reserves

The following tables summarize information regarding our estimated proved natural gas and oil reserves as of the dates indicated. Proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. The estimated reserves include reserves attributable to our direct ownership interests in oil and gas properties as well as the reserves attributable to our percentage interests in the oil and gas properties owned by investment partnerships in which we own partnership interests. All of the reserves are generally located in the Appalachian Basin and in Michigan’s Lower Peninsula. We base these estimated proved natural gas and oil reserves and future net revenues of natural gas and oil reserves upon reports prepared by independent petroleum engineers. In accordance with SEC guidelines, we make the standardized measure and PV-10 estimates of future net cash flows from proved reserves using natural gas and oil sales prices in effect as of the dates of the estimates, which are held constant throughout the life of the properties. We based our estimates of proved reserves upon the following weighted average prices as of the dates indicated:
 
33

 
   
At December 31,
 
At September 30,
 
   
2007
 
2006
 
2005
 
2005
 
                   
Natural gas (per Mcf)
 
$
6.93
 
$
6.33
 
$
10.84
 
$
14.75
 
Oil (per Bbl)
 
$
90.30
 
$
57.26
 
$
57.54
 
$
63.29
 

Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas and oil reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production and the timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserve reports of other engineers might differ from the reports of our consultants, Wright & Company. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of this estimate. Future prices received from the sale of natural gas and oil may be different from those estimated by our independent petroleum engineering firm in preparing their reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, the reserves set forth in the following tables ultimately may not be produced and the proved undeveloped reserves may not be developed within the periods anticipated. Please read “Item1A: Risk factors” You should not construe the estimated PV-10 and standardized measure values as representative of the current or future fair market value of our proved natural gas and oil properties. PV-10 and standardized measure values are based upon projected cash inflows, which do not provide for changes in natural gas and oil prices or for the escalation of expenses and capital costs. The meaningfulness of these estimates depends upon the accuracy of the assumptions upon which they were based.

We evaluate natural gas reserves at constant temperature and pressure. A change in either of these factors can affect the measurement of natural gas reserves. We deduct operating costs, development costs and production-related and ad valorem taxes in arriving at the estimated future cash flows. We base the estimates on operating methods and conditions prevailing as of the dates indicated.

   
Proved natural
 
 Proved natural
 
   
gas and oil reserves for
 
gas and oil reserves for
 
   
Atlas Energy Resources at
 
Atlas America E&P Operations at
 
   
December 31,
 
December 31,
 
September 30,
 
   
2007
 
2006
 
2005
 
2005
 
Natural gas reserves (Mmcf):
                 
Proved developed reserves
   
594,709
   
107,683
   
108,674
   
104,786
 
Proved undeveloped reserves (1)
   
290,050
   
60,859
   
49,250
   
53,241
 
Total proved reserves of natural gas
   
884,759
   
168,542
   
157,924
   
158,027
 
                           
Oil reserves (Mbbl):
                         
Proved developed reserves
   
1,977
   
2,064
   
2,122
   
2,116
 
Proved undeveloped reserves
   
6
   
4
   
135
   
143
 
Total proved reserves of oil
   
1,983
   
2,068
   
2,257
   
2,259
 
Total proved reserves (Mmcfe)
   
896,657
   
180,950
   
171,466
   
171,581
 
                           
PV-10 estimate of cash flows of proved reserves (in thousands) (2):
                         
Proved developed reserves
 
$
1,264,309
 
$
279,330
 
$
465,459
 
$
617,445
 
Proved undeveloped reserves
   
216,869
   
4,111
   
131,678
   
228,206
 
Total PV-10 estimate (3)
 
$
1,481,178
 
$
283,441
 
$
597,137
 
$
845,651
 
Standardized measure of discounted future cash flows (in thousands) (2) (3)
 
$
1,481,178
 
$
283,441
 
$
429,272
 
$
606,697
 
___________
 
(1)  
Our ownership in these reserves is subject to reduction as we generally contribute leasehold acreage associated with our proved undeveloped reserves to our investment partnerships in exchange for an approximate 30% equity interest in these partnerships, which effectively will reduce our ownership interest in these reserves from 100% to 30% as we make these contributions.
 
34

 
(2)  
Amounts shown for September 30, 2005 and December 31, 2005 reflect values for Atlas America E&P Operations, which paid income taxes. Amounts shown for December 31, 2006 and 2007 reflect values for our reserves. Since we are a limited liability company that allocates our taxable income to our unit holders, no provision for federal or state income taxes has been included in the December 31, 2006 and 2007 calculations of standardized measure which is, therefore, the same as the PV-10 value. Amounts include physical hedges but not financial hedging transactions.
 
(3)  
The following reconciles the PV-10 value to the standardized measure:
 
   
Proved natural gas and oil reserves for
 
Proved natural gas and oil reserves for
 
   
Atlas Energy Resources at
 
Atlas America E&P Operations at
 
   
December 31,
 
December 31,
 
September 30,
 
   
2007
 
2006
 
2005
 
2005
 
PV-10 value
 
$
1,481,178
 
$
283,441
 
$
597,137
 
$
845,651
 
Income tax effect
   
   
   
(167,865
)
 
(238,954
)
Standardized measure
 
$
1,481,178
 
$
283,441
 
$
429,272
 
$
606,697
 
 
Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.

Productive Wells

The following table sets forth information as of December 31, 2007, regarding productive natural gas and oil wells in which we have a working interest. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, directly or through our ownership interests in investment partnerships, and net wells are the sum of our fractional working interests in gross wells, based on the percentage interest we own in the investment partnership that owns the well.

   
Number of productive wells
 
   
Gross(1)
 
Net(1)
 
Oil wells
   
512
   
368
 
Gas wells
   
9,502
   
5,211
 
Total
   
10,014
   
5,579
 

____________
(1)
Includes our proportionate interest in wells owned by 92 investment partnerships for which we serve as managing general partner and various joint ventures. Does not include royalty or overriding interests in 705 wells.

Gas and Oil Production

The following table sets forth the quantities of our natural gas and oil production, average sales prices and average production costs per equivalent unit of production for the periods indicated.

                   
Average
 
                   
production
 
   
Production
 
Average sales price
 
cost per
 
Period
 
Oil (Bbls)
 
Gas (Mcf)
 
per Bbl
 
per Mcf (1)
 
Mcfe (2)
 
Year ended December 31, 2007
   
153,465
   
20,963,436
 
$
70.16
 
$
8.66
 
$
1.47
 
Year ended December 31, 2006
   
150,628
   
8,946,376
 
$
62.30
 
$
8.83
 
$
1.41
 
Three months ended December 31, 2005
   
39,678
   
1,975,099
 
$
56.13
 
$
11.06
 
$
1.10
 
Year ended September 30, 2005
   
157,904
   
7,625,695
 
$
50.91
 
$
7.26
 
$
.95
 

(1)  
Average sales price before the effects of financial hedging was $7.22 and $7.90 for the year ended December 31, 2007 and 2006, respectively. We did not have any financial hedging transactions in any of the other periods presented.
(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.
 
35

 
Developed and Undeveloped Acreage

The following table sets forth information about our developed and undeveloped natural gas and oil acreage as of December 31, 2007. The information in this table includes our proportionate interest in acreage owned by our investment partnerships. The table does not include the approximately 212,000 acres in Tennessee covered by our joint venture with Knox Energy because we do not own this acreage.

   
Developed acreage
 
Undeveloped acreage
 
   
Gross
 
Net
 
Gross
 
Net
 
Arkansas
   
2,560
   
403
   
   
 
Kansas
   
160
   
20
   
   
 
Kentucky
   
924
   
462
   
9,060
   
4,530
 
Louisiana
   
1,819
   
206
   
   
 
Michigan
   
293,999
   
231,869
   
63,005
   
53,262
 
Mississippi
   
40
   
3
   
   
 
Montana
   
   
   
2,650
   
2,650
 
New York
   
20,517
   
14,972
   
45,123
   
45,123
 
North Dakota
   
639
   
96
   
   
 
Ohio
   
114,033
   
95,913
   
32,025
   
32,025
 
Oklahoma
   
4,323
   
468
   
   
 
Pennsylvania
   
123,898
   
123,898
   
376,002
   
376,002
 
Tennessee
   
14,689
   
13,411
   
31,177
   
31,177
 
Texas
   
4,520
   
329
   
   
 
West Virginia
   
1,078
   
539
   
12,530
   
9,852
 
Wyoming
   
   
   
80
   
80
 
     
583,199
   
482,589
   
571,652
   
554,701
 
________________
(1)  
Developed acres are acres spaced or assigned to productive wells.
(2)  
Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether such acreage contains proved reserves.
(3)  
A gross acre is an acre in which we own an interest. The number of gross acres is the total number of acres in which we own an interest.
(4)  
Net acres are the sum of the fractional interests owned in gross acres. For example, a 50% interest in an acre is one gross acre but is 0.50 net acre.

The leases for our developed acreage generally have terms that extend for the life of the wells, while the leases on our undeveloped acreage have terms that vary from less than one year to five years. We paid rentals of approximately $2.4 million in fiscal 2007 to maintain our leases.

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

Our properties are subject to royalty, overriding royalty and other outstanding interests customary in the industry. Our properties are also subject to burdens such as liens incident to operating agreements, taxes, development obligations under natural gas and oil leases, farm-out arrangements and other encumbrances, easements and restrictions. We do not believe that any of these burdens will materially interfere with our use of our properties.
 
36

 
Drilling Activity

The number of wells we drill will vary depending on the amount of money we raise through our investment partnerships, the cost of each well, the estimated recoverable reserves attributable to each well and accessibility to the well site. The following table sets forth information with respect to the number of wells in which we have completed drilling during the periods indicated, regardless of when we initiated drilling

   
Development wells
 
Exploratory wells
 
   
Productive
 
Dry
 
Productive
 
Dry
 
   
Gross(1)
 
Net(2)
 
Gross(1)
 
Net(2)
 
Gross(1)
 
 Net(2)
 
Gross(1)
 
Net(2)
 
Appalachia:
                                  
Year ended December 31, 2007
   
1106.0
   
377.6
   
11.0
   
4.0
   
   
   
   
 
Year ended December 31, 2006
   
711.0
   
235.3
   
4.0
   
1.4
   
   
   
   
 
Three months ended December 31, 2005
   
192.0
   
64.1
   
   
   
   
   
   
 
Year ended September 30, 2005
   
644.0
   
210.0
   
18.0
   
6.3
   
   
   
   
 
Michigan:
                                                 
Year ended December 31, 2007
   
115.0
   
92.23
   
   
   
   
   
   
 
________________
 
(1)
Includes the number of physical wells in which we hold any working interest, regardless of our percentage interest.
 
(2)
Includes (i) our percentage interest in wells in which we have a direct ownership interest and (ii) with respect to wells in which we have an indirect ownership interest through our investment partnerships, our percentage interest in the wells based on our percentage interest in our investment partnerships and not those of the other partners in our investment partnerships.
 
ITEM 3: LEGAL PROCEEDINGS

One of our subsidiaries, Resource Energy, LLC, together with Resource America, Inc., (the former parent of AAI), was a defendant in a class action originally filed in February 2000 in the New York Supreme Court, Chautauqua County, by individuals, putatively on their own behalf and on behalf of similarly situated individuals, who leased property to us. The complaint alleged that we were not paying landowners the proper amount of royalty revenues with respect to natural gas produced from the leased properties. The complaint was seeking damages in an unspecified amount for the alleged difference between the amount of royalties actually paid and the amount of royalties that allegedly should have been paid. In April 2007, a settlement of this lawsuit was approved by the court. Pursuant to the settlement terms, we paid $300,000 in May 2007, upgraded certain gathering systems and capped certain transportation expenses chargeable to the landowners. We were indemnified by AAI for this matter.

Atlas Gas & Oil Company LLC, as successor to DTE Gas & Oil Company, was one of four defendants in a personal injury action filed in Antrim County Circuit Court in northern Michigan in August 2006.  The complaint alleged that plaintiff suffered serious personal injuries as a result of the defendants’ negligence. The Company paid $125,000 to the plaintiff in October 2007 in full settlement of this action.

We are also a party to various routine legal proceedings arising in the ordinary course of our business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of results of operations.
 
ITEM 4: SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On November 11, 2007 Atlas America, Inc. and Atlas Energy Management, Inc. took action by written resolutions in lieu of a special meeting of unitholders to approve (a) the change in the terms of our then outstanding Class D units to provide that each Class D unit would convert automatically into one of our common units and (b) the issuance of 16,702,827 common units to be issued upon such conversion. On that date, Atlas America and Atlas Energy Management collectively held 30,591,982 of our common units and Class A units, representing approximately 80.61% of our then outstanding voting units. We provided an information statement to each unitholder relating to this action on or about October 22, 2007.

37

 
PART II
ITEM 5: MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED SHAREHOLDERMATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common units are quoted on the New York Stock Exchange (“NYSE”) under the symbol "ATN." The following table sets forth the high and low sale prices, as reported by the NYSE, on a quarterly basis since our initial public offering in December 2006.

Fiscal 2007
 
High
 
Low
 
Fourth Quarter
 
$
36.00
 
$
28.50
 
Third Quarter
 
$
38.85
 
$
28.75
 
Second Quarter
 
$
37.47
 
$
26.26
 
First Quarter
 
$
27.46
 
$
22.10
 
               
Fiscal 2006
   
High
   
Low
 
Fourth Quarter
 
$
22.88
 
$
21.80
 

As of February 11, 2008, there were 60,710,749 common units outstanding held by 48 holders of record. For a description of our recent sale of unregistered securities, see our Current Report on Form 8-K filed June 29, 2007.

Our Cash Distribution Policy

Our limited liability company agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2006, we distribute all of our available cash to unit holders of record on the applicable record date.

Available cash generally means, for each fiscal quarter, all cash on hand at the end of the quarter:

·  
less the amount of cash reserves established by our board of directors to:
o  
provide for the proper conduct of our business (including reserves for future capital expenditures and credit needs);
o  
comply with applicable law and any of our debt instruments or other agreements; and
o  
provide funds for distributions (1) to our unit holders for any one or more of the next four quarters or (2) with respect to our management incentive interests;
·  
plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.

Working capital borrowings are borrowings that are made under our credit facility or another arrangement and used solely for working capital purposes or to pay distributions to unit holders.

On January 28, 2008, we declared a quarterly cash distribution for the fourth quarter of 2007 of $0.57 per common unit, which was paid on February 14, 2008 to common unit holders of record as of February 7, 2008.

For information concerning common units authorized for issuance under our incentive plan, see “Item 12: Security Ownership or Certain Beneficial Owners and ManagementEquity Compensation Plan Information.”
 
38

 
ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth selected historical combined financial and operating data for our predecessor, Atlas America E&P Operations before the date of our initial public offering on December 18, 2006 and our historical combined and consolidated financial and operating data after that date for the periods indicated. Atlas America E&P Operations were the subsidiaries of Atlas America which held its natural gas and oil development and production assets and liabilities, substantially all of which Atlas America transferred to us upon the completion of our initial public offering. We derived the historical financial data as of December 31, 2007 and 2006 and for the years ended December 31, 2007 and 2006, the three months ended December 31, 2005 and the year ended September 30, 2005 from Atlas Energy Resources, LLC and Atlas America E&P Operations’ financial statements, which were audited by Grant Thornton LLP, an independent registered public accounting firm, and are included in this report. We derived the historical financial data as of December 31, 2005, September 30, 2005 and 2004 and for the year ended September 30, 2004 from Atlas E&P Operations’ audited financial statements, which are not included in this report. We derived the historical financial data as of September 30, 2003, and for the year ended September 30, 2003 from Atlas America E&P Operations’ unaudited financial statements, which are not included in this report.

You should read the following financial data in conjunction with “Management’s discussion and analysis of financial condition and results of operations” and our financial statements and related notes appearing elsewhere in this report.

39


           
Three Months
             
           
Ended
             
   
Years Ended December 31,
 
December 31,
 
Years Ended September 30,
 
   
2007
 
2006
 
2005
 
2005
 
2004
 
2003
 
   
(in thousands)
 
Income statement data:
                         
Revenues:
                         
Gas and oil production
 
$
180,125
 
$
88,449
 
$
24,086
 
$
63,499
 
$
48,526
 
$
38,639
 
Partnership management:
                                     
Well construction and completion
   
321,471
   
198,567
   
42,145
   
134,338
   
86,880
   
52,879
 
Administration and oversight
   
18,138
   
11,762
   
2,964
   
9,590
   
8,396
   
5,090
 
Well services
   
17,592
   
12,953
   
2,561
   
9,552
   
8,430
   
7,635
 
Gathering (1)
   
14,314
   
9,251
   
1,407
   
4,359
   
4,191
   
3,898
 
Gain on mark-to-market derivatives
   
26,257
   
   
   
   
   
 
Total revenues
   
577,897
   
320,982
   
73,163
   
221,338
   
156,423
   
108,141
 
Expenses:
                                     
Gas and oil production (1)
   
32,193
   
13,881
   
2,441
   
8,165
   
7,289
   
6,770
 
Partnership management:
                                     
Well construction and completion
   
279,540
   
172,666
   
36,648
   
116,816
   
75,548
   
45,982
 
Well services
   
9,062
   
7,337
   
1,487
   
5,167
   
4,398
   
3,773
 
Gathering (1)
   
214
   
   
38
   
52
   
53
   
29
 
Gathering fee - Atlas Pipeline (1)
   
13,781
   
29,545
   
7,930
   
21,929
   
17,189
   
14,564
 
General and administrative
   
39,414
   
23,367
   
5,818
   
13,202
   
11,708
   
10,106
 
Net expense reimbursement - affiliate
   
   
1,237
   
163
   
602
   
1,050
   
1,400
 
Depreciation, depletion and  amortization
   
56,942
   
22,491
   
4,916
   
14,061
   
12,064
   
9,938
 
Total operating expenses
   
431,146
   
270,524
   
59,441
   
179,994
   
129,299
   
92,562
 
Operating income
   
146,751
   
50,458
   
13,722
   
41,344
   
27,124
   
15,579
 
Other income (expenses):
                                     
Interest expense
   
(30,096
)
 
   
   
   
   
 
Other - net
   
849
   
1,369
   
57
   
79
   
444
   
358
 
Total other income(expense)
   
(29,247
)
 
1,369
   
57
   
79
   
444
   
358
 
Net income before cumulative effect of accounting change
   
117,504
   
51,827
   
13,779
   
41,423
   
27,568
   
15,937
 
Cumulative effect of accounting change (2)
   
   
6,355
   
   
   
   
 
Net income
 
$
117,504
 
$
58,182
 
$
13,779
 
$
41,423
 
$
27,568
 
$
15,937
 
Cash flow data:
                                     
Cash provided by operating activities
 
$
230,982
 
$
80,536
 
$
43,596
 
$
90,525
 
$
42,523
 
$
20,365
 
Cash used in investing activities
   
(1,468,434
)
 
(75,588
)
 
(17,185
)
 
(59,050
)
 
(32,709
)
 
(22,112
)
Cash provided by (used in) financing activities
   
1,253,877
   
(17,033
)
 
(11,739
)
 
(25,401
)
 
(14,916
)
 
34
 
Capital expenditures
 
$
196,735
 
$
75,635
 
$
17,187
 
$
59,124
 
$
33,252
 
$
22,607
 
Other financial information  (unaudited):
                                     
EBITDA
 
$
204,542
 
$
74,318
 
$
18,695
 
$
55,484
 
$
39,632
 
$
25,875
 
Adjusted EBITDA
 
$
199,099
 
$
94,949
 
$
25,649
 
$
73,109
 
$
52,747
 
$
36,570
 
Balance sheet data (at period end):
                                     
Total assets
 
$
1,891,234
 
$
415,463
 
$
315,052
 
$
270,402
 
$
198,454
 
$
178,451
 
Liabilities associated with drilling contracts
   
132,517
   
86,765
   
70,514
   
60,971
   
29,375
   
22,157
 
Advances from affiliates
   
8,696
   
12,502
   
4,257
   
13,897
   
30,008
   
34,776
 
Long-term debt, including current maturities
   
740,030
   
68
   
156
   
81
   
420
   
194
 
Total equity
 
$
836,115
 
$
212,682
 
$
154,519
 
$
146,142
 
$
109,461
 
$
102,031
 

40

 
_____________
(1)  
We charge gathering fees to our investment partnership wells that are connected to Atlas Pipeline’s gathering systems. Historically, we in turn paid these fees, plus an additional amount to bring the total gathering charge up to, generally, 16% of the gas sales price, to Atlas Pipeline in accordance with our gathering agreements with it. Upon the completion of our initial public offering, Atlas America assumed our obligation to pay gathering fees to Atlas Pipeline. We are obligated to pay the gathering fees we receive from our investment partnerships to Atlas America, with the result that our gathering revenues and expenses within our partnership management segment net to $0. We also pay our proportionate share of gathering fees based on our percentage interest in the well, which are included in gas and oil production expense. Atlas America E & P Operations also owned several small gathering systems. The expenses associated with these systems are shown as gathering fees on our combined statements of income. We do not own these gathering systems after the completion of our initial public offering.

(2)  
The cumulative effect of accounting change results from our adoption of FIN 47 (see Notes 2 and 5 to our combined and consolidated financial statements).

EBITDA AND ADJUSTED EBITDA

We define EBITDA as earnings before interest, taxes, depreciation, depletion, and amortization and cumulative effect of accounting change. We calculate Adjusted EBITDA by adjusting EBITDA for other non-cash items such as equity compensation. EBITDA and Adjusted EBITDA are not measures of performance calculated in accordance with GAAP. Although not prescribed under GAAP, we believe the presentation of EBITDA and Adjusted EBITDA are relevant and useful because they help our investors to understand our operating performance and make it easier to compare our results with other companies that have different financing and capital structures or tax rates. EBITDA and Adjusted EBITDA should not be considered in isolation of, or as a substitute for, 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 and may be different from the EBITDA calculation under our credit facility. In addition, EBITDA and Adjusted EBITDA do not represent funds available for discretionary use. The following reconciles our net income before taxes and cumulative effect of accounting change to our EBITDA and Adjusted EBITDA for the periods indicated:
           
Three Months
     
           
Ended
 
Years Ended
 
   
Years Ended December 31,
 
December 31,
 
September 30,
 
   
2007
 
2006
 
2005
 
2005
 
2004
 
2003
 
   
(in thousands)
 
Net income before cumulative effect of accounting change
 
$
117,504
 
$
51,827
 
$
13,779
 
$
41,423
 
$
27,568
 
$
15,937
 
Plus interest expense
   
30,096
   
   
   
   
   
 
Plus depreciation, depletion and amortization
   
56,942
   
22,491
   
4,916
   
14,061
   
12,064
   
9,938
 
EBITDA
   
204,542
   
74,318
   
18,695
   
55,484
   
39,632
   
25,875
 
Less gain on mark-to-market derivatives
   
(14,000
)
 
   
   
   
   
 
Plus non-recurring derivative fees
   
3,873
                               
Plus non-cash stock compensation
   
4,684
   
337
   
393
   
300
   
64
   
 
Plus gathering fee
   
   
20,294
   
6,561
   
17,622
   
13,051
   
10,695
 
Adjusted EBITDA
 
$
199,099
 
$
94,949
 
$
25,649
 
$
73,109
 
$
52,747
 
$
36,570
 

41

 
ITEM 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
GENERAL

Manner of Presentation

The historical financial statements prior to our initial public offering on December 18, 2006 included in this report reflect substantially all the assets, liabilities and operations of various wholly-owned subsidiaries of Atlas America, which were contributed to us upon the closing of our initial public offering. We refer to these subsidiaries’ assets, liabilities and operations as Atlas America E & P Operations or our predecessor. The following discussion analyzes and includes the financial condition and results of operations of Atlas America E & P Operations before the date of our initial public offering and our results after the date of our initial public offering. You should read the following discussion of the financial condition and results of operations in conjunction with the historical combined and consolidated financial statements and notes to combined and consolidated financial statements included elsewhere in this report. Additionally, you should read “Forward-looking statements” and “Item 1A: Risk Factors” for information regarding some of the risks inherent in our business.

Change in Year End
 
On June 15, 2006, Atlas America’s board of directors changed our predecessor’s year-end from September 30 to December 31. As a result, the financial results now being reported by us relate to the years ended December 31, 2007 and 2006, the three-month transitional period ended December 31, 2005, and the year ended September 30, 2005. Thus, our financial statements do not present a prior one-year financial period on which to base a comparative discussion with the year ended December 31, 2006.

Comparability of Financial Statements

The historical financial statements of Atlas America E & P Operations included in this report are not comparable to our results of operations following our initial public offering for the following reasons:

·  
Historically, pursuant to an agreement with Atlas America, Atlas Pipeline received gathering fees generally equal to 16% of the gas sales price of gas gathered through its system. Each partnership pays us gathering fees generally equal to 13% of the gas sales price. After the closing of our initial public offering, we pay the amount we receive from the partnerships to Atlas America so that our gathering revenues and expenses within our partnership management segment net to $0. Atlas America then remits the full amount due to Atlas Pipeline pursuant to our contribution agreement with it. We also pay our proportionate share of gathering fees based on our percentage interest in the well, which are included in gas and oil production expense.
 
·  
Atlas America retained a small gathering system, which accounted for the gathering expense in our predecessor’s income statement.
 
·  
Because Atlas America did not previously allocate debt or interest expense to its subsidiaries, our historical results of operations do not include interest expense. We incurred indebtedness after the closing of our initial public offering, which created interest expense.
 
·  
Because we report our items of taxable income, loss, deductions and credits as a master limited partnership, we now incur additional general and administrative expense each year for costs associated with Schedule K-1 preparation and distribution to our unitholders.
 
·  
We acquired DTE Gas & Oil on June 29, 2007, which significantly increased our assets, debt and equity and will continue to significantly increase our revenues, expenses and cash flows in future periods.
 
42


OVERVIEW

We are a limited liability company focused on the development and production of natural gas and, to a lesser extent, oil principally in northern Michigan and the Appalachian Basin. In northern Michigan, we drill wells for our own account. In the Appalachian Basin, we sponsor and manage tax-advantaged investment partnerships, in which we coinvest, to finance the exploitation and development of our acreage.

We were formed in June 2006 to own and operate substantially all of the natural gas and oil assets and the investment partnership management business of Atlas America. Atlas America has been involved in the energy industry since 1968, expanding its operations in 1998 when it acquired The Atlas Group, Inc. and in 1999 when it acquired Viking Resources Corporation, both engaged in the development and production of natural gas and oil and the sponsorship of investment partnerships. We are managed by Atlas Energy Management, a wholly-owned subsidiary of Atlas America.

We operate three business segments:

·  
Two gas and oil production segments, in Appalachia and Michigan, which consist of our interests in oil and gas properties.
 
·  
Our partnership management segment, which consists of well construction and completion, administration and oversight, well services and gathering activities.
 
As of and for the year ended December 31, 2007, we had the following key assets:
 
In our Appalachia gas and oil operations:
 
·  
proved reserves of 229.9 Bcfe including the reserves net to our equity interest in the investment partnerships and our direct interests in producing wells;
 
·  
direct and indirect working interests in approximately 7,722 gross producing gas and oil wells;
 
·  
overriding royalty interests in approximately 627 gross producing gas and oil wells;
 
·  
net daily production of 29.7 Mmcfe per day;
 
·  
approximately 797,800 gross (697,300 net) acres, of which approximately 508,600 gross (501,400 net) acres, are undeveloped; and
 
·  
an interest in a joint venture that gave us the right to drill up to 77 additional net wells before March 31, 2008 on approximately 212,000 acres in Tennessee.
 
In our Michigan gas and oil operations:
 
·  
proved reserves of 666.8 Bcfe;
 
·  
direct and indirect working interests in approximately 2,292 gross producing gas and oil wells;
 
·  
overriding royalty interests in approximately 78 gross producing gas and oil wells;
 
·  
net daily production of 59.8 Mmcfe per day; and
 
·  
approximately 357,000 gross (285,100 net) acres, of which approximately 63,000 gross (53,300 net) acres, are undeveloped.
 
In our partnership management business:
 
·  
our investment partnership business, which includes equity interests in 92 investment partnerships and a registered broker-dealer which acts as the dealer-manager of our investment partnership offerings; and
 
·  
managed total proved reserves of 503.7 Bcfe.
 
43

 
Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Historically, natural gas and oil prices have been volatile and may fluctuate widely in the future. Sustained periods of low prices for natural gas or oil could materially and adversely affect our financial position, our results of operations, the quantities of natural gas and oil reserves that we can economically produce and our access to capital.
 
We utilize the successful efforts method of accounting for our natural gas and oil properties. Unproved properties are assessed periodically within specific geographic areas and impairments are charged to expense. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Drilling costs are capitalized, but charged to expense if the well is determined to be unsuccessful. Generally, if a well does not find proved reserves within one year following completion of drilling, the costs of drilling the well are charged to expense.
 
Higher natural gas and oil prices have led to higher demand for drilling rigs, operating personnel and field supplies and services and have caused increases in the costs of those goods and services. To date, the higher sales prices have more than offset the higher drilling and operating costs.

We face the challenge of natural production declines. As initial reservoir pressures are depleted, natural gas production from a given well decreases. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend in part on our ability to continue to add reserves in excess of production.

Acquisition of DTE Antrim assets

On June 29, 2007, we acquired DTE Gas & Oil Company, now known as Atlas Gas & Oil Company, or AGO, from DTE Energy Company (“DTE” -NYSE:DTE) for $1.3 billion in cash. The assets acquired, which consisted principally of interests in natural gas wells in the Antrim Shale, are the basis for the formation of our gas and oil operations. We funded the purchase price from borrowings under a new credit facility with an initial borrowing base of $850.0 million that matures in June 2012. We intend to continue to expand our business through strategice acquisitions and internal growth projects that increase distributable cash flow.

Private equity offering

We financed a portion of the purchase price for the DTE Gas & Oil acquisition with the proceeds of a private offering, completed on June 29, 2007. We raised net proceeds of $597.5 million through the sale of 7,298,181 Class B common units and 16,702,828 Class D units at a weighted average price of $25.00. On November 10, 2007, the Class D units automatically converted to common units on a one-for-one basis. On February 20, 2008, a registration statement with the Securities and Exchange Commission covering the resale of these units became effective.
 
New credit facility
 
Upon the closing of the DTE Gas & Oil acquisition, we replaced our credit facility with a new 5-year, credit facility with an initial borrowing base of $850.0 million ($740.0 million outstanding at December 31, 2007). In January 2008, the credit facility has a current borrowing base of $672.5 million, which will be redetermined semi-annually based on changes in our oil and gas reserves. The facility is secured by our assets and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR rate plus the applicable margin, elected at our option. The base rate for any day equals the higher of the federal funds rate plus 0.50% of the JPMorgan prime rate. Adjusted LIBOR is LIBOR divided by 1.00 minus the percentage prescribed by the Federal Reserve Board for determining the reserve requirement for Eurocurrency liabilities. The applicable margin ranges from 0.0% to 1.25% for base rate loans and 1.00% to 2.25% for LIBOR loans. At December 31, 2007, the weighted average interest rate on outstanding borrowings was 7.2%.
 
RECENT DEVELOPMENTS
 
Private debt offering

In January 2008, we issued $250.0 million of 10-year, 10.75% senior unsecured notes due 2018. We used the proceeds of the note offering to reduce the balance outstanding on our senior secured credit facility. Interest on the senior notes is payable semi-annually in arrears on February 1 and August 1 of each year. The senior notes are redeemable at any time at certain redemption prices, together with accrued and unpaid interest to the date of redemption. In addition, before February 1, 2011, we may redeem up to 35% of the aggregate principal amount of the senior notes with the proceeds of certain equity offerings at a stated redemption price. The senior notes are also subject to repurchase by us at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if we do not reinvest the net proceeds within 360 days. The senior notes are junior in right of payment to our secured debt, including our obligations under our credit facility. The indenture governing the senior notes contains covenants, including limitations of our ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of our assets.
 
44

 
New interest rate swap

In January 2008, we entered into an interest rate swap contract for $150.0 million, swapping the floating rate incurred on a portion of our existing senior secured credit facility for a fixed rate of approximately 4.36%, which includes an initial margin of 1.25% over the three year fixed swap rate of 3.11%. The interest rate swap contract will mature in January 2011. Combining the 4.36% interest rate on the new swap and the 10.75% interest rate on the new senior notes, we have fixed $400 million of our outstanding debt at a weighted average interest rate of approximately 8.35%.

GENERAL TRENDS AND OUTLOOK

We expect our business to continue to be affected by the risks described in “Item 1A: Risk factors” as well as the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

Commodity prices

Significant factors that may impact future commodity prices include developments in the issues currently impacting Iraq and Iran and the Middle East in general; the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to continue to manage oil supply through export quotas; and overall North American gas supply and demand fundamentals, including the impact of increasing liquefied natural gas deliveries to the United States. Although we cannot predict the occurrence of events that will affect future commodity prices or the degree to which these prices will be affected, the prices for commodities that we produce will generally approximate market prices in the geographic region of the production.

In order to address, in part, volatility in commodity prices, we have implemented a hedging program that is intended to reduce the volatility in our revenues. This program mitigates, but does not eliminate, our sensitivity to short-term changes in commodity prices. Please read “Item 7A: -Quantitative and Qualitative Disclosures About Market Risk.”

Natural gas supply and outlook

We believe that current natural gas prices will continue to cause relatively high levels of natural gas-related drilling in the United States as producers seek to increase their level of natural gas production. Although the number of natural gas wells drilled in the United States has increased overall in recent years, a corresponding increase in production has not been realized, primarily as a result of smaller discoveries and the decline in production from existing wells. We believe that an increase in United States drilling activity, additional sources of supply such as liquefied natural gas, and imports of natural gas will be required for the natural gas industry to meet the expected increased demand for, and to compensate for the slowing production of, natural gas in the United States. The areas in which we operate are experiencing significant drilling activity as a result of recent high natural gas prices, new increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques.
 
While we anticipate continued high levels of exploration and production activities in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new natural gas reserves. Drilling activity generally decreases as natural gas prices decrease. We have no control over the level of drilling activity in the areas of our operations.

45

 
Reserve outlook

Our future oil and gas reserves, production, cash flow and our ability to make payments on our debt and distributions depend on our success in producing our current reserves efficiently, developing our existing acreage and acquiring additional proved reserves economically. In order to sustain and grow our level of distributions, we will need to make acquisitions that are accretive to distributable cash flow per unit. We intend to pursue acquisitions of producing oil and gas properties from third parties. In addition, we reserve a portion of our cash flow from operations to allow us to develop our oil and gas properties at a level that will allow us to maintain a flat production profile and reserve levels.

Impact of inflation

Inflation in the United States did not have a material impact on our results of operations for the three-year period ended December 31, 2007. It may in the future, however, increase the cost to acquire or replace property, plant and equipment, and may increase the costs of labor and supplies. To the extent permitted by competition and our existing agreements, we have and will continue to pass along increased costs to our investors and customers in the form of higher fees.

46

 
RESULTS OF OPERATIONS

The following table sets forth information relating to our production revenues (shown in thousands), production volumes, sales prices, production costs and depletion for our operations during the periods indicated:
 
           
Three Months
     
   
Years Ended
 
Ended
 
Year Ended
 
   
December 31,
 
December 31,
 
September 30,
 
Production revenues (in thousands):
 
2007
 
2006
 
2005
 
2005
 
Gas (1)(6)
 
$
169,314
 
$
79,016
 
$
21,851
 
$
55,376
 
Oil
 
$
10,768
 
$
9,384
 
$
2,227
 
$
8,039
 
Production volumes(2):
                       
Appalachia: