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: 001-32169

ATLAS AMERICA, INC.

(Exact name of registrant as specified in its charter)

Delaware	51-0404430
(State or other jurisdiction or incorporation or organization)	(I.R.S. Employer 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: None

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

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

Common stock, par value $.01 per share

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  x Accelerated filer ¨ 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 the voting common stock held by non-affiliates of the registrant, based on the closing price of such stock on the last business day of the registrant’s most recently completed second quarter, June 30, 2007, was $1.301 billion.

The number of outstanding shares of the registrant’s common stock on February 25, 2008 was 26.9 million shares.

DOCUMENTS INCORPORATED BY REFERENCE: None

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ATLAS AMERICA, INC. AND SUBSIDIARIES

INDEX TO ANNUAL REPORT

ON FORM 10-K

TABLE OF CONTENTS

			Page
PART I	Item 1:	Business	3
	Item 1A:	Risk Factors	28
	Item 1B:	Unresolved Staff Comments	55
	Item 2:	Properties	55
	Item 3:	Legal Proceedings	60
	Item 4:	Submission of Matters to a Vote of Security Holders	60
PART II	Item 5:	Market for Registrant’s Common Equity and Related Stockholder Matters	60
	Item 6:	Selected Financial Data	61
	Item 7:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	62
	Item 7A:	Quantitative and Qualitative Disclosures about Market Risk	84
	Item 8:	Financial Statements and Supplementary Data	90
	Item 9:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	148
	Item 9A:	Controls and Procedures	148
	Item 9B:	Other Information	150
PART III	Item 10:	Directors, Executive Officers and Corporate Governance	150
	Item 11:	Executive Compensation	153
	Item 12:	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	167
	Item 13:	Certain Relationships and Related Transactions, and Director Independence Matters	170
	Item 14:	Principal Accounting Fees and Services	172
PART IV	Item 15:	Exhibits and Financial Statement Schedules	173
SIGNATURES			174

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FORWARD-LOOKING STATEMENTS

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

Other 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.

PART I

ITEM 1: BUSINESS

General

We are a publicly traded Delaware corporation whose common units are listed on the NASDAQ Stock Market under the symbol “ATLS”. Our assets currently consist principally of cash on hand and our ownership interests in the following entities:

·   Atlas Energy Resources, LLC (“Atlas Energy” or “ATN”), a publicly traded Delaware limited liability company (NYSE: ATN) focused on natural gas development and production in northern Michigan’s Antrim Shale and the Appalachian Basin, which we manage through our subsidiary, Atlas Energy Management, Inc., under the supervision of ATN’s board of directors;

·   Atlas Pipeline Holdings, L.P. (“Atlas Pipeline Holdings” or “AHD”), a publicly traded Delaware limited partnership (NYSE: AHD) and owner of the general partner of Atlas Pipeline Partners, L.P. (“Atlas Pipeline” or “APL”), a midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachia regions (NYSE:APL). Through our ownership of its general partner, we manage AHD; and

·   Lightfoot Capital Partners LP (“Lightfoot”) and Lightfoot Capital Partners GP, LLC (“Lightfoot GP”), the general partner of Lightfoot, entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. We have an approximate 18% ownership interest in Lightfoot GP and a commitment to invest a total of $20.0 million in Lightfoot.

Our ownership interest in ATN consists of the following:

·   all of the outstanding Class A units, representing 1,238,986 units at December 31, 2007, which entitles us to receive 2% of the cash distributed by ATN without any obligation to make future capital contributions to ATN;

·   all of the management incentive interests in ATN, which entitle us to receive increasing percentages, up to a maximum of 25.0%, of any cash distributed by ATN as it reaches certain target distribution levels in excess of $0.48 per ATN common unit in any quarter after ATN has met the tests set forth within its limited liability company agreement; and

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·   29,352,996 common units, representing approximately 48.3% of the outstanding common units at December 31, 2007, or a 49.4% ownership interest in ATN.

Our ownership of ATN’s management incentive interests entitles us to receive an increasing percentage of cash distributed by ATN as it reaches certain target distribution levels after ATN has met the tests set forth within its limited liability company agreement. The rights entitle us to receive 15.0% of all cash distributed in a quarter after each ATN common unit has received $0.48 for that quarter, and 25.0% of all cash distributed after each ATN common unit has received $0.59 for that quarter. As set forth in ATN’s limited liability company agreement, for us to receive distributions from ATN under the management incentive interests, ATN must:

·   for 12 full, consecutive, non-overlapping calendar quarters, (a) pay a quarterly cash distribution to the outstanding Class A and common units in an amount that, on average exceeds $0.48 per unit, (b) generate adjusted operating surplus, as defined, that on average is equal to the amount of all cash distributions paid to the Class A and common units plus the amount of management incentive distributions earned, and (c) not reduce the quarterly cash distribution per unit for any of such 12 quarters; and

·   for the last four full, consecutive, non-overlapping quarters during the 12 quarter period described previously (or any four full, consecutive and non-overlapping quarters after the completion of the 12 quarter test is complete), (a) pay a quarterly cash distribution to the outstanding Class A and common units in an amount that exceeds $0.48 per unit, (b) generate adjusted operating surplus, as defined, that on average is equal to the amount of all cash distributions paid to the Class A and common units plus the amount of management incentive distributions earned and (c) not reduce the quarterly cash distribution per unit for any of such four quarters.

Our ownership interest in AHD consists of 17,500,000 common units, representing approximately 64.0% of the outstanding common units of AHD at December 31, 2007. AHD’s general partner, which is a wholly-owned subsidiary of ours, does not have an economic interest in AHD, and AHD’s capital structure does not include incentive distribution rights. AHD’s ownership interest in APL consists of the following:

·   a 2.0% general partner interest, which entitles it to receive 2% of the cash distributed by APL;

·   all of the incentive distribution rights, which entitle it to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed by APL as it reaches certain target distribution levels in excess of $0.42 per APL common unit in any quarter. In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see “—General” under “—Atlas Pipeline Partners, L.P.”), AHD, the holder of all of the incentive distribution rights in APL, had agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter (“IDR Adjustment Agreement”); and

·   5,476,253 common units, representing approximately 14.1% of the outstanding common units at December 31, 2007, or a 13.5% ownership interest in APL.

AHD’s ownership of APL’s incentive distribution rights entitles it to receive an increasing percentage of cash distributed by APL as it reaches certain target distribution levels. The rights entitle AHD, subject to the IDR Adjustment Agreement, to receive the following:

·   13.0% of all cash distributed in a quarter after each APL common unit has received $0.42 for that quarter;

·   23.0% of all cash distributed after each APL common unit has received $0.52 for that quarter; and

·   48.0% of all cash distributed after each APL common unit has received $0.60 for that quarter.

See Note 13 to our consolidated financial statements included in this report for information for each of our business segments regarding revenues from external customers, profits and total assets.

Atlas Energy

General

In December 2006, we contributed substantially all of our natural gas and oil assets and our investment partnership management business to ATN, a then wholly-owned subsidiary. Concurrent with this transaction, ATN issued 7,273,750 common units, representing a 19.4% ownership interest at that moment, in an initial public offering at a price of $21.00 per unit. The net proceeds of approximately $139.9 million, after underwriting discounts and commissions, were distributed to us.

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ATN is an independent developer and producer of natural gas and oil, with operations in northern Michigan’s Antrim Shale and the Appalachian Basin region of the United States, principally in western New York, eastern Ohio, western Pennsylvania and Tennessee. ATN is also a leading sponsor and manager of tax-advantaged direct investment natural gas and oil partnerships in the United States. ATN funds the drilling of natural gas and oil wells on its acreage by sponsoring and managing tax advantaged investment partnerships. It generally structures its investment partnerships so that, upon formation of a partnership, ATN co-invests in and contributes leasehold acreage to it, enters into drilling and well operating agreements with it and becomes its managing general partner. ATN is managed by Atlas Energy Management, Inc., our wholly-owned subsidiary, through which we provide ATN with the personnel necessary to manage its assets and raise capital.

As of and for the year ended December 31, 2007, ATN had the following key assets:

Appalachia gas and oil operations

·   proved reserves of 229.9 Bcfe including the reserves net to ATN’s equity interest in its investment partnerships and ATN’s 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 ATN the right to drill up to 77 additional net wells before March 31, 2008 on approximately 212,000 acres in Tennessee.

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.

Partnership management business

·   ATN investment partnership business, which includes equity interests in 92 investment partnerships and a registered broker-dealer which acts as the dealer-manager of ATN’s investment partnership offerings; and

·   managed total proved reserves of 503.7 Bcfe.

On June 29, 2007, ATN acquired DTE Gas & Oil Company 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 ATN’s Michigan gas and oil operations. ATN funded the purchase price in part from its private placement of 7,298,181 Class B common units and 16,702,828 Class D units to investors at a weighted average negotiated price of $25.00, resulting in net proceeds of $597.5 million. ATN funded the remaining purchase price from borrowings under a new credit facility with an initial borrowing base of $850.0 million that matures in June 2012. ATN intends to continue to expand its business through strategic acquisitions and internal growth projects that increase distributable cash flow.

Atlas Energy’s gas and oil production business constitutes our gas and oil production segment, and its partnership well drilling business constitutes our well construction and completion segment.

Recent Developments

Private debt offering. In January 2008, Atlas Energy issued $250.0 million of 10-year, 10.75% senior unsecured notes due 2018. It used the proceeds of the note offering to reduce the balance outstanding on its 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, Atlas Energy 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 it 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 it does not reinvest the net proceeds within 360 days. The senior notes are junior in right of payment to Atlas Energy’s secured debt, including its obligations under its credit facility. The indenture governing the senior notes contains covenants, including limitations of Atlas Energy’s 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, Atlas Energy entered into an interest rate swap contract for $150 million, swapping the floating rate incurred on a portion of its 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 its new senior notes, Atlas Energy has fixed $400 million of its outstanding debt at a weighted average interest rate of approximately 8.35%.

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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 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 approximately $0.34 per MMBtu.

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.

Seasonal Nature of Business

Seasonal weather conditions and lease stipulations can limit ATN’s drilling and production activities and other operations in certain areas of the Appalachian region and Michigan. These seasonal anomalies may pose challenges for meeting ATN’s well construction objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay its operations. In the past, ATN has drilled a greater number of wells during the winter months due to the fact that it has typically received the majority of funds from its 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.

Gas and Oil Production

Appalachia. As of December 31, 2007, ATN owned interests in approximately 8,349 gross wells in the Appalachia basin, of which it operated approximately 7,091. During the year ended December 31, 2007, average daily production from ATN’s wells was approximately 29.7 Mmcfe/d. During the year ended December 31, 2007, ATN 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, ATN had approximately 797,800 gross (697,300 net) acres, of which approximately 508,600 gross (501,400 net) acres are undeveloped. In September 2004, ATN expanded operations into Tennessee through a joint venture with Knox Energy, LLC that gave ATN an exclusive right to drill wells through December 31, 2007 on approximately 212,000 acres owned by Knox Energy. This agreement was extended through January 2008, and ATN is currently negotiating terms of a further joint venture agreement with Knox Energy. As of December 31, 2007, ATN had drilled 321.0 net wells under this agreement and, in addition, had identified over 580 proved undeveloped drilling locations and approximately 2,600 additional potential drilling locations on ATN’s Appalachia acreage and the Tennessee joint venture acreage.

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In the fourth quarter of 2006, ATN and its 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 ATN’s acreage in Western Pennsylvania. As of February 20, 2008, ATN controlled approximately 483,000 Marcellus Shale acres in Pennsylvania, New York and West Virginia, and ATN continues to expand its position. As of that date, ATN 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. ATN is currently focused on its approximately 224,000 existing Marcellus acres in southwestern Pennsylvania, where it has drilled all but one of its Marcellus wells and have now, through this drilling, largely delineated its acreage. Almost all of this acreage in southwestern Pennsylvania has ample pipeline capacity that is controlled by its affiliate, Atlas Pipeline. ATN’s independent petroleum engineering consultants have evaluated its first 14 southwestern Pennsylvania Marcellus wells and assigned proved reserves that averaged 961 million cubic feet (“Mmcf”) per well. These wells included 5 initial wells where ATN utilized first generation completion techniques. For the nine subsequent wells where ATN implemented its advanced drilling, completion and production techniques, ATN’s independent petroleum engineering consultant 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, ATN’s initial daily rates (24 hours) into a pipeline have averaged 1.3 Mmcf per day in southwestern Pennsylvania. ATN plans to drill and complete at least 150 vertical Marcellus Shale wells over the next 18 months.

Michigan. As of December 31, 2007, ATN owned interests in approximately 2,370 gross wells in the Antrim shale, of which it operated approximately 1,738. During the six months ended December 31, 2007, average daily production from ATN’s wells was approximately 59.8 Mmcfe/d. During the six months ended December 31, 2007, ATN has drilled 102 gross (88.6 net) wells, 100% of which were successful in producing natural gas in commercial quantities. As of December 31, 2007, ATN had approximately 357,000 gross (285,100 net) acres, of which approximately 63,000 gross (53,300 net) acres are undeveloped.

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 1/8^th (12.5%) resulting in a 87.5% net revenue interest to ATN, and in Michigan this amount is typically 1/6^th (16.67%) resulting in an 83.3% net revenue interest to ATN, for most leases directly acquired by ATN. In certain instances, this royalty amount may increase to 1/6^th in the Appalachian Basin and to 3/16^th (18.75%) in Michigan when leases are taken from larger landowners or mineral owners such as coal and timber companies.

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, ATN 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 1/32^nd to 1/16^th (3.125% to 6.25%), which further reduces the net revenue interest available to ATN 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 ATN 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 ATN. Normally the retained interest is a 25% working interest. In this event, ATN’s working interest ownership will be reduced by the amount retained by the third party operator. In all other instances, ATN anticipates owning a 100% working interest in newly drilled wells.

In almost all of the areas ATN operates in the Appalachian Basin and Michigan, the surface owner is normally the natural gas and oil owner allowing ATN 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.

Investment Partnerships

ATN generally funds its drilling activities, other than those of its Michigan business unit, through sponsorship of tax-advantaged investment partnerships. Accordingly, the amount of development activities ATN undertakes depends in part upon its ability to obtain investor subscriptions to the partnerships. ATN 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, ATN’s investment partnerships invested $423.1 million in drilling and completing wells, of which ATN contributed $137.6 million. During fiscal 2006, ATN’s investment partnerships invested $272.2 million in drilling and completing wells, of which ATN contributed $73.6 million.

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ATN generally structures its investment partnerships so that, upon formation of a partnership, it coinvests in and contributes leasehold acreage to it, enters into drilling and well operating agreements with it and becomes its managing general partner. In addition to providing capital for its drilling activities, ATN’s investment partnerships are a source of fee-based revenues, which are not directly dependent on natural gas and oil prices. ATN receives an interest in the investment partnerships proportionate to the amount of capital and the value of the leasehold acreage it contributes, typically 27% to 30% of the overall capitalization in a particular partnership. ATN also receives an additional interest in each partnership, typically 7%, for which ATN does not make any additional capital contribution.

As managing general partner of the investment partnerships, ATN receives the following fees:

·   Well construction and completion. For each well that is drilled by an investment partnership, ATN receives 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, ATN receives a fixed fee of approximately $15,000 ($45,000 for Marcellus wells). Additionally, the partnership pays ATN a monthly per well administrative fee of $75 for the life of the well. Because ATN coinvests in the partnerships, the net fee that it receives is reduced by its proportionate interest in the well.

·   Well services. Each partnership pays ATN a monthly per well operating fee, currently $100 to $477, for the life of the well. Because ATN coinvests in the partnerships, the net fee that ATN receives is reduced by its 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 APL. Since the completion of ATN’s initial public offering in December 2006, pursuant to the terms of our contribution agreement with ATN, ATN’s gathering revenues and costs within its partnership management segment net to $0. Please read “—Our Relationship with Atlas Energy, Atlas Pipeline Holdings and Atlas Pipeline”. Atlas Energy also pays its proportionate share of gathering fees based on its percentage interest in the well, which are included in gas and oil production expense.

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

ATN’s 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 ATN’s 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.

Contractual Revenue Arrangements

Appalachia Natural Gas. ATN has a natural gas supply agreement with Hess Corporation (“Hess”) which is valid through March 31, 2009. Subject to certain exceptions, Hess has a last right of refusal to buy all of the natural gas produced and delivered by ATN and its affiliates, including its 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.

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A portion of ATN’s and its investment partnerships’ natural gas is subject to the agreement with Hess, with the following exceptions:

·   natural gas ATN sells 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 ATN 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 ATN as of December 31, 2007, we anticipate that ATN and its affiliates, including its investment partnerships, will sell approximately 18% of their Appalachian natural gas production during the year ending December 31, 2008 under the Hess 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 ATN may solicit offers from third parties to buy the natural gas for that delivery point. If Hess does not match this price, then ATN may sell the natural gas to the third party. ATN markets the remainder of its natural gas, which is principally located in the Fayette County, PA area, primarily to Colonial Energy, Inc., UGI Energy Services, and others. During the year ended December 31, 2007, ATN received an average of $8.66 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 ATN’s 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 Natural Gas. In Michigan, ATN has 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 ATN and its affiliates from specific projects at certain delivery points with the facilities of:

·   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.

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Based on the most recent monthly production data available to ATN as of December 31, 2007, we anticipate that ATN and its affiliates will sell approximately 50% of their 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. Crude oil produced from ATN’s wells flows directly into storage tanks where it is picked up by an oil company, a common carrier, or pipeline companies acting for an oil company, which is purchasing the crude oil. ATN sells any oil produced by its 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.

Natural Gas Hedging

ATN seeks to provide greater stability in its cash flows through its 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, ATN has a management committee to assure that all financial trading is done in compliance with its hedging policies and procedures. ATN does not intend to contract for positions that it cannot offset with actual production. As of December 31, 2007, ATN had financial hedges and physical hedges in place for approximately 65% of its expected Appalachian production and for approximately 87% of its Michigan production for the twelve months ending December 31, 2008.

Hess and other third-party marketers to which ATN sells 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 ATN 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. ATN generally limits 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.

Competition

The energy industry is intensely competitive in all of its aspects. ATN operates in a highly competitive environment for acquiring properties and other natural gas and oil companies, attracting capital through its investment partnerships, contracting for drilling equipment and securing trained personnel. ATN also competes 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. ATN’s 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 ATN’s competitors possess greater financial and other resources which may enable them to identify and acquire desirable properties and market their natural gas and oil production more effectively than ATN does. Moreover, ATN also competes 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.

Atlas Pipeline Holdings and Atlas Pipeline

General

In July 2006, we contributed our ownership interests in Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP”), the general partner of APL, to AHD. Concurrent with this transaction, AHD issued 3,600,000 common units, representing a 17.1% ownership interest at that moment, in an initial public offering at a price of $23.00 per unit. The net proceeds of approximately $74.3 million, after underwriting discounts and commissions, were distributed to us. AHD’s cash generating assets currently consist solely of its interests in APL.

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APL is a publicly-traded midstream energy services provider engaged in the transmission, gathering and processing of natural gas. APL is a leading provider of natural gas gathering services in the Anadarko, Arkoma, Golden Trend and Permian Basins in the southwestern and mid-continent United States and the Appalachian Basin in the eastern United States. In addition, APL is a leading provider of natural gas processing services in Oklahoma and Texas. APL also provides interstate gas transmission services in southeastern Oklahoma, Arkansas and southeastern Missouri. APL conducts its business through two operating segments: its Mid-Continent operations and its Appalachian operations.

Through its Mid-Continent operations, APL owns and operates:

·   a Federal Energy Regulatory Commission (“FERC”)-regulated, 565-mile interstate pipeline system (“Ozark Gas Transmission”), that extends from southeastern Oklahoma through Arkansas and into southeastern Missouri and has throughput capacity of approximately 400 million cubic feet per day (“MMcfd”);

·   seven natural gas processing plants with aggregate capacity of approximately 750 MMcfd and one treating facility with a capacity of approximately 200 MMcfd, located in Oklahoma and Texas; and

·   7,870 miles of active natural gas gathering systems located in Oklahoma, Arkansas and Texas, which transport gas from wells and central delivery points in the Mid-Continent region to APL’s natural gas processing plants or Ozark Gas Transmission.

Through its Appalachian operations, APL owns and operates 1,600 miles of active natural gas gathering systems located in eastern Ohio, western New York and western Pennsylvania. Through an omnibus agreement and other agreements between us, APL and ATN, APL gathers substantially all of the natural gas for its Appalachian Basin operations from wells operated by ATN. Among other things, the omnibus agreement requires ATN to connect to APL’s gathering systems wells it operates that are located within 2,500 feet of APL’s gathering systems. APL is also a party to natural gas gathering agreements with us and ATN under which it receives gathering fees generally equal to a percentage, typically 16%, of the selling price of the natural gas it transports.

Since APL’s initial public offering in January 2000, it has completed seven acquisitions at an aggregate purchase price of approximately $2.4 billion, including, most recently:

·   On July 27, 2007, APL acquired control of Anadarko Petroleum Corporation’s (“Anadarko” - NYSE: APC) 100% interest in the Chaney Dell natural gas gathering system and processing plants located in Oklahoma and its 72.8% undivided joint venture interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (the “Anadarko Assets”). The Chaney Dell system includes 3,470 miles of gathering pipeline and three processing plants, while the Midkiff/Benedum system includes 2,500 miles of gathering pipeline and two processing plants. The transaction was effected by the formation of two joint venture companies which own the respective systems, to which APL contributed $1.9 billion and Anadarko contributed the Anadarko Assets. In connection with this acquisition, APL reached an agreement with Pioneer Natural Resources Company (“Pioneer” - NYSE: PXD), which currently holds an approximate 27.2% undivided joint venture interest in the Midkiff/Benedum system, whereby Pioneer will have an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system on June 15, 2008, and up to an additional 7.4% interest on June 15, 2009. If the option is fully exercised, Pioneer would increase its interest in the system to approximately 49.2%. Pioneer would pay approximately $230 million, subject to certain adjustments, for the additional 22% interest if fully exercised. APL will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercised the purchase options. APL funded the purchase price in part from its private placement of $1.125 billion of its common units to investors at a negotiated purchase price of $44.00 per unit. Of the $1.125 billion, AHD purchased $168.8 million of these APL units, which was funded through AHD’s issuance of 6.25 million common units in a private placement at a negotiated purchase price of $27.00 per unit. AHD, as general partner and holder of all of APL’s incentive distribution rights, has also agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. APL funded the remaining purchase price from an $830.0 million senior secured term loan which matures in July 2014 and a new $300.0 million senior secured revolving credit facility that matures in July 2013; and

·   In May 2006, APL acquired the remaining 25% ownership interest in NOARK Pipeline System, Limited Partnership (“NOARK”) from Southwestern Energy Company (“Southwestern”) for a net purchase price of $65.5 million, consisting of $69.0 million in cash to the seller, (including the repayment of the $39.0 million of outstanding NOARK notes at the date of acquisition), less the seller’s interest in working capital at the date of acquisition of $3.5 million. In October 2005, APL acquired from Enogex, a wholly-owned subsidiary of OGE Energy Corp., all of the outstanding equity of Atlas Arkansas, which owned the initial 75% ownership interest in NOARK, for $163.0 million, plus $16.8 million for working capital adjustments and related transaction costs. NOARK’s principal assets include the Ozark Gas Transmission system, a 565-mile interstate natural gas pipeline, and Ozark Gas Gathering, a 365-mile natural gas gathering system.

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Both APL’s Mid-Continent and Appalachian operations are located in areas of abundant and long-lived natural gas production and significant new drilling activity. The Ozark Gas Transmission system, which is part of the NOARK system, and APL’s gathering systems are connected to approximately 7,300 central delivery points or wells, giving APL significant scale in its service areas. APL provides gathering and processing services to the wells connected to its systems, primarily under long-term contracts. APL provides fee-based, FERC-regulated transmission services through Ozark Gas Transmission under both long-term and short-term contractual arrangements. As a result of the location and capacity of the Ozark Gas Transmission system and its gathering and processing assets, APL management believes that it is strategically positioned to capitalize on the significant increase in drilling activity in its service areas and the positive price differential across Ozark Gas Transmission, also known as basis spread. APL intends to continue to expand its business through strategic acquisitions and internal growth projects that increase distributable cash flow.

In January 2008, Atlas Pipeline entered into interest rate derivative contracts having an aggregate notional principal amount of $200.0 million. Under the terms of this agreement, Atlas Pipeline will pay 2.88%, plus the applicable margin as defined under the terms of its credit facility, and will receive LIBOR plus the applicable margin, on the notional principal amount of $200.0 million. This hedge effectively converts $200.0 million of Atlas Pipeline’s floating rate debt under the credit facility to fixed-rate debt. The interest rate swap agreement begins on January 31, 2008 and expires on January 31, 2010.

The Midstream Natural Gas Gathering, Processing and Transmission Industry

The midstream natural gas gathering and processing industry is characterized by regional competition based on the proximity of gathering systems and processing plants to producing natural gas wells.

The natural gas gathering process begins with the drilling of wells into natural gas or oil bearing rock formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems generally consist of a network of small diameter pipelines that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission. Gathering systems are operated at design pressures that will maximize the total throughput from all connected wells.

While natural gas produced in some areas, such as the Appalachian Basin, does not require treatment or processing, natural gas produced in many other areas, such as APL’s Velma service area, is not suitable for long-haul pipeline transmission or commercial use and must be compressed, transported via pipeline to a central processing facility, and then processed to remove the heavier hydrocarbon components such as NGLs and other contaminants that would interfere with pipeline transmission or the end use of the natural gas. Natural gas processing plants generally treat (remove carbon dioxide and hydrogen sulfide) and remove the NGLs, enabling the treated, “dry” gas (stripped of liquids) to meet pipeline specification for long-haul transport to end users. After being separated from natural gas at the processing plant, the mixed NGL stream, commonly referred to as “y-grade” or “raw mix,” is typically transported on pipelines to a centralized facility for fractionation into discrete NGL purity products: ethane, propane, normal butane, isobutane, and natural gasoline.

Natural gas transmission pipelines receive natural gas from producers, other mainline transmission pipelines, shippers and gathering systems through system interconnects and redeliver the natural gas to processing facilities, local gas distribution companies, industrial end-users, utilities and other pipelines. Generally natural gas transmission agreements generate revenue for these systems based on a fee per unit of volume transported.

Contracts and Customer Relationships

APL’s principal revenue is generated from the transportation and sale of natural gas and NGLs. Variables that affect its revenue are:

·   the volumes of natural gas APL gathers, transports and processes which, in turn, depends upon the number of wells connected to its gathering systems, the amount of natural gas they produce, and the demand for natural gas and NGLs; and

·   the transportation and processing fees APL receives which, in turn, depends upon the price of the natural gas and NGLs it transports and processes, which itself is a function of the relevant supply and demand in the mid-continent, mid-Atlantic and northeastern areas of the United States.

In APL’s Appalachian region, substantially all of the natural gas it transports is for ATN under percentage-of-proceeds (“POP”) contracts, as described below, in which APL earns a fee equal to a percentage, generally 16%, of the gross sales price for natural gas subject, in most cases, to a minimum of $0.35 or $0.40 per thousand cubic feet, or mcf, depending on the ownership of the well. Since APL’s inception in January 2000, its Appalachian system transportation fee has always exceeded this minimum in general. The balance of the Appalachian system natural gas APL transports is for third-party operators generally under fixed-fee contracts.

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APL’s Mid-Continent segment revenue consists of the fees earned from its transmission, gathering and processing operations. Under certain agreements, APL purchases natural gas from producers and moves it into receipt points on its pipeline systems, and then sells the natural gas, or produced NGLs, if any, off of delivery points on its systems. Under other agreements, APL transports natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with APL’s FERC-regulated transmission pipeline is comprised of firm transportation rates and, to the extent capacity is available following the reservation of firm system capacity, interruptible transportation rates and is recognized at the time transportation service is provided. Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas. In connection with APL’s gathering and processing operations, it enters into the following types of contractual relationships with its producers and shippers:

Fee-Based Contracts. These contracts provide for a set fee for gathering and processing raw natural gas. APL’s revenue is a function of the volume of natural gas that it gathers and processes and is not directly dependent on the value of the natural gas.

POP Contracts. These contracts provide for APL to retain a negotiated percentage of the sale proceeds from residue natural gas and NGLs it gathers and processes, with the remainder being remitted to the producer. In this situation, APL and the producer are directly dependent on the volume of the commodity and its value; APL owns a percentage of that commodity and is directly subject to its market value.

Keep-Whole Contracts. These contracts require APL, as the processor, to purchase raw natural gas from the producer at current market rates. Therefore, APL bears the economic risk (the “processing margin risk”) that the aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that it paid for the unprocessed natural gas. However, because the natural gas received by APL’s Elk City/Sweetwater and Chaney Dell systems, which have keep-whole contracts, is generally low in liquids content and meets downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants on these systems and delivered directly into downstream pipelines during periods of margin risk. Therefore, the processing margin risk associated with a portion of APL’s keep-whole contracts is minimized.

APL’s Mid-Continent Operations

APL owns and operates a 565-mile interstate natural gas pipeline, approximately 7,870 miles of intrastate natural gas gathering systems, including approximately 800 miles of inactive pipeline, located in Oklahoma, Arkansas, southeastern Missouri, northern and western Texas and the Texas panhandle, and seven processing plants and one stand-alone treating facility in Oklahoma and Texas. Ozark Gas Transmission transports natural gas from receipt points in eastern Oklahoma, including major intrastate pipelines, and western Arkansas, where the Arkoma Basin is located, to local distribution companies in Arkansas and Missouri and to interstate pipelines in northeastern and central Arkansas. APL’s gathering and processing assets service long-lived natural gas regions that continue to experience an increase in drilling activity, including the Anadarko Basin, the Arkoma Basin, the Permian Basin and the Golden Trend area of Oklahoma. APL’s systems gather natural gas from oil and natural gas wells and process the raw natural gas into merchantable, or residue, gas by extracting NGLs and removing impurities. In the aggregate, APL’s Mid-Continent systems have approximately 7,300 receipt points, consisting primarily of individual connections and, secondarily, central delivery points which are linked to multiple wells. APL’s gathering systems interconnect with interstate and intrastate pipelines operated by Ozark Gas Transmission, ONEOK Gas Transportation, LLC, Southern Star Central Gas Pipeline, Inc., Panhandle Eastern Pipe Line Company, LP, Northern Natural Gas Company, CenterPoint Energy, Inc., ANR Pipeline Company, El Paso Natural Gas Company and Natural Gas Pipeline Company of America.

Mid-Continent Overview

The heart of the Mid-Continent region is generally defined as running from Kansas through Oklahoma, branching into northern and western Texas, southeastern New Mexico as well as western Arkansas. The primary producing areas in the region include the Hugoton field in southwestern Kansas, the Anadarko Basin in western Oklahoma, the Permian Basin in West Texas and the Arkoma Basin in western Arkansas and eastern Oklahoma.

FERC-Regulated Transmission System

Through NOARK, APL owns Ozark Gas Transmission, a 565-mile FERC-regulated natural gas interstate pipeline transports natural gas from receipt points in eastern Oklahoma, including major intrastate pipelines, and Arkansas, where the Arkoma Basin, Fayetville and Woodford Shales are located, to local distribution companies and industrial markets in Arkansas and Missouri and to interstate pipelines in northeastern and central Arkansas. Ozark Gas Transmission delivers natural gas primarily via six interconnects with Mississippi River Transmission Corp., Natural Gas Pipeline Company of America and Texas Eastern Transmission Corp., and receives natural gas from numerous interconnects with intrastate pipelines, including Enogex, BP’s Vastar gathering system, Arkansas Oklahoma Gas Corporation, Arkansas Western Gas Company, ONEOK Gas Transmission and our own Ozark Gas Gathering system.

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Mid-Continent Gathering Systems

Chaney Dell. The Chaney Dell gathering system is located in north central Oklahoma and southern Kansas’ Anadarko Basin. Chaney Dell’s natural gas gathering operations are conducted through two gathering systems, the Westana and Chaney Dell/Chester systems. As of December 31, 2007, the combined gathering systems had approximately 3,470 miles of natural gas gathering pipelines with approximately 3,260 receipt points. The Chaney Dell system has approximately 825 active contracts with producers.

Elk City/Sweetwater. The Elk City and Sweetwater gathering system, which APL considers combined due to the close geographic proximity of the processing plants they are connected to, includes approximately 450 miles of natural gas pipelines located in the Anadarko Basin in western Oklahoma and the Texas panhandle, including the Springer and Granite Wash plays. The Elk City and Sweetwater gathering system connects to over 470 receipt points, with a majority of the system’s western end located in areas of active drilling.

Midkiff/Benedum. The Midkiff/Benedum gathering system, which APL operates and has an approximate 72.8% ownership in at December 31, 2007, consists of approximately 2,500 miles of gas gathering pipeline located across four counties within the Permian Basin in Texas. Pioneer, the largest active driller in the Spraberry Trend and a major producer in the Permian Basin, owns the remaining interest in the Midkiff/Benedum system. The Midkiff/Benedum operations provide gathering and processing under approximately 150 contracts, including one with Pioneer.

When APL acquired control of the Midkiff/Benedum system in July 2007, APL and Pioneer agreed to extend the existing gas sales and purchase agreement to 2022 and entered into an agreement under which Pioneer has the right to increase its ownership interest in the Midkiff/Benedum system by an additional 14.6% in June 2008 and 7.4% in June 2009, for an aggregate ownership interest of 49.2%. The gas sales and purchase agreement requires that all Pioneer wells in the proximity of the Midkiff/Benedum system are dedicated to that system’s gathering and processing operations in return for specified natural gas processing rates. Through this agreement, APL anticipates that it will continue to provide gathering and processing for the majority of Pioneer’s wells in the Spraberry Trend of the Permian Basin.

Ozark Gas Gathering. Through NOARK, APL owns Ozark Gas Gathering, which owns 370 miles of intrastate natural gas gathering pipeline located in eastern Oklahoma and western Arkansas, providing access to both the well-established Arkoma Basin and the newly-exploited Fayetteville and Woodford shales. This system connects to approximately 300 receipt points and compresses and transports gas to interconnections with Ozark Gas Transmission and CenterPoint.

Velma. The Velma gathering system is located in the Golden Trend area of southern Oklahoma and the Barnett Shale area of northern Texas. As of December 31, 2007, the gathering system had approximately 1,080 miles of active pipeline with approximately 690 receipt points consisting primarily of individual connections and, secondarily, central delivery points which are linked to multiple wells. The system includes approximately 800 miles of inactive pipeline, much of which can be returned to active status as local drilling activity warrants.

Processing and Treating Plants

Chaney Dell. The Chaney Dell system processes natural gas through the Waynoka and Chester plants, both of which are active cryogenic natural gas processing facilities. The Chaney Dell system’s processing operations have total capacity of approximately 230 MMcfd. The Waynoka processing plant, which began operations in December 2006 and became fully operational in July 2007, contains the most technologically advanced controls, systems and processes and demonstrates strong NGL recovery rates, including approximately 90% of ethane recovery and greater than 98% recovery of all other NGLs. As a result, APL is able to process far more efficient volume than were previously processed at Chaney Dell’s lean oil plants. Chaney Dell has a third plant, the Chaney Dell plant, which was idled in the fourth quarter of 2006 when the Waynoka plant began operations. Because of drilling activity in the Anadarko Basin, the Waynoka and Chester plants have been operating at high utilization rates. As a result, APL reactivated the Chaney Dell plant in early 2008, which added 22 MMcfd of additional processing capacity.

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Velma. The Velma processing plant, located in Stephens County, Oklahoma, is a cryogenic facility with a natural gas capacity of approximately 100 MMcfd. The Velma plant is one of only two facilities in the area that is capable of treating both high-content hydrogen sulfide and carbon dioxide gases which are characteristic in this area. APL sells natural gas to purchasers at the tailgate of the Velma plant and sells NGL production to ONEOK Hydrocarbon. APL’s Velma operations gather and process natural gas for approximately 135 producers. APL has made capital expenditures at the facility to improve its efficiency and competitiveness, including installing electric-powered compressors rather than higher-cost natural gas-powered compressors used by many of its competitors. This results in higher margins, greater efficiency and lower fuel costs.

Elk City/Sweetwater. The Elk City processing plant, located in Beckham County, Oklahoma, is a cryogenic natural gas processing plant with a total capacity of approximately 130 MMcfd. APL transports to, and sells natural gas to purchasers at, the tailgate of its Elk City processing plant, as well as sells NGL production to ONEOK Hydrocarbon. The Prentiss treating facility, also located in Beckham County, is an amine treating facility with a total capacity of approximately 200 MMcfd. The Sweetwater processing plant, which began operations in September 2006, is a cryogenic natural gas processing plant located in Beckham County, near the Elk City processing plant. The Sweetwater plant has a total capacity of approximately 120 MMcfd. APL built the Sweetwater plant to further access natural gas production being actively developed in western Oklahoma and the Texas panhandle. Built with state-of-the-art technology, APL believes that the Sweetwater plant is capable of recovering more NGLs than a lean oil processing plant. The Sweetwater plant is currently running near full capacity. As such, APL is currently in the process of expanding the processing capacity at the plant by 50% to a total processing capacity of 180 MMcfd and is expected to be completed during 2008. Through this expansion, APL will extend the system’s reach into the Granite Wash play in the Roberts County, Texas area, which APL believes will continue to increase its natural gas processing and throughput volumes.

The Elk City, Sweetwater and Prentiss facilities are on the same gathering system and are referred to as our Elk City/Sweetwater operations. APL’s Elk City/Sweetwater operations gather and process gas for more than 140 producers.

Natural Gas Supply

In the Mid-Continent, APL has natural gas purchase, gathering and processing agreements with approximately 800 producers with terms ranging from one month to 15 years. These agreements provide for the purchase or gathering of natural gas under fixed-fee, percentage-of-proceeds or keep-whole arrangements. Most of the agreements provide for compression, treating, and/or low volume fees. Producers generally provide, in-kind, their proportionate share of compressor fuel required to gather the natural gas and to operate APL’s processing plants. In addition, the producers generally bear their proportionate share of gathering system line loss and, except for keep-whole arrangements, bear natural gas plant “shrinkage,” or the gas consumed in the production of NGLs.

APL has enjoyed long-term relationships with the majority of its Mid-Continent producers. For instance, on the Velma system, where APL has producer relationships going back over 20 years, its top four producers, which accounted for a significant portion of the Velma volumes for the year ended December 31, 2007, have contracts with primary terms running into 2009 and 2010. At the end of the primary terms, most of the contracts with producers on APL’s gathering systems have evergreen term extensions.

Natural Gas and NGL Marketing

APL typically sells natural gas to purchasers at the tailgate of its processing plants and at various delivery points on Ozark Gas Transmission and Ozark Gas Gathering. The Velma plant has access to ONEOK Gas Transportation, an intrastate pipeline, and Southern Star Central Gas Pipeline, an interstate pipeline, and APL currently sells the majority of its natural gas to Conoco Phillips and Oilco Gas Co. at the average of ONEOK Gas Transportation and Southern Star Central Gas Pipeline first-of-month indices as published in Inside FERC. The Elk City/Sweetwater plants have access to five major interstate and intrastate downstream pipelines: Natural Gas Pipe Line of America, Panhandle Eastern Pipeline Co., CenterPoint Energy Gas Transmission Company, Northern Natural Gas Company, ANR Pipeline Company and ONEOK Gas Transmission. At the Elk City/Sweetwater plants, APL sells substantially all of its natural gas to ONEOK Energy Marketing, based on first-of-month index pricing. Ozark Gas Gathering gas prices are generally based on Centerpoint Energy Gas Transmission index as published in Inside FERC and natural gas sales have historically been to Eagle Energy Partners. The Chaney Dell plants have access to Panhandle Eastern Pipeline Co. and Southern Star Central Gas Pipeline and APL currently sells substantially all of its natural gas to Tenaska Marketing Ventures, Constellation Energy and ONEOK Energy Marketing based on first-of-month index pricing. The Midkiff/Benedum plants have access to Northern Natural Gas Company and El Paso Pipeline Company and APL currently sells substantially all of its natural gas to Tenaska Marketing Ventures, Eagle Energy Partners, Odyssey Energy Services and NGTS LP based on first-of-month index pricing.

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APL sells its NGL production to ONEOK Hydrocarbon under four separate agreements. The Velma agreement has an initial term expiring February 1, 2011, the Elk City/Sweetwater agreement has an initial term expiring October 1, 2008 and the Chaney Dell and Midkiff/Benedum agreements have initial terms expiring September 1, 2009. NGLs under the contracts are priced at the average monthly Oil Price Information Service, or OPIS, price for the selected market.

Condensate is collected at the Velma gas plant and around the Velma gathering system and currently sold for APL’s account to SemCrude L.P. and EnerWest Trading Company LLC. Condensate collected at the Elk City/Sweetwater plants and around the Elk City/Sweetwater plants is currently sold to Petro Source Partners L.P. Condensate collected at the Chaney Dell plants and around the Chaney Dell plants is currently sold to Plains Marketing. Condensate collected at the Midkiff/Benedum plants and around the Midkiff/Benedum plants is currently sold to ConocoPhillips, Oxy USA and Oasis Transportation.

Natural Gas and NGL Hedging

APL’s Mid-Continent operations are exposed to certain commodity price risks. These risks result from either taking title to natural gas and NGLs, including condensate, or being obligated to purchase natural gas to satisfy contractual obligations with certain producers. APL mitigates a portion of these risks through a comprehensive risk management program which employs a variety of hedging tools. The resulting combination of the underlying physical business and the financial risk management program is a conversion from a physical environment that consists of floating prices to a risk-managed environment that is characterized by fixed prices.

APL (a) purchases natural gas and subsequently sells processed natural gas and the resulting NGLs, or (b) purchases natural gas and subsequently sells the unprocessed natural gas, or (c) transports and/or processes the natural gas for a fee without taking title to the commodities. Scenario (b) exposes APL to a generally neutral price risk (long sales approximate short purchases) while scenario (c) does not expose APL to any price risk; in both scenarios, risk management is not required. Scenario (a) does involve commodity risk.

APL is exposed to commodity price risks when natural gas is purchased for processing. The amount and character of this price risk is a function of APL’s contractual relationships with natural gas producers, or, alternatively, a function of cost of sales. APL is therefore exposed to price risk at a gross profit level rather than at a revenue level. These cost-of-sales or contractual relationships are generally of two types:

·   Percentage-of-proceeds: requires APL to pay a percentage of revenue to the producer. This results in APL being net long physical natural gas and NGLs.

·   Keep-whole: requires APL to deliver the same quantity of natural gas at the delivery point as it received at the receipt point; any resulting NGLs produced belong to APL. This results in APL being long physical NGLs and short physical natural gas.

APL hedges a portion of these risks by using fixed-for-floating swaps, which result in a fixed price, or by utilizing the purchase or sale of options, which result in a range of fixed prices.

APL recognizes gains and losses from the settlement of its hedges in revenue when it sells the associated physical residue natural gas or NGLs. Any gain or loss realized as a result of hedging is substantially offset in the market when APL sells the physical residue natural gas or NGLs. The majority of APL’s hedges are characterized as cash flow hedges as defined in Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” APL determines gains or losses on open and closed hedging transactions as the difference between the hedge price and the physical price. This mark-to-market methodology uses daily closing NYMEX prices when applicable and an internally-generated algorithm for hedged commodities that are not traded on a market. To insure that these financial instruments will be used solely for hedging price risks and not for speculative purposes, APL has established a hedging committee to review its hedges for compliance with its hedging policies and procedures. APL’s revolving credit facility prohibits speculative hedging and limits its overall hedge position to 80% of its equity volumes.

For additional information on APL’s hedging activities and a summary of its outstanding hedging instruments as of December 31, 2007, please see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk.”

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APL’s Appalachian Basin Operations

APL owns and operates approximately 1,600 miles of intrastate gas gathering systems located in eastern Ohio, western New York and western Pennsylvania. APL’s Appalachian operations serve approximately 6,720 wells with an average throughput of 68.7 MMcfd of natural gas for the year ended December 31, 2007. APL’s gathering systems provide a means through which well owners and operators can transport the natural gas produced by their wells to interstate and public utility pipelines for delivery to customers. To a lesser extent, APL’s gathering systems transport natural gas directly to customers. APL’s gathering systems connect with various public utility pipelines, including Peoples Natural Gas Company, National Fuel Gas Supply, Tennessee Gas Pipeline Company, National Fuel Gas Distribution Company, Dominion East Ohio Gas Company, Columbia Gas of Ohio, Consolidated Natural Gas Co., Texas Eastern Pipeline, Columbia Gas Transmission Corp., Equitrans Pipeline Company, Gatherco Incorporated, Piedmont Natural Gas Co., Inc. and Equitable Utilities. APL’s systems are strategically located in the Appalachian Basin, a region characterized by long-lived, predictable natural gas reserves that are close to major eastern U.S. markets. Substantially all of the natural gas APL transports in the Appalachian Basin is derived from wells operated by ATN. APL is party to an omnibus agreement with ATN which is intended to maximize the use and expansion of APL’s gathering systems and the amount of natural gas which it transport in the region.

Appalachian Basin Overview

The Appalachian Basin includes the states of Kentucky, Maryland, New York, Ohio, Pennsylvania, Virginia, West Virginia and Tennessee. The Appalachian Basin is strategically located near the energy-consuming regions of the mid-Atlantic and northeastern United States.

Natural Gas Supply

From the inception of APL’s operations in January 2000 through December 31, 2007, APL connected 3,720 new wells to its Appalachian gathering system, 685 of which were added through acquisitions of other gathering systems. For the year ended December 31, 2007, APL connected 874 wells to its gathering system. APL’s ability to increase the flow of natural gas through its gathering systems and to offset the natural decline of the production already connected to its gathering systems will be determined primarily by the number of wells drilled by ATN and connected to APL’s gathering systems and by APL’s ability to acquire additional gathering assets.

Natural Gas Revenue

APL’s Appalachian Basin revenue is determined primarily by the amount of natural gas flowing through its gathering systems and the price received for this natural gas. APL has an agreement with ATN under which ATN pays APL gathering fees generally equal to a percentage, typically 16%, of the gross weighted average sales price of the natural gas APL transports subject, in most cases, to minimum prices of $0.35 or $0.40 per Mcf. For the year ended December 31, 2007, APL received gathering fees averaging $1.35 per Mcf. APL charges other operators fees negotiated at the time it connects their wells to its gathering systems or, in a pipeline acquisition, that were established by the entity from which APL acquired the pipeline.

Because APL does not buy or sell gas in connection with its Appalachian operations, APL does not engage in hedging. ATN maintains a hedging program. Since APL receives transportation fees from ATN generally based on the selling price received by ATN inclusive of the effects of financial and physical hedging, these financial and physical hedges mitigate the risk of APL’s percentage-of-proceeds arrangements.

Competition

Acquisitions

APL has encountered competition in acquiring midstream assets owned by third parties. In several instances, APL submitted bids in auction situations and in direct negotiations for the acquisition of such assets and was either outbid by others or was unwilling to meet the sellers’ expectations. In the future, APL expects to encounter equal if not greater competition for midstream assets because, as natural gas, crude oil and NGL prices increase, the economic attractiveness of owning such assets increases.

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Mid-Continent

In APL’s Mid-Continent service area, it competes for the acquisition of well connections with several other gathering/servicing operations. These operations include plants and gathering systems operated by Duke Energy Field Services, ONEOK Field Services, Enogex, Inc. and Enbridge, Inc. APL believes that the principal factors upon which competition for new well connections is based are:

·   the price received by an operator or producer for its production after deduction of allocable charges, principally the use of the natural gas to operate compressors; and

·   responsiveness to a well operator’s needs, particularly the speed at which a new well is connected by the gatherer to its system.

APL believes that its relationships with operators connected to its system are good and that APL presents an attractive alternative for producers. However, if APL cannot compete successfully, it may be unable to obtain new well connections and, possibly, could lose wells already connected to its systems.

Being a regulated entity, Ozark Gas Transmission faces somewhat more indirect competition that is more regional or even national in character. CenterPoint Energy, Inc.’s interstate system is the nearest direct competitor.

Appalachian Basin

APL’s Appalachian Basin operations do not encounter direct competition in their service areas since Atlas Energy controls the majority of the drillable acreage in each area. However, because APL’s Appalachian Basin operations principally serve wells drilled by Atlas Energy, APL is affected by competitive factors affecting Atlas Energy’s ability to obtain properties and drill wells, which affects APL’s ability to expand its gathering systems and to maintain or increase the volume of natural gas it transports and, thus, its transportation revenues. Atlas Energy also may encounter competition in obtaining drilling services from third-party providers. Any competition it encounters could delay Atlas Energy in drilling wells for its sponsored partnerships, and thus delay the connection of wells to APL’s gathering systems. These delays would reduce the volume of natural gas APL otherwise would have transported, thus reducing APL’s potential transportation revenues.

As the omnibus agreement with Atlas Energy generally requires APL to connect wells it operates to APL’s system, APL does not expect any direct competition in connecting wells drilled and operated by Atlas Energy in the future. In addition, APL occasionally connects wells operated by third parties. For the year ended December 31, 2007, APL connected 38 third-party wells.

Our Relationship with Atlas Energy, Atlas Pipeline Holdings and Atlas Pipeline

ATN Contribution Agreement

The substantial majority of the assets ATN owns were held, directly or indirectly, by us and our subsidiaries. In connection with ATN’s initial public offering, we entered into a contribution agreement pursuant to which we contributed to ATN all of the stock of our natural gas and oil development and production subsidiaries as well as the development and production assets owned by us. As consideration for this contribution, ATN distributed to us the net proceeds ATN received from that offering, as well as 29,352,996 of ATN’s common units, the Class A units and the management incentive interests. As part of the contribution agreement, we have agreed to indemnify ATN for losses attributable to title defects to ATN’s 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, ATN has agreed to indemnify us for all losses attributable to the post-closing operations of the assets contributed to ATN, to the extent not subject to its indemnification obligations. In addition, we agreed to assume ATN’s obligation to pay gathering fees to Atlas Pipeline under the master natural gas gathering agreement (described below); ATN agreed to pay us the gathering fees it receives from its investment partnerships and fees associated with production to its interest.

Management Agreement between Atlas Energy Management and Atlas Energy

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

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Before making any distribution on its common units, Atlas Energy will reimburse Atlas Energy Management for all expenses that it incurs on Atlas Energy’s behalf pursuant to the management agreement. These expenses will include costs for providing corporate staff and support services to Atlas Energy. Atlas Energy Management will charge on a fully-allocated cost basis for services provided to Atlas Energy. This fully-allocated cost basis is based on the percentage of time spent by personnel of Atlas Energy Management and its affiliates on Atlas Energy’s 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 Atlas Energy’s business and affairs, subject to the periodic review and approval of the Atlas Energy’s audit or conflicts committee.

Atlas Energy Management, its stockholders, directors, officers, employees and affiliates will not be liable to Atlas Energy, any subsidiary of Atlas Energy, Atlas Energy’s directors or Atlas Energy’s unitholders for acts or omissions performed in good faith and in accordance with and pursuant to the management agreement, except by reason of acts constituting gross negligence, bad faith, willful misconduct, fraud or a knowing violation of criminal law. Atlas Energy 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 Atlas Energy and Atlas Energy’s 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 and omissions and other customary insurance.

The management agreement may not be amended without the prior approval of Atlas Energy’s conflicts committee if the proposed amendment will, in the reasonable discretion of Atlas Energy’s board, adversely affect common unitholders.

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

Omnibus Agreement

Under the omnibus agreement, we and our affiliates agreed to add wells to APL’s gathering systems and provide consulting services when APL constructs new gathering systems or extends existing systems. In December 2006, in connection with the completion of the initial public offering of, and our contribution and sale of the natural gas and oil development and production assets to, ATN, ATN joined the omnibus agreement as an obligor (except for the provisions of the omnibus agreement imposing conditions upon the disposition of AHD as general partner of APL), and we became secondarily liable as a guarantor of ATN’s performance. The omnibus agreement is a continuing obligation, having no specified term or provisions regarding termination except for a provision terminating the agreement if AHD is removed as general partner of APL without cause. The omnibus agreement may not be amended without the approval of the conflicts committee of the managing board of AHD’s general partner if, in its reasonable discretion, such amendment will adversely affect APL’s common unitholders. APL’s common unitholders do not have explicit rights to approve any termination or material modification of the omnibus agreement. We anticipate that the conflicts committee of the managing board of AHD’s general partner would submit to APL’s common unitholders for their approval any proposal to terminate or amend the omnibus agreement if it determines, in its reasonable discretion, that the termination or amendment would materially adversely affect APL’s common unitholders.

Well Connections. Under the omnibus agreement, with respect to any well ATN drills and operates for itself or an affiliate that is within 2,500 feet of APL’s gathering systems, ATN must, at its sole cost and expense, construct small diameter (two inches or less) sales or flow lines from the wellhead of any such well to a point of connection to the gathering system. Where an ATN well is located more than 2,500 feet from one of APL’s gathering systems, but ATN has extended the flow line from the well to within 1,000 feet of the gathering system, ATN has the right to require APL, at APL’s cost and expense, to extend its gathering system to connect to that well. With respect to other ATN wells that are more than 2,500 feet from APL’s gathering systems, APL has the right, at its cost and expense, to extend its gathering system to within 2,500 feet of the well and to require ATN, at its cost and expense, to construct up to 2,500 feet of flow line to connect to the gathering system extension. If APL elects not to exercise its right to extend its gathering systems, ATN may connect an ATN well to a natural gas gathering system owned by someone other than APL or one of APL’s subsidiaries or to any other delivery point; however, APL will have the right to assume the cost of construction of the necessary flow lines, which will then become APL’s property and part of its gathering systems.

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Consulting Services. The omnibus agreement requires Atlas Energy to assist APL in identifying existing gathering systems for possible acquisition and to provide consulting services to APL in evaluating and making a bid for these systems. Atlas Energy must give APL notice of identification by it or any of its affiliates of any gathering system as a potential acquisition candidate, and must provide APL with information about the gathering system, its seller and the proposed sales price, as well as any other information or analyses compiled by Atlas Energy with respect to the gathering system. APL must determine, within a time period specified by Atlas Energy’s notice to APL, which must be a reasonable time under the circumstances, whether APL wants to acquire the identified system and advise Atlas Energy of its intent. If APL intends to acquire the system, it has an additional 60 days to complete the acquisition. If APL advises Atlas Energy that it does not intend to make the acquisition, does not complete the acquisition within a reasonable time period, or advises Atlas Energy that it does not intend to acquire the system, then Atlas Energy may do so.

Gathering System Construction. The omnibus agreement requires ATN to provide APL with construction management services if APL determines it needs to expand one or more of its gathering systems. APL must reimburse ATN for its costs, including an allocable portion of employee salaries, in connection with its construction management services.

Disposition of Interest in APL’s General Partner. Before the completion of AHD’s and ATN’s initial public offerings, we owned both entities and the entities which act as the general partners, operators or managers of the drilling investment partnerships sponsored by us. The omnibus agreement prohibited us from transferring its interest in AHD, as general partner of APL, unless it also transferred to the same person its interests in those subsidiaries. We were permitted, however, to transfer our interest in AHD to a wholly- or majority-owned direct or indirect subsidiary as long as we continued to control the new entity. In connection with AHD’s initial public offering, we transferred our interest in APL’s general partner to AHD, then our wholly-owned subsidiary. We currently own a 64.0% interest in AHD.

Natural Gas Gathering Agreements

We and certain of our subsidiaries entered into a master natural gas gathering agreement with APL in connection with the completion of its initial public offering in February 2000. In December 2006, in connection with the completion of the initial public offering of, and our contribution and sale of our natural gas and oil development and production assets to, ATN, ATN joined the master natural gas gathering agreement as an obligor. However, pursuant to the contribution agreement, we agreed to assume ATN’s obligation to pay gathering fees to Atlas Pipeline and ATN agreed to pay us the gathering fees it receives from its investment partnerships and fees associated with production to its interest. Under the master natural gas gathering agreement, APL receives a fee from ATN for gathering natural gas, determined as follows:

·   for natural gas from well interests allocable to ATN or its affiliates (excluding general or limited partnerships sponsored by them) that were connected to APL’s gathering systems at February 2, 2000, the greater of $0.40 per Mcf or 16% of the gross sales price of the natural gas transported;

·   for (i) natural gas from well interests allocable to general and limited partnerships sponsored by ATN that drill wells on or after December 1, 1999 that are connected to APL’s gathering systems (ii) natural gas from well interests allocable to ATN or its affiliates (excluding general or limited partnerships sponsored by them) that are connected to APL’s gathering systems after February 2, 2000, and (iii) well interests allocable to third parties in wells connected to APL’s 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 operated by ATN and drilled after December 1, 1999 that are connected to a gathering system that is not owned by APL and for which APL 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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The master natural gas gathering agreement is a continuing obligation and, accordingly, has no specified term or provisions regarding termination. However, if the general partner of APL is removed as general partner without cause, then no gathering fees will be due under the agreement with respect to new wells drilled by ATN.

The master natural gas gathering agreement may not be amended without the approval of the conflicts committee of the managing board of APL’s general partner if, in the reasonable discretion of APL’s general partner, such amendment will adversely affect APL’s common unitholders. APL’s common unitholders do not have explicit rights to approve any termination or material modification of the master natural gas gathering agreement. We anticipate that the conflicts committee of the managing board of APL’s general partner would submit to APL’s common unitholders for their approval any proposal to terminate or amend the master natural gas gathering agreement if APL’s general partner determines, in its reasonable discretion, that the termination or amendment would materially adversely affect APL’s common unitholders.

In addition to the master natural gas gathering agreement, APL has three other gas gathering agreements with subsidiaries of ATN. Under two of these agreements, relating to certain wells located in southeastern Ohio and in Fayette County, Pennsylvania, APL receives a fee of $0.80 per Mcf. Under the third agreement, which covers wells owned by third parties unrelated to ATN or the investment partnerships it sponsors, APL receives fees that range between $0.20 to $0.29 per Mcf or between 10% to 16% of the weighted average sales price for the natural gas APL transports.

Major Customers

Atlas Energy’s natural gas sold under contract to various purchasers. For the year December 31, 2007, no single Atlas Energy customer accounted for more than 10% of our consolidated total revenues.

Substantially all of APL’s Appalachian operating system revenues currently consist of the fees it receives under the master natural gas gathering agreement and other transportation agreements with Atlas Energy and its affiliates. During 2007, Chesapeake Energy Corporation, Pioneer, Conoco Phillips, Sanguine Gas Exploration, LLC, St. Mary Land and Exploration Company, XTO Energy Inc., Henry Petroleum, L.P. and Senex Pipeline Company supplied APL’s Mid-Continent systems with a majority of their natural gas supply.  For the year ended December 31, 2007, there was one APL customer who accounted for approximately 37% of our consolidated revenues.

Seasonal Nature of Business

Seasonal weather conditions and lease stipulations can limit Atlas Energy’s drilling and producing activities and other operations in certain areas of the Appalachian region and Michigan. These seasonal anomalies may pose challenges for meeting Atlas Energy’s well construction objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay its operations. In the past, Atlas Energy has drilled a greater number of wells during the winter months because it has typically received the majority of funds from its 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

Atlas Energy Overview

ATN’s operations are subject to comprehensive and stringent federal, state and local laws and regulations governing, among other things, where and how it installs wells, how it handles wastes from its operations and the discharge of materials into the environment. ATN’s 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;

·   impose substantial liabilities for pollution resulting from ATN’s 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 APL’s operating costs. We believe that ATN’s operations on the whole substantially comply with all currently applicable environmental laws and regulations and that ATN’s continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict how environmental laws and regulations that may take effect in the future may impact ATN’s properties or operations. For the three years ended December 31, 2007, ATN did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of ATN’s 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.

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Atlas Pipeline Overview

The operation of pipelines, plant and other facilities for gathering, compressing, treating, processing, or transporting natural gas, natural gas liquids and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, APL must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact APL’s business activities in many ways, such as:

·   restricting the way APL can handle or dispose of its wastes;

·   limiting or prohibiting construction and operating activities in sensitive areas such as wetlands, coastal regions, or areas inhabited by endangered species;

·   requiring remedial action to mitigate pollution conditions caused by APL’s operations or attributable to former operators; and

·   enjoining some or all of the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where substances or wastes have been disposed 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 substances or wastes into the environment.

We believe that APL’s operations are in substantial compliance with applicable environmental laws and regulations and that compliance with existing federal, state and local environmental laws and regulations will not have a material adverse effect on its business, financial position or results of operations. Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Moreover, we cannot assure you that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause APL to incur significant costs. For the three years ended December 31, 2007, APL did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of its facilities or systems.  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 and the midstream natural gas gathering, processing and transmission 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 impact the environment. In the course of such evaluations, an agency will typically require an Environmental Assessment to assess the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that will be made available for public review and comment. All of ATN’s 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. RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes associated with the exploration, development, or production of crude oil and natural gas. However, these oil and gas exploration and production wastes may still be regulated under state law or the less stringent solid waste requirements of RCRA. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements.

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

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Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, 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.

ATN’s operations are, in many cases, conducted at properties that have been used for natural gas and oil exploitation and production for many years. Although we believe we utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by ATN 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 ATN’s control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, ATN 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.

APL currently owns or leases, and have in the past owned or leased, numerous properties that for many years have been used for the measurement, gathering, field compression and processing of natural gas. Although APL used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by APL or on or under other locations where such substances have been taken for disposal. In fact, there is evidence that petroleum spills or releases have occurred at some of the properties owned or leased by APL. In addition, some of these properties have been operated by third parties or by previous owners whose treatment and disposal or release of petroleum hydrocarbons or wastes was not under APL’s control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, APL could be required to remove previously disposed wastes (including waste disposed of by prior owners or operators), remediate contaminated property (including groundwater contamination, whether from prior owners or operators or other historic activities or spills), or perform remedial 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 ATN’s and APL’s 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 ATN’s and APL’s 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 ATN’s or APL’s customers to the point where demand for natural gas is affected. APL likely will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that APL’s operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to APL than to any other similarly situated companies. We believe that ATN’s and APL’s operations are in substantial compliance with the requirements of the Clean Air Act.

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OSHA and Other Regulations. ATN and APL 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 ATN and APL organize and/or disclose information about hazardous materials used or produced in their operations. We believe that ATN and APL 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 impact ATN’s and APL’s future operations. ATN’s and APL’s 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 impact ATN’s and APL’s business.

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 ATN’s and APL’s cost of doing business and, consequently, affects ATN’s and APL’s profitability, these burdens generally do not affect ATN and APL any differently or to any greater or lesser extent than they affect other companies in their industries with similar types, quantities and locations of production.

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

Hydrogen Sulfide. Exposure to gas containing high levels of hydrogen sulfide, referred to as sour gas, is harmful to humans, and prolonged exposure can result in death. The gas produced at APL’s Velma gas plant contains high levels of hydrogen sulfide, and APL employs numerous safety precautions at the system to ensure the safety of its employees. There are various federal and state environmental and safety requirements for handling sour gas, and APL is in substantial compliance with all such requirements.

Drilling and Production. ATN’s 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 ATN 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 ATN’s 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 ATN can produce from its wells or limit the number of wells or the locations at which ATN 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.

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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 ATN’s wells, and to limit the number of wells or locations ATN 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 our shareholders.

Pipeline Safety. APL’s pipelines are subject to regulation by the U.S. Department of Transportation, or the DOT, under the Natural Gas Pipeline Safety Act of 1968, as amended, or the NGPSA, pursuant to which the DOT has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The NGPSA covers the pipeline transportation of natural gas and other gases, and the transportation and storage of liquefied natural gas and requires any entity that owns or operates pipeline facilities to comply with the regulations under the NGPSA, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that APL’s pipeline operations are in substantial compliance with existing NGPSA requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, future compliance with the NGPSA could result in increased costs.

The DOT, through the Office of Pipeline Safety, recently finalized a series of rules intended to require pipeline operators to develop integrity management programs for gas transmission pipelines that, in the event of a failure, could affect “high consequence areas.” “High consequence areas” are currently defined as areas with specified population densities, buildings containing populations of limited mobility, and areas where people gather that are located along the route of a pipeline. The Texas Railroad Commission, the Oklahoma Corporation Commission and other state agencies have adopted similar regulations applicable to intrastate gathering and transmission lines. Compliance with these existing rules has not had a material adverse effect on APL’s operations but there is no assurance that this trend will continue in the future.

Regulation by FERC of Interstate Natural Gas Pipelines. FERC regulates APL’s interstate natural gas pipeline interests. Ozark Gas Transmission transports natural gas in interstate commerce. As a result, Ozark Gas Transmission qualifies as a “natural gas company” under the Natural Gas Act and is subject to the regulatory jurisdiction of FERC. In general, FERC has authority over natural gas companies that provide natural gas pipeline transportation services in interstate commerce, and its authority to regulate those services includes:

· rate structures;

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· rates of return on equity;

· recovery of costs;

· the services that our regulated assets are permitted to perform;

· the acquisition, construction and disposition of assets; and

· to an extent, the level of competition in that regulated industry.

Under the Natural Gas Act, FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Its authority to regulate those services includes the rates charged for the services, terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the acquisition and disposition of facilities, the initiation and discontinuation of services, and various other matters. Natural gas companies may not charge rates that have been determined not to be just and reasonable in proceedings before FERC. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.

The rates, terms and conditions of service provided by natural gas companies are required to be on file with FERC in FERC-approved tariffs. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. We cannot assure you that FERC will continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity, transportation and storage facilities. Any successful complaint or protest against Ozark Gas Transmission’s FERC-approved rates could have an adverse impact on APL’s revenues associated with providing transmission services.

Gathering Pipeline Regulation. Section 1(b) of the Natural Gas Act exempts natural gas gathering facilities from the jurisdiction of the FERC. APL owns a number of intrastate natural gas pipelines in New York, Pennsylvania, Ohio, Arkansas, Kansas, Oklahoma and Texas that APL believes would meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. However, the distinction between the FERC-regulated transmission services and federally unregulated gathering services is the subject of regular litigation, so the classification and regulation of some of APL’s gathering facilities may be subject to change based on future determinations by FERC and the courts.

In Ohio, a producer or gatherer of natural gas may file an application seeking exemption from regulation as a public utility, except for the continuing jurisdiction of the Public Utilities Commission of Ohio to inspect our gathering systems for public safety purposes. APL’s operating subsidiary has been granted an exemption by the Public Utilities Commission of Ohio for its Ohio facilities. The New York Public Service Commission imposes traditional public utility regulation on the transportation of natural gas by companies subject to its regulation. This regulation includes rates, services and siting authority for the construction of certain facilities. APL’s gas gathering operations currently are not subject to regulation by the New York Public Service Commission. APL’s operations in Pennsylvania currently are not subject to the Pennsylvania Public Utility Commission’s regulatory authority since they do not provide service to the public generally and, accordingly, do not constitute the operation of a public utility. Similarly, APL’s operations in Arkansas are not subject to rate oversight by the Arkansas Public Service Commission, but may, in certain circumstances, be subject to safety and environmental regulation by such commission or the Arkansas Oil and Gas Commission. In the event the Arkansas, Ohio, New York or Pennsylvania authorities seek to regulate APL’s operations, APL believes that its operating costs could increase and its transportation fees could be adversely affected, thereby reducing APL’s net revenues and ability to make distributions to us, as general partner, and its common unitholders.

Nonetheless, APL is currently subject to state ratable take, common purchaser and/or similar statutes in one or more jurisdictions in which it operates. Common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer, while ratable take statutes generally require gatherers to take, without discrimination, natural gas production that may be tendered to the gatherer for handling. In particular, Kansas, Oklahoma and Texas have adopted complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and discrimination with respect to rates or terms of service. Should a complaint be filed or regulation by the Kansas Corporation Commission, the Oklahoma Corporation Commission or the Texas Railroad Commission become more active, APL’s revenues could decrease. Collectively, any of these laws may restrict APL’s right as an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas.

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Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that FERC has taken a less stringent approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. For example, the Texas Railroad Commission has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of one customer over another. APL’s gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services.

APL’s gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on APL’s operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Sales of Natural Gas. A portion of APL’s revenues is tied to the price of natural gas. The wholesale price of natural gas is not currently subject to federal regulation and, for the most part, is not subject to state regulation. Sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry, and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes to APL’s operations, and we note that some of FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that APL will be affected by any such FERC action materially differently than other companies with whom APL competes.

Energy Policy Act of 2005. The Energy Policy Act contains numerous provisions relevant to the natural gas industry and to interstate pipelines in particular. Overall, the legislation attempts to increase supply sources by engaging in various studies of the overall resource base and attempting to advantage deep water production on the Outer Continental Shelf in the Gulf of Mexico. However, the primary provisions of interest to APL’s interstate pipelines focus on two areas: (1) infrastructure development; and (2) market transparency and enhanced enforcement. Regarding infrastructure development, the Energy Policy Act includes provisions to clarify that FERC has exclusive jurisdiction over the siting of liquefied natural gas terminals; provides for market-based rates for new storage facilities placed into service after the date of enactment; shortens depreciable life for gathering facilities; statutorily designates FERC as the lead agency for federal authorizations and permits; creates a consolidated record for all federal decisions relating to necessary authorizations and permits; and provides for expedited judicial review of any agency action and review by only the D.C. Circuit Court of Appeals of any alleged failure of a federal agency to act by a deadline set by FERC as lead agency. Such provisions, however, do not apply to review and authorization under the Coastal Zone Management Act of 1972. Regarding market transparency and manipulation rules, the Natural Gas Act is amended to prohibit market manipulation and add provisions for FERC to prescribe rules designed to encourage the public provision of data and reports regarding the price of natural gas in wholesale markets. The Natural Gas Act and the Natural Gas Policy Act are also amended to increase monetary criminal penalties to $1,000,000 from current law at $5,000 and to add and increase civil penalty authority to be administered by FERC to $1,000,000 per day per violation without any limitation as to total amount.

Employees

As of December 31, 2007, we employed 801 persons.

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.atlasamerica.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 is 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.

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ITEM 1A: RISK FACTORS

Risks Relating to Our Business

We are required to pay gathering fees to Atlas Pipeline pursuant to our contribution agreement with Atlas Energy equal to the difference between the gathering fee payable and the amount Atlas Energy receives from its investment partnerships for gathering services out of our own resources.

Under our contribution agreement with Atlas Energy, we assumed Atlas Energy’s obligation to pay gathering fees to Atlas Pipeline pursuant to the master natural gas gathering agreement, and Atlas Energy agreed to pay us the gathering fees it receives from its investment partnerships and fees associated with production to its interest. The gathering fees payable to Atlas Pipeline generally exceed the amount Atlas Energy receives from its investment partnerships for gathering services. For the twelve months ended December 31, 2007, this excess amount was approximately $11.9 million.

We may be required to indemnify Atlas Energy for claims relating to activities before our contribution of assets to it.

Pursuant to our contribution agreement with Atlas Energy, we will indemnify Atlas Energy until December 18, 2007 against certain potential environmental liabilities associated with the operation of the assets we contributed to it and occurring before December 18, 2006 and against claims for covered environmental liabilities made before December 18, 2010. Our obligation will not exceed $25.0 million, and we will not have any indemnification obligation until Atlas Energy’s losses exceed $500,000 in the aggregate, and then only to the extent such aggregate losses exceed $500,000. Additionally, we will indemnify Atlas Energy for losses attributable to title defects to the oil and gas property interests until December 18, 2009, and indefinitely for losses attributable to retained liabilities and income taxes attributable to pre-closing operations and the formation transactions.

We could be liable for taxes in connection with our spin-off from Resource America.

In connection with our initial public offering, Resource America and we entered into a tax matters agreement which governs our respective rights, responsibilities, and obligations with respect to tax liabilities and benefits. In general, under the tax matters agreement:

· Resource America is responsible for any U.S. federal income taxes of the affiliated group for U.S. federal income tax purposes of which Resource America is the common parent. With respect to any periods beginning after our initial offering, we are responsible for any U.S. federal income taxes attributable to us or any of our subsidiaries.

· Resource America is responsible for any U.S. state or local income taxes reportable on a consolidated, combined or unitary return that includes Resource America or one of its subsidiaries, on the one hand, and us or one of our subsidiaries, on the other hand. However, in the event that we or one of our subsidiaries are included in such a group for U.S. state or local income tax purposes for periods (or portions thereof) beginning after the date of the initial public offering, we are responsible for our portion of such income tax liability as if we and our subsidiaries had filed a separate tax return that included only us and our subsidiaries for that period (or portion of a period).

· Resource America is responsible for any U.S. state or local income taxes reportable on returns that include only Resource America and its subsidiaries (excluding us and our subsidiaries), and we are responsible for any U.S. state or local income taxes filed on returns that include only us and our subsidiaries.

· Resource America is responsible for any U.S. state or local income taxes reportable on returns that include only Resource America and its subsidiaries (excluding us and our subsidiaries), and we are responsible for any U.S. state or local income taxes filed on returns that include only us and our subsidiaries.

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Risks Related to Atlas Energy

Atlas Energy may not have sufficient cash flow from operations to pay the initial quarterly distribution, or IQD, to us following the establishment of cash reserves and payment of fees and expenses.

Atlas Energy may not have sufficient cash flow from operations each quarter to pay the IQD of $0.42. Under the terms of its limited liability company agreement, the amount of cash otherwise available for distribution will be reduced by its operating expenses and the amount of any cash reserve amounts that its board of directors establishes to provide for future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders and the holders of the management incentive interests. The amount of cash it can distribute principally depends upon the amount of cash it generate from its operations, which will fluctuate from quarter to quarter based on, among other things:

· the amount of natural gas and oil it produces;

· the price at which it sells its natural gas and oil;

· the level of its operating costs;

· its ability to acquire, locate and produce new reserves;

· results of its hedging activities;

· the level of its interest expense, which depends on the amount of its indebtedness and the interest payable on it; and

· the level of its capital expenditures.

In addition, the actual amount of cash we will receive from its distributions will depend on other factors, some of which are beyond its control, including:

· its ability to make working capital borrowings to pay distributions;

· the cost of acquisitions, if any;

· fluctuations in its working capital needs;

· timing and collectibility of receivables;

· restrictions on distributions imposed by lenders;

· the amount of its estimated maintenance capital expenditures;

· prevailing economic conditions; and

· the amount of cash reserves established by its board of directors for the proper conduct of its business.

As a result of these factors, the amount of cash Atlas Energy distributes in any quarter to us may fluctuate significantly from quarter to quarter and may be significantly less than the IQD amount that we expect to receive.

If commodity prices decline significantly, Atlas Energy’s cash flow from operations will decline and it may have to lower its distributions or may not be able to pay distributions at all.

Atlas Energy’s 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 its financial results and impede its growth. Changes in natural gas and oil prices will have a significant impact on the value of its reserves and on its 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 its control, such as:

· the level of the domestic and foreign supply and demand;

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· 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 Atlas Energy replaces its reserves, its reserves and production will decline, which would reduce its cash flow from operations and impair its ability to make distributions to us.

Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Based on Atlas Energy’s December 31, 2007 reserve report, its 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 Atlas Energy’s existing wells declines in a different manner than it has estimated and can change when it drills additional wells, makes acquisitions and under other circumstances. Thus, Atlas Energy’s future natural gas reserves and production and, therefore, its cash flow and income are highly dependent on its success in efficiently developing and exploiting its current reserves and economically finding or acquiring additional recoverable reserves. Atlas Energy’s ability to find and acquire additional recoverable reserves to replace current and future production at acceptable costs depends on its generating sufficient cash flow from operations and other sources of capital, principally its sponsored investment partnerships, all of which are subject to the risks discussed elsewhere in this section.

Atlas Energy’s 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 its 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. Atlas Energy’s independent petroleum engineers prepare estimates of its proved reserves. Over time, its internal engineers may make material changes to reserve estimates taking into account the results of actual drilling and production. Some of its 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, it makes 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 its 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. Atlas Energy’s PV-10 is calculated using natural gas prices that include its physical hedges but not its financial hedges. Numerous changes over time to the assumptions on which its reserve estimates are based, as described above, often result in the actual quantities of natural gas and oil it ultimately recover being different from its reserve estimates.

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The present value of future net cash flows from Atlas Energy’s proved reserves is not necessarily the same as the current market value of its estimated natural gas reserves. Atlas Energy bases the estimated discounted future net cash flows from its proved reserves on prices and costs in effect on the day of estimate. However, actual future net cash flows from its natural gas properties also will be affected by factors such as:

· actual prices it receive for natural gas;

· the amount and timing of actual production;

· the amount and timing of its capital expenditures;

· supply of and demand for natural gas; and

· changes in governmental regulations or taxation.

The timing of both its production and its 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 it uses 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 it or the natural gas and oil industry in general.

Any significant variance in its assumptions could materially affect the quantity and value of reserves, the amount of PV-10, and its financial condition and results of operations. In addition, its 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 its production can reduce the estimated volumes of its reserves because the economic life of its wells could end sooner. Similarly, a decline in market prices for natural gas or oil may reduce its PV-10. Any of these negative effects on its reserves or PV-10 may decrease the value of our investment in it.

Atlas Energy’s operations require substantial capital expenditures, which will reduce its cash available for distribution. In addition, each quarter it is required to deduct estimated maintenance capital expenditures from operating surplus, which may result in less cash available to us than if actual maintenance capital expenditures were deducted.

Atlas Energy will need to make substantial capital expenditures to maintain its capital asset base over the long term. For the twelve months ending December 31, 2008, we estimate these expenditures to be approximately $43.5 million. These maintenance capital expenditures may include the drilling and completion of additional wells to offset the production decline from its producing properties or additions to its inventory of unproved or proved reserves. These expenditures could increase as a result of:

· changes in its reserves;

· changes in natural gas prices;

· changes in labor and drilling costs;

· its ability to acquire, locate and produce reserves;

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· changes in leasehold acquisition costs; and

· government regulations relating to safety and the environment.

Atlas Energy’s significant maintenance capital expenditures will reduce the amount of cash it has available for distribution to us. In addition, its actual maintenance capital expenditures will vary from quarter to quarter. Its limited liability company agreement requires it 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 its board of directors, including a majority of its conflicts committee, at least once a year. In years when its estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to us will be lower than if it deducted actual maintenance capital expenditures from operating surplus. If it underestimates the appropriate level of estimated maintenance capital expenditures, it may have less cash available for distribution in future periods when actual capital expenditures begin to exceed its previous estimates. Over time, if it does not set aside sufficient cash reserves or have available sufficient sources of financing and make sufficient expenditures to maintain its capital asset base, it will be unable to pay distributions at the anticipated level and may have to reduce its 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 its indebtedness and working capital requirements;

· an inability to integrate successfully or timely the businesses it acquires;

· 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, Atlas Energy’s 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.

Atlas Energy may be unsuccessful in integrating the operations from its recent acquisition or any future acquisitions with its operations and in realizing all of the anticipated benefits of these acquisitions.

ATN acquired DTE Gas & Oil in June 2007 and is currently in the process of integrating its operations. ATN also has an active, on-going program to identify other potential acquisitions. The integration of previously independent operations can be a complex, costly and time-consuming process. The difficulties of combining these systems, as well as any operations it may acquire in the future, with it include, among other things:

· operating a significantly larger combined entity;

· the necessity of coordinating geographically disparate organizations, systems and facilities;

· integrating personnel with diverse business backgrounds and organizational cultures;

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· 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 its indebtedness; and

· potential environmental or regulatory liabilities and title problems.

Atlas Energy acquired DTE Gas & Oil with the expectation that combining it with its existing operations will result in benefits, including, among other things, increased geographic diversification and reserve life. There can be no assurance that Atlas Energy will realize any of these benefits or that the acquisition will not result in the deterioration or loss of its business. Costs incurred and liabilities assumed in connection with an acquisition and increased capital expenditures and overhead costs incurred to expand its operations could harm its business or future prospects, and result in significant decreases in its gross margin and cash flows.

The DTE Gas & Oil acquisition has substantially changed Atlas Energy’s business, making it difficult to evaluate our business based upon our historical financial information.

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

Atlas Energy has 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 its 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.

Atlas Energy has limited experience in drilling development wells to the Marcellus Shale. As of December 31, 2007, Atlas Energy had 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, Atlas Energy has much less information with respect to the ultimate recoverable reserves and the production decline rate in the Marcellus Shale than it has in our other areas of operation. In addition, the wells to be drilled in the Marcellus Shale will be drilled deeper than its 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 Atlas Energy’s other areas of operation.

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Changes in tax laws may impair Atlas Energy’s 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 it sponsors, including deductions for intangible drilling costs and depletion deductions. Changes to federal tax law that reduce or eliminate these benefits may make investment in its investment partnerships less attractive and, thus, reduce its ability to obtain funding from this significant source of capital funds.

Atlas Energy has a substantial amount of indebtedness which could adversely affect its financial position.

ATN currently has a substantial amount of indebtedness. As of February 20, 2008, it had total debt of approximately $770.1 million, consisting of $250.0 million of senior notes, $520.0 million of borrowings under its credit facility, and $0.1 million of other debt. Atlas Energy may also incur significant additional indebtedness in the future. Its substantial indebtedness may:

· make it difficult for ATN to satisfy its financial obligations, including making scheduled principal and interest payments on the senior notes and its other indebtedness;

· limit its ability to borrow additional funds for working capital, capital expenditures, acquisitions or other general business purposes;

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

· require it to use a substantial portion of its cash flow from operations to make debt service payments;

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

· place it at a competitive disadvantage compared to its less leveraged competitors; and

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

Atlas Energy’s ability to service its indebtedness will depend upon, among other things, its 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 its control. If its operating results are not sufficient to service its current or future indebtedness, it 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 its indebtedness, or seeking additional equity capital or bankruptcy protection. It may not be able to effect any of these remedies on satisfactory terms or at all.

Covenants in Atlas Energy’s debt agreements restrict its business in many ways.

The indenture governing ATN’s senior notes and its credit facility contain various covenants that limit its ability and/or its 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;

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· make loans, investments and capital expenditures;

· enter into agreements that restrict distributions from its subsidiaries;

· sell assets and capital stock of its subsidiaries;

· enter into certain transactions with affiliates; and

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

In addition, its credit facility contains restrictive covenants and requires it to maintain specified financial ratios. ATN’s ability to meet those financial ratios can be affected by events beyond its control, and it may be unable to meet those tests. A breach of any of these covenants could result in a default under its credit facility and/or the senior notes. Upon the occurrence of an event of default under its credit facility, the lenders could elect to declare all amounts outstanding under its credit facility to be immediately due and payable and terminate all commitments to extend further credit. If ATN were unable to repay those amounts, the lenders could proceed against the collateral granted to them to secure that indebtedness. ATN has pledged a significant portion of its assets as collateral under its credit facility. If the lenders under its credit facility accelerate the repayment of borrowings, ATN may not have sufficient assets to repay its credit facility and its other indebtedness, including the notes. ATN’s borrowings under its credit facility are, and are expected to continue to be, at variable rates of interest and expose it to interest rate risk. If interest rates increase, ATN’s debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and its net income would decrease.

Atlas Energy may not be able to continue to raise funds through its investment partnerships at the levels it has recently experienced, which may in turn restrict its ability to maintain its drilling activity at the levels recently experienced.

Atlas Energy has sponsored limited and general partnerships to raise funds from investors to finance its development drilling activities in Appalachia. Accordingly, the amount of development activities it undertakes there depends in large part upon its ability to obtain investor subscriptions to invest in these partnerships. During the past three years it has 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, Atlas Energy may not be successful in raising funds through these investment partnerships at the same levels it has recently experienced, and it also may not be successful in increasing the amount of funds it raises as it has done in recent years. Atlas Energy’s ability to raise funds through its 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 Atlas Energy’s historical track record of generating returns and tax benefits to the investors in its existing partnerships.

In the event that Atlas Energy’s investment partnerships do not achieve satisfactory returns on investment or the anticipated tax benefits, it may have difficulty in continuing to increase the amount of funds it raises through these partnerships or in maintaining the level of funds it has recently raised through its partnerships. In this event, Atlas Energy may need to obtain financing for its drilling activities on a less attractive basis than the financing it realized through these partnerships or it may determine to reduce drilling activity.

Atlas Energy’s fee-based revenues may decline if it is unsuccessful in continuing to sponsor investment partnerships, and its fee-based revenue may not increase at the same rate as recently experienced if it is unable to raise funds at the same or higher levels as it has recently experienced.

Atlas Energy’s fee-based revenues are based on the number of investment partnerships it sponsors and the number of partnerships and wells it manages or operates. If it is unsuccessful in sponsoring future investment partnerships, its fee-based revenues may decline. Additionally, its fee-based revenue may not increase at the same rate as recently experienced if it is unable to raise funds at the same or higher levels as it has recently experienced.

Atlas Energy’s revenues may decrease if investors in its investment partnerships do not receive a minimum return.

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

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Competition in the natural gas and oil industry is intense, which may hinder Atlas Energy’s ability to acquire gas and oil properties and companies and to obtain capital, contract for drilling equipment and secure trained personnel.

Atlas Energy operates in a highly competitive environment for acquiring properties and other natural gas and oil companies, attracting capital through its investment partnerships, contracting for drilling equipment and securing trained personnel. Atlas Energy will also compete with the exploration and production divisions of public utility companies for natural gas and oil property acquisitions. Atlas Energy’s 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 its financial or personnel resources permit. Moreover, Atlas Energy’s 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 it does. All of these challenges could make it more difficult for it to execute its growth strategy. It 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 its competitors possess greater financial and other resources than it does, which may enable them to identify and acquire desirable properties and market their natural gas and oil production more effectively than Atlas Energy does.

Atlas Energy depends on certain key customers for sales of its natural gas. To the extent these customers reduce the volumes of natural gas they purchase from Atlas Energy, its revenues and cash available for distribution could decline.

In Appalachia, its 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 Atlas Energy’s affiliates, and it including its investment partnerships. During fiscal 2007 natural gas sales to Hess Corporation accounted for approximately 18% of its 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 its total Michigan oil and gas revenues. To the extent these and other key customers reduce the amount of natural gas they purchase from Atlas Energy, its revenues and cash available for distributions to unitholders could temporarily decline in the event it is unable to sell to additional purchasers.

Atlas Energy’s Appalachia business depends on the gathering and transportation facilities of Atlas Pipeline. Any limitation in the availability of those facilities would interfere with its ability to market the natural gas it produces and could reduce its revenues and cash available for distribution.

Atlas Pipeline gathers more than 90% of Atlas Energy’s current Appalachia production and approximately 50% of its total production. The marketability of its 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.

Shortages of drilling rigs, equipment and crews could delay Atlas Energy’s 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, Atlas Energy 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 its ability to drill the wells and conduct the operations which it currently has planned. Any delay in the drilling of new wells or significant increase in drilling costs could reduce its revenues.

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Because Atlas Energy handles natural gas and oil, it 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 Atlas Energy’s 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;

· RCRA and comparable state laws that impose requirements for the handling and disposal of waste from its 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 Atlas Energy or at locations to which it has 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 Atlas Energy may incur environmental costs and liabilities due to the nature of its business and the substances it handles. For example, an accidental release from one of its wells could subject it 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 its compliance costs and the cost of any remediation that may become necessary. Atlas Energy may not be able to recover remediation costs under its insurance policies.

Many of Atlas Energy’s leases are in areas that have been partially depleted or drained by offset wells.

Atlas Energy’s key project areas are located in active drilling areas in the Appalachian Basin. As a result, many of its 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.

Atlas Energy’s identified drilling location inventories are susceptible to uncertainties that could materially alter the occurrence or timing of its drilling activities, which may result in lower cash from operations .Its management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on its existing acreage.

As of December 31, 2007, Atlas Energy had identified over 3,950 potential drilling locations. These identified drilling locations represent a significant part of its growth strategy. Its 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, Atlas Energy’s independent petroleum engineering consultants have not assigned any proved reserves to the over 2,650 unproved potential drilling locations it has identified and therefore there may exist greater uncertainty with respect to the success of drilling wells at these drilling locations. Its final determination on whether to drill any of its drilling locations will be dependent upon the factors described above as well as, to some degree, the results of its drilling activities with respect to its proved drilling locations. Because of these uncertainties, it does not know if the numerous drilling locations it has identified will be drilled within its expected timeframe or will ever be drilled or if it will be able to produce natural gas and oil from these or any other potential drilling locations. As such, its actual drilling activities may materially differ from its anticipated drilling activities.

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Some of Atlas Energy’s undeveloped leasehold acreage is subject to leases that may expire in the near future.

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

Drilling for and producing natural gas are high-risk activities with many uncertainties.

Atlas Energy’s drilling activities are subject to many risks, including the risk that it 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, its drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

· 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 Atlas Energy’s receipt of drilling and production revenues, thereby reducing its earnings, and could reduce revenues in one or more of its investment partnerships, which may make it more difficult to finance its 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 Atlas Energy maintains insurance against various losses and liabilities arising from its operations, insurance against all operational risks is not available to it. Additionally, it may elect not to obtain insurance if it believes that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could reduce our results of operations.

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Properties that Atlas Energy buys may not produce as projected and it may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.

One of Atlas Energy’s growth strategies is to capitalize on opportunistic acquisitions of natural gas reserves. However, its 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 it acquires. 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 it inspects a well. Any unidentified problems could result in material liabilities and costs that negatively affect its financial condition and results of operations.

Even if Atlas Energy is 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 Atlas Energy’s potential gains or cause it to lose money.

Pricing for natural gas has been volatile and unpredictable for many years. To limit exposure to changing natural gas prices, Atlas Energy uses financial and physical hedges for its 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. It generally limits these arrangements to smaller quantities than those projected to be available at any delivery point. In addition, 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 its natural gas production, Atlas Energy has reduced, but not eliminated, the potential effects of changing natural gas prices on its 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 its 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 its 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.

Atlas Energy may be exposed to financial and other liabilities as the managing general partner in investment partnerships.

Atlas Energy serves as the managing general partner of 92 investment partnerships and will be the managing general partner of new investment partnerships that it sponsors. As a general partner, Atlas Energy is contingently liable for the obligations of its partnerships to the extent that partnership assets or insurance proceeds are insufficient. It has agreed to indemnify each investor partner in its investment partnerships from any liability that exceeds such partner’s share of the investment partnership’s assets.

Atlas Energy is subject to comprehensive federal, state, local and other laws and regulations that could increase the cost and alter the manner or feasibility of it doing business.

Atlas Energy’s 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, it 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 Atlas Energy operates 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, its activities are subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect its operations and limit the quantity of natural gas it may produce and sell. A major risk inherent in its 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 its 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 its profitability. Furthermore, it 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 it.

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Atlas Energy’s tax treatment depends on its status as a partnership for federal income tax purposes, as well as Atlas Energy not being subject to entity-level taxation by individual states. If the IRS were to treat Atlas Energy as a corporation for federal income tax purposes or Atlas Energy 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 Atlas Energy’s common units depends largely on Atlas Energy being treated as a partnership for federal income tax purposes. Atlas Energy has not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects Atlas Energy.

If Atlas Energy were treated as a corporation for federal income tax purposes, it would pay federal income tax on its 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 Atlas Energy unit holders would generally be taxed as corporate distributions, and no income, gain, loss, deduction or credit would flow through to unit holders. Because a tax may be imposed on Atlas Energy as a corporation, Atlas Energy’s cash available for distribution to its unit holders could be reduced. Therefore, Atlas Energy’s treatment as a corporation could result in a material reduction in the anticipated cash flow and after-tax return to its unit holders and therefore result in a substantial reduction in the value of Atlas Energy’s common units.

Current law or Atlas Energy’s business may change so as to cause it to be treated as a corporation for federal income tax purposes or otherwise subject Atlas Energy 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 unit holders would be reduced. Atlas Energy’s limited liability company agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects Atlas Energy to taxation as a corporation or otherwise subject it 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 Atlas Energy.

Atlas Energy will be considered to have terminated for tax purposes due to a sale or exchange of 50% or more of its interests within a twelve-month period.

Atlas Energy 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 its capital and profits within a twelve-month period. A constructive termination results in the closing of Atlas Energy’s 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 Atlas Energy’s 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 Atlas Energy filing two tax returns, and Atlas Energy 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 Atlas Energy unit holders.

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Risks Related to Atlas Pipeline Holdings

AHD’s only cash generating assets are its interests in APL, and its cash flow is therefore completely dependent upon the ability of APL to make distributions to its partners.

The amounts of cash that APL generates may not be sufficient for it to pay distributions at the current or any other level of distribution. APL’s ability to make cash distributions depends primarily on its cash flow. Cash distributions do not depend directly on APL’s profitability, which is affected by non-cash items. Therefore, cash distributions may be made during periods when APL records losses and may not be made during periods when APL records profits. The actual amounts of cash APL generates will depend upon numerous factors relating to its business which may be beyond its control, including:

· the demand for and price of its natural gas and NGLs;

· expiration of significant contracts;

· the volume of natural gas APL transports;

· continued development of wells for connection to APL’s gathering systems;

· the availability of local, intrastate and interstate transportation systems;

· the expenses APL incurs in providing its gathering services;

· the cost of acquisitions and capital improvements;

· APL’s issuance of equity securities;

· required principal and interest payments on APL’s debt;

· fluctuations in working capital;

· prevailing economic conditions;

· fuel conservation measures;

· alternate fuel requirements;

· government regulation and taxation; and

· technical advances in fuel economy and energy generation devices.

In addition, the actual amount of cash that APL will have available for distribution will depend on other factors, including:

· the level of capital expenditures it makes;

· the sources of cash used to fund its acquisitions;

· its debt service requirements and requirements to pay dividends on its outstanding preferred units, and restrictions on distributions contained in its current or future debt agreements; and

· the amount of cash reserves established by us, as APL’s general partner, for the conduct of APL’s business.

APL is unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” under its partnership agreement. Because APL will be unable to borrow money to pay distributions unless it establishes a facility that meets the definition contained in its partnership agreement, APL’s ability to pay a distribution in any quarter is solely dependent on its ability to generate sufficient operating surplus with respect to that quarter.

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AHD’s and APL’s debt levels and restrictions in AHD’s and APL’s credit facilities could limit their ability to make distributions to its unitholders.

APL has a significant amount of debt. APL will need a substantial portion of its cash flow to make principal and interest payments on its indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to its unitholders. If APL’s operating results are not sufficient to service its current or future indebtedness, it 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 its indebtedness, or seeking additional equity capital or bankruptcy protection. APL may not be able to effect any of these remedies on satisfactory terms, or at all.

AHD’s and APL’s credit facilities contain covenants limiting the ability to incur indebtedness, grant liens, engage in transactions with affiliates and make distributions to unitholders. AHD’s and APL’s credit facilities also contain covenants requiring APL and AHD to maintain certain financial ratios. In addition, AHD and APL are prohibited from making any distribution to its respective unitholders if such distribution would cause an event of default or otherwise violate a covenant under their respective credit facilities.

If AHD does not pay distributions on its common units with respect to any fiscal quarter, AHD’s unitholders are not entitled to receive such payments in the future.

AHD’s distributions to its unitholders are not cumulative. Consequently, if AHD does not pay distributions on its common units with respect to any fiscal quarter, AHD’s unitholders are not entitled to receive such payments in the future.

In the future, AHD may not have sufficient cash to pay distributions at its current quarterly distribution level or to increase distributions.

The source of AHD’s earnings and cash flow currently consists exclusively of cash distributions from APL. Therefore, the amount of distributions AHD is able to make to its unitholders may fluctuate based on the level of distributions APL makes to its partners. AHD cannot assure unit holders that APL will continue to make quarterly distributions at its current level or increase its quarterly distributions in the future. In addition, while AHD would expect to increase or decrease distributions to its unitholders if APL increases or decreases distributions to AHD, the timing and amount of such increased or decreased distributions, if any, will not necessarily be comparable to the timing and amount of the increase or decrease in distributions made by APL to AHD.

AHD’s ability to distribute cash received from APL to its unitholders is limited by a number of factors, including:

· interest expense and principal payments on any current or future indebtedness;

· restrictions on distributions contained in any current or future debt agreements;

· AHD’s general and administrative expenses, including expenses it incurs as a result of being a public company;

· expenses of AHD’s subsidiaries other than APL, including tax liabilities of AHD’s corporate subsidiaries, if any;

· reserves necessary for AHD to make the necessary capital contributions to maintain its 2.0% general partner interest in APL as required by its partnership agreement upon the issuance of additional partnership securities by APL; and

· reserves AHD’s general partner believes prudent for it to maintain for the proper conduct of its business or to provide for future distributions.

AHD cannot guarantee that in the future it will be able to pay distributions or that any distributions it does make will be at or above its current quarterly distribution level. The actual amount of cash that is available for distribution to AHD’s unitholders will depend on numerous factors, many of which are beyond AHD’s control or the control of its general partner.

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AHD, as the parent of APL’s general partner, may limit or modify the incentive distributions it is entitled to receive from APL in order to facilitate the growth strategy of APL. The board of directors of AHD’s general partner, our subsidiary, can give this consent without a vote of our or AHD’s unitholders.

AHD owns APL’s general partner, which owns the incentive distribution rights in APL that entitles AHD to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed by APL as it reaches certain target distribution levels in excess of $0.42 per common unit in any quarter. A substantial portion of the cash flows AHD receives from APL is provided by these incentive distributions. APL’s board of directors may reduce the incentive distribution rights payable to AHD with its consent, which AHD may provide without the approval of its unitholders or us. In July 2007, in connection with APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems, AHD agreed to allocate up to $5.0 million of incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter.

In order to facilitate acquisitions by APL, the general partner of APL may elect to limit the incentive distributions AHD is entitled to receive with respect to a particular acquisition or unit issuance contemplated by APL. This is because a potential acquisition might not be accretive to APL’s common unitholders as a result of the significant portion of that acquisition’s cash flows which would be paid as incentive distributions to AHD. By limiting the level of incentive distributions in connection with a particular acquisition or issuance of units of APL, the cash flows associated with that acquisition could be accretive to APL’s common unitholders as well as substantially beneficial to AHD. In doing so, the managing board of APL’s general partner would be required to consider both its fiduciary obligations to investors in APL as well as to AHD. AHD’s partnership agreement specifically permits its general partner to authorize the general partner of APL to limit or modify the incentive distribution rights held by AHD if its general partner determines that such limitation or modification does not adversely affect AHD’s limited partners in any material respect.

A reduction in APL’s distributions will disproportionately affect the amount of cash distributions to which AHD is currently entitled.

AHD is entitled to receive incentive distribution from APL with respect to any particular quarter only in the event that APL distributes more than $0.42 per common unit for such quarter. Furthermore, as described in the immediately preceeding risk factor, AHD agreed to allocate up to $5.0 million of incentive distributions per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter.

Because the incentive distribution rights currently participate at the maximum target cash distribution level, future growth in distributions AHD receives from APL will not result from an increase in the target cash distribution level associated with the incentive distribution rights. Furthermore, a decrease in the amount of distributions by APL to less than $0.60 per common unit per quarter would reduce AHD’s percentage of the incremental cash distributions from 48% to 23%, if APL’s distribution is between $0.52 and $0.59, and to 13%, if APL’s distribution is between $0.43 and $0.51, subject in both cases to the effect of the incentive distribution adjustment agreement. As a result, any such reduction in quarterly cash distributions from APL would have the effect of disproportionately reducing the amount of all incentive distributions that AHD receives as compared to cash distributions AHD receives on its 2.0% general partner interest in APL and the APL common units AHD owns.

AHD’s ability to meet its financial needs may be adversely affected by its cash distribution policy and AHD’s lack of operational assets.

AHD’s cash distribution policy, which is consistent with AHD’s partnership agreement, requires it to distribute all of its available cash quarterly. AHD’s only cash generating assets are partnership interests, including incentive distribution rights, in APL, and AHD currently has no independent operations separate from those of APL. Moreover, a reduction in APL’s distributions will disproportionately affect the amount of cash distributions AHD receives. Given that AHD’s cash distribution policy is to distribute available cash and not retain it and that AHD’s only cash generating assets are partnership interests in APL, AHD may not have enough cash to meet its needs if any of the following events occur:

· an increase in AHD’s operating expenses;

· an increase in general and administrative expenses;

· an increase in principal and interest payments on AHD’s outstanding debt;

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· an increase in working capital requirements; or

· an increase in cash needs of APL or its subsidiaries that reduces APL’s distributions.

There is no guarantee that AHD’s unitholders will receive quarterly distributions from AHD.

While AHD’s cash distribution policy, which is consistent with the terms of its partnership agreement, requires that AHD distribute all of its available cash quarterly, AHD’s cash distribution policy is subject to the following restrictions and limitations and may be changed at any time, including in the following ways:

· AHD may lack sufficient cash to pay distributions to its unitholders due to a number of factors, including increases in its general and administrative expenses, the effect of the IDR Adjustment Agreement, principal and interest payments on debt AHD may incur, tax expenses, working capital requirements and anticipated cash needs of AHD or APL and their subsidiaries.

· AHD’s cash distribution policy is, and APL’s cash distribution policy is, subject to restrictions on distributions under AHD’s and APL’s credit facilities, such as material financial tests and covenants and limitations on paying distributions during an event of default.

· The AHD general partner’s board of directors will have the authority under AHD’s partnership agreement to establish reserves for the prudent conduct of its business and for future cash distributions to its unitholders, and the managing board of APL’s general partner has the authority under APL’s partnership agreement to establish reserves for the prudent conduct of APL’s business and for future cash distributions to APL’s common unitholders. The establishment of those reserves could result in a reduction in cash distributions to AHD’s unitholders from current levels pursuant to AHD’s stated cash distribution policy.

· AHD’s partnership agreement, including its cash distribution policy contained therein, may be amended by a vote of the holders of a majority of AHD’s common units.

· Even if AHD’s cash distribution policy is not amended, modified or revoked, the amount of distributions AHD pays under its cash distribution policy and the decision to make any distribution is determined by its general partner, taking into consideration the terms of AHD’s partnership agreement, the amount of distributions paid under APL’s cash distribution policy and the decision to make any distribution to its unitholders is at the discretion of APL’s general partner, taking into consideration the terms of its partnership agreement.

· Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, APL may not make a distribution to its partners if the distribution would cause its liabilities to exceed the fair value of its assets, and AHD may not make a distribution to its unitholders if the distribution would cause its liabilities to exceed the fair value of its assets.

Because of these restrictions and limitations on AHD’s cash distribution policy and its ability to change its cash distribution policy, AHD may not have available cash to distribute to its unitholders, and there is no guarantee that its unitholders will receive quarterly distributions from AHD.

AHD’s cash distribution policy limits its ability to grow.

Because AHD distributes all of its available cash, its growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. In fact, AHD’s growth is completely dependent upon APL’s ability to increase its quarterly distribution per unit because currently its only cash-generating assets are partnership interests in APL, including incentive distribution rights. If AHD issues additional units or incurs additional debt to fund acquisitions and capital expenditures, the payment of distributions on those additional units or interest on that debt could increase the risk that AHD will be unable to maintain or increase its per unit distribution level.

Consistent with the terms of its partnership agreement, APL distributes to its partners its available cash each quarter. In determining the amount of cash available for distribution, APL sets aside cash reserves, including reserves it believes prudent to maintain for the proper conduct of its business or to provide for future distributions. Additionally, it has relied upon external financing sources, including commercial borrowings and other debt and equity issuances, to fund its acquisition capital expenditures. Accordingly, to the extent APL does not have sufficient cash reserves or is unable to finance growth externally, its cash distribution policy will significantly impair its ability to grow. In addition, to the extent APL issues additional units in connection with any acquisitions or capital expenditures, the payment of distributions on those additional common units may increase the risk that APL will be unable to maintain or increase its per common unit distribution level, which in turn may impact the available cash that AHD has to distribute to its unitholders. The incurrence of additional debt to finance its growth strategy would result in increased interest expense to APL, which in turn may impact the available cash that AHD has to distribute to its unitholders.

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AHD is largely dependent on APL for its growth. As a result of the fiduciary obligations of APL’s general partner, which is AHD’s wholly-owned subsidiary, to the common unitholders of APL, AHD’s ability to pursue business opportunities independently will be limited.

AHD currently intends to grow primarily through the growth of APL. While AHD is not precluded from pursuing business opportunities independently of APL, AHD’s subsidiary, as the general partner of APL, has fiduciary duties to APL unitholders which would make it difficult for AHD to engage in any business activity that is competitive with APL. Those fiduciary duties are applicable to AHD because it controls the general partner through its ability to elect all of its directors. While there may be circumstances in which these fiduciary duties may be satisfied while allowing AHD to pursue business opportunities independent of APL, AHD expects such opportunities to be limited. Accordingly, AHD may be unable to diversify its sources of revenue in order to increase cash distributions.

AHD’s ability to sell its general partner interest and incentive distribution rights in APL is limited.

AHD faces contractual limitations on its ability to sell its general partner interest and incentive distribution rights and the market for such interests is illiquid.

APL’s common unitholders have the right to remove APL’s general partner with the approval of the holders of 66 2/3% of all units, which would cause AHD to lose its general partner interest and incentive distribution rights in APL and the ability to manage APL.

AHD currently manages APL through Atlas Pipeline GP, APL’s general partner and AHD’s wholly-owned subsidiary. APL’s partnership agreement, however, gives common unitholders of APL the right to remove the general partner of APL upon the affirmative vote of holders of 66 2/3% of APL’s outstanding common units. If Atlas Pipeline GP were removed as general partner of APL, it would receive cash or common units in exchange for its 2.0% general partner interest and the incentive distribution rights and would lose its ability to manage APL. While the common units or cash AHD would receive are intended under the terms of APL’s partnership agreement to fully compensate AHD in the event such an exchange is required, the value of these common units or investments AHD makes with the cash over time may not be equivalent to the value of the general partner interest and the incentive distribution rights had AHD retained them.

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APL may issue additional limited partner units, which may increase the risk of it not having sufficient available cash to maintain or increase its per common unit distribution level.

APL has wide discretion to issue additional limited partner units, including units that rank senior to its common units and the incentive distribution rights as to quarterly cash distributions, on the terms and conditions established by its general partner. The payment of distributions on additional APL common units may increase the risk of APL being unable to maintain or increase its per common unit distribution level. To the extent new APL limited partner units are senior to the APL common units and the incentive distribution rights, their issuance will increase the uncertainty of the payment of distributions on the common units and the incentive distribution rights. Neither the common units nor the incentive distribution rights are entitled to any arrearages from prior quarters.

AHD may issue an unlimited number of limited partner interests without the consent of its unitholders, which will dilute existing limited partners’ ownership interest in AHD and may increase the risk that AHD will not have sufficient available cash to maintain or increase its per unit distribution level.

AHD may issue an unlimited number of limited partner interests of any type without the approval of its unitholders on terms and conditions established by AHD’s general partner at any time. The issuance by AHD of additional common units or other equity securities of equal or senior rank will have the following effects:

· AHD unitholders’ proportionate ownership interest in it will decrease;

· the amount of cash available for distribution on each unit may decrease;

· the relative voting strength of each previously outstanding unit may be diminished;

· the ratio of taxable income to distributions may increase; and

· the market price of the common units may decline.

If in the future AHD ceases to manage and control APL through AHD’s ownership of APL’s general partner interests, AHD may be deemed to be an investment company under the Investment Company Act of 1940.

If AHD ceases to manage and control APL and is deemed to be an investment company under the Investment Company Act of 1940, AHD would either have to register as an investment company under the Investment Company Act of 1940, obtain exemptive relief from the SEC or modify AHD’s organizational structure or its contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit AHD’s ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from AHD’s affiliates, restrict AHD’s ability to borrow funds or engage in other transactions involving leverage and require AHD to add additional directors who are independent of AHD or its affiliates.

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The value of AHD’s investment in APL depends largely on it being treated as a partnership for federal income tax purposes, which requires that 90% or more of APL’s gross income for every taxable year consist of qualifying income, as defined in Section 7704 of the Internal Revenue Code. APL may not meet this requirement or current law may change so as to cause, in either event, APL to be treated as a corporation for federal income tax purposes or otherwise subject to federal income tax. Moreover, the anticipated after-tax benefit of an investment in AHD’s common units depends largely on AHD being treated as a partnership for federal income tax purposes. AHD has not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting AHD.

If APL were treated as a corporation for federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 35%. Distributions to AHD would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to AHD. As a result, there would be a material reduction in AHD’s anticipated cash flow, likely causing a substantial reduction in the value of AHD’s units.

If AHD were treated as a corporation for federal income tax purposes, AHD would pay federal income tax on its taxable income at the corporate tax rate. Distributions to AHD’s unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to AHD’s unitholders. Because a tax would be imposed upon AHD as a corporation, AHD’s cash available for distribution to its unitholders would be substantially reduced. Thus, treatment of AHD as a corporation would result in a material reduction in AHD’s anticipated cash flow, likely causing a substantial reduction in the value of AHD’s units.

Current law may change, causing AHD or APL to be treated as a corporation for federal income tax purposes or otherwise subjecting AHD or APL to entity level taxation. For example, 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 AHD or APL as an entity, the cash available for distribution to AHD’s unitholders would be reduced.

Risks Relating to APL’s Business

Because AHD’s cash flow currently consists exclusively of distributions from APL, risks to APL’s business are also risks to AHD. Set forth below are the material risks to APL’s business or results of operations, the occurrence of which could negatively impact APL’s financial performance and decrease the amount of cash it is able to distribute to AHD, thereby decreasing the amount of cash AHD has available for distribution to its unitholders.

APL’s profitability is affected by the volatility of prices for natural gas and NGL products.

APL derives a majority of its revenues from POP and keep-whole contracts. As a result, APL’s income depends to a significant extent upon the prices at which the natural gas it transports, treats or processes and the NGLs it produces are sold. A 10% change in the average price of NGLs, natural gas and condensate APL processes and sells would result in a change to its gross margin for the twelve-month period ended December 31, 2008, excluding the effect of minority interests in APL’s net income, of approximately $3.7 million. Additionally, changes in natural gas prices may indirectly impact APL’s profitability since prices can influence drilling activity and well operations and thus the volume of gas APL gathers and processes. Historically, the price of both natural gas and NGLs has been subject to significant volatility in response to relatively minor changes in the supply and demand for natural gas and NGL products, market uncertainty and a variety of additional factors beyond APL’s control, including those AHD describes in “--AHD’s only cash generating assets are its partnership interests in APL, and its cash flow is therefore completely dependent upon the ability of APL to make distributions to its partners,” under “Risks Relating to Atlas Pipeline Holdings”. APL expects this volatility to continue. This volatility may cause APL’s gross margin and cash flows to vary widely from period to period. APL’s hedging strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all of the throughput volumes subject to percentage-of-proceeds contracts. Moreover, hedges are subject to inherent risks, which is described in “— APL’s hedging strategies may fail to protect it and could reduce its gross margin and cash flow.”

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The amount of natural gas APL transports will decline over time unless it is able to attract new wells to connect to its gathering systems.

Production of natural gas from a well generally declines over time until the well can no longer economically produce natural gas and is plugged and abandoned. Failure to connect new wells to APL’s gathering systems could, therefore, result in the amount of natural gas APL transports reducing substantially over time and could, upon exhaustion of the current wells, cause it to abandon one or more of its gathering systems and, possibly, cease operations. The primary factors affecting APL’s ability to connect new supplies of natural gas to its gathering systems include APL’s success in contracting for existing wells that are not committed to other systems, the level of drilling activity near its gathering systems and, in the Mid-Continent region, APL’s ability to attract natural gas producers away from its competitors’ gathering systems. Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. APL has no control over the level of drilling activity in its service areas, the amount of reserves underlying wells that connect to its systems and the rate at which production from a well will decline. In addition, APL has no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulation and the availability and cost of capital. Because APL’s operating costs are fixed to a significant degree, a reduction in the natural gas volumes it transports or processes would result in a reduction in its gross margin and cash flows.

The amount of natural gas APL transports, treats or processes may be reduced if the natural gas liquids pipelines to which it delivers NGLs cannot or will not accept the gas.

If one or more of the pipelines to which APL delivers NGLs has service interruptions, capacity limitations or otherwise does not accept the NGLs APL sells to or transports on, and APL cannot arrange for delivery to other pipelines, the amount of NGLs APL sells or transport may be reduced. Since APL’s revenues depend upon the volumes of NGLs it sells or transports, this could result in a material reduction in its gross margin and cash flows.

The success of APL’s Appalachian operations depends upon Atlas Energy’s ability to drill and complete commercial producing wells.

Substantially all of the wells APL connects to its gathering systems in its Appalachian service area are drilled and operated by Atlas Energy for drilling investment partnerships sponsored by Atlas Energy. As a result, APL’s Appalachian operations depend principally upon the success of Atlas Energy in sponsoring drilling investment partnerships and completing wells for these partnerships. Atlas Energy operates in a highly competitive environment for acquiring undeveloped leasehold acreage and attracting capital. Atlas Energy may not be able to compete successfully in the future in acquiring undeveloped leasehold acreage or in raising additional capital through its drilling investment partnerships. Furthermore, Atlas Energy is not required to connect wells for which it is not the operator to APL’s gathering systems. If Atlas Energy cannot or does not continue to sponsor drilling investment partnerships, if the amount of money raised by those partnerships decreases, or if the number of wells actually drilled and completed as commercially producing wells decreases, the amount of natural gas transported by APL’s Appalachian gathering systems would substantially decrease and could, upon exhaustion of the wells currently connected to APL’s gathering systems, cause APL to abandon one or more of its Appalachian gathering systems, thereby materially reducing APL’s gross margin and cash flows.

The success of APL’s Mid-Continent operations depends upon its ability to continually find and contract for new sources of natural gas supply from unrelated third parties.

Unlike APL’s Appalachian operations, none of the drillers or operators in its Mid-Continent service area is an affiliate of APL. Moreover, APL’s agreements with most of the drillers and operators with which its Mid-Continent operations do business do not require them to dedicate significant amounts of undeveloped acreage to APL’s systems. As a result, APL does not have assured sources to provide it with new wells to connect to its Mid-Continent gathering systems. Failure to connect new wells to APL’s Mid-Continent operations will, as described in “— The amount of natural gas APL transports will decline over time unless it is able to attract new wells to connect to its gathering systems,” above, reduce APL’s gross margin and cash flows.

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APL’s Mid-Continent operations currently depend on certain key producers for their supply of natural gas; the loss of any of these key producers could reduce its revenues.

During 2007, Chesapeake Energy Corporation, Pioneer, Conoco Phillips, Sanguine Gas Exploration, LLC, St. Mary Land and Exploration Company, XTO Energy Inc., Henry Petroleum, L.P. and Senex Pipeline Company supplied APL’s Mid-Continent systems with a majority of their natural gas supply. If these producers reduce the volumes of natural gas that they supply to APL, APL’s gross margin and cash flows would be reduced unless it obtains comparable supplies of natural gas from other producers.

The curtailment of operations at, or closure of, any of APL’s processing plants could harm its business.

If operations at any of APL’s processing plants were to be curtailed, or closed, whether due to accident, natural catastrophe, environmental regulation or for any other reason, APL’s ability to process natural gas from the relevant gathering system and, as a result, its ability to extract and sell NGLs, would be harmed. If this curtailment or stoppage were to extend for more than a short period, APL’s gross margin and cash flows would be materially reduced.

APL may face increased competition in the future in its Mid-Continent service areas.

APL’s Mid-Continent operations may face competition for well connections. Duke Energy Field Services, LLC, ONEOK, Inc., Carrera Gas Company, Cimmarron Transportation, LLC and Enogex, Inc. operate competing gathering systems and processing plants in APL’s Velma service area. In APL’s Elk City and Sweetwater service area, ONEOK Field Services, Eagle Rock Midstream Resources, L.P., Enbridge Energy Partners, L.P., CenterPoint Energy, Inc. and Enogex Inc. operate competing gathering systems and processing plants. CenterPoint Energy, Inc.’s interstate system is the nearest direct competitor to APL’s Ozark Gas Transmission system. CenterPoint and Hiland Partners operate competing gathering systems in Ozark Gas Gathering’s service area. Hiland Partners, DCP Midstream, Mustang Fuel Corporation and ONEOK Partners operate competing gathering systems and processing plants in APL’s Chaney Dell service area. DCP Midstream, J.L. Davis, and Targa Resources operate competing gathering systems and processing plants in APL’s Midkiff/Benedum service area. Some of APL’s competitors have greater financial and other resources than APL does. If these companies become more active in APL’s Mid-Continent service areas, it may not be able to compete successfully with them in securing new well connections or retaining current well connections. If APL does not compete successfully, the amount of natural gas APL transports, processes and treats will decrease, reducing its gross margin and cash flows.

The amount of natural gas APL transports, treats or processes may be reduced if the public utility and interstate pipelines to which APL delivers gas cannot or will not accept the gas.

APL’s gathering systems principally serve as intermediate transportation facilities between sales lines from wells connected to APL’s systems and the public utility or interstate pipelines to which APL delivers natural gas. If one or more of these pipelines has service interruptions, capacity limitations or otherwise does not accept the natural gas APL transports, and APL cannot arrange for delivery to other pipelines, local distribution companies or end users, the amount of natural gas APL transports may be reduced. Since APL’s revenues depend upon the volumes of natural gas it transports, this could result in a material reduction in APL’s gross margin and cash flows.

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:

· the risk that reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;

· mistaken assumptions about revenues and costs, including synergies;

· significant increases in APL’s indebtedness and working capital requirements;

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· an inability to integrate successfully or timely the businesses APL acquires;

· 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, APL’s future acquisition costs may be higher than those it has achieved historically.  Any of these factors could adversely impact APL’s future growth and its ability to increase distributions.

APL may be unsuccessful in integrating the operations from its recent acquisitions or any future acquisitions with its operations and in realizing all of the anticipated benefits of these acquisitions.

APL acquired the Chaney Dell and the Midkiff/Benedum systems in July 2007 and is currently in the process of integrating their operations with their own. APL also has an active, on-going program to identify other potential acquisitions. APL’s integration of previously independent operations with its own can be a complex, costly and time-consuming process. The difficulties of combining these systems with its existing systems, as well as any operations APL may acquire in the future, include, among other things:

· operating a significantly larger combined entity;

· 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 APL’s indebtedness; and

· potential environmental or regulatory liabilities and title problems.

APL acquired the Chaney Dell and Midkiff/Benedum systems with the expectation that combining them with its existing operations will result in benefits, including, among other things, benefits from organic growth and synergies, increased scale and presence in the Mid-Continent area, expansion of relationships with top producers and increased geographic diversification. There can be no assurance that APL will realize any of these benefits or that the acquisition will not result in the deterioration or loss of its business. In addition, APL investment in the interconnection of its Elk City/Sweetwater and Chaney Dell systems and the additional overhead costs APL incurs to grow its NGL business may not deliver the expected incremental volume or cash flow. Costs incurred and liabilities assumed in connection with the acquisition and increased capital expenditures and overhead costs incurred to expand APL’s operations could harm its business or future prospects, and result in significant decreases in APL’s gross margin and cash flows.

The acquisitions of APL’s Chaney Dell and Midkiff/Benedum systems have substantially changed APL’s business, making it difficult to evaluate its business based upon its historical financial information.

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The acquisitions of APL’s Chaney Dell and Midkiff/Benedum systems have significantly increased its size and substantially redefined APL’s business plan, expanded its geographic market and resulted in large changes to its revenues and expenses. As a result of this acquisition, and APL’s continued plan to acquire and integrate additional companies that it believes presents attractive opportunities, APL’s financial results for any period or changes in its results across periods may continue to dramatically change. APL’s historical financial results, therefore, should not be relied upon to accurately predict its future operating results, thereby making the evaluation of its business more difficult.

Due to APL’s lack of asset diversification, negative developments in its operations would reduce its ability to make distributions to its common unitholders.

APL relies exclusively on the revenues generated from its transportation, gathering and processing operations, and as a result, its financial condition depends upon prices of, and continued demand for, natural gas and NGLs. Due to APL’s lack of asset-type diversification, a negative development in one of these businesses would have a significantly greater impact on its financial condition and results of operations than if APL maintained more diverse assets.

APL’s construction of new assets may not result in revenue increases and is subject to regulatory, environmental, political, legal and economic risks, which could impair its results of operations and financial condition.

One of the ways APL may grow its business is through the construction of new assets, such as the Sweetwater plant. The construction of additions or modifications to its existing systems and facilities, and the construction of new assets, involve numerous regulatory, environmental, political and legal uncertainties beyond APL’s control and require the expenditure of significant amounts of capital. Any projects APL undertakes may not be completed on schedule at the budgeted cost, or at all. Moreover, APL’s revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if APL expands a gathering system, the construction may occur over an extended period of time, and it will not receive any material increases in revenues until the project is completed. Moreover, APL may construct facilities to capture anticipated future growth in production in a region in which growth does not materialize. Since APL is not engaged in the exploration for and development of natural gas reserves, it often does not have access to estimates of potential reserves in an area before constructing facilities in the area. To the extent APL relies on estimates of future production in its decision to construct additions to its systems, the estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract enough throughput to achieve APL’s expected investment return, which could impair its results of operations and financial condition. In addition, APL’s actual revenues from a project could materially differ from expectations as a result of the price of natural gas, the NGL content of the natural gas processed and other economic factors described in this section.

If APL is unable to obtain new rights-of-way or the cost of renewing existing rights-of-way increases, then it may be unable to fully execute its growth strategy and its cash flows could be reduced.

The construction of additions to APL’s existing gathering assets may require it to obtain new rights-of-way before constructing new pipelines. APL may be unable to obtain rights-of-way to connect new natural gas supplies to its existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for APL to obtain new rights-of-way or to renew existing rights-of-way. If the cost of obtaining new rights-of-way or renewing existing rights-of-way increases, then its cash flows could be reduced.

Regulation of APL’s gathering operations could increase its operating costs, decrease its revenues, or both.

Currently APL’s gathering of natural gas from wells is exempt from regulation under the Natural Gas Act. However, the implementation of new laws or policies, or interpretations of existing laws, could subject APL to regulation by FERC under the Natural Gas Act. APL expects that any such regulation would increase its costs, decrease its gross margin and cash flows, or both.

Nonetheless, FERC regulation will still affect APL’s business and the market for its products. FERC’s policies and practices affect a range of APL’s natural gas pipeline activities, including, for example, its policies on open access transportation, ratemaking, capacity release, and market center promotion, which indirectly affect intrastate markets. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, APL cannot ensure that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity.

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Since federal law generally leaves any economic regulation of natural gas gathering to the states, state and local regulations may also affect APL’s business. Matters subject to regulation include access, rates, terms of service and safety. For example, APL’s gathering lines are subject to ratable take, common purchaser and similar statutes in one or more jurisdictions in which APL operates. Common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer, while ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Texas and Oklahoma have adopted complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and discrimination with respect to rates or terms of service. Should a complaint be filed or regulation by the Texas Railroad Commission or Oklahoma Corporation Commission become more active, APL’s revenues could decrease. Collectively, all of these statutes restrict APL’s right as an owner of gathering facilities to decide with whom it contracts to purchase or transports natural gas.

Increased regulatory requirements relating to the integrity of the Ozark Transmission pipeline will require it to spend additional money to comply with these requirements. In particular, Ozark Gas Transmission is subject to extensive laws and regulations related to pipeline integrity. Federal legislation signed into law in December 2002 includes guidelines for the U.S. Department of Transportation and pipeline companies in the areas of testing, education, training and communication. Compliance with existing and recently enacted regulations requires significant expenditures. Additional laws and regulations that may be enacted in the future, such as U.S. Department of Transportation implementation of additional hydrostatic testing requirements, could significantly increase the amount of these expenditures.

Ozark Gas Transmission is subject to FERC rate-making policies that could have an adverse impact on APL’s ability to establish rates that would allow it to recover the full cost of operating the pipeline.

Rate-making policies by FERC could affect Ozark Gas Transmission’s ability to establish rates, or to charge rates that would cover future increases in its costs, or even to continue to collect rates that cover current costs. Natural gas companies may not charge rates that have been determined not to be just and reasonable by FERC. The rates, terms and conditions of service provided by natural gas companies are required to be on file with FERC in FERC-approved tariffs. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. APL cannot ensure that FERC will continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas capacity and transportation facilities. Any successful complaint or protest against Ozark Gas Transmission’s rates could reduce APL’s revenues associated with providing transmission services. APL cannot ensure you that it will be able to recover all of Ozark Gas Transmission’s costs through existing or future rates.

Ozark Gas Transmission is subject to regulation by FERC in addition to FERC rules and regulations related to the rates it can charge for its services.

FERC’s regulatory authority also extends to:

· operating terms and conditions of service;

· the types of services Ozark Gas Transmission’s may offer to its customers;

· construction of new facilities;

· acquisition, extension or abandonment of services or facilities;

· accounts and records; and

· relationships with affiliated companies involved in all aspects of the natural gas and energy businesses.

FERC action in any of these areas or modifications of its current regulations can impair Ozark Gas Transmission’s ability to compete for business, the costs it incurs in its operations, the construction of new facilities or its ability to recover the full cost of operating its pipeline. For example, the development of uniform interstate gas quality standards by FERC could create two distinct markets for natural gas--an interstate market subject to uniform minimum quality standards and an intrastate market with no uniform minimum quality standards. Such a bifurcation of markets could make it difficult for APL’s pipelines to compete in both markets or to attract certain gas supplies away from the intrastate market. The time FERC takes to approve the construction of new facilities could raise the costs of APL’s projects to the point where they are no longer economic.

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FERC has authority to review pipeline contracts. If FERC determines that a term of any such contract deviates in a material manner from a pipeline’s tariff, FERC typically will order the pipeline to remove the term from the contract and execute and refile a new contract with FERC or, alternatively, to amend its tariff to include the deviating term, thereby offering it to all shippers. If FERC audits a pipeline’s contracts and finds deviations that appear to be unduly discriminatory, FERC could conduct a formal enforcement investigation, resulting in serious penalties and/or onerous ongoing compliance obligations.

Should Ozark Gas Transmission’s fail to comply with all applicable FERC administered statutes, rules, regulations and orders, it could be subject to substantial penalties and fines. Under the recently enacted Energy Policy Act, FERC has civil penalty authority under the Natural Gas Act to impose penalties for current violations of up to $1,000,000 per day for each violation.

Finally, APL cannot give any assurance regarding the likely future regulations under which APL will operate Ozark Gas Transmission or the effect such regulation could have on its business, financial condition, and results of operations.

Compliance with pipeline integrity regulations issued by the DOT and state agencies could result in substantial expenditures for testing, repairs and replacement.

DOT and state agency regulations require pipeline operators to develop integrity management programs for transportation pipelines located in “high consequence areas.” The regulations require operators to:

· perform ongoing assessments of pipeline integrity;

· identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

· improve data collection, integration and analysis;

· repair and remediate the pipeline as necessary; and

· implement preventative and mitigating actions.

APL does not believe that the cost of implementing integrity management program testing along certain segments of APL’s pipeline will have a material effect on its results of operations. This does not include the costs, if any, of any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which costs could be substantial.

APL’s midstream natural gas operations may incur significant costs and liabilities resulting from a failure to comply with new or existing environmental regulations or a release of hazardous substances into the environment.

The operations of APL’s gathering systems, plant and other facilities are subject to stringent and complex federal, state and local environmental laws and regulations. These laws and regulations can restrict or impact APL’s business activities in many ways, including restricting the manner in which it disposes of substances, requiring remedial action to remove or mitigate contamination, and requiring capital expenditures to comply with control requirements. 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 impose strict, joint and several liability for costs required to clean up and restore sites where substances and wastes have been disposed 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 substances or wastes into the environment.

There is inherent risk of the incurrence of environmental costs and liabilities in APL’s business due to its handling of natural gas and other petroleum products, air emissions related to APL’s operations, historical industry operations including releases of substances into the environment, and waste disposal practices. For example, an accidental release from one of APL’s pipelines or processing facilities could subject it to substantial liabilities arising from environmental cleanup, restoration costs and natural resource damages, 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 could significantly increase APL’s compliance costs and the cost of any remediation that may become necessary. APL may not be able to recover some or any of these costs from insurance.

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APL may not be able to execute its growth strategy successfully.

APL’s strategy contemplates substantial growth through both the acquisition of other gathering systems and processing assets and the expansion of its existing gathering systems and processing assets. APL’s growth strategy involves numerous risks, including:

· APL may not be able to identify suitable acquisition candidates;

· APL may not be able to make acquisitions on economically acceptable terms for various reasons, including limitations on access to capital and increased competition for a limited pool of suitable assets;

· APL’s costs in seeking to make acquisitions may be material, even if it cannot complete any acquisition it has pursued;

· irrespective of estimates at the time it makes an acquisition, the acquisition may prove to be dilutive to earnings and operating surplus;

· APL may encounter difficulties in integrating operations and systems; and

· any additional debt APL incurs to finance an acquisition may impair its ability to service its existing debt.

Limitations on APL’s access to capital or the market for its common units will impair APL’s ability to execute its growth strategy.

APL’s ability to raise capital for acquisitions and other capital expenditures depends upon ready access to the capital markets. Historically, APL has financed its acquisitions, and to a much lesser extent, expansions of its gathering systems by bank credit facilities and the proceeds of public and private equity offerings of its common units and preferred units of its operating partnership. If APL is unable to access the capital markets, it may be unable to execute its strategy of growth through acquisitions.

APL’s hedging strategies may fail to protect it and could reduce its gross margin and cash flow.

APL pursues various hedging strategies to seek to reduce its exposure to losses from adverse changes in the prices for natural gas and NGLs. APL’s hedging activities will vary in scope based upon the level and volatility of natural gas and NGL prices and other changing market conditions. APL’s hedging activity may fail to protect or could harm it because, among other things:

· hedging can be expensive, particularly during periods of volatile prices;

· available hedges may not correspond directly with the risks against which APL seeks protection;

· the duration of the hedge may not match the duration of the risk against which APL seeks protection; and

· the party owing money in the hedging transaction may default on its obligation to pay.

Litigation or governmental regulation relating to environmental protection and operational safety may result in substantial costs and liabilities.

APL’s operations are subject to federal and state environmental laws under which owners of natural gas pipelines can be liable for clean-up costs and fines in connection with any pollution caused by their pipelines. APL may also be held liable for clean-up costs resulting from pollution which occurred before its acquisition of the gathering systems. In addition, APL is subject to federal and state safety laws that dictate the type of pipeline, quality of pipe protection, depth, methods of welding and other construction-related standards. Any violation of environmental, construction or safety laws could impose substantial liabilities and costs on APL.

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APL is also subject to the requirements of OSHA and comparable state statutes. Any violation of OSHA could impose substantial costs on APL.

APL cannot predict whether or in what form any new legislation or regulatory requirements might be enacted or adopted, nor can APL predict its costs of compliance. In general, APL expects that new regulations would increase its operating costs and, possibly, require it to obtain additional capital to pay for improvements or other compliance action necessitated by those regulations.

APL is subject to operating and litigation risks that may not be covered by insurance.

APL’s operations are subject to all operating hazards and risks incidental to transporting and processing natural gas and NGLs. These hazards include:

· damage to pipelines, plants, related equipment and surrounding properties caused by floods and other natural disasters;

· inadvertent damage from construction and farm equipment;

· leakage of natural gas, NGLs and other hydrocarbons;

· fires and explosions;

· other hazards, including those associated with high-sulfur content, or sour gas, that could also result in personal injury and loss of life, pollution and suspension of operations; and

· acts of terrorism directed at APL’s pipeline infrastructure, production facilities, transmission and distribution facilities and surrounding properties.

As a result, APL may be a defendant in various legal proceedings and litigation arising from its operations. APL may not be able to maintain or obtain insurance of the type and amount desired at reasonable rates. As a result of market conditions, premiums and deductibles for some of APL’s insurance policies have increased substantially, and could escalate further. In some instances, insurance could become unavailable or available only for reduced amounts of coverage. For example, insurance carriers are now requiring broad exclusions for losses due to war risk and terrorist acts. If APL were to incur a significant liability for which it was not fully insured, its gross margin and cash flows would be materially reduced.

ITEM 1B: UNRESOLVED STAFF COMMENTS

None

ITEM 2: PROPERTIES

Office Properties

Atlas Energy leases a 27,000 square foot office building in Moon Township, Pennsylvania. Atlas Energy owns a 17,000 square foot field office and warehouse facility in Jackson Center, Pennsylvania, and a 24,000 square foot office in Fayette County, Pennsylvania and a field office in Deerfield, Ohio. Atlas Energy leases a 13,800 square foot office building in Traverse City, Michigan, which expires in 2012, and a 1,400 square foot field office in Ohio expiring in 2009. It also rents 17,200 square feet of office space in Uniontown, Ohio under a lease expiring in August 30, 2008. In addition, Atlas Energy leases other field offices in Ohio and New York on a month-to-month basis. APL leases 37,100 square feet of office space in Tulsa, Oklahoma through November 2009.

Atlas Energy

We owned the properties discussed below until we transferred them on December 18, 2006 to Atlas Energy. Accordingly, we refer to them as Atlas Energy’s properties even though we owned them before that date.

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Natural Gas and Oil Reserves

The following tables summarize information regarding Atlas Energy’s 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 Atlas Energy’s direct ownership interests in oil and gas properties as well as the reserves attributable to its percentage interests in the oil and gas properties owned by investment partnerships in which Atlas Energy owns partnership interests. All of the reserves are located in the United States. Atlas Energy bases 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, Atlas Energy makes 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. Atlas Energy bases its estimates of proved reserves upon the following weighted average prices as of the dates indicated:

		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 Wright & Company in preparing its reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, the reserves set forth in the following tables ultimately may not be produced and the proved undeveloped reserves may not be developed within the periods anticipated. Please read Item 1A, “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.

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

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		Proved natural gas and oil reserves for						Proved natural gas and oil reserves for Atlas America E & P
		Atlas Energy Resources at						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):
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 (2)		$	1,481,178		$	283,441		$	597,137		$	845,651
Standardized measure of
discounted future cash flows
(in thousands) (2)		$	1,144,990		$	205,520		$	429,272		$	606,697

(1) Atlas Energy’s ownership in these reserves is subject to reduction as it generally contributes leasehold acreage associated with its proved undeveloped reserves to its investment partnerships in exchange for an approximate 30% equity interest in these partnerships, which effectively will reduce Atlas Energy’s ownership interest in these reserves from 100% to 30% as it make these contributions.

(2) The following reconciles the PV-10 value to the standardized measure:

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			Proved natural gas  and oil reserves for Atlas Energy Resources at						Proved natural gas  and oil reserves for 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			(336,188	)		(77,921	)		(167,865	)		(238,954	)
Standardized measure		$	1,144,990		$	205,520		$	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 Atlas Energy has 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 Atlas Energy has an interest, directly or through its ownership interests in investment partnerships, and net wells are the sum of its fractional working interests in gross wells, based on the percentage interest Atlas Energy owns 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 Atlas Energy’s proportionate interest in wells owned by 92 investment partnerships for which Atlas Energy serves 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.

			Production						Average sales price						Average production
Period			Oil (Bbls)			Gas (Mcf)			per Bbl			per Mcf (1)			cost per Mcfe (2)
Year ended December 31, 2007			153,465			20,963,436		$	70.16		$	8.08		$	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		$	0.95

(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. Atlas Energy 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.

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Developed and Undeveloped Acreage

The following table sets forth information about Atlas Energy’s developed and undeveloped natural gas and oil acreage as of December 31, 2007. The information in this table includes Atlas Energy’s proportionate interest in acreage owned by its investment partnerships. The table does not include the approximately 212,000 acres in Tennessee covered by Atlas Energy’s joint venture with Knox Energy because Atlas Energy does 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 Atlas Energy owns an interest. The number of gross acres is the total number of acres in which Atlas Energy owns 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 Atlas Energy’s developed acreage generally have terms that extend for the life of the wells, while the leases on Atlas Energy’s undeveloped acreage have terms that vary from less than one year to five years. Atlas Energy paid rentals of approximately $2.4 million in fiscal 2007 to maintain its leases.

Atlas Energy believes that it holds good and indefeasible title to its producing properties, in accordance with standards generally accepted in the natural gas industry, subject to exceptions stated in the opinions of counsel employed by Atlas Energy in the various areas in which it conducts its activities. Atlas Energy does not believe that these exceptions detract substantially from its use of any property. As is customary in the natural gas industry, Atlas Energy conducts only a perfunctory title examination at the time it acquires a property. Before it commences drilling operations, Atlas Energy conducts an extensive title examination and performs curative work on defects that it deems significant. Atlas Energy has obtained title examinations for substantially all of its managed producing properties. No single property represents a material portion of Atlas Energy’s holdings.

Atlas Energy’s properties are subject to royalty, overriding royalty and other outstanding interests customary in the industry. Atlas Energy’s 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. Atlas Energy does not believe that any of these burdens will materially interfere with its use of its properties.

Drilling Activity

The number of wells Atlas Energy drills will vary depending on the amount of money it raises through its 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 Atlas Energy has completed drilling during the periods indicated, regardless of when it initiated drilling

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		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 Atlas Energy holds any working interest, regardless of its percentage interest.

(2) Includes (i) Atlas Energy’s percentage interest in wells in which it has a direct ownership interest and (ii) with respect to wells in which it has an indirect ownership interest through its investment partnerships, Atlas Energy’s percentage interest in the wells based on its percentage interest in its investment partnerships and not those of the other partners in Atlas Energy’s investment partnerships.

Atlas Pipeline and Atlas Pipeline Holdings

A description of APL’s and AHD’s properties is contained within Item 1, “Business”.

ITEM 3: LEGAL PROCEEDINGS

We, Atlas Energy, Atlas Pipeline Holdings, and Atlas Pipeline and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of our collective business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations.

ITEM 4: SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Not applicable

PART II

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

Our common stock is listed for trading on The NASDAQ Stock Market under the symbol “ATLS.” The following table sets forth, for the fiscal quarters indicated, the high and low sales prices per share as reported on The NASDAQ Stock Market. The quarterly share prices have been adjusted to reflect the 3-for-2 stock splits on March 10, 2006 and May 25, 2007.

								Cash Dividends
		High			Low			Declared
Fiscal year ended December 31, 2006
First quarter		$	32.77		$	27.57		$	—
Second quarter			35.43			26.74			—
Third quarter			31.82			27.67			—
Fourth quarter			34.68			26.85			—
Fiscal year ended December 31, 2007
First quarter			38.44			32.32			—
Second quarter			58.15			37.67			0.05
Third quarter			57.43			44.05			0.05
Fourth quarter			62.83			51.01			0.05

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As of February 11, 2008, there were 26,881,246 shares of common stock outstanding held by 261 holders of record.

On April 27, 2007, our Board of Directors approved a three-for-two stock split effected in the form of a 50% stock dividend. Shareholders of record as of May 15, 2007, received one additional share of common stock for each two shares of common stock they owned on that date. The shares were distributed on April 25, 2007, and the adjusted per share stock price was reported by the NASDAQ Stock Market, effective May 28, 2007.

For information concerning common stock authorized for issuance under our stock incentive plan, see Item 12: Security Ownership or Certain Beneficial Owners and Management - Equity Compensation Plan Information.

ITEM 6. SELECTED FINANCIAL DATA

In June 2006, we changed our year end to December 31 from September 30 and therefore information below includes our transition period, the three months ended December 31, 2005, and our new year ended December 31.

The following table sets forth selected financial data as of and for the years ended September 30, 2003 through 2005, the three months ended December 31, 2005 and the years ended December 31, 2006 and 2007. We derived the financial data as of December 31, 2007 and 2006 and for the years ended December 31, 2007 and 2006, three months ended December 31, 2005 and year ended September 30, 2005 from our financial statements, which were audited by Grant Thornton LLP, independent accountants, and are included in this report. We derived the financial data as of December 31, 2005, September 30, 2005, 2004 and 2003 and for the year ended September 30, 2003 from our financial statements, which were audited by Grant Thornton LLP, and are not included in this report.

			Years Ended December 31,						Three Months Ended December 31,			Years Ended September 30,
			2007			2006			2005			2005			2004			2003
			(in thousands, except per share data)
Revenues		$	1,207,647		$	749,306		$	200,496		$	481,980		$	186,460		$	110,143
Income from continuing operations
before cumulative effect of
accounting change			35,336			42,022			11,724			32,940			21,187			13,720
Net income			35,336			45,847			11,724			32,940			21,187			13,912
Basic net income per share from
continuing operations before
cumulative effect of accounting
change		$	1.30		$	1.42		$	0.39		$	1.10		$	0.81		$	0.57
Diluted net income per share from
continuing operations before
cumulative effect of accounting
change		$	1.25		$	1.39		$	0.39		$	1.10		$	0.81		$	0.57

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		Years Ended December 31,						Three Months Ended December 31,			Years Ended September 30,
		2007			2006			2005			2005			2004			2003
		(in thousands, except per share data)
Other financial information:
Net cash provided by operating
activities		$	203,219		$	42,324		$	52,769		$	112,045		$	50,043		$	44,941
Capital expenditures		$	349,625		$	159,466		$	31,809		$	99,185		$	41,162		$	28,029
EBITDA (1)		$	250,506		$	142,286		$	35,081		$	89,320		$	50,177		$	34,033

Balance sheet data:
Total assets		$	4,906,529		$	1,379,838		$	1,056,180		$	759,711		$	423,709		$	232,388
Total debt		$	1,994,456		$	324,151		$	298,781		$	191,727		$	85,640		$	31,194
Stockholders’ equity		$	413,163		$	271,341		$	132,850		$	120,351		$	91,003		$	87,511

(1) We define EBITDA as earnings before interest, taxes, depreciation, depletion and amortization. EBITDA is not a measure of performance calculated in accordance with accounting principles generally accepted in the United States, or GAAP. Although not prescribed under GAAP, we believe the presentation of EBITDA is relevant and useful because it helps our investors to understand our operating performance and makes it easier to compare our results with other companies that have different financing and capital structures or tax rates. EBITDA should not be considered in isolation 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 is different from the EBITDA calculation under our various credit facilities. In addition, EBITDA does not represent funds available for discretionary use. The following reconciles EBITDA to our income from continuing operations for the periods indicated.

			Years Ended December 31,						Three Months Ended December 31,			Years Ended September 30,
			2007			2006			2005			2005			2004			2003
			(in thousands)
Income from continuing operations before cumulative effect of accounting change		$	35,336		$	42,022		$	11,724		$	32,940		$	21,187		$	13,720
Plus interest expense			92,611			27,313			6,147			11,467			2,881			1,961
Plus income taxes			14,642			27,308			6,886			20,018			11,409			6,757
Plus depreciation, depletion and amortization			107,917			45,643			10,324			24,895			14,700			11,595
EBITDA		$	250,506		$	142,286		$	35,081		$	89,320		$	50,177		$	34,033

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

Overview of Years Ended December 31, 2007 and 2006, Three Months Ended December 31, 2005 and Year Ended September 30, 2005

Manner of Presentation

In the discussion that follows, we present a comparative analysis for the years ended December 31, 2007 and 2006 and a discussion of the three-month transitional period ended December 31, 2005 and the year ended September 30, 2005, rather than a year-to-year analysis for the three year period covered by our financial statements for two reasons:

·   During fiscal 2007, both ATN and APL made acquisitions that were transformative to their and our business. On June 29, 2007, ATN acquired DTE Gas & Oil, now Atlas Gas & Oil, from DTE for $1.273 billion, including related expenses. The acquisition more than quadrupling ATN’s proved reserve base to 801.7 Bcfe and tripling its average net daily production to approximately 88 Mmcfe. On July 27, 2007, APL acquired control of Anadarko Petroleum Corporation’s 100% interest in the Chaney Dell natural gas gathering system and processing plants located in Oklahoma and its 72.8% undivided joint venture interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (the “Anadarko Assets”). The Chaney Dell system includes 3,470 miles of gathering pipeline and three processing plants, while the Midkiff/Benedum system includes 2,500 miles of gathering pipeline and two processing plants. The transaction was effected by the formation of two joint venture companies which own the respective systems, to which APL contributed $1.9 billion and Anadarko contributed the Anadarko Assets. Largely as a result of these acquisitions, our property and equipment, net, increased from $884.8 million at December 31, 2006 to $3.4 billion at December 31, 2007, and our total assets increased from $1.4 billion at December 31, 2006 to $4.9 billion at December 31, 2007.

·   On June 15, 2006, our Board of Directors changed our 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.

As a result of these events, management believes that the manner of presentation adopted below provides a more meaningful analysis of our financial condition, changes in financial condition and results of operations.

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Other Corporate Events

 Restructuring. In December 2006, we contributed substantially all of our Appalachian natural gas and oil assets and our investment partnership management business to Atlas Energy, our then wholly-owned subsidiary. Concurrent with this transaction, Atlas Energy issued 7,273,750 common units, representing a 19.5% ownership interest, in an initial public offering at a price of $21.00 per unit. The net proceeds of approximately $139.9 million, after underwriting discounts and commissions were distributed to us. After completion of the offering, we have an approximate 78.5% ownership interest in Atlas Energy. Additionally, we own Atlas Energy Management, which owns 2% of the membership interests and all of the management incentive interests in Atlas Energy.

In July 2006, we contributed our ownership interests in Atlas Pipeline GP, our then wholly-owned subsidiary, and the general partner of Atlas Pipeline Partners to AHD. Concurrent with this transaction, AHD issued 3,600,000 common units representing a 17.1% ownership interest in it, in an initial public offering at a price of $23.00 per unit. The net proceeds of approximately $74.3 million after underwriting discounts and commissions were distributed to us.

As a result of this restructuring, our assets currently consist principally of cash and of the following ownership interests:

·   ATN: All of the outstanding Class A units, representing 1,238,986 units at December 31, 2007, which entitle us to receive 2% of the cash distributed by ATN without any obligation to make future capital contributions to ATN; all of the management incentive interests, which entitle us to receive increasing percentages, up to a maximum of 25.0%, of any cash distributed by ATN as it reaches certain target distribution levels after it has met the tests set forth in its limited liability company agreement; and 29,352,996 common units, representing approximately 48.3% of the outstanding common units at December 31, 2007, or a 49.4% ownership interest in ATN.

·   AHD: 17,500,000 common units, representing approximately 64.0% of the outstanding common units of AHD at December 31, 2007. AHD’s general partner, which is a wholly-owned subsidiary of ours, does not have an economic interest in AHD, and AHD’s capital structure does not include incentive distribution rights. AHD’s ownership interest in APL consists of the following:

·   a 2.0% general partner interest, which entitles it to receive 2% of the cash distributed by APL;

·   all of the incentive distribution rights, which entitle it to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed by APL as it reaches certain target distribution levels. In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems, AHD agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter (“IDR Adjustment Agreement”); and

·   5,476,253 common units, representing approximately 14.1% of the outstanding common units at December 31, 2007, or a 13.5% ownership interest in APL.

In addition, We have an approximate 18% ownership interest in Lightfoot GP, the general partner of Lightfoot, which incubates new MLPs and invests in existing MLPs. We are committed to invest a total of $20.0 million in Lightfoot.

Spin-off by Resource America. On June 30, 2005, Resource America distributed the remaining 10.7 million shares it owned in us to its stockholders in the form of a tax-free dividend. Each Resource America stockholder received 0.59367 of a share of our common stock for each share of Resource America common stock owned on June 24, 2005, the record date. Although the distribution itself was tax-free to Resource America’s stockholders, as a result of the deconsolidation there may be some tax liability arising from prior unrelated corporate transactions among us and some of our subsidiaries. We anticipate that all or a portion of any liability arising from this transaction may be paid by us to Resource America. In addition, we were required to make a non-recurring income tax payment, payable to Resource America, of $1.2 million associated with the spin-off.

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In July 2006, we contributed our ownership interests in Atlas Pipeline Partners, GP, LLC, or Atlas Pipeline GP, our then wholly-owned subsidiary, and the general partner of Atlas Pipeline Partners to AHD. Concurrent with this transaction, AHD issued 3,600,000 common units representing a 17.1% ownership interest in it, in an initial public offering at a price of $23.00 per unit. The net proceeds of approximately $74.3 million after underwriting discounts and commissions were distributed to us.

Atlas Energy

ATN is an independent developer and producer of natural gas and oil, with operations in northern Michigan’s Antrim Shale and the Appalachian Basin region of the United States, principally in western New York, eastern Ohio, western Pennsylvania and Tennessee. ATN is also a leading sponsor and manager of tax-advantaged direct investment natural gas and oil partnerships in the United States. ATN funds the drilling of natural gas and oil wells on its acreage by sponsoring and managing tax advantaged investment partnerships. It generally structures its investment partnerships so that, upon formation of a partnership, ATN co-invests in and contributes leasehold acreage to it, enters into drilling and well operating agreements with it and becomes its managing general partner. ATN is managed by Atlas Energy Management, our wholly-owned subsidiary, through which we provide ATN with the personnel necessary to manage its assets and raise capital.

As of and for the year ended December 31, 2007, ATN had the following key assets:

Appalachia gas and oil operations

· proved reserves of 229.9 Bcfe including the reserves net to ATN’s equity interest in its investment partnerships and ATN’s 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 ATN the right to drill up to 77 additional net wells before March 31, 2008 on approximately 212,000 acres in Tennessee.

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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.

Partnership management business

· ATN investment partnership business, which includes equity interests in 92 investment partnerships and a registered broker-dealer which acts as the dealer-manager of ATN’s investment partnership offerings; and

· managed total proved reserves of 503.7 Bcfe.

Recent Developments

Acquisition of DTE Antrim assets. On June 29, 2007, ATN acquired DTE Gas & Oil Company, now Atlas Gas & Oil Company, from DTE for $1.273 billion, including related expenses. At June 30, 2007, Atlas Gas & Oil owned interests in approximately 2,210 natural gas wells producing from the Antrim Shale, located in Michigan’s northern lower peninsula. The Antrim Shale is a mature play characterized by long-lived reserves and predictable production rates. Atlas Gas & Oil had 610.6 Bcfe of proved reserves. In order to produce methane from the Antrim Shale, water must be drawn off first, a process that takes 3 to 12 months. As a result, ATN does not believe its Michigan business unit wells are compatible with its investment partnerships, and intends to drill those wells for its own account.

Private equity offering. ATN 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, of 7,298,181 Class B common units at a weighted average price of $25.00 for net proceeds of $597.5 million. 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 covering the resale of these units became effective.

New credit facility. Upon the closing of the DTE Gas & Oil acquisition, ATN replaced its credit facility with a new 5-year, $850.0 million credit facility administered by JPMorgan Chase Bank, N.A. The credit facility has a current borrowing base of $735.0 million, which will be redetermined semi-annually on April 1 and October 1 subject to changes in our oil and gas reserves. The facility is secured by ATN’s 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 7.3%.

Private debt offering. In January 2008, Atlas Energy issued $250.0 million of 10-year, 10.75% senior unsecured notes due 2018. It used the proceeds of the note offering to reduce the balance outstanding on its 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, Atlas Energy 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 it 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 it does not reinvest the net proceeds within 360 days. The senior notes are junior in right of payment to Atlas Energy’s secured debt, including its obligations under its credit facility. The indenture governing the senior notes contains covenants, including limitations of Atlas Energy’s 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, Atlas Energy entered into an interest rate swap contract for $150 million, swapping the floating rate incurred on a portion of its 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 its new senior notes, Atlas Energy has fixed $400 million of its outstanding debt at a weighted average interest rate of approximately 8.35%.

Atlas Pipeline Holdings and Atlas Pipeline

General

AHD’s cash generating assets currently consist solely of its interests in APL.

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APL is a publicly-traded midstream energy services provider engaged in the transmission, gathering and processing of natural gas. APL is a leading provider of natural gas gathering services in the Anadarko, Arkoma, Golden Trend and Permian Basins in the southwestern and mid-continent United States and the Appalachian Basin in the eastern United States. In addition, APL is a leading provider of natural gas processing services in Oklahoma and Texas. APL also provides interstate gas transmission services in southeastern Oklahoma, Arkansas and southeastern Missouri. APL conducts its business through two operating segments: its Mid-Continent operations and its Appalachian operations.

Through its Mid-Continent operations, APL owns and operates:

· a Federal Energy Regulatory Commission (“FERC”)-regulated, 565-mile interstate pipeline system (“Ozark Gas Transmission”), that extends from southeastern Oklahoma through Arkansas and into southeastern Missouri and has throughput capacity of approximately 400 million cubic feet per day (“MMcfd”);

· seven natural gas processing plants with aggregate capacity of approximately 750 MMcfd and one treating facility with a capacity of approximately 200 MMcfd, located in Oklahoma and Texas; and

· 7,870 miles of active natural gas gathering systems located in Oklahoma, Arkansas and Texas, which transport gas from wells and central delivery points in the Mid-Continent region to APL’s natural gas processing plants or Ozark Gas Transmission.

Through its Appalachian operations, APL owns and operates 1,600 miles of active natural gas gathering systems located in eastern Ohio, western New York and western Pennsylvania. Through an omnibus agreement and other agreements between us, APL and ATN, APL gathers substantially all of the natural gas for its Appalachian Basin operations from wells operated by ATN. Among other things, the omnibus agreement requires ATN to connect to APL’s gathering systems wells it operates that are located within 2,500 feet of APL’s gathering systems. APL is also a party to natural gas gathering agreements with us and ATN under which it receives gathering fees generally equal to a percentage, typically 16%, of the selling price of the natural gas it transports.

Since APL’s initial public offering in January 2000, it has completed seven acquisitions at an aggregate purchase price of approximately $2.4 billion, including, most recently:

· On July 27, 2007, APL acquired control of Anadarko’s 100% interest in the Chaney Dell natural gas gathering system and processing plants located in Oklahoma and its 72.8% undivided joint venture interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas. The Chaney Dell system includes 3,470 miles of gathering pipeline and three processing plants, while the Midkiff/Benedum system includes 2,500 miles of gathering pipeline and two processing plants. The transaction was effected by the formation of two joint venture companies which own the respective systems, to which APL contributed $1.9 billion and Anadarko contributed the Anadarko Assets. In connection with this acquisition, APL reached an agreement with Pioneer Natural Resources Company (“Pioneer” - NYSE: PXD), which currently holds an approximate 27.2% undivided joint venture interest in the Midkiff/Benedum system, whereby Pioneer will have an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system on June 15, 2008, and up to an additional 7.4% interest on June 15, 2009. If the option is fully exercised, Pioneer would increase its interest in the system to approximately 49.2%. Pioneer would pay approximately $230 million, subject to certain adjustments, for the additional 22% interest if fully exercised. APL will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercised the purchase options. APL funded the purchase price in part from its private placement of $1.125 billion of its common units to investors at a negotiated purchase price of $44.00 per unit. Of the $1.125 billion, AHD purchased $168.8 million of these APL units, which was funded through AHD’s issuance of 6.25 million common units in a private placement at a negotiated purchase price of $27.00 per unit. AHD, as general partner and holder of all of APL’s incentive distribution rights, has also agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. APL funded the remaining purchase price from an $830.0 million senior secured term loan which matures in July 2014 and a new $300.0 million senior secured revolving credit facility that matures in July 2013; and

· In May 2006, APL acquired the remaining 25% ownership interest in NOARK Pipeline System, Limited Partnership (“NOARK”) from Southwestern Energy Company (“Southwestern”) for a net purchase price of $65.5 million, consisting of $69.0 million in cash to the seller, (including the repayment of the $39.0 million of outstanding NOARK notes at the date of acquisition), less the seller’s interest in working capital at the date of acquisition of $3.5 million. In October 2005, APL acquired from Enogex, a wholly-owned subsidiary of OGE Energy Corp., all of the outstanding equity of Atlas Arkansas, which owned the initial 75% ownership interest in NOARK, for $163.0 million, plus $16.8 million for working capital adjustments and related transaction costs. NOARK’s principal assets include the Ozark Gas Transmission system, a 565-mile interstate natural gas pipeline, and Ozark Gas Gathering, a 365-mile natural gas gathering system.

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Exploration and Development - Atlas Energy

Gas and Oil Production

The following table sets forth information relating to our consolidated production revenues, production volumes, sales prices, production costs and depletion for our operations during the periods indicated:

		Years Ended December 31,						Three Months Ended December 31			Year Ended September 30,
		2007			2006			2005			2005
Production revenues (in thousands):
Gas (1)(6)		$	169,314		$	79,016		$	21,851		$	55,376
Oil		$	10,768		$	9,384		$	2,227		$	8,039
Production volumes(2):
Appalachia:
Gas (Mcf/d) (1)			27,156			24,511			21,468			20,892
Oil (Bbls/d)			418			413			431			433
Michigan(5):
Gas (Mcf/d)			59,737			—			—			—
Oil (Bbls/d)			4			—			—			—
Total (Mcfe/d)			89,425			26,989			24,054			23,490
Average sales prices:
Gas (per Mcf) (3)(7)		$	8.66		$	8.83		$	11.06		$	7.26
Oil (per Bbl)		$	70.16			62.30		$	56.13		$	50.91
Production costs (4):
As a percent of production revenues			12	%		10	%		7	%		10	%
Per Mcfe-Appalachia		$	0.89		$	0.86			0.78		$	0.71
Per Mcfe-Michigan		$	1.06
Total Per Mcfe		$	0.97		$	0.86		$	0.78		$	0.71
Transportation costs:
Per Mcfe-Appalachia		$	0.74		$	0.55		$	0.32		$	0.24
Per Mcfe-Michigan		$	0.26
Depletion per Mcfe		$	2.49		$	2.08		$	2.01		$	1.42

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

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(2) Production quantities consist of the sum of (i) ATN’s proportionate share of production from wells in which it has a direct interest, based on its proportionate net revenue interest in such wells, and (ii) its proportionate share of production from wells owned by the investment partnerships in which it has an interest, based on its equity interest in each such partnership and based on each partnership’s proportionate net revenue interest in these wells.

(3) Our average sales price before the effects of financial hedging was $7.22 and $7.90 per mcf for the years ended December 31, 2007 and 2006, respectively. We had no financial hedging transactions in any of the other periods presented.

(4) Production costs include labor to operate the wells and related equipment, repairs and maintenance, materials and supplies, property taxes, severance taxes, insurance and production overhead.

(5) Amounts represent production volumes related DTE Gas & Oil from the acquisition date (June 29, 2007).

(6) Excludes non-qualifying derivative gains of $26.3 million associated with the DTE Gas & Oil acquisition in the year ended December 31, 2007.

(7) Includes $12.3 million in derivative proceeds, which were not included as gas revenue in the year ended December 31, 2007.

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Our natural gas revenues were $169.3 million in the year ended December 31, 2007, an increase of $90.3 million (114%) from $79.0 million in the year ended December 31, 2006. The increase was attributable to volumes associated with our Michigan operations acquired on June 29, 2007 and an 11% increase in the production volumes of our Appalachian operating area. The $90.3 million increase in natural gas revenues consisted of $97.1 million attributable to production volumes partially offset by $6.8 million attributable to decreases in natural gas prices.

We believe that gas volumes will continue to be favorably impacted in 2008 with the contribution of our Michigan business unit and as ongoing projects to extend and enhance the gathering systems of Atlas Pipeline are completed and wells drilled are connected in these areas of expansion.

Our oil revenues were $10.8 million in the year ended December 31, 2007, an increase of $1.4 million (15%) from $9.4 million in the year ended December 31, 2006. The increase resulted from a 13% increase in the average sales price of oil, and a 2% increase in production volumes. The $1.4 million increase consisted of $1.2 million attributable to increases in sales prices, and $199,000 attributable to volume increases. We drill primarily for natural gas rather than oil.

Our production costs were $24.2 million in the year ended December 31, 2007, an increase of $15.7 million (185%) from $8.5 million in the year ended December 31, 2006. This increase is attributable to $14.6 million of production costs associated with our acquisition of DTE Gas & Oil on June 29, 2007 and a $3.1 million increase in transportation charges, water hauling and labor and maintenance costs associated with an increase in the number of wells we own in Appalachia from the prior year period.

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Three Months Ended December 31, 2005

Our natural gas revenues were $21.9 million in the three months ended December 31, 2005. We experienced favorable natural gas prices which averaged $11.06 per Mcf for the quarter. Our oil revenues were $2.2 million in the three months ended December 31, 2005. Oil prices were also favorably impacted and averaged $56.13 per barrel for the quarter. Total gas and oil production volumes for the period were 24,054 Mcfe per day.

Our production costs were $1.7 million in the three months ended December 31, 2005. Production costs as a percentage of production revenue decreased to 7% of production revenue as a result of an increase in our average sales price. Additionally, we experienced an increase in production costs per mcfe due to increases in transportation and labor costs.

Year Ended September 30, 2005

Our natural gas revenues were $55.4 million in the year ended September 30, 2005. Our natural gas prices averaged $7.26 per Mcf for the fiscal year. Our oil revenues were $8.0 million in the year ended September 30, 2005. Our oil prices averaged $50.91 per barrel for the fiscal year. Total gas and oil production volumes for the period were 23,490 per day.

Our production costs were $8.2 million in the year ended September 30, 2005. Production costs as a percentage of production revenue were 10% for the fiscal year.

Well Construction and Completion

Our well drilling revenues and costs and expenses incurred represent the billings and costs associated with the completion of wells for drilling investment partnerships we sponsor. The following table sets forth information relating to these revenues and the related costs, gross profit margins and number of net wells drilled during the periods indicated (in thousands):

		Years Ended December 31,						Three Months Ended December 31,			Year Ended September 30,
		2007			2006			2005			2005
Average construction and completion revenue per well		$	317		$	307		$	225		$	218
Average construction and completion cost per well			276			267			196			190
Average construction and completion segment margin per well		$	41		$	40		$	29		$	28
Segment margin		$	41,931		$	25,901		$	5,497		$	17,552
Net wells drilled			1,014			647			187			615

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Our well construction and completion segment margin was $41.9 million in the year ended December 31, 2007, an increase of $16.0 million (62%) from $25.9 million in the year ended December 31, 2006. During the year ended December 31, 2007, the increase of $16.0 million in segment margin was attributable to an increase in the number of wells we drilled ($15.2 million) and an increase in the gross profit per well ($864,000). The increase in the number of wells we drilled of 367 is a result of an increase in our fundraising in 2007. Since our drilling contracts are on a “cost plus” basis (typically cost plus 15%), an increase in our average cost per well also results in an increase in our average revenue per well.

It should be noted that “Liabilities associated with drilling contracts” on our balance sheet includes $118.0 million of funds raised in our investment programs that have not been applied to the completion of wells as of December 31, 2007 due to the timing of drilling operations, and thus have not been recognized as well construction and completion revenue. We expect to recognize this amount as revenue in the first half of 2008. During the year ended December 31, 2007, we raised $363.3 million and plan to raise approximately $400.0 million in fiscal 2008. We anticipate favorable oil and gas prices will continue to favorably impact our fundraising and therefore our drilling revenues in the year ending December 31, 2008.

Three Months Ended December 31, 2005 and Year Ended September 30, 2005

Our well construction and completion segment margin was $5.5 million in the three months ended December 31, 2005. During this period, 187 wells (net to our interest) were drilled. Our well construction and completion segment margin was $17.6 million in the year ended September 30, 2005. During this period, 615 wells (net to our interest) were drilled.

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Transmission, Gathering and Processing - AHD

The following table illustrates selected volumetric information related to Atlas Pipeline’s operating segments for the periods indicated:

		Year Ended December 31, 2007			Year Ended December 31, 2006			Three Months Ended December 31, 2005			Year Ended  September 30, 2005
Operating data(1):
Appalachia:
Average throughput volume (Mcfd)			68,715			61,892			56,391			54,885
Mid-Continent:
Velma system:
Gathered gas volume (Mcfd)			62,497			60,682			61,093			66,099
Elk City/Sweetwater system:
Gathered gas volume (Mcfd)			298,200			277,063			266,280			242,294
Chaney Dell system(2)
Gathered gas volume (Mcfd)			259,270			—			—			—
Midkiff/Benedum system(2)
Gathered gas volume (Mcfd)			147,240			—			—			—
NOARK system:
Average Ozark Gas
Transmission throughput
volume (Mcfd)			326,651			249,581			255,777			—
Combined throughput volume (Mcfd)			1,093,858			649,218			639,541			363,278

(1) “Mcf” represents thousand cubic feet; “mcfd” represents thousand cubic feet per day.

(2) Volumetric data for the Chaney Dell system and Midkiff/Benedum system for the year ended December 31, 2007 represents volumes recorded for the 158-day period from July 27, 2007, the date of APL’s acquisition, through December 31, 2007.

Transmission, gathering, and processing below includes revenues earned by Atlas Pipeline’s Appalachian segment under its master gas gathering agreement with us and Atlas Energy, which is eliminated upon consolidation in our financial statements. Revenues earned under this agreement were approximately $33.6 million, $30.3 million, $7.9 million and $21.9 million for the years ended December 31, 2007 and 2006, three months ended December 31, 2005, and year ended September 30, 2005, respectively. This is offset by transportation revenues received by us from our investment partnerships for gathering services of $13.8 million, $9.3 million, $1.4 million and $4.3 million for the same periods.

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Our transmission, gathering and processing revenues were $842.9 million for the year ended December 31, 2007, an increase of $386.6 million (85%) from $456.3 million for the year ended December 31, 2006. The increase in natural gas and liquids revenue was primarily attributable to revenue contribution from Atlas Pipeline’s Chaney Dell and Midkiff/Benedum systems, which was acquired in July 2007, of $344.2 million, an increase of $26.5 million from Atlas Pipeline’s Elk City/Sweetwater system due primarily to an increase in volumes, which includes processing volumes from the newly constructed Sweetwater gas plant, and an increase of $18.5 million from Atlas Pipeline’s Velma system due primarily to an increase in volumes. These increases were partially offset by a decrease of $21.0 million from Atlas Pipeline’s NOARK system due primarily to lower natural gas sales volumes on its gathering systems. Gathered natural gas volume on the Chaney Dell system was 259.3 MMcfd for the period from July 27, 2007, the date of acquisition, to December 31, 2007, while the Midkiff/Benedum system had gathered natural gas volume of 147.2 MMcfd for the same period. Gathered natural gas volume on the Elk City/Sweetwater system averaged 298.2 MMcfd for the year ended December 31, 2007, an increase of 7.6% from the prior year. Gathered natural gas volume averaged 62.5 MMcfd on the Velma system for the year ended December 31, 2007, an increase of 3.0% from the prior year. Transportation revenue increased over the prior year primarily due to an increase of $10.4 million from the transportation revenues associated with the NOARK system, $4.0 million of contributions from the Chaney Dell and Midkiff/Benedum systems, a $3.5 million increase from the Appalachia system, and an increase of $2.9 million associated with the Elk City/Sweetwater system. These revenues do not include the Gain (loss) on mark to market derivatives of ($179.6) million and $2.3 million in the years ended December 31, 2007 and 2006, respectively.

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Our transmission, gathering and processing costs and expenses were $635.7 million for the year ended December 31, 2007, an increase of $274.8 million (76.1%) from 360.9 million for the year ended December 31, 2006. Natural gas and liquids cost of goods sold of $587.5 million and plant operating expenses of $34.7 million for the year ended December 31, 2007 represented increases of $253.2 million and $18.9 million, respectively, from the prior year amounts due primarily to contribution from Atlas Pipeline’s Chaney Dell and Midkiff/Benedum acquisition and an increase in gathered and processed natural gas volumes on the Elk City/Sweetwater system, which includes contributions from the Sweetwater processing facility, partially offset by a decrease in the NOARK gathering system natural gas purchases. Transportation and compression expenses increased $2.7 million to $13.5 million for the year ended December 31, 2007 due to higher NOARK and Appalachia system operating and maintenance costs as a result of increased capacity and additional well connections.

Three Months Ended December 31, 2005

Our transmission, gathering and processing revenues were $135.3 million for the three months ended December 31, 2005, primarily attributable to revenue contributions from Atlas Pipeline’s Elk City system, which was acquired during April 2005. Gathered natural gas volume averaged 67.1 MMcfd on Atlas Pipeline’s Velma system for the three months ended December 31, 2005. Gathered natural gas volume on the Appalachia system averaged 55.2 MMcfd for the three months ended December 31, 2005.

Our transmission, gathering and processing costs and expenses were $109.9 million for the three months ended December 31, 2005, primarily related to costs associated with the revenue contributions from Atlas Pipeline’s Elk City acquisition.

Year Ended September 30, 2005

Our transmission, gathering and processing revenues were $282.3 million for the year ended September 30, 2005, principally attributable to revenue contributions from Atlas Pipeline’s Elk City system, which was acquired during April 2005, and its Velma system, which was acquired in July 2004, and higher commodity prices. Gathered natural gas volume averaged 65.9 MMcfd on Atlas Pipeline’s Velma system for the year ended September 30, 2005. Gathered natural gas volume on the Elk City system averaged 181.2 MMcfd from its date of acquisition through September 30, 2005.

Our transmission, gathering and processing costs and expenses were $229.8 million for the year ended September 30, 2005, primarily related to costs associated with the revenue contributions from Atlas Pipeline’s Elk City and Velma acquisitions, an increase in commodity prices and higher Appalachia system operating costs as a result of compressors added during 2005 in connection with a capacity expansion project and higher maintenance expense associated with additional wells connected to the gathering system.

Gain (loss) on Mark-to-Market Derivatives

Year Ended December 21, 2007 Compared to Year Ended December 31, 2006

Our gain (loss) on mark-to-market derivatives was a loss of $153.3 million in year ended December 31, 2007 as compared to a gain of $2.3 million in the year ended December 31, 2006. The loss in 2007 relates primarily to a loss of $130.2 million in the fourth quarter of 2007 on unfavorable price movements on derivatives at Atlas Pipeline which are based on forward crude oil prices which increased from an average of $74.78/bbl at September 30, 2007 to $89.89 per/bbl at December 31, 2007.

Other Income, Costs and Expenses

General and Administrative

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Our general and administrative expenses were $111.6 million in the year ended December 31, 2007, and increase of $65.1 million (136%) from $46.5 million in the year ended December 31, 2006. These expenses include, among other things, salaries and benefits not allocated to a specific segment, costs of running our corporate offices, partnership syndication activities and outside services. The increase of $65.1 million in year ended December 31, 2007 is principally attributable to the following:

· an increase of $52.6 million related to employee costs including benefits and stock compensation awards;

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· an increase of $7.1 million related to audit, tax and professional fees, including $3.9 million in fees related to hedges entered into which were associated with the DTE Gas & Oil acquisition; and

· an increase of $3.4 million related to the costs associated with running our corporate offices and partnership syndication activities due to the growth in our business.

Three Months Ended December 31, 2005

Our general and administrative expenses in the three months ended December 31, 2005 were $9.5 million and consisted principally of the following:

· $4.8 million in salary, wages and benefits;

· $2.4 million in professional fees and insurance; and

· $1.3 million in corporate overhead and syndication activities.

Year Ended September 30, 2005

Our general and administrative expenses were $24.0 million in the year ended September 30, 2005 and consisted principally of the following:

· general and administrative expenses related to Atlas Pipeline’s Mid-Continent operations were $3.8 million, which include costs associated with operations of Elk City acquired in April 2005, and a full year of expense associated with operations of Mid-Continent, acquired in July 2004;

· costs associated with Atlas Pipeline’s long term incentive plan were $3.2 million;

· salaries and wages of $8.4 million which include executive salaries and increases in the number of employees as a result of our spin-off from our parent;

· professional fees and insurance were $5.5 million, which includes the implementation of Sarbanes-Oxley Section 404 compliance, and

· $3.1 million for costs incurred in syndicating ATN’s partnerships as it continues to increase the amount of money raised.

Depletion

We are subject to variances in our depletion rates from period to period, including the periods described below. These variances result from changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and gas properties.

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Our depletion of oil and gas properties as a percentage of oil and gas revenues was 30% in the year ended December 31, 2007 compared to 23% in 2006. Depletion was $2.49 per mcfe in the year ended December 31, 2007, an increase of $0.41 per mcfe (19%) from $2.08 per mcfe in the year ended December 31, 2006. Increases in our depletable basis and production volumes, primarily from the acquisition of DTE Gas & Oil on June 29, 2007, as well as changes in our oil and gas reserve quantities, and product prices caused depletion expense to increase $33.9 million to $54.4 million in 2007 compared to $20.5 million in 2006. Depletion expense associated with our Michigan asset base was $28.3 million in fiscal 2007.

Three Months Ended December 31, 2005 and Year Ended September30, 2005

 Depletion expense was $4.4 million and $12.2 million for the three months ended December 31, 2005 and year ended September 30, 2005, respectively. Our depletion on oil and gas properties as a percentage of oil and gas revenues was 18% in the three months ended December 31, 2005 and our depletion expense per mcfe was $2.01. Our depletion of oil and gas properties as a percentage of oil and gas revenues was 19% in the year ended September 30, 2005 and our depletion expense was $1.42 per mcfe in the year ended September 30, 2005.

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Depreciation and Amortization

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Our depreciation and amortization expenses were $53.5 million in the year ended December 31, 2007, an increase of $28.4 million (113%) from $25.2 million in the year ended December 31, 2006. The $28.4 million increase is primarily due to Atlas Pipeline’s acquisition of the Chaney Dell and Midkiff/Benedum assets and its capital expansion of the Sweetwater processing facility.

Three Months Ended December 2005 and Year Ended September 30, 2005

Depreciation and amortization expenses were $5.9 million, and $12.7 million in the three months ended December 31, 2005 and in the year ended September 30, 2005. These expenses are associated primarily with Atlas Pipeline’s Mid-Continent operations.

Interest Expense

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Our interest expense was $92.6 million in the year ended December 31, 2007, an increase of $65.3 million from $27.3 million in the year ended December 31, 2006. This increase resulted primarily from an increase in outstanding borrowings by Atlas Pipeline and Atlas Energy due to borrowings associated with their acquisitions in fiscal 2007.

Three Months Ended December 31, 2005

Our interest expense was $6.1 million in the three months ended December 31, 2005 and primarily relates to outstanding borrowing on Atlas Pipeline’s credit facility.

Year Ended September 30, 2005

Our interest expense was $11.5 million in fiscal 2005, primarily from outstanding borrowings by Atlas Pipeline to fund the acquisitions of Spectrum and Elk City, as well as $1.0 million of accelerated amortization of deferred financing costs associated with the retirement of the term portion of the Atlas Pipeline credit facility in April 2005.

Minority Interests

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

At December 31, 2007, we owned 10% of the partnership interest in Atlas Pipeline through our ownership in AHD. Because we control the operations of AHD, we include it in our consolidated financial statements and show the ownership by the public as a minority interest. The minority interest income in AHD's and APL’s consolidated loss was $135.1 million in the year ended December 31, 2007 and was an expense of $17.7 million in the year ended December 31, 2006, a decrease of $152.8 million. This decrease is primarily due to a loss on Atlas Pipeline’s mark-to-market derivatives.

After the initial public offering of Atlas Energy on December 18, 2006 and the equity offerings in June 2007 in conjunction with the acquisition of the DTE assets, approximately 51% of Atlas Energy is owned by the general public. Because we control the operations of Atlas Energy, we include it in our consolidated financial statements and show the ownership by the public as a minority interest. The minority interest in Atlas Energy was $41.6 million in the year ended December 31, 2007, an increase of $41.0 million from the year ended December 31, 2006. This increase is a result of an increase in the percentage interest of public unit holders as discussed above, and an increase in Atlas Energy’s net income.

Three Months Ended December 31, 2005

At December 31, 2005, we owned a combined general partner and limited partner interest in Atlas Pipeline of 15% which resulted in minority interest expense of $6.7 million in the three months ended December 31, 2005.

Year Ended September 30, 2005

At September 30, 2005, we owned 19% of the partnership interest in Atlas Pipeline through our general partner and limited partner units, which resulted in a minority interest expense of $14.8 million in the year ended September 30, 2005.

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Other Income, Net

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Our other income was $10.7 million in the year ended December 31, 2007, an increase of $2.1 million as compared to $8.6 million in the year ended December 31, 2006. We earned $5.8 million in interest income from proceeds received by us from the initial public offering of AHD and $4.3 million in interest income from investments of proceeds received by us from the initial public offering of Atlas Energy.

Our other income was $8.6 million in the year ended December 31, 2006. We received $5.6 million in proceeds, resulting in a $2.7 million gain from the sale of certain gathering pipelines within Atlas Pipeline’s Velma gas system and cash proceeds of $7.5 million, resulting in a $2.9 million gain from an insurance claim settlement related to fire damage at a Velma compressor station sustained during 2006. We also earned $1.3 million in interest income from investments of the proceeds received by us from the initial public offering of AHD.

Income Taxes

Our effective income tax rates were 29%, 39%, 37%, and 38% in the years ended December 31, 2007 and 2006, three months ended December 31, 2005 and the year ended September 30, 2005. The decrease in our rate in the year ended December 31, 2007 is a result of an increase in tax exempt interest relative to net income and a decrease in state income taxes. We incurred a $1.2 million income tax charge related to our spin-off from Resource America in the year ended September 30, 2005.

Arbitration settlement-net

On December 30, 2004, Atlas Pipeline entered into a settlement agreement with SEMCO Energy, Inc. settling all issues and matters related to SEMCO’s termination of the sale of Alaska Pipeline Company to Atlas Pipeline. For the year ended September 30, 2005, Atlas Pipeline received $4.3 million (net of expenses incurred of $1.2 million) which is shown as arbitration settlement-net on our statements of income.

Issuance of Subsidiary Units

Year Ended December 31, 2007

In July 2007, Atlas Pipeline Holdings issued 6.5 million common units (an approximate 27% interest in it) for net proceeds of $167.2 million after offering costs in a private placement offering. In addition, in July 2007 Atlas Pipeline issued 25.6 million common units through a private placement to investors, of which 3.8 million units were purchased by Atlas Pipeline Holdings. We have accounted for our offerings of subsidiary units in accordance with Staff Accounting Bulletin No. 51, Accounting by the Parent in Consolidation for Sales of Stock by a Subsidiary. Accordingly, a gain of $53.0 million, net of an income tax provision of $34.3 million, was recorded in consolidated equity as an increase to paid-in capital as well as a corresponding adjustment of $87.3 million to minority interest, in the year ended December 31, 2007. We have adopted a policy to recognize gains on such transactions as an increase directly to equity rather than as income. This gain represents our portion of the excess net offering price per unit of each of our subsidiary’s units to the book carrying amount per unit.

In June 2007, Atlas Energy issued 24.0 million Class B common and Class D units (an approximate 31% interest in it) for net proceeds of $597.5 million after offering costs in a private placement offering. A gain of $147.9 million, net of an income tax provision of $87.5 million, was recorded in consolidated equity as an increase to paid-in capital as well as a corresponding adjustment of $235.4 million to minority interest, in the year ended December 31, 2007. This gain represents our portion of the excess net offering price per unit of our subsidiary’s units to the book carrying amount per unit.

Year Ended December 31, 2006 and Prior Years

In December 2006, Atlas Energy issued 7.3 million common units (an approximate 19.4% interest in it) for net proceeds of $139.9 million after offering costs in a private placement offering. We recognized a gain of $44.1 million, net of an income tax provision of $31.9 million, which was recorded in consolidated equity as a credit to paid-in capital as well as a corresponding adjustment of $76.0 million to minority interest.

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In July 2006, Atlas Pipeline Holdings issued 3.6 million common units (an approximate 17.1% in it) resulting in net proceeds of approximately $74.3 million after offering costs. We recognized a gain of $37.9 million, net of an income tax provision of $27.4 million, which was recorded in consolidated equity as a credit to paid-in capital as well as a corresponding adjustment of $65.3 million to minority interest.

In May 2006, Atlas Pipeline issued 500,000 common units (an approximate 4% interest in it) resulting in net proceeds of approximately $19.7 million after offering costs. We recognized a gain of  $626,000, net of an income tax provision of $452,000, which was recorded in consolidated equity as a credit to paid-in capital as well as a corresponding adjustment of $1.1 million to minority interest.

We have experienced sales of subsidiary units in years prior to 2006 and had not previously recorded gains of $26.6 million on such sales. We have determined after applying Staff Accounting Bulletin No. 99, Materiality, that the recording of such gains was not material to our results of operations or financial position for such years and we have recorded cummulative gains in the year ended December 31, 2006 financial statements. It is anticipated that our public subsidiaries will have additional issuances in the future as we continue to grow through acquisitions.

The following table provides information about our current and prior year gains for the sale of subsidiary units (in thousands):

Years Ended		Subsidiary			Gain			Tax Provision			Gain - Net of Tax
Year ended December, 31, 2007			Atlas Energy		$	235,438		$	87,521		$	147,917
Year ended December, 31, 2006			Atlas Energy			76,034			31,920			44,114
Year ended December, 31, 2006			Atlas Pipeline			1,078			452			626
Years ended December 2003 to 2005			Atlas Pipeline			45,821			19,236			26,585
Year ended December, 31, 2007			AHD			87,295			34,316			52,979
Year ended December 31, 2006			AHD			65,366			27,442			37,924
					$	511,032		$	200,887		$	310,145

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Liquidity and Capital Resources

General. We fund operations from a combination of sources. Atlas Energy funds its exploration and production operations from cash generated by operations, capital raised through drilling investment partnerships, issuance of its units and use of its credit facility. Atlas Pipeline funds its operations through a combination of cash generated by operations, its credit facility and sales of its common units.

The following table sets forth our sources and uses of cash for the periods indicated (in thousands):

			Years Ended December 31,						Three Months Ended December 31,			Year Ended September 30,
			2007			2006			2005			2005
Provided by operations		$	203,219		$	42,324		$	52,769		$	112,045
Used in investing activities			(3,516,966	)		(180,186	)		(194,941	)		(294,891	)
Provided by financing activities			3,273,881			268,108			179,046			171,935
Increase (decrease) in cash and cash equivalents		$	(39,866	)	$	130,246		$	36,874		$	(10,911	)

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

We had $145.5 million in cash and cash equivalents on hand at December 31, 2007, as compared to $185.4 million at December 31, 2006. Our ratio of earnings from continuing operations before income taxes, minority interest and interest expense to fixed charges was 1.0 to 1.0 for the year ended December 31, 2007, as compared to 4.0 to 1.0 for the year ended December 31, 2006. We had a working capital deficit of $67.4 million, a decrease of $147.8 million from working capital of $80.4 million at December 31, 2006. The decrease in our working capital reflects an increase in our current liabilities of $256.8 million, partially offset by an increase in our current assets of $109.0 million. The increase in our current liabilities is primarily due to an increase of $93.9 million in our short-term hedge liability and an increase of $45.8 million in our liabilities associated with drilling contracts due to the continued growth of our business. The increase in our current assets is primarily due to an increase in accounts receivable of $121.9 million due to acquisitions by APL and ATN in fiscal 2007.

At December 31, 2007, AHD had $25.0 million outstanding and $25.0 million of remaining committed capacity under its credit facility, subject to covenant limitations. APL had $105.0 million of outstanding borrowings under its new $300.0 million credit facility at December 31, 2007 and $9.1 million of outstanding letters of credit, which are not reflected as borrowings on our consolidated balance sheet, and $185.9 million of remaining committed capacity under its credit facility, subject to covenant limitations. In addition to the availability under its credit facility, APL has a universal shelf registration statement on file with the Securities and Exchange Commission, which allows it to issue equity or debt securities of which $352.1 million remains available at December 31, 2007.

At December 31, 2007, the borrowing base under Atlas Energy’s credit facility was $850.0 million, and it had $741.1 million outstanding including letters of credit of $1.1 million. See Note 8 to our consolidated financial statements for information on Atlas Energy’s, AHD’s and Atlas Pipeline’s credit facilities at December 31, 2007.

Cash flows from operating activities. Cash provided by operations is an important source of short-term liquidity for us. Atlas Energy is directly affected by changes in the price of natural gas and oil, interest rates and its ability to raise funds from its drilling investment partnerships. Cash provided by operations is also the primary source of liquidity to fund Atlas Pipeline’s quarterly cash distributions and maintenance capital expenditures and is affected by changes in the price of natural gas as a significant portion of Atlas Pipeline’s transportation fees are calculated as a percentage of natural gas sale prices. Net cash provided by operating activities was $203.2 million in the year ended December 31, 2007, an increase of $160.9 million from $42.3 million for the year ended December 31, 2006. The increase was principally a result of the following:

· net income before depreciation, depletion and amortization increased by $58.5 million in the year ended December 31, 2007 from $95.3 million in the year ended December 31, 2006 to $153.8 million;

· adjustments for non-cash transactions which were added to cash flows totaled $108.3 million in fiscal 2007, including $155.4 million in non-cash loss on derivative value and non-cash compensation expense related to incentive compensation plans of $46.4 million, less minority interest expense of $93.5 million. This was an increase of $86.2 million over same period in 2006;

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· changes in operating assets and liabilities increased operating cash flow by $44.6 million in fiscal 2007, an increase of $37.0 million over $7.6 million in fiscal 2006, primarily due to an increase of $127.9 million in accounts payable and accrued liabilities, partially offset by an increase in accounts receivable and prepaid expense of $89.1 million. Our level of assets and liabilities continues to grow and depends, in part, upon the remaining amount of our drilling obligations at any balance sheet date, which is dependent upon the timing of funds raised through our drilling investment partnerships; and

· these increases were partially offset by distributions to minority interest holders of Atlas Pipeline, Atlas Pipeline Holdings and Atlas Energy of $104.3 million in fiscal 2007, an increase of $66.1 million over the same period in fiscal 2006.

Cash flows from investing activities. Net cash used in our investing activities during the year ended December 31, 2007 was $3.5 billion principally as a result of the following:

· cash used for business acquisitions in fiscal 2007 was $3.2 billion, as a result of the DGO acquisition by ATN for $1.3 billion and the Chaney Dell and Midkiff/Benedum acquisition by APL for $1.9 billion; and

· capital expenditures for oil and gas properties and gas gathering expansions were $349.6 million in fiscal 2007, an increase of $190.1 million over the same period last year as a result of growth in ATN’s and APL’s businesses.

Cash flows from financing activities. Net cash provided by our financing activities during the year ended December 31, 2007 was $3.3 billion, principally as a result of the following:

· Atlas Energy’s net proceeds from the issuance of common units increased $457.6 million in fiscal 2007;

· APL’s and AHD’s net proceeds from the issuance of common units and senior notes increased $942.9 million in fiscal 2007;

· net borrowings increased cash flows by $1.7 billion in 2007, principally as a result of new revolving credit facilities used to fund acquisitions for Atlas Energy and Atlas Pipeline; and

· these increases were partially offset by an increase in repurchases of our common stock of $50.6 million pursuant to our “Dutch Auction” tender offer in February 2007.

Three Months Ended December 31, 2005

Cash flows from operating activities. Net cash provided by operating activities was $52.8 million in the three months ended December 31, 2005, substantially as a result of the following:

· net income before depreciation, depletion and amortization was $22.6 million;

· advances from affiliates increased operating cash flows by $6.3 million; and

· changes in operating assets and liabilities increased operating cash flows by $21.0 million, primarily due to an increase in accounts payable and liabilities associated with our drilling contracts related to an increase in drilling activity.

Cash flows from investing activities. Cash used by our investing activities was $194.9 million, primarily as a result of acquisitions by APL and capital expenditures related to wells ATN drilled.

Cash flows from financing activities. Cash provided by our financing activities was $179.0 million, as a result of the issuance of senior notes and units by APL of $364.1 million, partially offset by repayments on debt of $182.5 million.

Year Ended September 30, 2005

Cash flows from operating activities. Net cash provided by operating activities was $112.0 million principally as a result of the following:

· net income before depreciation, depletion and amortization was $60.3 million;

· a decrease in non-cash items included in net income which were added back to cash flows totaled $2.4 million. These include $3.0 million of terminated acquisition costs, $2.5 million of gains on derivative value, less $3.0 million of non-cash compensation awards;

· distributions paid to minority interests was $18.1 million;

· minority interest was $14.8 million as a result of Atlas Pipeline’s earnings; and

· changes in operating assets and liabilities increased cash flow by $51.3 million , primarily due to an increase in accounts receivable and prepaid expenses offset by an increase in accounts payable and accrued liabilities.

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Cash flows from investing activities. Net cash used in our investing activities was $294.9 million primarily as a result of the following:

· cash used for business acquisitions was $195.3 million; and

· capital expenditures was $99.2 million due to wells we drilled, as well as the expansion of our Mid-Continent gathering systems and processing facilities.

Cash flows from financing activities. Net cash provided by our financing activities was $171.9 million, principally a result of the following:

· payments to RAI in the form of repayments of advances was $22.4 million;

· net borrowings was $106.2 as a result of borrowings associated with the acquisition of Elk City; and

· we received proceeds from the issuance of APL common and preferred units of $91.7 million.

Capital Requirements

Atlas Pipeline

APL’s operations require continual investment to upgrade or enhance existing operations and to ensure compliance with safety, operational, and environmental regulations. APL’s capital requirements consist primarily of:

· maintenance capital expenditures to maintain equipment reliability and safety and to address environmental regulations; and

· expansion capital expenditures to acquire complementary assets and to expand the capacity of its existing operations.

Expansion capital expenditures increased to $143.8 million for the year ended December 31, 2007, due principally to expansions of the Appalachia, Velma and Elk City/Sweetwater, NOARK, Chaney Dell and Midkiff/Benedum gathering systems and upgrades to processing facilities and compressors to accommodate new wells drilled in its service areas. Maintenance capital expenditures the year ended December 31, 2007 increased to $9.1 million due to the additional maintenance requirements of the Chaney Dell and Midkiff/Benedum acquisition and fluctuations in the timing of scheduled maintenance activity. As of December 31, 2007, APL is committed to expend approximately $168.4 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

Atlas Energy

During the year ended December 31, 2007, Atlas Energy’s capital expenditures consisted of maintenance capital expenditures and expansion capital expenditures, as defined below:

· maintenance capital expenditures are those capital expenditures ATN made on an ongoing basis to maintain its capital asset base and its current production volumes at a steady level; and

· expansion capital expenditures are those capital expenditures ATN made to expand its capital asset base for longer than the short-term and include new leasehold interests and the development and exploitation of existing leasehold interests through acquisitions and investments in its drilling partnerships.

During the year ended December 31, 2007, ATN’s capital expenditures related primarily to investments in its investment partnerships, in which it invested $137.6 million. For the year ended December 31, 2006, three months ended December 31, 2005, and year ended September 30, 2005, ATN’s capital expenditures related primarily to investments in its partnerships, which totaled $73.6 million, $15.2 million, and $57.9 million, respectively. ATN funded and expects to continue to fund these capital expenditures through cash on hand, from operations and from amounts available under its credit facility.

The level of capital expenditures ATN devotes to its exploration and production operations depends upon any acquisitions made and the level of funds raised through its investment partnerships.  During the year ended December 31, 2007, ATN raised $363.3 million. For the years ended December 31, 2006 and September 30, 2005, it had raised $218.5 million and $148.7 million, respectively. We believe cash flows from operations and amounts available under ATN’s credit facility will be adequate to fund its capital expenditures.  However, the amount of funds it raises and the level of its capital expenditures will vary in the future depending on market conditions for natural gas and other factors.  

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ATN expects to fund its maintenance capital expenditures with cash flow from operations and the temporary use of funds raised in its investment partnerships in the period before it invests these funds, as well as funding its investment capital expenditures and any expansion capital expenditures that it might incur with borrowings under its credit facility and with the temporary use of funds raised in its investment partnerships in the period before it invests the funds. ATN estimates that it will have sufficient cash flow from operations after funding its maintenance capital expenditures to enable it to make its quarterly cash distributions in the amount of the initial quarterly distribution to unit holders through December 31, 2008.

ATN continuously evaluates acquisitions of gas and oil assets. In order to make any acquisition, we believe ATN will be required to access outside capital either through debt or equity placements or through joint venture operations with other energy companies. There can be no assurance that ATN will be successful in its efforts to obtain outside capital.

Changes in Prices and Inflation

Our revenues, the value of our assets, our ability to obtain bank loans or additional capital on attractive terms and our ability to finance our drilling activities through drilling investment partnerships have been and will continue to be affected by changes in oil and gas prices. Natural gas and oil prices are subject to significant fluctuations that are beyond our ability to control or predict. During the year ended December 31, 2007, we received an average of $8.66 per mcf of natural gas and $70.16 per bbl of oil as compared to $8.83 per mcf and $62.30 per bbl in the year ended December 31, 2006. We received an average price of $11.06 per mcf and $56.13 per barrel of oil in the three months ended December 31, 2005 as compared to $7.26 per mcf and $50.91 per barrel in the year ended September 30, 2005.

Although certain of our costs and expenses are affected by general inflation, inflation has not normally had a significant effect on us. However, inflationary trends may occur if the price of natural gas were to increase since such an increase may increase the demand for acreage and for energy equipment and services, thereby increasing the costs of acquiring or obtaining such equipment and services.

Environmental Regulation

To date, compliance with environmental laws and regulations has not had a material impact on our capital expenditures, earnings or competitive position. We cannot assure you that compliance with environmental laws and regulations will not, in the future, increase our costs of doing business or restrictions on the manner in which we conduct our operations.

Dividends

We paid cash dividends of $3.6 million in the year ended December 31, 2007. We did not pay dividends in the year ended December 31, 2006. The determination of the amount of future cash dividends, if any, is at the sole discretion of our board of directors and will depend on the various factors affecting our financial condition and other matters the board of directors deems relevant.

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Contractual Obligations and Commercial Commitments

The following table summarizes our contractual obligations at December 31, 2007 (in thousands):

						Payments Due By Period (in thousands)
Contractual cash obligations:			Total			Less than 1 Year			1 - 3 Years			4 - 5 Years			After 5 Years
Long-term debt		$	1,994,456		$	64		$	25,000		$	740,000		$	1,229,392
Secured revolving credit facilities			—			—			—			—			—
Operating lease obligations			16,460			5,402			5,233			3,215			2,610
Capital lease obligations			40			40			—			—			—
Unconditional purchase obligations			—			—			—			—			—
Derivative based obligations			229,513			110,867			115,694			2,952			—
Other long-term obligations			—			—			—			—			—
Total contractual cash obligations		$	2,240,469		$	116,373		$	145,927		$	746,167		$	1,232,002

Not included in the table above are estimated interest payments calculated at the rates in effect at December 31, 2007: less than one year - $149.3 million; 1 to 3 years - $297.6 million; 4 to 5 years - $268.8 million; after 5 years - $206.5 million.

					Payments Due By Period (in thousands)
Other commercial commitments:		Total			Less than 1 Year			1 - 3 Years			4 - 5 Years			After 5 Years
Standby letters of credit		$	10,200		$	10,200		$	—		$	—		$	—
Guarantees			32,857			5,434			11,045			10,689			5,689
Standby replacement commitments			—			—			—			—			—
Other commercial commitments			168,352			168,352			—			—			—
Total commercial commitments		$	211,409		$	183,986		$	11,045		$	10,689		$	5,689

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of our assets, liabilities, revenues and cost and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, we evaluate our estimates, including those related to the provision for possible losses, deferred tax assets and liabilities, goodwill and identifiable intangible assets, and certain accrued liabilities. We base our estimates on historical experience and on various other assumptions that we believe reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

We have identified the following policies as critical to our business operations and the understanding of our results of operations.

Accounts Receivable and Allowance for Possible Losses.

Through our business segments, we engage in credit extension, monitoring, and collection. In evaluating our allowance for possible losses, we perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by our review of our customer’s credit information. We extend credit on an unsecured basis to many of our energy customers. At December 31, 2007, our credit evaluation indicated that we have no need for an allowance for possible losses for our oil and gas receivables.

Derivative Instruments

We apply the provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, or SFAS 133. SFAS 133 requires each derivative instrument to be recorded in the balance sheet as either an asset or liability measured at fair value. Changes in a derivative instrument’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met (See Note 7).

Reserve Estimates

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

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Impairment of Oil and Gas Properties

We review Atlas Energy’s producing oil and gas properties for impairment on an annual basis and whenever events and circumstances indicate a decline in the recoverability of their carrying values. We estimate the expected future cash flows from our oil and gas properties and compare such future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to their fair value in the current period. The factors used to determine fair value include, but are not limited to, estimates of reserves, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected. Because of the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that will require us to record an impairment of our oil and gas properties. Any such impairment may affect or cause a reduction in our credit facilities.

Dismantlement, Restoration, Reclamation and Abandonment Costs

On an annual basis, we estimate the costs of future dismantlement, restoration, reclamation and abandonment of our natural gas and oil-producing properties. We also estimate the salvage value of equipment recoverable upon abandonment. On December 31, 2006 we adopted the Financial Accounting Standards Board, or FASB, Interpretation No. 47, or FIN 47, Accounting for Conditional Asset Retirement Obligations, as discussed in Note 2 to our consolidated financial statements. As of December 31, 2007 and 2006, our estimate of salvage values was greater than or equal to our estimate of the costs of future dismantlement, restoration, reclamation and abandonment. A decrease in salvage values or an increase in dismantlement, restoration, reclamation and abandonment costs from those we have estimated, or changes in our estimates or costs, could reduce our gross profit from operations.

Goodwill and Other Long-Lived Assets

Goodwill and other intangibles with an indefinite useful life are no longer amortized, but instead are assessed for impairment annually. We have recorded goodwill of $744.4 million in connection with several acquisitions of assets. In assessing impairment of goodwill, we use estimates and assumptions in estimating the fair value of reporting units. If under these estimates and assumptions we determine that the fair value of a reporting unit has been reduced, the reduction can result in an “impairment” of goodwill. However, future results could differ from the estimates and assumptions we use. Events or circumstances which might lead to an indication of impairment of goodwill would include, but might not be limited to, prolonged decreases in expectations of long-term well servicing and/or drilling activity or rates brought about by prolonged decreases in natural gas or oil prices, changes in government regulation of the natural gas and oil industry or other events which could affect the level of activity of exploration and production companies.

In assessing impairment of long-lived assets other than goodwill, where there has been a change in circumstances indicating that the carrying amount of a long-lived asset may not be recoverable, we have estimated future undiscounted net cash flows from the use of the asset based on actual historical results and expectations about future economic circumstances, including natural gas and oil prices and operating costs. Our estimate of future net cash flows from the use of an asset could change if actual prices and costs differ due to industry conditions or other factors affecting our performance.

Revenue Recognition

Exploration and Development

Atlas Energy conducts certain activities through, and a portion of its revenues are attributable to, sponsored energy limited partnerships. These energy partnerships raise capital from investors to drill gas and oil wells. Atlas Energy serves as general partner of the energy partnerships and assumes customary rights and obligations for them. As the general partner, it is liable for partnership liabilities and can be liable to limited partners if it breaches responsibilities with respect to the operations of the partnerships. The income from Atlas Energy’s general partner interest is recorded when the gas and oil are sold by a partnership.

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Atlas Energy contracts with the energy partnerships to drill partnership wells. The contracts require that the energy partnerships must pay the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed in less than 60 days. We classify the difference between the contract payments Atlas Energy has received and the revenue earned as a current liability, included in liabilities associated with drilling contracts.

Atlas Energy recognizes gathering, transmission and processing revenues at the time the natural gas is delivered to the purchaser.

Atlas Energy recognizes well services revenues at the time the services are performed.

Atlas Energy is entitled to receive management fees according to the respective partnership agreements. Atlas Energy recognizes such fees as income when earned and includes them in well services revenues.

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

Transmission, Gathering and Processing

Atlas Pipeline’s Mid-Continent revenue is determined primarily by the fees earned from its transmission, gathering and processing operations. Revenue associated with Atlas Pipeline’s regulated transmission pipeline is recognized at the time the transportation service is provided. Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas. The majority of the revenue associated with Atlas Pipeline’s gathering and processing operations are based on percentage-of-proceeds (“POP”) and fixed-fee contracts. Under its POP purchasing arrangements, Atlas Pipeline purchases natural gas at the wellhead, processes the natural gas by extracting NGLs and removing impurities, and sells the residue gas and NGLs at market-based prices, remitting to producers a contractually-determined percentage of the sale proceeds.

Revenue in the Appalachian segment is recognized at the time the natural gas is transported through Atlas Pipeline’s gathering systems. Substantially all the fees received for the gathering services are generally the greater of 16% of the gross sales price for natural gas produced from the wells, or $0.35 or $0.45 per Mcf, depending on the ownership of the well.

Income Taxes

As part of the process of preparing consolidated financial statements, we are required to estimate income taxes in each of the jurisdictions in which we operate. Significant judgment is required in determining the income tax expense provision. We recognize deferred tax assets and liabilities based on differences between the financial reporting and tax bases of assets and liabilities using the enacted tax rates and laws that are expected to be in effect when the differences are expected to be recovered. We assess the likelihood of our deferred tax assets being recovered from future taxable income. We then provide a valuation allowance for deferred tax assets for which we do not consider realization of such assets to be more likely than not. We consider future taxable income and ongoing prudent and feasible tax planning strategies in assessing the valuation allowance. Any decrease in the valuation allowance could have a material impact on net income in the period in which such determination is made.

Recently Issued Financial Accounting Standards

In December 2007, the Financial Accounting Standards Board, or FASB, issued SFAS 160, Noncontrolling Interests in Consolidated Financial Statements.  This Statement amends Accounting Research Bulletin 51 to establish accounting and reporting standards for the noncontrolling (minority) interest in a subsidiary and for the deconsolidation of a subsidiary.  It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements.  This Statement is effective for fiscal years beginning on or after December 15, 2008.  We do not expect the adoption of SFAS 160 to have significant impact on our financial position and results of operations.

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In December 2007, the FASB issued SFAS No 141(R), “Business Combinations” (“SFAS No. 141(R)”). SFAS No. 141(R) replaces SFAS No. 141, “Business Combinations”, however retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. SFAS No. 141(R) requires an acquirer to recognize the assets acquired, liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date, be measured at their fair values as of that date, with specified limited exceptions. Changes subsequent to that date are to be recognized in earnings, not goodwill. Additionally, SFAS No. 141 (R) requires costs incurred in connection with an acquisition be expensed as incurred. Restructuring costs, if any, are to be recognized separately from the acquisition. The acquirer in a business combination achieved in stages must also recognize the identifiable assets and liabilities, as well as the noncontrolling interests in the acquiree, at the full amounts of their fair values. SFAS No. 141(R) is effective for business combinations occurring in fiscal years beginning on or after December 15, 2008. We will apply the requirements of SFAS No. 141(R) upon its adoption on January 1, 2009 and are currently evaluating whether SFAS No. 141(R) will have an impact on our financial position and results of operations.

In April 2007, the FASB issued FASB Interpretation No. 39-1, amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts (“FIN 39-1”). FIN 39-1 amends FIN 39, which allows an entity to offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. FIN 39-1 was effective for fiscal years beginning after November 15, 2007. We do not expect the adoption of FIN 39-1 to have an impact on our financial position or results of operations.

In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, or SFAS 159. SFAS 159 permits entities to choose to measure eligible financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The Statement will be effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. The Statement offers various options in electing to apply the provisions of this Statement, and at this time we have not made any decisions in its application to our financial position or results of operations. We do not expect the adoption of SFAS 159 to have an impact on our financial position or results of operations.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurement, or SFAS 157. SFAS 157 addresses the need for increased consistency in fair value measurements, defining fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. It also establishes a framework for measuring fair value and expands disclosure requirements.

 In February 2008, the FASB issued Final FASB Staff Position 157-2, or FSP No. 157-2, the FSP, which was effective upon issuance, delays the effective date of SFAS 157, for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value at least once a year, to fiscal years beginning after November 15, 2008. The FSP also covers interim periods within the fiscal years for items within the scope of this FSP. The delay is intended to allow the FASB and its constituents the time to consider the various implementation issues associated with SFAS 157. We do not expect the adoption of SAFS 157 to have a significant impact on our financial position and results of operations.

In September 2006, the Securities and Exchange Commission staff issued Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements”, or SAB 108. SAB 108 was issued in order to eliminate the diversity of practice surrounding how public companies quantify financial statement misstatements. SAB 108 is effective for fiscal years ending on or after November 15, 2006. Traditionally, there have been two widely-recognized methods for quantifying the effects of financial statement misstatements: the “roll-over” method and the “iron curtain” method. The roll-over method focuses primarily on the impact of a misstatement on the income statement, including the reversing effect of prior year misstatements, but its use can lead to the accumulation of misstatements in the balance sheet. The iron-curtain method, on the other hand, focuses primarily on the effect of correcting the period-end balance sheet with less emphasis on the reversing effects of prior year errors on the income statement. Prior to the Company’s application of the guidance in SAB 108, the Company used the roll-over method for quantifying identified financial statement misstatements and concluded that they were immaterial individually and in the aggregate.

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With SAB 108, the SEC staff established an approach that requires quantification of financial statement misstatements based on the effects of the misstatements on each of the company’s financial statements and the related financial statement disclosures. This model is commonly referred to as a “dual approach” because it requires quantification of errors under both the iron curtain and the roll-over methods. SAB 108 permits existing public companies to initially apply its provisions either by (i) restating prior financial statements as if the “dual approach” had always been applied or (ii) recording the cumulative effect of initially applying the “dual approach” as adjustments to the carrying values of assets and liabilities as of the beginning of a Company’s fiscal year, with an offsetting adjustment recorded to the opening balance of retained earnings. The Company elected to record the effects of applying SAB 108 using the cumulative effect transition method to its accounting practice for recording incentive compensation for its executive officers and other employees which it historically recognized in the year in which it was paid. Concurrent with the Company’s change in year-end from September 30 to December 31, the Company adopted the provisions of SAB 108, and recorded an increase in accrued liabilities in the amount of $4.0 million, a decrease in accrued income taxes of $1.6 million and a reduction of retained earnings of approximately $2.4 million as of January 1, 2006.

In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109, or FIN 48. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements and provides guidance on the recognition, de-recognition and measurement of benefits related to an entity’s uncertain tax positions. FIN 48 was effective for us beginning January 1, 2007. The adoption of FIN 48 did not have a significant impact on our financial position or results of operations.

ITEM 7A: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The following discussion is not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than trading.

General

We are exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We manage these risks through the use of derivative financial instruments such as forward contracts and interest rate cap and swap agreements.

The following analysis presents the effect on our earnings, cash flows and financial position as if hypothetical changes in market risk factors occurred on December 31, 2007. Only the potential impacts of hypothetical assumptions are analyzed. The analysis does not consider other possible effects that could impact our business.

Interest Rate Risk. At December 31, 2007, Atlas Energy has revolving credit facility with an initial borrowing base of $850.0 million of which $740.0 million was outstanding (including $1.1 million in letters of credit). The weighted average interest rate for borrowing under this facility was 7.2% at December 31, 2007.

At December 31, 2007, Atlas Pipeline has a new credit facility comprised of a senior secured term loan of $830.0 million, all of which was outstanding, and a $300.0 million senior secured revolving credit facility of which $105.0 million was outstanding. The weighted average interest rate for borrowings was 7.2% at December 31, 2007.

In January 2008, Atlas Energy entered into an interest rate swap contract for $150 million, swapping the floating rate incurred on a portion of its 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.

In January 2008, APL entered into interest rate derivative contracts having an aggregate notional principal amount of $200.0 million. Under the terms of this agreement, APL will pay 2.88%, plus the applicable margin as defined under the terms of its credit facility, and will receive LIBOR plus the applicable margin, on the notional principal amount of $200.0 million. This hedge effectively converts $200.0 million of APL’s floating rate debt under the credit facility to fixed-rate debt. The interest rate swap agreement beings on January 31, 2008 and expires on January 31, 2010.

With the subsequent changes in the interest rate structure for the Atlas Energy and Atlas Pipeline interest rate swaps, a hypothetical 10% change in the weighted average interest rate would change our net income by approximately $2.2 million.

Commodity Price Risk. Our major market risk exposure in commodities is fluctuations in the price of natural gas, NGLs, condensate and oil. To limit Atlas Energy's exposure to changing natural gas prices, Atlas Energy uses financial hedges for a portion of its projected natural gas production. Atlas Pipeline is exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs and condensate rather than cash. Atlas Pipeline enters into financial swap and option instruments to hedge forecasted sales against the variability in expected future cash flows attributable to changes in market prices. Our commodity risk is based on that of our major subsidiaries, Atlas Energy and Atlas Pipeline. These financial swap and option instruments are generally classified as cash flow hedges in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, or SFAS No. 133. A 10% change in the average price of natural gas, NGLs, condensate and oil would result in a change to our consolidated net income for the twelve-month period ending December 31, 2008 of approximately $1.2 million.

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Atlas Energy. Realized pricing of Atlas Energy’s oil and gas production is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas production. Pricing for gas and oil production has been volatile and unpredictable for many years. To limit our exposure to changing natural gas prices, ATN enters into natural gas and costless collar option contracts. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. 

ATN formally documents all relationships between hedging instruments and the items being hedged, including the risk management objective and strategy for undertaking the hedging transactions. This includes matching the natural gas futures and options contracts to the forecasted transactions. ATN assesses, both at the inception of the hedge and on an ongoing basis, whether the derivatives are highly effective in offsetting changes in the fair value of hedged items. Historically these contracts have qualified and been designated as cash flow hedges and recorded at their fair values. Gains or losses on future contracts are determined as the difference between the contract price and a reference price, generally prices on NYMEX. Changes in fair value are recognized in stockholders’ equity and realized gains and losses are recognized within the combined statements of income in the month the hedged commodity is sold. If it is determined that a derivative is not highly effective as a hedge or it has ceased to be a highly effective hedge, due to the loss of correlation between changes in reference prices underlying a hedging instrument and actual commodity prices, ATN will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings.

As of December 31, 2007, ATN had financial hedges in place for approximately 80% of its expected production volumes for the twelve months ending December 31, 2008. At December 31, 2007, ATN had 360 open natural gas futures contracts related to natural gas sales covering 130.6 million MMBtus of natural gas, (which includes 72.6 million MMBtu covering natural gas production assets acquired from AGO), maturing through December 31, 2012 at an average settlement price of $8.32 per MMBtu. On May 18, 2007, ATN signed a definitive agreement to acquire AGO (see Note 3 to our consolidated financial statements). In connection with the financing of this transaction, ATN agreed as a condition precedent to closing that it would hedge 80% of its projected natural gas volumes for no less than three years from the closing date of the transaction. During May 2007, it entered into derivative instruments to hedge 80% of the projected production of the assets to be acquired as required under the financing agreement. The production volume of the assets to be acquired was not considered to be “probable forecasted production” under SFAS No. 133 at the date these derivatives were entered into because the acquisition of the assets had not yet been completed. Accordingly, ATN recognized the instruments as non-qualifying for hedge accounting at inception with subsequent changes in the derivative value recorded within revenues in our consolidated statements of income. We recognized non-cash income of $26.3 million related to the change in value of these derivatives from May 22, 2007 to June 28, 2007, which is shown as “Gain (loss) on mark-to-market derivatives” in our consolidated statements of income for the year ended December 31, 2007. Upon closing of the acquisition on June 29, 2007, the production volume of the assets acquired was considered “probable forecasted production” under SFAS No. 133 and ATN evaluated these derivatives under the cash flow hedge criteria in accordance with SFAS No. 133. In addition, we recognized gains on settled contracts covering natural gas production of $17.6 million and $7.1 million for the years ended December 31, 2007 and 2006, respectively. There were no gains or losses recognized on hedging for the three months ended December 31, 2005 and for the year ended September 30, 2005. Of Atlas Energy’s $5.5 million net unrealized hedge gain at December 31, 2007, its portion is a gain of $8.9 million and a loss of $3.4 million has been reallocated to the investment partnerships.

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

Atlas Pipeline formally documents all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity gas futures and derivative contracts to the forecasted transactions. Atlas Pipeline assesses, both at the inception of the hedge and on an ongoing basis, whether the derivatives are effective in offsetting changes in the forecasted cash flow of the hedged production. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying commodity, Atlas Pipeline will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by Atlas Pipeline through utilization of market data, will be recognized immediately within other income (loss) in our consolidated statements of operations.

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For Atlas Pipeline’s derivatives qualifying as hedges, we recognize the effective portion of changes in fair value in accumulated other comprehensive income (loss), and reclassify them to natural gas and liquids revenue within our consolidated statements of income as the underlying transactions are settled. For Atlas Pipeline’s non-qualifying derivatives and for the ineffective portion of qualifying derivatives, we recognize changes in fair value within our consolidated statements of income as they occur. Ineffective hedge gains or losses are recorded within Gain (loss) on mark-to-market derivatives in our consolidated statements of income while the hedge contracts are open and may increase or decrease until settlement of the contract. At December 31, 2007 and December 31, 2006, we reflected net derivative liabilities on our consolidated balance sheets of $229.5 million and $20.1 million, respectively, related to APL’s derivative contracts.

Atlas Pipeline recognized losses of $49.3 million, $13.9 million, $5.6 million, and $5.0 million for the years ended December 31, 2007, December 31, 2006, three months ended December 31, 2005, and year ended September 30, 2005, respectively, which is shown within natural gas and liquids revenue in our consolidated statements of income related to the settlement of qualifying hedge instruments. Atlas Pipeline recognized a loss of $179.6 million, a gain of $2.3 million, a loss of $138,000, and a gain of $1.9 million for the years ended December 31, 2007 and December 31, 2006, three months ended December 31, 2005, and year ended September 30, 2005, respectively, which is shown within ”Gain (loss) on mark-to-market derivatives” on our consolidated statements of income related to the change in market value of non-qualifying derivatives, the ineffective portion of qualifying derivatives and on the loss on settlements of non-qualifying derivatives.

On June 3, 2007, Atlas Pipeline signed definitive agreements to acquire control of the Chaney Dell and Midkiff/Benedum systems. In connection with agreements entered into with respect to its new credit facility, term loan and private placement of common units, Atlas Pipeline agreed as a condition precedent to closing that it would hedge 80% of its projected natural gas, NGL and condensate production volume for no less than three years from the closing date of the transaction. During June 2007, Atlas Pipeline entered into derivative instruments to hedge 80% of the projected production of the assets to be acquired as required under the financing agreements. The production volume were not considered to be “probable forecasted production” under SFAS No. 133 at the date these derivatives were entered into because the acquisition had not yet been completed. Accordingly, Atlas Pipeline recognized the instruments as non-qualifying for hedge accounting at inception with subsequent changes in the derivative value recorded within other income (loss) in our consolidated statements of income. Atlas Pipeline recognized a non-cash loss of $18.8 million related to the change in value of derivatives entered into specifically for the Chaney Dell and Midkiff/Benedum systems from the time the derivative instruments were entered into to the date of closing of Atlas Pipeline’s acquisition during the year ended December 31, 2007. Upon closing of Atlas Pipeline’s acquisition in July 2007, the production volumes associated with the acquisition were considered “probable forecasted production” under SFAS No. 133. Atlas Pipeline designated these instruments as cash flow hedges and will evaluate these derivatives under the cash flow hedge criteria in accordance with SFAS No. 133.

Atlas America. At December 31, 2007 and December 31, 2006, we reflected a net hedging liability and asset on our balance sheets of $224.0 million and $27.3 million, respectively, as a result of Atlas Energy and Atlas Pipeline derivative contracts. Of the $5.9 million net loss in accumulated other comprehensive income at December 31, 2007, we will reclassify $3.5 million of gains to our consolidated statements of income over the next twelve month period as these contracts expire, and $9.4 million of losses will be reclassified in later periods if the fair values of the instruments remain at current market values. Actual amounts that will be reclassified will vary as a result of future price changes.

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As of December 31, 2007, we had the following NGLs, natural gas, and crude oil volumes hedged:

ATLAS ENERGY RESOURCES HEDGES

Fixed Price Swaps

Twelve Month Period Ending								Average			Fair Value
December 31					Volumes			Fixed Price			Asset (2)
					(mmbtu)(3)			(per mmbtu)			(in thousands)
2008						35,960,000		$	8.86		$	37,457
2009						32,720,000			8.50			170
2010						23,000,000			8.01			(11,398	)
2011						17,600,000			7.79			(10,939	)
2012						9,000,000			7.74			(5,242	)
											$	10,048	)

Costless Collars

Twelve Month Period Ending								Average			Fair Value
December 31		Option Type			Volumes			Floor and Cap			Asset (2)
					(mmbtu)(3)			(per mmbtu)			(in thousands)
2008			Puts purchased			1,560,000		$	7.50		$	368
2008			Calls sold			1,560,000			9.40			—
2010			Puts purchased			2,880,000			7.75			—
2010			Calls sold			2,880,000			8.75			(948	)
2011			Puts purchased			7,200,000			7.50			—
2011			Calls sold			7,200,000			8.45			(3,495	)
2012			Puts purchased			720,000			7.00			—
2012			Calls sold			720,000			8.37			(470	)
											$	(4,545	)
							Atlas Energy - net asset				$	5,503

ATLAS PIPELINE HEDGES

Natural Gas Liquids Sales

Production Period								Average			Fair Value
Ended December 31,					Volumes			Fixed Price			Liability(1)
					(gallons)			(per gallon)			(in thousands)
2008						61,362,000		$	0.706		$	(29,435	)
2009						8,568,000			0.746			(4,189	)
											$	(33,624	)

Crude Oil Sales Options (associated with NGL volumes)

Production Period Ended December 31,		Option Type			Crude Volume			Associated NGL Volume			Average Crude Strike Price			Fair Value Asset/ Liability (2)
					(barrels)			(gallons)			(per barrel)			(in thousands)
2008			Puts purchased			4,173,600			279,347,544		$	60.00		$	852
2008			Calls sold			4,173,600			279,347,544			79.23			(55,674	)
2009			Puts purchased			5,184,000			354,533,760			60.00			5,216
2009			Calls sold			5,184,000			354,533,760			78.88			(64,031	)
2010			Puts purchased			3,127,500			213,088,050			61.08			5,638
2010			Calls sold			3,127,500			213,088,050			81.09			(35,442	)
2011			Puts purchased			606,000			34,869,240			70.59			2,681
2011			Calls sold			606,000			34,869,240			95.56			(3,924	)
2012			Puts purchased			450,000			25,893,000			70.80			2,187
2012			Calls sold			450,000			25,893,000			97.10			(2,922	)
														$	(145,419	)

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Natural Gas Sales

Production Period					Average			Fair Value
Ended December 31,		Volumes			Fixed Price			Asset/(Liability)(2)
		(mmbtu)(3)			(per mmbtu) (3)			(in thousands)
2008			5,484,000		$	8.795		$	5,397
2009			5,724,000			8.611			538
2010			4,560,000			8.526			(351	)
2011			2,160,000			8.270			(607	)
2012			1,560,000			8.250			(331	)
								$	4,646

Natural Gas Basis Sales

Production Period					Average			Fair Value
Ended December 31,		Volumes			Fixed Price			Asset/(Liability)(2)
		(mmbtu)(3)			(per mmbtu)(3)			(in thousands)
2008			5,484,000		$	(0.727	)	$	187
2009			5,724,000			(0.558	)		828
2010			4,560,000			(0.622	)		221
2011			2,160,000			(0.664	)		(32	)
2012			1,560,000			(0.601	)		47
								$	1,251

Natural Gas Purchases

Production Period					Average			Fair Value
Ended December 31,		Volumes			Fixed Price			Asset/(Liability)(2)
		(mmbtu)(3)			(per mmbtu)(3)			(in thousands)
2008			16,260,000		$	8.978	(4)	$	(18,575	)
2009			15,564,000			8.680			(2,542	)
2010			8,940,000			8.580			464
2011			2,160,000			8.270			607
2012			1,560,000			8.250			331
								$	(19,715	)

Natural Gas Basis Purchases

Production Period					Average			Fair Value
Ended December 31,		Volumes			Fixed Price			Liability(2)
		(mmbtu)(3)			(per mmbtu)(3)			(in thousands)
2008			16,260,000		$	(1.114	)	$	(194	)
2009			15,564,000			(0.654	)		(6,152	)
2010			8,940,000			(0.600	)		(2,337	)
2011			2,160,000			(0.700	)		(89	)
2012			1,560,000			(0.610	)		(64	)
								$	(8,836	)

Crude Oil Sales

Production Period					Average			Fair Value
Ended December 31,		Volumes			Fixed Price			Liability(2)
		(barrels)			(per barrel)			(in thousands)
2008			65,400		$	59.424		$	(2,234	)
2009			33,000			62.700			(842	)
								$	(3,076	)

88

Crude Oil Sales Options

Production Period Ended December 31,		Option Type		Volumes			Average Strike Price			Fair Value Asset/(Liability)(2
				(barrels)			(per barrel)			(in thousands)
2008		Puts purchased		262,800		$	60.000		$	(42	)
2008		Calls sold		262,800			78.174			(11,149	)
2009		Puts purchased		306,000			60.000			807
2009		Calls sold		306,000			80.017			(9,072	)
2010		Puts purchased		234,000			61.795			835
2010		Calls sold		234,000			83.027			(5,283	)
2011		Puts purchased		30,000			60.000			272
2011		Calls sold		30,000			74.500			(724	)
2012		Puts purchased		30,000			60.000			195
2012		Calls sold		30,000			73.900			(579	)
									$	(24,740	)
				Atlas Pipeline-net liability					$	(229,513	)
				Total net liability					$	(224,010	)

⁽¹⁾ Fair value based upon management estimates, including forecasted forward NGL prices as a function of forward NYMEX natural gas, light crude and propane prices.

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

⁽³⁾ mmbtu represents million British Thermal Units.

⁽⁴⁾ Includes APL’s premium received from its sale of an option for it to sell 936,000 mmbtu of natural gas at an average price of $15.50 per mmbtu for the year ended December 31, 2008

89

ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

[THE REMAINDER PAGE INTENTIONALLY LEFT BLANK]

90

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

Atlas America, Inc.

We have audited the accompanying consolidated balance sheets of Atlas America, Inc. and subsidiaries (a Delaware corporation) as of December 31, 2007 and 2006, and the related consolidated statements of income, comprehensive income, equity, and cash flows for the years ended December 31, 2007 and 2006, the three month period ended December 31, 2005 and the year ended September 30, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Atlas America, Inc. and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for the years ended December 31, 2007 and 2006, the three month period ended December 31, 2005 and the year ended September 30, 2005 in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Atlas America, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated February 27, 2008 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

February 27, 2008

91

ATLAS AMERICA, INC.

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)

		December 31,
		2007			2006
ASSETS
Current assets:
Cash and cash equivalents		$	145,535		$	185,401
Accounts receivable			204,900			82,954
Prepaid expenses and other			22,939			13,738
Current portion of derivative asset			38,181			33,150
Prepaid and deferred income taxes			20,641			7,934
Total current assets			432,196			323,177
Property, plant and equipment, net			3,442,036			884,812
Intangible assets, net			224,264			30,741
Other assets, net			63,584			42,501
Goodwill, net			744,449			98,607
		$	4,906,529		$	1,379,838
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt		$	64		$	109
Accounts payable			75,524			56,438
Liabilities associated with drilling contracts			132,517			86,765
Accrued producer liabilities			80,697			32,766
Accrued derivative liability			111,223			17,363
Accrued liabilities			99,468			49,207
Advances from affiliate			58			117
Total current liabilities			499,551			242,765
Long-term debt			1,994,392			324,042
Deferred tax liability			197,106			82,307
Long-term derivative liability			157,850			12,340
Other liabilities			46,524			40,656
Minority interest			1,597,943			406,387
Commitments and contingencies (Note 11)
Stockholders’ equity:
Preferred stock, $0.01 par value: 1,000,000 authorized shares			—			—
Common stock, $0.01 par value: 49,000,000 authorized shares			290			200
Additional paid-in capital			390,591			186,696
Treasury stock, at cost			(108,886	)		(29,349	)
ESOP loan receivable			(417	)		(490	)
Accumulated other comprehensive income (loss)			(5,935	)		8,426
Retained earnings			137,520			105,858
Total stockholders’ equity			413,163			271,341
		$	4,906,529		$	1,379,838

See accompanying notes to consolidated financial statements

92

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per share data)

								Three Months Ended			Year Ended
		Years Ended December 31,						December 31,			September 30,
		2007			2006			2005			2005
REVENUES
Well construction and completion		$	321,471		$	198,567		$	42,145		$	134,338
Gas and oil production			180,125			88,449			24,086			63,499
Transmission, gathering and processing			823,646			435,259			128,878			262,829
Administration and oversight			18,138			11,762			2,964			9,875
Well services			17,592			12,953			2,561			9,552
Gain (loss) on mark-to-market derivatives			(153,325	)		2,316			(138	)		1,887
			1,207,647			749,306			200,496			481,980
COSTS AND EXPENSES
Well construction and completion			279,540			172,666			36,648			116,816
Gas and oil production			24,184			8,499			1,721			6,044
Transmission, gathering and processing			635,987			361,045			109,889			229,816
Well services			9,062			7,337			1,487			5,167
General and administrative			111,636			46,517			9,453			23,961
Net expense reimbursement - affiliate			930			1,237			163			602
Depreciation, depletion and amortization			107,917			45,643			10,324			24,895
			1,169,256			642,944			169,685			407,301
OPERATING INCOME			38,391			106,362			30,811			74,679
OTHER INCOME (EXPENSE)
Interest expense			(92,611	)		(27,313	)		(6,147	)		(11,467	)
Minority interests			93,476			(18,283	)		(6,745	)		(14,773	)
Arbitration settlement, net			─			—			—			4,290
Other, net			10,722			8,564			691			229
			11,587			(37,032	)		(12,201	)		(21,721	)
Income before income taxes and cumulative effect of accounting change			49,978			69,330			18,610			52,958
Provision for income taxes			(14,642	)		(27,308	)		(6,886	)		(20,018	)
Net income before cumulative effect of accounting change		$	35,336		$	42,022		$	11,724		$	32,940
Cumulative effect of accounting change (net of tax of $2,530)			—			3,825			—			—
Net income		$	35,336		$	45,847		$	11,724		$	32,940
Net income per common share - basic
Net income before cumulative effect of accounting change-basic		$	1.30		$	1.42		$	0.39		$	1.10
Cumulative effect of accounting change			—			0.13			—			—
		$	1.30		$	1.55		$	0.39		$	1.10
Weighted average common shares outstanding - basic			27,227			29,575			30,005			30,002
Net income per common share - diluted
Net income before cumulative effect on accounting change - diluted		$	1.25		$	1.39		$	0.39		$	1.10
Cumulative effect of accounting change			─			0.13			—			—
		$	1.25		$	1.52		$	0.39		$	1.10
Weighted average common shares outstanding - diluted			28,279			30,236			30,320			30,074

See accompanying notes to consolidated financial statements

93

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)  

		Years Ended						Three Months Ended			Year Ended
		December 31,						December 31,			September 30,
		2007			2006			2005			2005
Net income		$	35,336		$	45,847		$	11,724		$	32,940
Other comprehensive income (loss):
Unrealized holding gains (losses) on hedging contracts, net of tax of $7,426, ($8,631), $653, and $2,452			(11,782	)		14,155			(1,112	)		(4,360	)
Postretirement plan liability , net of tax of $7 and $267			(50	)		(416	)		—			—
Reclassification adjustment for hedge (gains) losses realized in net income, net of tax of $1,486, $127, ($946) and ($730)			(2,529	)		(197	)		1,611			1,298
			(14,361	)		13,542			499			(3,062	)
Comprehensive income		$	20,975		$	59,389		$	12,223		$	29,878

See accompanying notes to consolidated financial statements

94

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(in thousands, except share data)

																				Accumulated
								Additional									ESOP			Other						Total
		Common Stock						Paid-In			Treasury Stock						Loan			Comprehensive			Retained			Stockholders’
		Shares			Amount			Capital			Shares			Amount			Receivable			Income (Loss)			Earnings			Equity
Balance, October 1, 2004			13,333,333		$	133		$	75,584			—			—			—		$	(2,553	)	$	17,839		$	91,003
Issuance of common stock			1,370			—			53			—			—			—			—			—			53
Other comprehensive income			—			—			—			—			—			—			(3062	)		—			(3,062	)
Loan to ESOP			—			—			—			—			—			(602	)		—			—			(602	)
Repayment of ESOP loan			—			—			—			—			—			19			—			—			19
Net income			—			—			—			—			—			—			—			32,940			32,940
Balance, September 30, 2005			13,334,703		$	133		$	75,637			—		$	—			(583	)	$	(5,615	)	$	50,779		$	120,351
Issuance of common stock			1,328			—			64			—			—			—			—			—			64
Other comprehensive income			—			—			—			—			—			—			499			—			499
Employee stock option plan			—			—			266			—			—			—			—			—			266
Repayment of ESOP loan			—			—			—			—			—			19			—			—			19
Treasury stock purchase			—			—			—			(1,335	)		(73	)		—			—			—			(73	)
Net income			—			—			—			—			—			—			—			11,724			11,724
Balance, December 31, 2005			13,336,031		$	133		$	75,967			(1,335	)	$	(73	)	$	(564	)	$	(5,116	)	$	62,503		$	132,850
Cumulative effect adjustment for adoption of SAB 108 (net of tax of 1,575)			—			—			—			—			—			—			—			(2,425	)		(2,425	)
Restated Balance, January 1, 2006			13,336,031		$	133			75,967			(1,335	)	$	(73	)		(564	)	$	(5,116	)	$	60,078		$	130,425
Issuance of common stock			7,790			—			100			9,542			580			—			—			—			680
Other comprehensive income			—			—			—			—			—			—			13,542			—			13,542
Repayment of ESOP loan			—			—			—			—			—			74			—			—			74
Treasury stock purchase			—			—			—			(667,342	)		(29,856	)		—			—			—			(29,856	)
Stock option compensation			—			—			1,425			—			—			—			—			—			1,425
Three-for-two stock split			6,664,598			67			(45	)		—			—			—			—			(67	)		(45	)
Gain on sale of subsidiary units			—			—			109,249			—			—			—			—			—			109,249
Net income			—			—			—			—			—			—			—			45,847			45,847
Balance, December 31, 2006			20,008,419		$	200		$	186,696			(659,135	)	$	(29,349	)	$	(490	)	$	8,426		$	105,858		$	271,341
Issuance of common stock			56,736			—			1,181			19,685			912			—			—			—			2,093
Other comprehensive income			—			—			—			—			—-			—			(14,361	)		—			(14,361	)
Repayment of ESOP loan			—			—			—			—			—			73			—			—			73
Treasury stock purchase			—			—			—			(1,486,605	)		(80,449	)		—			—			—			(80,449	)
Stock option compensation			—			—			1,542			—			—			—			—			—-			1,542
Three-for-two stock split			8,938,057			90			—			—			—			—			—			(90	)		—
Dividends paid			—			—			—			—			—			—			—			(3,584	)		(3,584	)
Tax benefits from employee stock options			—			—			276			—			—			—			—			—			276
Gain on sale of subsidiary units			—			—			200,896			—			—			—			—			—			200,896
Net income			—			—			—			—			—			—			—			35,336			35,336
Balance, December 31, 2007			29,003,212		$	290		$	390,591			2,126,055		$	(108,886	)	$	(417	)	$	(5,935	)	$	137,520		$	413,163

See accompanying notes to consolidated financial statements

95

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

								Three Months
		Years Ended						Ended			Year Ended
		December 31,						December 31,			September 30,
		2007			2006			2005			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income before taxes		$	35,336		$	45,847		$	11,724		$	32,940
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			107,917			45,643			10,324			24,895
Amortization of deferred finance costs			10,529			3,818			544			2,448
Non-cash loss (gain) on derivative value			155,425			(2,316	)		138			(1,887	)
Non-cash compensation on long-term incentive plans			46,394			9,961			1,320			3,467
Cumulative effect of change in accounting principle			—			(3,825	)		—			—
Minority interests			(93,476	)		18,283			6,745			14,773
(Gain) loss on asset dispositions			916			(5,679	)		(2	)		(104	)
Distributions paid to minority interests			(104,344	)		(38,276	)		(6,381	)		(18,073	)
Deferred income taxes			(127	)		(38,767	)		1,033			2,275
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable and prepaid expenses			(102,808	)		(13,726	)		(3,804	)		(38,067	)
Increase (decrease) in accounts payable and accrued liabilities			146,667			18,809			24,797			89,268
Increase (decrease) in payable / receivable to affiliate			(59	)		2,552			6,331			110
Increase/decrease in other operating assets/liabilities			849			─			─			─
Net cash provided by operating activities			203,219			42,324			52,769			112,045
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures			(349,625	)		(159,466	)		(31,809	)		(99,185	)
Business acquisitions, net of cash acquired			(3,156,976	)		(30,000	)		(163,630	)		(195,262	)
Investment in Lightfoot Capital Partners, L.P.			(10,447	)
Proceeds from disposal of assets			1,645			9,109			3			170
Decrease (increase) in other assets			(1,563	)		171			495			(614	)
Net cash used in investing activities			(3,516,966	)		(180,186	)		(194,941	)		(294,891	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings			2,123,046			157,250			216,841			385,750
Principal payments on borrowings			(465,429	)		(167,857	)		(399,367	)		(279,590	)
Net proceeds from Atlas Energy equity offering			597,495			139,944			—			—
Net proceeds from Atlas Pipeline Holdings, L.P. equity offering			166,984			74,326			—			—
Net proceeds from Atlas Pipeline Partners, L.P. common and preferred unit offerings			946,399			59,585			120,980			91,720
Issuance of Atlas Pipeline Partners L.P. senior notes			—			36,582			243,102			—
Dividend paid			(3,584	)		—			—			—
Purchase of treasury stock			(80,449	)		(29,856	)		—			—
Advances to former parent			—			—			—			(22,431	)
Increase in deferred financing costs and other assets			(10,581	)		(1,866	)		(2,510	)		(3,514	)
Net cash provided by financing activities			3,273,881			268,108			179,046			171,935
Increase (decrease) in cash and cash equivalents			(39,866	)		130,246			36,874			(10,911	)
Cash and cash equivalents at beginning of period			185,401			55,155			18,281			29,192
Cash and cash equivalents at end of period		$	145,535		$	185,401		$	55,155		$	18,281

See accompanying notes to consolidated financial statements

96

 ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2007

NOTE 1 — NATURE OF OPERATIONS

Company Overview

Atlas America, Inc. (the “Company” or “AAI and its subsidiaries”) is a publicly traded (NASDAQ:ATLS) Delaware corporation whose assets consist primarily of cash and its ownership interests in Atlas Energy Resources, LLC (NYSE:ATN - “Atlas Energy” or “ATN”) and Atlas Pipeline Holdings, L.P. (NYSE:AHD - “Atlas Pipeline Holdings” or “AHD”).

In December 2006, the Company contributed substantially all of its Appalachian natural gas and oil assets and its investment partnership management business to Atlas Energy, a then wholly-owned subsidiary. Concurrent with this transaction, Atlas Energy issued 7,273,750 common units, representing a 19.4% ownership interest, in an initial public offering at a price of $21.00 per unit. The net proceeds of approximately $139.9 million after underwriting discounts and commissions were distributed to the Company. After completion of the offering, the Company owned approximately 78.5% of Atlas Energy. Additionally, the Company owns Atlas Energy Management, Inc., which owns 2% of the membership interests and all of the management incentive interests in Atlas Energy. On June 29, 2007, Atlas Energy completed a private placement of 7,298,181 Class B common units and 16,702,828 Class D units to a group of institutional investors to fund the acquisition of DTE Gas and Oil Company as described below. After completion of the offering and private placement, the Company owns approximately 49.4% of Atlas Energy.

Atlas Energy is an energy company engaged primarily in the development and production of natural gas and, to a lesser extent, oil in the western New York, eastern Ohio, western Pennsylvania and Tennessee region of the Appalachian Basin for its own account and for investors through the offering of tax-advantaged investment programs. The Company has been involved in the energy industry since 1968. The Company began to expand its operations at the end of 1998 when it acquired The Atlas Group, Inc. and a year later when it acquired Viking Resources Corporation, both energy finance and production companies. On June 29, 2007, Atlas Energy acquired DTE Gas & Oil Company from DTE Energy Company (“DTE”) for $1.273 billion in cash (see Note 3).

In July 2006, the Company contributed its ownership interests in Atlas Pipeline Partners GP, LLC, its then wholly-owned subsidiary, and the general partner of Atlas Pipeline Partners, L.P. (NYSE: APL - “Atlas Pipeline” or “APL”), to AHD. Concurrent with this transaction, AHD issued 3,600,000 common units, representing a 17.1% ownership interest in it, in an initial public offering. In July 2007, AHD sold 6,250,000 common units through a private placement and used the net proceeds from the sale to purchase 3,835,227 units of APL in connection with APL’s acquisition of Anadarko Petroleum Corporation’s (NYSE:APL - “Anadarko”) interests in the Chaney Dell and Midkiff/Benedum systems and processing plants (see Note 3). As a result, AHD, through its ownership of Atlas Pipeline GP, owns a 2% general partner interest and 5,476,253 common units constituting a 13.6% limited partner interest for a total partnership interest of 15.6% in Atlas Pipeline. Because AHD controls the decisions and operations of APL, Atlas Pipeline is consolidated in the Company’s financial statements.

APL owns and operates approximately 7,870 miles of active intrastate gas gathering pipeline and a 565-mile interstate natural gas pipeline in Oklahoma, Arkansas and Texas. Atlas Pipeline also operates seven gas processing plants and a treating facility in Oklahoma and Texas. In Appalachia, it owns and operates approximately 1,600 miles of natural gas gathering pipelines in western Pennsylvania, western New York and eastern Ohio.

On June 15, 2006, the Company’s Board of Directors approved the change of its year end to December 31 from September 30. Accordingly, the Company’s consolidated financial statements include its operations for the years ended December 31, 2007 and 2006, the three-month transition period ended December 31, 2005 and the year ended September 30, 2005.

97

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 1 - NATURE OF OPERATIONS - (Continued)

On April 27, 2007, the Company’s Board of Directors approved a 3-for-2 stock split of the Company’s common stock effected in the form of a 50% stock dividend. All shareholders of record as of May 15, 2007 received one additional share of common stock for every two shares of common stock held on that date. The additional shares of common stock were distributed on May 25, 2007. Information pertaining to shares and earnings per share has been restated in the accompanying financial statements and notes to the consolidated financial statements to reflect this split.

Spin-off from Resource America, Inc.

On June 30, 2005, RAI distributed its remaining 10.7 million shares of the Company to its stockholders in the form of a tax-free dividend. Each stockholder of RAI received 0.59367 shares of the Company for each share of RAI common stock owned as of June 24, 2005, the record date. Although the distribution itself is tax-free to RAI stockholders, as a result of the deconsolidation there may be some tax liability arising from prior unrelated corporate transactions among the Company and some of its subsidiaries. The Company anticipates that all or a portion of any liability arising from this transaction may be reimbursed by us to RAI. The Company no longer consolidated with RAI as of June 30, 2005. In connection with the spin-off, RAI and Company entered into a series of agreements. There are two agreements that govern the ongoing relationship between the Company and RAI that are still in effect at December 31, 2007. These agreements are the tax matters agreement and the transition services agreement.

The tax matters agreement governs the respective rights, responsibilities and obligations of the Company and RAI with respect to tax liabilities and benefits, tax attributes, tax contests and other matters regarding income taxes, non-income taxes and related tax returns.

The transition services agreement governs the provision of support services by the Company to RAI and by RAI to the Company, such as:

· cash management and debt service administration;

· accounting and tax;

· investor relations;

· payroll and human resources administration;

· legal;

· information technology;

· data processing;

· real estate management; and

· other general administrative functions.

The Company and RAI pay each other a fee for these services. The fee is payable monthly in arrears, 15 days after the close of the month. The Company and RAI also agreed to pay or reimburse each other for any out-of-pocket payments, costs and expenses associated with these services.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly-owned except for Atlas Pipeline Holdings and Atlas Energy Resources, which are majority-controlled by the Company. In accordance with established practice in the oil and gas industry, the Company’s financial statements include its pro-rata share of assets, liabilities, revenues, and costs and expenses of the energy partnerships in which the Company has an interest. Such interests typically range from 30% to 35%. All material intercompany transactions have been eliminated.

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ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Use of Estimates

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

Reclassifications

Certain reclassifications have been made to the prior period consolidated financial statements to conform to the 2007 presentation.

Stock-Based Compensation

The Company adopted SFAS No. 123, “Share-Based Payment,” as revised (“SFAS No. 123(R)”), as of October 31, 2005 using the modified prospective method to account for its Long-Term Incentive Plans (see Note 10). Generally, the approach to accounting in SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values.

Prior to the adoption of SFAS No. 123(R), the Company applied the intrinsic value-based method of accounting prescribed by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees (“APB No. 25”), and related interpretations, including the Company’s participation of its employees’ in RAI’s stock option plans prior to its spin-off from RAI. Under this method compensation expense is recorded on the date of grant only if the current market price of the underlying stock exceeds the exercise price.

Under SFAS 123R, the fair value of stock-based awards to employees is calculated through the use of option pricing models, even though such models were developed to estimate the fair value of freely tradable, fully transferable options without vesting restrictions, which significantly differ from the Company’s stock option awards. These models also require subjective assumptions, including future stock price volatility and expected time to exercise, which greatly affect the calculated values. SFAS No. 123R also requires the benefits of tax deductions in excess of recognized compensation expense to be reported as a financing cash flow, rather than as an operating cash flow as prescribed under the prior accounting rules.

Prior to October 1, 2005, no stock-based employee compensation cost was reflected in the Company’s net income, as all options granted under both the plans in which the Company’s employees participate (see Note 10) had an exercise price equal to the market value of the underlying common stock on the date of grant. The vesting of all unvested options under the RAI plan was accelerated for all Company employees and all options were subsequently exercised prior to June 30, 2005 in anticipation of the spin-off from RAI. The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS 123(R) to stock-based employee compensation (in thousands, except share data).

		Year Ended
		September 30,
		2005
Net income, as reported		$	32,940
Less total stock-based employee compensation expense determined under the fair value based method for all awards, net of income taxes			(7,283	)
Pro forma net income		$	25,657
Earnings per share:
Basic-as reported		$	1.10
Basic-pro forma		$	0.85
Earnings per share:
Diluted-as reported		$	1.09
Diluted-pro forma		$	0.85

99

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

The pro forma net income in 2005 above includes $6.7 million in expense (net of taxes) related to options for 1,125,000 split-adjusted shares issued in 2005 which were immediately exercisable. The Company issued these options under these terms to avoid a substantial charge to earnings upon adoption of FASB Statement No 123(R).

Earnings Per Share

Basic earnings per share is determined by dividing net income by the weighted average number of shares of common stock outstanding during the period. Earnings per share - diluted is computed by dividing net income by the sum of the weighted average number of shares of common stock outstanding and dilutive potential shares issuable from the exercise of stock options and award plans. Dilutive potential shares of common stock consist of the excess of shares issuable under the terms of various stock option agreements over the number of such shares that could have been reacquired (at the weighted average price of shares during the period) with the proceeds received from the exercise of the options.

The components of basic and diluted earnings per share for the periods indicated are as follows:  

			Years Ended						Three Months Ended			Year Ended
			December 31,						December 31,			September 30,
			2007			2006			2005			2005
Income from continuing operations		$	35,336		$	42,022		$	11,724		$	32,940
Cumulative effect of accounting change, net of taxes			—			3,825			—			—
Net income		$	35,336		$	45,847		$	11,724		$	32,940
Weighted average common shares outstanding—basic			27,227			29,575			30,005			30,002
Dilutive effect of stock option and award plans			1,052			661			315			72
Weighted average common shares—diluted			28,279			30,236			30,320			30,074

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources. These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” and for the Company include changes in the fair value, net of taxes, of unrealized hedging gains and losses and changes in post retirement plan liabilities.

Components of Accumulated other comprehensive income (loss) at the dates indicated are as follows (in thousands):

		December 31,
		2007			2006
Unrealized holding gain on hedging contacts		$	(5,469	)	$	8,842
Post retirement plan liability			(466	)		(416	)
		$	(5,935	)	$	8,426

Receivables

In evaluating its allowance for possible losses, the Company performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by the Company’s review of its customer’s credit information. The Company extends credit on an unsecured basis to many of its energy customers. At December 31, 2007, the Company’s credit evaluation indicated that it has no need for an allowance for possible losses.

100

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Property Plant, and Equipment

Property plant, and equipment is stated at cost. Depreciation, depletion and amortization is based on cost less estimated salvage value primarily using the unit-of-production or straight line method over the assets estimated useful lives. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized.

The estimated service lives of property and equipment are as follows:

Pipelines, processing and compression facilities			15 - 40 years
Rights-of-way - Mid-Continent			40 years
Rights-of-way - Appalachia			20 years
Buildings and improvements			10 - 40 years
Furniture and equipment			3 - 7 years
Other			3 - 10 years

Property Plant, and equipment consists of the following at the dates indicated:  

			December 31,
			2007			2006
Natural gas and oil properties:
Proved properties:
Leasehold interests		$	1,043,687		$	11,302
Wells and related equipment			752,184			338,580
			1,795,871			349,882
Unproved properties			16,380			1,002
Support equipment			6,936			5,541
			1,819,187			356,425
Pipelines, processing and compression facilities			1,638,845			611,275
Rights-of-way			168,359			30,401
Land, building and improvements			21,742			8,451
Other			17,730			9,902
			3,
			3,665,863			1,016,454
Accumulated depreciation, depletion and amortization:			(223,827	)		(131,642	)
		$	3,442,036		$	884,812

In May 2006, Atlas Pipeline acquired the remaining 25% ownership interest in NOARK, and in 2006 adjusted the preliminary purchase price allocation for the NOARK acquisition based upon the findings of an independent valuation firm (see Note 3) and allocated additional amounts to property, plant and equipment.

101

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Oil and Gas Properties

The Company follows the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil is converted to gas equivalent basis (“mcfe”) at the rate one barrel equals 6 mcf. Depletion is provided on the units-of-production method.

Upon the sale or retirement of a complete or partial unit of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to accumulated depletion. Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the statements of income. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

Goodwill

The Company applies the provisions of SFAS No. 142 which requires that goodwill no longer be amortized, but instead evaluated for impairment at least annually. The evaluation of impairment under SFAS 142 requires the use of projections, estimates and assumptions as to the future performance of the Company’s operations, including anticipated future revenues, expected future operating costs and the discount factor used. Actual results could differ from projections, resulting in revisions to the Company’s assumptions and, if required, recognition of an impairment loss. The Company’s evaluation of goodwill at December 31, 2007 (the most recent valuation date) indicated there was no impairment loss and no impairment indicators have arisen since that date. The Company will continue to evaluate its goodwill at least annually or when impairment indicators arise, and will reflect the impairment of goodwill, if any, within the consolidated statements of income in the period in which the impairment is indicated.

APL recorded its initial purchase price allocation for the Chaney Dell and Midkiff/Benedum acquisition on July 27, 2007. During the fourth quarter of 2007, APL adjusted its preliminary purchase price allocation by increasing the estimated amount allocated to goodwill and reducing amounts initially allocated to property, plant and equipment. Due to the recent date of APL’s Chaney Dell and Midkiff/Benedum acquisition, the purchase price allocation for the acquisition is based upon preliminary data that remains subject to adjustment and could further change as APL continues to evaluate this allocation. Unresolved items which could affect the final purchase price allocation include, among other things, the recoverability of state sales tax paid on the transaction, which has been included as an acquisition cost. The recovery of state sales tax paid on the transaction in future periods could reduce amounts allocated to goodwill. During 2006, APL adjusted the preliminary purchase price allocation for the NOARK acquisition and reduced the estimated amount allocated to goodwill based upon the findings of an independent valuation firm and allocated additional amounts to property, plant and equipment

A reconciliation of the Company’s goodwill for the periods indicated is as follows (in thousands).

		December 31,
		2007			2006
Goodwill at beginning of period, net of accumulated amortization of $4,532		$	98,607		$	146,544
Adjustment to goodwill related to Atlas Pipeline acquisitions (see Note 3)			645,842			(47,937	)
Goodwill at end of period, net of accumulated amortization of $4,532		$	744,449		$	98,607

Impairment of long-lived assets

The Company’s long-lived assets are reviewed for impairment annually for events or changes in circumstances that indicate that the carrying amount of an asset may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. If the carrying value exceeds such cash flows, an impairment loss is recognized for the difference between the estimated fair market value, (as determined by discounted future cash flows) and the carrying value of the assets.

The review of our oil and gas properties is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates.

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable and impaired if conditions indicate the Company will not explore the acreage prior to expiration or the carrying value is above fair value.

Asset Retirement Obligations

The Company accounts for asset retirement obligations as required under FAS No. 143, Accounting for Retirement Asset Obligations (“SFAS 143”). SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, with the associated asset retirement costs being capitalized as a part of the carrying amount of the long-lived asset. The Company has asset retirement obligations related to the plugging and abandonment of its oil and gas wells. SFAS 143 requires the Company to consider estimated salvage value in the calculation of depreciation, depletion and amortization.

 In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (“FIN 47”). FIN 47 clarified that the term “conditional asset retirement obligation” as used in FAS No. 143 which refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Since the obligation to perform the asset retirement activity is unconditional, FIN 47 provides that a liability for the fair value of a conditional asset obligation should be recognized if that fair value can be reasonably estimated, even though uncertainty exists about the timing and/or method of settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of a conditional asset retirement obligation under SFAS 143.

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ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Under SFAS 143, the Company had recorded its asset retirement obligation based on a probability factor which considered the Company’s history of selling its wells or otherwise disposing of them without incurring a disposal expense. FIN 47 requires the Company to record its retirement obligation without regard to its prior practice and accrue for obligations for all wells owned by the Company without regard to their probability of being sold or otherwise disposed of without incurring a disposal expense.

Accordingly, the Company adopted FIN 47 as of December 31, 2006 and recognized $3.8 million (net of tax of $2.6 million) in 2006 as the cumulative effect of an accounting change. Additionally, the Company’s balance sheet recognize.d an increase as of December 31, 2006 in its asset retirement obligation of $8.0 million, and a net increase in property and equipment of approximately $14.4 million.

Had the Company implemented FIN 47 retroactively to October 1, 2002, the following pro forma information summarizes the impact for the periods presented (in thousands):

		Years Ended			Three Months Ended			Year Ended
		December 31,			December 31,			September 30,
		2006			2005			2005
Net income as reported		$	45,847		$	11,724		$	32,940
Proforma asset retirement obligation adjustment			851			346			948
Net income as adjusted			46,698			12,070		$	33,888
Proforma asset retirement obligation		$	26,726		$	26,086		$	25,126

Fair Value of Financial Instruments

The Company used the following methods and assumptions in estimating the fair value of each class of financial instrument for which it is practicable to estimate fair value.

For cash and cash equivalents, receivables and payables, the carrying amounts approximate fair value due to the short maturity of these instruments.

For derivatives, the carrying value approximates fair value.

For secured revolving credit facilities and all other debt, the carrying value approximates fair value due to the short term maturity of these instruments and the variable interest rates in the debt agreements.

Derivative Instruments

The Company applies the provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”). SFAS 133 requires each derivative instrument to be recorded in the balance sheet as either an asset or liability measured at fair value. Changes in a derivative instrument’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met (See Note 7).

Concentration of Credit Risk

Financial instruments, which potentially subject the Company to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Company places its temporary cash investments in high-quality short-term money market instruments and deposits with high-quality financial institutions and brokerage firms. At December 31, 2007, the Company had $99.5 million in deposits at various banks, of which $70.4 million was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments.

103

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Environmental Matters

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

The Company accounts for environmental contingencies in accordance with SFAS No. 5 Accounting for Contingencies. Environmental expenditures that relate to current operations are expensed. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are also expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. The Company maintains insurance which may cover in whole or in part certain environmental expenditures. At December 31, 2007 and 2006, the Company had no environmental matters requiring specific disclosure or requiring recording of a liability.

Revenue Recognition

Atlas Energy. Certain energy activities are conducted by Atlas Energy through and a portion of its revenues are attributable to, sponsored energy limited partnerships. Atlas Energy contracts with the energy partnerships to drill partnership wells. The contracts require that the energy partnerships must pay Atlas Energy the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed in less than 60 days. On an uncompleted contract, Atlas Energy classifies the difference between the contract payments it has received and the revenue earned as a current liability.

Atlas Energy recognizes well services revenues at the time the services are performed.

Atlas Energy is entitled to receive management fees according to the respective partnership agreements, and recognizes such fees as income when earned and includes them in well services revenues.

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

Atlas Pipeline. Revenue associated with Atlas Pipeline’s regulated transmission pipeline is recognized at the time the transportation service is provided. Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas. In connection with its gathering and processing operations, Atlas Pipeline enters into the following types of contractual relationships with its producers and shippers:

a) Fee based contracts provide for a set fee for gathering and processing raw natural gas. Atlas Pipeline’s revenue is a function of the volume of natural gas that it gathers and processes and is not directly dependent on the value of the natural gas.

b) POP contracts provide for Atlas Pipeline to retain a negotiated percentage of the sale proceeds from residue natural gas and NGLs it gathers and processes, with the remainder being remitted to the producer.

104

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

c) Keep whole contracts require Atlas Pipeline, as the processor, to purchase raw natural gas from the producer at current market rates. Therefore, it bears the economic risk that the aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount paid for the unprocessed natural gas. However, because the natural gas received by the Elk City/Sweetwater and Chaney Dell systems, which have keep-whole contracts, is generally low in liquids content and meets downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants and delivered directly into downstream pipelines during periods of margin risk. Therefore, the processing margin risk associated with a portion of APL’s keep-whole contracts is minimized.

Because there are timing differences between the delivery of natural gas, NGLs and oil and the Company’s receipt of a delivery statement, the Company has unbilled revenues. These revenues are accrued based upon volumetric data from the Company’s records and the Company’s estimates of the related transportation and compression fees which are, in turn, based upon applicable product prices. The Company had unbilled trade receivables at December 31, 2007 and 2006 of $131.7 and $40.2 million, respectively, which are included in Accounts Receivable on its Consolidated Balance Sheets.

Supplemental Cash Flow Information

The Company considers temporary investments with a maturity at the date of acquisition of 90 days or less to be cash equivalents.

Supplemental disclosure of cash flow information (in thousands):

		Years Ended						Three Months Ended			Year Ended
		December 31,						December 31,			September 30,
		2007			2006			2005			2005
Interest paid, net of amounts capitalized of $6.0 million and $2.6 million in fiscal 2007 and 2006		$	78,174		$	26,800		$	3,458		$	8,807
Income taxes paid			36,856			57,670			4,957			23
Non-cash investing activities include the following:
Fair value of assets acquired:
Current assets			38,866			─			27,803			6,084
Property, plant & equipment and other			3,150,177			28,575			204,156			193,749
Fair value of assets acquired		$	3,189,043		$	28,575		$	231,959		$	199,833
Liabilities assumed			(32,067	)	$	1,425		$	(52,114	)	$	(4,571	)
Cash Acquired		$	─		$	─		$	(16,215	)	$	─
Net cash paid		$	3,156,976		$	30,000		$	163,630		$	195,262

Income Taxes

The Company records deferred tax assets and liabilities, as appropriate, to account for the estimated future tax effects attributable to temporary differences between the financial statement and tax bases of assets and liabilities and operating loss carryforwards, using currently enacted tax rates. The deferred tax provision or benefit each year represents the net change during that year in the deferred tax asset and liability balances. Separate company state tax returns are filed in those states in which the Company is registered to do business.

105

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Capitalized Interest

The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and gas wells and other capital projects. Interest is capitalized only during the periods in which these assets are brought to their intended use.

The weighted average interest rate used to capitalize interest was 7.4% and 8.1% for the years ended December 31, 2007, and 2006, which resulted in interest capitalized of $6.0 million and $2.6 million, respectively. Amounts capitalized prior to fiscal year 2006 were immaterial.

Recently Issued Financial Accounting Standards

In December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS 160, Noncontrolling Interests in Consolidated Financial Statements.  This Statement amends Accounting Research Bulletin 51 to establish accounting and reporting standards for the noncontrolling (minority) interest in a subsidiary and for the deconsolidation of a subsidiary.  It also clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements.  This Statement is effective for fiscal years beginning on or after December 15, 2008. The company does not expect the adoption of SFAS 160 to have a significant impact on its financial statements or results of operations.

In December 2007, the FASB issued SFAS No 141(R), “Business Combinations” (“SFAS No. 141(R)”). SFAS No. 141(R) replaces SFAS No. 141, “Business Combinations”, however retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. SFAS No. 141(R) requires an acquirer to recognize the assets acquired, liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date, be measured at their fair values as of that date, with specified limited exceptions. Changes subsequent to that date are to be recognized in earnings, not goodwill. Additionally, SFAS No. 141 (R) requires costs incurred in connection with an acquisition be expensed as incurred. Restructuring costs, if any, are to be recognized separately from the acquisition. The acquirer in a business combination achieved in stages must also recognize the identifiable assets and liabilities, as well as the noncontrolling interests in the acquiree, at the full amounts of their fair values. SFAS No. 141(R) is effective for business combinations occurring in fiscal years beginning on or after December 15, 2008. The Company will apply the requirements of SFAS No. 141(R) upon its adoption on January 1, 2009 and is currently evaluating whether SFAS No. 141(R) will have an impact on its financial position and results of operations.

In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS 159”). SFAS 159 permits entities to choose to measure eligible financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The statement will be effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. The Statement offers various options in electing to apply the provisions of this Statement. The Company does not expect the adoption of FASB 159 to have an impact on its financial position or results of operations.

In April 2007, the FASB issued FASB Interpretation No. 39-1, amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts (“FIN 39-1”). FIN 39-1 amends FIN 39, which allows an entity to offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. FIN 39-1 was effective for fiscal years beginning after November 15, 2007. The Company does not expect the adoption of FIN 39-1 to have an impact on its financial position or results of operations.

106

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurement (“SFAS 157”). SFAS 157 addresses the need for increased consistency in fair value measurements, defining fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. It also establishes a framework for measuring fair value and expands disclosure requirements

In February 2008, the FASB issued Final FASB Staff Position, FSP No. FAS 157-2. The FSP, which was effective upon issuance, delays the effective date of SFAS 157, for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value at least once a year, to fiscal years beginning after November 15, 2008. The FSP also covers interim periods within the fiscal years for items within the scope of this FSP. The delay is intended to allow the FASB and its constituents the time to consider the various implementation issues associated with SFAS 157.  The Company does not expect the adoption of SAFS 157 to have a significant impact on its financial position and results of operations.

In September 2006, the Securities and Exchange Commission staff issued Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”). SAB 108 was issued in order to eliminate the diversity of practice surrounding how public companies quantify financial statement misstatements. SAB 108 was effective for fiscal years ending on or after November 15, 2006.

Traditionally, there have been two widely-recognized methods for quantifying the effects of financial statement misstatements: the “roll-over” method and the “iron curtain” method. The roll-over method focuses primarily on the impact of a misstatement on the income statement, including the reversing effect of prior year misstatements, but its use can lead to the accumulation of misstatements in the balance sheet. The iron-curtain method, on the other hand, focuses primarily on the effect of correcting the period-end balance sheet with less emphasis on the reversing effects of prior year errors on the income statement. Prior to the Company’s application of the guidance in SAB 108, the Company used the roll-over method for quantifying identified financial statement misstatements and concluded that they were immaterial individually and in the aggregate.

With SAB 108, the SEC staff established an approach that requires quantification of financial statement misstatements based on the effects of the misstatements on each of the company’s financial statements and the related financial statement disclosures. This model is commonly referred to as a “dual approach” because it requires quantification of errors under both the iron curtain and the roll-over methods.

SAB 108 permits existing public companies to initially apply its provisions either by (i) restating prior financial statements as if the “dual approach” had always been applied or (ii) recording the cumulative effect of initially applying the “dual approach” as adjustments to the carrying values of assets and liabilities as of the beginning of a Company’s fiscal year, with an offsetting adjustment recorded to the opening balance of retained earnings. The Company elected to record the effects of applying SAB 108 using the cumulative effect transition method to its accounting practice for recording incentive compensation for its executive officers and other employees which it historically recognized in the year in which it was paid. Concurrent with the Company’s change in year-end from September 30 to December 31, the Company adopted the provisions of SAB 108, and recorded an increase in accrued liabilities in the amount of $4.0 million, a decrease in accrued income taxes of $1.6 million and a reduction of retained earnings of approximately $2.4 million as of January 1, 2006.

In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109, or (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements and provides guidance on the recognition, de-recognition and measurement of benefits related to an entity’s uncertain tax positions. FIN 48 was effective for the Company beginning January 1, 2007. The adoption of FIN 48 did not have a significant impact on the Company’s financial position or results of operations.

107

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 3 - ACQUISITIONS

Acquisitions by Atlas Pipeline

Chaney Dell and Midkiff/Benedum

On July 27, 2007, APL acquired control of Anadarko’s 100% interest in the Chaney Dell natural gas gathering system and processing plants located in Oklahoma and its 72.8% undivided joint venture interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (the “Anadarko Assets”). The Chaney Dell System includes 3,470 miles of gathering pipeline and three processing plants, while the Midkiff/Benedum System includes 2,500 miles of gathering pipeline and two processing plants. The transaction was effected by the formation of two joint venture companies which own the respective systems, to which APL contributed $1.9 billion and Anadarko contributed the Anadarko Assets.

In connection with this acquisition, APL has reached an agreement with Pioneer, which currently holds a 27.2% undivided joint venture interest in the Midkiff/Benedum system, whereby Pioneer will have an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system on June 15, 2008, and up to an additional 7.4% interest on June 15, 2009. If the option is fully exercised, Pioneer would increase its interest in the system to approximately 49.2%. Pioneer would pay approximately $230 million, subject to certain adjustments, for the additional 22% interest if fully exercised. APL will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercises the purchase options.

APL funded the purchase price in part from the private placement of 25.6 million common limited partner units at a negotiated purchase price of $44.00 per unit, generating gross proceeds of $1.125 billion. AHD purchased 3.8 million of the 25.6 million common limited partner units issued by APL for $168.8 million and funded this through the private placement of 6.25 million of its common units to investors at a negotiated price of $27.00 per unit, yielding gross proceeds of $168.8 million (or net proceeds of $167.0 million, after underwriting fees and other transaction costs). APL also received a capital contribution from AHD of $23.1 million in order for AHD to maintain its 2.0% general partner interest in APL. AHD funded this capital contribution and the underwriting fees and other transaction costs related to its private placement of common units through borrowings under its revolving credit facility of $25.0 million (see Note 8). AHD, which holds all of the incentive distribution rights of APL as General Partner, has also agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. APL funded the remaining purchase price from an $830.0 million senior secured term loan which matures in July 2014 and a new $300.0 million senior secured revolving credit facility that matures in July 2013 (see Note 8).

APL’s acquisition was accounted for using the purchase method of accounting under SFAS No. 141, “Business Combinations” (“SFAS No. 141”). The following table presents the preliminary purchase price allocation, as of December 31, 2007, including professional fees and other related acquisition costs, to the assets acquired and liabilities assumed in the acquisition, based on their fair values at the date of the acquisition (in thousands):

Prepaid expenses and other		$	4,587
Property, plant and equipment			1,030,232
Intangible assets - customer relationships			205,312
Goodwill			645,842
Total assets acquired			1,885,973
Accounts payable and accrued liabilities			(1,515	)
Net cash paid for acquisition		$	1,884,458

Atlas Pipeline recorded goodwill in connection with this acquisition as a result of Chaney Dell’s and Midkiff/Benedum’s significant cash flow and strategic industry position. Due to the recent date of the acquisition, the purchase price allocation for the acquisition is based upon preliminary data that remains subject to adjustment and could further change significantly as APL continues to evaluate this allocation. Unresolved items which could affect the final purchase price allocation include, among other things, the recoverability of state sales tax paid on the transaction, which has been included as an acquisition cost. The recovery of state sales tax paid on the transaction in future periods could reduce amounts allocated to goodwill. The results of Chaney Dell’s and Midkiff/Benedum’s operations are included within the Company’s consolidated financial statements from the date of acquisition.

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DECEMBER 31, 2007

NOTE 3 — ACQUISITIONS - (Continued)

NOARK

In May 2006, APL acquired the remaining 25% ownership interest in NOARK from Southwestern, for a net purchase price of $65.5 million, consisting of $69.0 million of cash to the seller (including the repayment of the $39.0 million of outstanding NOARK notes at the date of acquisition), less the seller’s interest in NOARK’s working capital (including cash on hand and net payables to the seller) at the date of acquisition of $3.5 million. In October 2005, APL acquired from Enogex, Inc., a wholly-owned subsidiary of OGE Energy Corp. (NYSE: OGE), all of the outstanding equity of Atlas Arkansas Pipeline, LLC, which owned the initial 75% ownership interest in NOARK, for total consideration of $179.8 million, including $16.8 million for working capital adjustments and other related transaction costs. NOARK’s assets included a Federal Energy Regulatory Commission (“FERC”)-regulated interstate pipeline and an unregulated natural gas gathering system. The acquisition was accounted for using the purchase method of accounting under SFAS No. 141. The following table presents the purchase price allocation, including professional fees and other related acquisition costs, to the assets acquired and liabilities assumed in both acquisitions, based on their fair values at the date of the respective acquisitions (in thousands):

Cash and cash equivalents		$	16,215
Accounts receivable			11,091
Prepaid expenses			497
Property, plant and equipment			232,576
Other assets			140
Total assets acquired			260,519
Accounts payable and accrued liabilities			(50,689	)
Net assets acquired			209,830
Less: Cash and cash equivalents acquired			(16,215	)
Net cash paid for acquisitions		$	193,615

APL’s ownership interests in the results of NOARK’s operations associated with each acquisition are included within its consolidated financial statements from the respective dates of the acquisitions.

Elk City

In April 2005, Atlas Pipeline acquired all of the outstanding equity interests in ETC Oklahoma Pipeline, Ltd. (“Elk City”), a Texas limited partnership, for $196.0 million, including related transaction costs. Elk City’s principal assets included approximately 450 miles of natural gas pipelines located in the Anadarko Basin in western Oklahoma, a natural gas processing facility in Elk City, Oklahoma and a gas treatment facility in Prentiss, Oklahoma. The acquisition was accounted for using the purchase method of accounting under SFAS No. 141. The following table presents the purchase price allocation, including professional fees and other related acquisition costs, to the assets acquired and liabilities assumed, based on their fair values at the date of acquisition (in thousands):

Accounts receivable		$	5,587
Other assets			497
Property, plant and equipment			104,106
Intangible assets - customer contracts			12,390
Intangible assets - customer relationships			17,260
Goodwill			61,136
Total assets acquired			200,976
Accounts payable and accrued liabilities			(4,970	)
Net assets acquired		$	196,006

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 3 — ACQUISITIONS - (Continued)

APL recorded goodwill in connection with this acquisition as a result of Elk City’s significant cash flow and its strategic industry position. Elk City’s results of operations are included within the Partnership’s consolidated financial statements from its date of acquisition.

Acquisition by Atlas Energy

DTE Gas and Oil Company (DGO):

On June 29, 2007, ATN acquired all of the outstanding equity interests of DTE Gas & Oil Company (“DGO”) from DTE Energy Company (NYSE:DTE) and MCN Energy Enterprises for $1.273 billion, including adjustments for working capital of $15.0 million and current year capital expenditures of $19.0 million. Assets acquired include interests in approximately 2,150 natural gas wells with estimated proved reserves of approximately 613.7 billion cubic feet of natural gas equivalents located in the northern lower peninsula of Michigan, 228,000 developed acres, and 66,000 undeveloped acres. With this acquisition, the Company increased its natural gas and oil production as well as entered into a new region that offers additional opportunities to expand its operations. Subsequent to the acquisition of DGO, ATN changed DGO’s name to Atlas Gas & Oil Company (“AGO”).

To fund the acquisition, ATN borrowed $713.9 million on its new credit facility (See Note 8) and received net proceeds of $597.5 million from a private placement of its Class B common and new Class D units. Proceeds of $52.5 million were used to pay the outstanding balance of ATN’s credit facility with Wachovia Bank. The acquisition was accounted for using the purchase method of accounting under SFAS No. 141, Business Combinations (“SFAS No. 141”). The following table presents the purchase price allocation, including professional fees and other related acquisition costs, to the assets acquired and liabilities assumed based on their estimated fair market value at the date of acquisition (in thousands):

Accounts receivable		$	33,764
Prepaid expenses			515
Other assets			890
Natural gas and oil properties			1,267,901
Total assets acquired			1,303,070
Accounts payable and accrued liabilities			(19,233	)
Other liabilities			(210	)
Asset retirement obligations			(11,109	)
			(30,552	)
Net assets acquired		$	1,272,518

 The purchase price allocation for the acquisition is based upon a third party valuation. It is subject to minor adjustments as management finalizes the allocation. AGO’s operations are included within the Company’s consolidated financial statements beginning June 29, 2007.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 3 — ACQUISITIONS - (Continued)

The following data presents pro forma revenues, net income and basic and diluted net income per share for the Company as if the ATN and APL acquisitions had occurred on January 1, 2006. The Company has prepared these pro forma unaudited financial results for comparative purposes only; they may not be indicative of the results that would have occurred if the acquisitions had occurred on January 1, 2006 or the results that will be attained in the future (in thousands, except per share data; unaudited):

		Year Ended
		December 31, 2007
		As Reported			Pro Forma Adjustments			Pro Forma
Revenues		$	1,207,647		$	337,120		$	1,544,767
Net income		$	35,336		$	(20,051	)	$	15,285
Net income per share - basic		$	1.30		$	(0.74	)	$	0.56
Weighted average shares outstanding - basic			27,227			—			27,227
Net income per share - diluted		$	1.25		$	(0.71	)	$	0.54
Weighted average shares outstanding - diluted			28,279			—			28,279

		Year Ended
		December 31, 2006
		As Reported			Pro Forma Adjustments			Pro Forma
Revenues		$	749,306		$	917,237		$	1,658,225
Net income		$	45,847		$	45,584		$	91,431
Net income per share - basic		$	1.55		$	1.54		$	3.09
Weighted average shares outstanding - basic			29575			—			29,575
Net income per share - diluted		$	1.52		$	1.50		$	3.02
Weighted average shares outstanding - diluted			30,236			—			30,236

Pro forma adjustments to revenues include substantial losses and gains on derivatives realized by AGO of $54.1 million and $149.5 million in fiscal 2007 and 2006, respectively. All existing derivatives were canceled upon the acquisition of AGO by ATN and ATN entered into new derivative contracts covering future AGO production. Pro forma adjustments include financial hedges between AGO and its affiliate. In addition, pro forma adjustments include depreciation, depletion and amortization related to assets acquired by ATN and APL and interest expense associated with debt entered into to acquire such assets.

NOTE 4 — OTHER ASSETS AND INTANGIBLE ASSETS

Other Assets

The following table provides information about other assets at the dates indicated (in thousands):  

			December 31,
			2007			2006
Deferred financing costs, net of accumulated amortization of $5,337 and $6,862		$	26,118		$	13,040
Investments			12,061			1,553
Security deposits			2,630			1,538
Long-term hedge receivable from Partnerships			6,882			2,131
Long-term derivative receivable			13,542			24,148
Other			2,351			91
		$	63,584		$	42,501

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 4 — OTHER ASSETS AND INTANGIBLE ASSETS - (Continued)

Deferred financing costs are recorded at cost and are amortized over the terms of the related loan agreements which range from three to ten years. Investments include the Company’s $10.4 million investment in Lightfoot Capital Partners, L.P. (see Note 17). Long-term hedge receivable from Partnerships represents amounts due from ATN’s affiliated partnerships for unrealized long-term holding losses from hedging activities allocated to them based on their share of total production volumes sold.

Intangible Assets

Customer contracts and relationships. At December 31, 2007, Atlas Pipeline had $219.2 million of intangible assets, net of accumulated amortization of $16.2 million which was recorded in connection with natural gas gathering contracts and customer relationships assumed in its acquisitions. Statement of Financial Accounting Standard No. 142, Goodwill and Other Intangible Assets (“SFAS 142”), requires that intangible assets such as these gas gathering contracts and customer relations with finite useful lives be amortized over their respective estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best estimate of its useful life. At a minimum, Atlas Pipeline assesses the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. They are based on the approximate average length of customer contracts and average non-contracted customer relationships in existence at the date of acquisition. During the fourth quarter of 2007, APL adjusted the preliminary purchase price allocation for its Chaney Dell and Midkiff/Benedum acquisition and increased the estimated amount allocated to customer contracts and customer relationships based upon the findings of an independent valuation firm and reduced amounts initially allocated to property, plant and equipment.

During 2006, APL adjusted the preliminary purchase price allocation for its NOARK acquisition and reduced the estimated amount allocated to customer contracts and customer relationships based upon the findings of an independent valuation firm and allocated additional amounts to property, plant and equipment (see Note 3). Amortization expense on intangible assets was $12.1 million, $2.0 million, $1.6 million and $492,000 for the years ended December 31, 2007, 2006, three months ended December 31, and 2005 and year ended September 30, 2005, respectively.

Partnership management, operating contracts and non-compete agreement. At December 31, 2007, Atlas Energy had intangible assets of $5.1 million, net of accumulated amortization of $10.2 million. Included in intangible assets are partnership management and operating contracts acquired through acquisitions that are recorded at fair value on their acquisition dates. In addition, Atlas Energy entered into a two year non-compete agreement in connection with the acquisition of AGO. Atlas Energy amortizes contracts acquired on the declining balance and straight-line methods, over their respective estimated lives, ranging from two to thirteen years. Amortization expense for these contracts for the years ended December 31, 2007, and 2006, three months ended December 31, 2005 and years ended September 30, 2005 was $1.0 million, $878,800, $220,000 and $933,000, respectively.

The following table provides information about intangible assets at the dates indicated:

		December 31, 2007						December 31, 2006
		(in thousands)						(in thousands)
		Cost			Accumulated Amortization			Cost			Accumulated Amortization
Customer contracts and relations		$	235,382		$	(16,179	)	$	29,650		$	(4,120	)
Partnership management, operating contracts			14,343			(9,949	)		14,343			(9,132	)
Non-compete agreement			890			(223	)		─			─
Intangible assets, net		$	250,615		$	(26,351	)	$	43,993		$	(13,252	)

Aggregate estimated annual amortization expense for all of the contracts described above for the next five periods ending December 31 is as follows: 2008-$26.8 million; 2009-$26.6 million; 2010-$26.3 million; 2011-$26.3 million and 2012-$25.8 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

.NOTE 5 - ASSET RETIREMENT OBLIGATIONS

The Company follows SFAS No 143 and FIN 47, which require the Company to recognize an estimated liability for the plugging and abandonment of its oil and gas wells. Under SFAS 143, the Company must currently recognize a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. SFAS 143 requires the Company to consider estimated salvage value in the calculation of depreciation, depletion and amortization.

The estimated liability is based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The increase in asset retirement obligations in 2005 was due to an upward revision in the estimated cost of plugging and abandoning wells.

The Company has no assets legally restricted for purposes of settling asset retirement obligations. Except for the item previously referenced, the Company has determined that there are no other material retirement obligations associated with tangible long-lived assets.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 5 - ASSET RETIREMENT OBLIGATIONS - (Continued)

A reconciliation of the Company’s liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands):

		Year Ended December 31,						Three Months Ended December 31,			Year Ended September 30,
		2007			2006			2005			2005
Asset retirement obligations, beginning of year		$	26,726		$	18,499		$	17,651		$	4,888
Cumulative effect of adoption of FIN 47			—			8,042			—			—
Liabilities acquired			11,109			—			—			—
Liabilities incurred			2,582			1,570			725			770
Liabilities settled			(91	)		(194	)		—			(137	)
Revision in estimates			—			(2,411	)		—			11,789
Accretion expense			2,032			1,220			123			341
Asset retirement obligations, end of year		$	42,358		$	26,726		$	18,499		$	17,651

The above accretion expense is included in depreciation, depletion and amortization in the Company’s consolidated statements of income and the asset retirement obligation liabilities are included in other liabilities in the Company’s consolidated balance sheets.

NOTE 6 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

In the ordinary course of its business operations, the Company has ongoing relationships with several related entities:

Relationship with Company Sponsored Partnerships. The Company conducts certain activities through, and a substantial portion of its revenues are attributable to, energy limited partnerships (“Partnerships”). The Company serves as general partner of the Partnerships and assumes customary rights and obligations for the Partnerships. As the general partner, the Company is liable for Partnership liabilities and can be liable to limited partners if it breaches its responsibilities with respect to the operations of the Partnerships. The Company is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Partnerships’ revenue, and costs and expenses according to the respective Partnership agreements.

Relationship with RAI. On June 30, 2005, RAI completed its spin-off of the Company. The Company reimburses RAI for various costs and expenses it incurs on behalf of the Company, primarily payroll and rent. For the years ended December 31, 2007 and 2006, three months ended December 31, 2005, and the year ended September 30, 2005, these costs totaled $930,000, $1.2 million, $163,000 and $602,000, respectively.

RAI’s relationship with Anthem Securities (a wholly-owned subsidiary of the Company). Anthem Securities is a wholly-owned subsidiary of the Company and a registered broker-dealer which serves as the dealer-manager of investment programs sponsored by RAI’s real estate and equipment finance segments. Some of the personnel performing services for Anthem have been paid by RAI, and Anthem reimburses RAI for the allocable costs of such personnel. In addition, RAI has agreed to cover some of the operating costs for Anthem’s office of supervisory jurisdiction, principally licensing fees and costs. RAI paid $5.2 million, $1.3 million, $111,000 and $270,000, toward such operating costs of Anthem for the years ended December 31, 2007 and 2006, three months ended December 31, 2005 and the year ended September 30, 2005, respectively. During the same periods, Anthem reimbursed RAI $3.2 million, $2.7 million, $442,000 and $653,000, respectively, for costs incurred on Anthem’s behalf.

As of December 31, 2007 and 2006, certain operating expenditures totaling $58,000 and $117,000, respectively, that remain to be settled between the Company and RAI are reflected in the Company’s consolidated balance sheets as advances to/from affiliate.

NOTE 7 — DERIVATIVE INSTRUMENTS

Atlas Energy Resources. From time to time, Atlas Energy enters into natural gas futures, option contracts and costless collars contracts to hedge its exposure to changes in natural gas prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 7 — DERIVATIVE INSTRUMENTS - (Continued)

Atlas Energy formally documents all relationships between hedging instruments and the items being hedged, including the risk management objective and strategy for undertaking the hedging transactions. This includes matching the natural gas futures and options contracts to the forecasted transactions. Atlas Energy assesses, both at the inception of the hedge and on an ongoing basis, whether the derivatives are highly effective in offsetting changes in the fair value of hedged items. Historically these contracts have qualified and been designated as cash flow hedges and recorded at their fair values in accordance with SFAS 133. Gains or losses on future contracts are determined as the difference between the contract price and a reference price, generally prices on NYMEX. Such gains and losses are charged or credited to accumulated other comprehensive income (loss). Realized gains and losses are recognized as a component of gas production revenue in the month the hedged gas is sold. If it is determined that a derivative is not highly effective as a hedge or it has ceased to be a highly effective hedge, due to the loss of correlation between changes in gas reference prices under a hedging instrument and actual gas prices, Atlas Energy will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings.

At December 31, 2007, Atlas Energy had 360 open natural gas futures contracts related to natural gas sales covering 130.6 million MMBtus of natural gas, maturing through December 31, 2012 at a combined average settlement price of $8.32 per MMBtu. On May 18, 2007, Atlas Energy signed a definitive agreement to acquire AGO (see Note 3). In connection with the financing of this transaction, Atlas Energy agreed as a condition precedent to closing that it would hedge 80% of its projected natural gas volumes for no less than three years from the closing date of the transaction. During May 2007, Atlas Energy entered into derivative instruments to hedge 80% of the projected production of the assets to be acquired as required under the financing agreement. The production volume of the assets to be acquired was not considered to be “probable forecasted production” under SFAS No. 133 at the date these derivatives were entered into because the acquisition of the assets had not yet been completed. Accordingly, Atlas Energy recognized the instruments as non-qualifying for hedge accounting at inception with subsequent changes in the derivative value recorded within revenues in its consolidated statements of income. Atlas Energy recognized non-cash income of $26.3 million related to the change in value of these derivatives from May 22, 2007 to June 28, 2007, which is shown as “Gain (loss) on mark-to-market derivatives” in the Consolidated Statements of Income for the year ended December 31, 2007. Upon closing of the acquisition on June 29, 2007, the production volume of the assets acquired was considered “probable forecasted production” under SFAS No. 133 and Atlas Energy evaluated these derivatives under the cash flow hedge criteria in accordance with SFAS No. 133. In addition, Atlas Energy recognized gains on settled contracts covering natural gas production of $17.6 million and $7.1 million for the years ended December 31, 2007 and 2006, respectively. There were no gains or losses recognized on hedging for the three months ended December 31, 2005 and for the year ended September 30, 2005. Of Atlas Energy’s $5.5 million net unrealized hedge gain at December 31, 2007, its portion is a gain of $8.9 million and a loss of $3.4 million has been reallocated to the investment partnerships.

Atlas Pipeline. Atlas Pipeline also enters into financial swap and option instruments to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate is sold. Under these swap agreements, Atlas Pipeline receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Option instruments are contractual agreements that grant the right, not the obligation, to purchase or sell natural gas, NGL’s, and condensate at a fixed price for the relevant contract period. These financial swaps and option instruments are generally classified as cash flow hedges in accordance with SFAS 133.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 7 — DERIVATIVE INSTRUMENTS - (Continued)

Atlas Pipeline formally documents all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity gas futures and derivative contracts to the forecasted transactions. Atlas Pipeline assesses, both at the inception of the hedge and on an ongoing basis, whether the derivatives are effective in offsetting changes in the forecasted cash flow of the hedged production. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying commodity, Atlas Pipeline will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined through the utilization of market data, will be recognized immediately within other income (loss) in its consolidated statements of income.

For Atlas Pipeline’s derivatives qualifying as hedges, the Company recognizes the effective portion of changes in fair value in stockholders’ equity as accumulated other comprehensive income (loss), and reclassifies them to natural gas and liquids revenue within the consolidated statements of income as the underlying transactions are settled. For Atlas Pipeline’s non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Company recognizes changes in fair value within the consolidated statements of income as they occur. Ineffective hedge gains or losses are recorded within Gain on mark-to-market derivatives in the company’s consolidated statements of income while the hedge contracts are open and may increase or decrease until settlement of the contract. At December 31, 2007 and December 31, 2006, Atlas Pipeline’s net derivative liabilities recorded on the Company’s consolidated balance sheets totaled $229.5 million and $20.1 million, respectively.

Atlas Pipeline recognized losses of $49.3 million, $13.9 million, $5.6 million, and $5.0 million for the years ended December 31, 2007, December 31, 2006, three months ended December 31, 2005, and year ended September 30, 2005, respectively, which is shown within natural gas and liquids revenue in the Company’s consolidated statements of income related to the settlement of qualifying hedge instruments. Atlas Pipeline recognized a loss of $179.6 million, a gain of $2.3 million, a loss of $138,000, and a gain of $1.9 million for the years ended December 31, 2007, December 31, 2006, three months ended December 31, 2005, and year ended September 30, 2005, respectively, which is shown within “Gain (loss) on mark-to-market derivatives” on the Company’s consolidated statements of income related to the change in market value of non-qualifying derivatives, the ineffective portion of qualifying derivatives and on the loss in settlements of non-qualifying derivatives. There were no gains or losses recognized for the year ended December 31, 2006, three months ended December 31, 2005 and year ended September 30, 2005 related to cash settlements of non-qualifying derivatives

On June 3, 2007, the Atlas Pipeline signed definitive agreements to acquire control of the Chaney Dell and Midkiff/Benedum systems (see Note 3). In connection with certain additional agreements entered into to finance this transaction, Atlas Pipeline agreed as a condition precedent to closing that it would hedge 80% of its projected natural gas, NGL and condensate production volume for no less than three years from the closing date of the transaction. During June 2007, Atlas Pipeline entered into derivative instruments to hedge 80% of the projected production of the Anadarko Assets to be acquired as required under the financing agreements. The production volume of the Anadarko Assets to be acquired was not considered to be “probable forecasted production” under SFAS 133 at the date these derivatives were entered into because the acquisition of the Anadarko Assets had not yet been completed. Accordingly, Atlas Pipeline recognized the instruments as non-qualifying for hedge accounting at inception with subsequent changes in the derivative value recorded within other income (loss) in its consolidated statements of operations. Atlas Pipeline recognized a non-cash loss of $18.8 million related to the change in value of derivatives entered into specifically for the Chaney Dell and Midkiff/Benedum systems from the time the derivative instruments were entered into to the date of closing of the acquisition during the year ended December 31, 2007. Upon closing of the acquisition in July 2007, the production volume of the Anadarko Assets acquired was considered “probable forecasted production” under SFAS 133. Atlas Pipeline designated many of these instruments as cash flow hedges and evaluated these derivatives under the cash flow hedge criteria in accordance with SFAS 133.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 7 — DERIVATIVE INSTRUMENTS - (Continued)

In connection with the Chaney Dell and Midkiff/Benedum acquisition, Atlas Pipeline reached an agreement with Pioneer which grants Pioneer an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system beginning on June 15, 2008 and an additional 7.4% interest beginning on June 15, 2009 (see Note 3). At December 31, 2007, Atlas Pipeline has received no indication that Pioneer will exercise either of its options under the agreement. If Pioneer does exercise either of these options, Atlas Pipeline will discontinue hedge accounting for the derivative instruments covering the portion of the forecasted production of the Midkiff/Benedum system sold to Pioneer and will evaluate these derivative instruments to determine if they can be documented to match other forecasted production Atlas Pipeline may have.

During December 2007, Atlas Pipeline discontinued hedge accounting for crude oil derivative instruments covering certain forecasted condensate production for 2008 and other future periods, and then documented these derivative instruments to match certain forecasted NGL production for the respective periods. The discontinuation of hedge accounting for these instruments with regard to Atlas Pipeline’s condensate production resulted in a $12.6 million non-cash derivative loss included in loss on mark-to-market derivatives on the Company’s consolidated statements of income and a corresponding decrease in accumulated other comprehensive loss on the Company’s consolidated balance sheets.

Atlas America. At December 31, 2007 and December 31, 2006, the Company reflected a net hedging liability and asset on its balance sheets of $224.0 million and $27.3 million, respectively, as a result of Atlas Energy and Atlas Pipeline hedges. Of the $5.9 million net loss in accumulated other comprehensive income at December 31, 2007, the Company will reclassify $3.5 million of gains to our consolidated statements of income over the next twelve month period as these contracts expire, and $9.4 million of losses will be reclassified in later periods if the fair values of the instruments remain at current market values. Actual amounts that will be reclassified will vary as a result of future price changes.

117

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 7 — DERIVATIVE INSTRUMENTS - (Continued)

As of December 31, 2007, we had the following NGLs, natural gas, and crude oil volumes hedged:

ATLAS ENERGY RESOURCES HEDGES

Fixed Price Swaps

Twelve Month											Fair Value
Period Ending December 31					Volumes			Average Fixed Price			Asset/ Liability (2)
					(mmbtu)(3)			(per mmbtu)			(in thousands)
2008						35,960,000		$	8.86		$	37,457
2009						32,720,000			8.50			170
2010						23,000,000			8.01			(11,398	)
2011						17,600,000			7.79			(10,939	)
2012						9,000,000			7.74			(5,242	)
											$	10,048	)

Costless Collars

Twelve Month											Fair Value
Period Ending December 31		Option Type			Volumes			Average Floor and Cap			Asset/ Liability (2)
					(mmbtu)(3)			(per mmbtu)			(in thousands)
2008			Puts purchased			1,560,000		$	7.50		$	368
2008			Calls sold			1,560,000			9.40			—
2010			Puts purchased			2,880,000			7.75			—
2010			Calls sold			2,880,000			8.75			(948	)
2011			Puts purchased			7,200,000			7.50			—
2011			Calls sold			7,200,000			8.45			(3,495	)
2012			Puts purchased			720,000			7.00			—
2012			Calls sold			720,000			8.37			(470	)
											$	(4,545	)
							Atlas Energy - net asset				$	5,503

ATLAS PIPELINE HEDGES

Natural Gas Liquids Sales

Production Period								Average			Fair Value
Ended December 31,					Volumes			Fixed Price			Asset/ Liability (1)
					(gallons)			(per gallon)			(in thousands)
2008						61,362,000		$	0.706		$	(29,435	)
2009						8,568,000			0.746			(4,189	)
											$	(33,624	)

Crude Oil Sales Options (associated with NGL volumes)

Production Period								Associated			Average			Fair Value
Ended December 31,		Option Type			Crude Volume			NGL Volume			Crude Strike Price			Asset/ Liability (2)
					(barrels)			(gallons)			(per barrel)			(in thousands)
2008			Puts purchased			4,173,600			279,347,544		$	60.00		$	852
2008			Calls sold			4,173,600			279,347,544			79.23			(55,674	)
2009			Puts purchased			5,184,000			354,533,760			60.00			5,216
2009			Calls sold			5,184,000			354,533,760			78.88			(64,031	)
2010			Puts purchased			3,127,500			213,088,050			61.08			5,638
2010			Calls sold			3,127,500			213,088,050			81.09			(35,442	)
2011			Puts purchased			606,000			34,869,240			70.59			2,681
2011			Calls sold			606,000			34,869,240			95.56			(3,924	)
2012			Puts purchased			450,000			25,893,000			70.80			2,187
2012			Calls sold			450,000			25,893,000			97.10			(2,922	)
														$	(145,419	)

118

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 7 — DERIVATIVE INSTRUMENTS - (Continued)

Natural Gas Sales

Production Period					Average			Fair Value
Ended December 31,		Volumes			Fixed Price			Asset/(Liability)(2)
		(mmbtu)(3)			(per mmbtu) (3)			(in thousands)
2008			5,484,000		$	8.795		$	5,397
2009			5,724,000			8.611			538
2010			4,560,000			8.526			(351	)
2011			2,160,000			8.270			(607	)
2012			1,560,000			8.250			(331	)
								$	4,646

Natural Gas Basis Sales

Production Period					Average			Fair Value
Ended December 31,		Volumes			Fixed Price			Asset/(Liability)(2)
		(mmbtu)(3)			(per mmbtu)(3)			(in thousands)
2008			5,484,000		$	(0.727	)	$	187
2009			5,724,000			(0.558	)		828
2010			4,560,000			(0.622	)		221
2011			2,160,000			(0.664	)		(32	)
2012			1,560,000			(0.601	)		47
								$	1,251

Natural Gas Purchases

Production Period					Average			Fair Value
Ended December 31,		Volumes			Fixed Price			Asset/(Liability)(2)
		(mmbtu)(3)			(per mmbtu)(3)			(in thousands)
2008			16,260,000		$	8.978	(4)	$	(18,575	)
2009			15,564,000			8.680			(2,542	)
2010			8,940,000			8.580			464
2011			2,160,000			8.270			607
2012			1,560,000			8.250			331
								$	(19,715	)

Natural Gas Basis Purchases

Production Period					Average			Fair Value
Ended December 31,		Volumes			Fixed Price			Liability(2)
		(mmbtu)(3)			(per mmbtu)(3)			(in thousands)
2008			16,260,000		$	(1.114	)	$	(194	)
2009			15,564,000			(0.654	)		(6,152	)
2010			8,940,000			(0.600	)		(2,337	)
2011			2,160,000			(0.700	)		(89	)
2012			1,560,000			(0.610	)		(64	)
								$	(8,836	)

Crude Oil Sales

Production Period					Average			Fair Value
Ended December 31,		Volumes			Fixed Price			Liability(2)
		(barrels)			(per barrel)			(in thousands)
2008			65,400		$	59.424		$	(2,234	)
2009			33,000			62.700			(842	)
								$	(3,076	)

119

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 7 — DERIVATIVE INSTRUMENTS - (Continued)

Crude Oil Sales Options

Production Period Ended December 31,		Option Type		Volumes			Average Strike Price			Fair Value Asset/(Liability)(2)
				(barrels)			(per barrel)			(in thousands)
2008		Puts purchased		262,800		$	60.000		$	(42	)
2008		Calls sold		262,800			78.174			(11,149	)
2009		Puts purchased		306,000			60.000			807
2009		Calls sold		306,000			80.017			(9,072	)
2010		Puts purchased		234,000			61.795			835
2010		Calls sold		234,000			83.027			(5,283	)
2011		Puts purchased		30,000			60.000			272
2011		Calls sold		30,000			74.500			(724	)
2012		Puts purchased		30,000			60.000			195
2012		Calls sold		30,000			73.900			(579	)
									$	(24,740	)
				Atlas Pipeline-net liability					$	(229,513	)
				Total net liability					$	(224,010	)

⁽¹⁾ Fair value based upon management estimates, including forecasted forward NGL prices as a function of forward NYMEX natural gas, light crude and propane prices.

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

⁽³⁾ mmbtu represents million British Thermal Units.

⁽⁴⁾ Includes APL’s premium received from its sale of an option for it to sell 936,000 mmbtu of natural gas at an average price of $15.50 per mmbtu for the year ended December 31, 2008

120

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 8 - DEBT

Total debt consists of the following at the dates indicated (in thousands): 

			December 31,
			2007			2006
Senior notes - APL		$	294,392		$	285,977
Revolving credit facility - APL			105,000			38,000
Revolving credit facility - AHD			25,000			―
Revolving credit facility - ATN			740,000			―
Term loan - APL			830,000			―
Other debt			64			174
			1,994,456			324,151
Less current maturities			(64	)		(109	)
		$	1,994,392		$	324,042

Atlas Pipeline Holdings Credit Facility

On July 26, 2006, AHD, as borrower, and Atlas Pipeline GP, as guarantor, entered into a $50.0 million revolving credit facility with a syndicate of banks. At December 31, 2007, AHD has $25.0 million outstanding under its revolving credit facility, which was utilized to fund its capital contribution to APL to maintain its 2.0% general partner interest and underwriters fees and other transaction costs related to its July 2007 private placement of common units. AHD’s credit facility matures in April 2010 and bears interest, at its option, at either (i) adjusted LIBOR (plus the applicable margin, as defined in the credit facility) or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank, National Association prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding credit facility borrowings at December 31, 2007 was 7.1%. Borrowings under AHD’s credit facility are secured by a first-priority lien on a security interest in all of AHD’s assets, including a pledge of Atlas Pipeline GP’s interests in APL, and are guaranteed by Atlas Pipeline GP and AHD’s other subsidiaries (excluding APL and its subsidiaries). AHD’s credit facility contains customary covenants, including restrictions on its ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to AHD’s unitholders if an event of default exists or would result from such distribution; or enter into a merger or sale of substantially all of AHD’s property or assets, including the sale or transfer of interests in its subsidiaries. AHD is in compliance with these covenants as of December 31, 2007.

The events which constitute an event of default under AHD’s credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreements, adverse judgments against AHD in excess of a specified amount, a change of control of Atlas America, AHD’s general partner or any other obligor, and termination of a material agreement and occurrence of a material adverse effect. AHD’s credit facility requires it to maintain a combined leverage ratio (defined as the ratio of the sum of (i) AHD’s funded debt (as defined in its credit facility) and (ii) APL’s funded debt (as defined in APL’s credit facility) to APL’s EBITDA (as defined in APL’s credit facility) of not more than 5.5 to 1.0. In addition, AHD’s credit facility requires it to maintain a funded debt (as defined in its credit facility) to EBITDA ratio of not more than 3.5 to 1.0; and an interest coverage ratio (as defined in its credit facility) of not less than 3.0 to 1.0. AHD’s credit facility defines EBITDA for any period of four fiscal quarters as the sum of (i) four times the amount of cash distributions payable with respect to the last fiscal quarter in such period by APL to AHD in respect of AHD’s general partner interest, limited partner interest and incentive distribution rights in APL and (ii) AHD’s consolidated net income (as defined in its credit facility and as adjusted as provided in its credit facility).

121

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 8 - DEBT - (Continued)

As of December 31, 2007, AHD’s combined leverage ratio was 4.5 to 1.0, its funded debt to EBITDA was 0.8 to 1.0, and its interest coverage ratio was 30.3 to 1.0.

AHD may borrow under its credit facility (i) for general business purposes, including for working capital, to purchase debt or limited partnership units of APL, to fund general partner contributions from AHD to APL and to make permitted acquisitions, (ii) to pay fees and expenses related to its credit facility and (iii) for letters of credit.

APL Term Loan and Credit Facility

In connection with APL’s July 27, 2007 acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see Note 3), APL entered into a new credit facility, comprised of an $830.0 senior secured term loan (“term loan”) which matures in July 2014 and a $300.0 million senior secured revolving credit facility which matures in July 2013. APL borrowed $830.0 million under the term loan and $15.0 million under the revolving credit facility to finance a portion of the acquisition purchase price and to repay indebtedness under its prior revolving credit facility. Borrowings under the APL credit facility bear interest, at APL’s option, at either (i) adjusted LIBOR plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). The weighted average interest rate on APL’s outstanding revolving credit facility borrowings at December 31, 2007 was 7.2%, and the weighted average interest rate on the outstanding term loan borrowings at December 31, 2007 was 7.6%. Up to $50.0 million of the APL credit facility may be utilized for letters of credit, of which $9.1 million was outstanding at December 31, 2007. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated balance sheet. Borrowings under the APL credit facility are secured by a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by the Chaney Dell and Midkiff/Benedum joint ventures, and by the guaranty of each of its consolidated subsidiaries other than the joint venture companies. The APL credit facility contains customary covenants, including restrictions on APL’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. APL is in compliance with these covenants as of December 31, 2007. Mandatory prepayments of the amounts borrowed under the term loan portion of the APL credit facility are required from the net cash proceeds of debt or equity issuances, and of dispositions of assets that exceed $50.0 million in the aggregate in any fiscal year that are not reinvested in replacement assets within 360 days. In connection with the new credit facility, APL agreed to remit an underwriting fee to the lead underwriting bank of the credit facility of 0.75% of the aggregate principal amount of the term loan outstanding on January 23, 2008.  In January 2008, APL and the underwriting bank agreed to extend the agreement through June 30, 2008.

The events which constitute an event of default for APL’s credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreements, adverse judgments against APL in excess of a specified amount, and a change of control of APL’s General Partner. APL’s credit facility requires APL to maintain a ratio of funded debt (as defined in the credit facility) to EBITDA (as defined in the credit facility) ratio of not more than 5.25 to 1.0, and an interest coverage ratio (as defined in the credit facility) of not less than 2.5 to 1.0, increasing to 2.75 to 1.0 commencing September 30, 2008. During a Specified Acquisition Period (as defined in the credit facility), for the first 2 full fiscal quarters subsequent to the closing of an acquisition with total consideration in excess of $75.0 million, the ratio of funded debt to EBITDA will be permitted to step up to 5.75 to 1.0. As of December 31, 2007, APL’s ratio of funded debt to EBITDA was 4.4 to 1.0 and its interest coverage ratio was 3.1 to 1.0.

APL is unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement.

APL Senior Notes

At December 31, 2007, APL has $293.5 million of 10-year, 8.125% senior unsecured notes due 2015 (“Senior Notes”) outstanding, net of unamortized premium received of $0.9 million. Interest on the APL Senior Notes is payable semi-annually in arrears on June 15 and December 15. The APL Senior Notes are redeemable at any time at certain redemption prices, together with accrued and unpaid interest to the date of redemption.

122

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 8 - DEBT - (Continued)

In addition, prior to December 15, 2008, APL may redeem up to 35% of the aggregate principal amount of the APL Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The APL Senior Notes are also subject to repurchase by APL 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 APL does not reinvest the net proceeds within 360 days. The APL Senior Notes are junior in right of payment to APL’s secured debt, including APL’s obligations under its credit facility. On April 18, 2007, APL issued Sunlight Capital $8.5 million of its Senior Notes in consideration of its consent to the amendment of APL’s preferred units agreement.

The indenture governing the APL Senior Notes contains covenants, including limitations of APL’s 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. APL is in compliance with these covenants as of December 31, 2007.

ATN Revolving Credit Facility

Upon the closing of its acquisition of DTE Gas & Oil (See Note 3), ATN replaced its Wachovia Bank credit facility with a new 5-year credit facility with an initial borrowing base of $850,000 with J.P. Morgan Chase Bank, N.A. (“J.P. Morgan”) as administrative agent, Wachovia Bank, N. A. as syndication agent, and other lenders.. The revolving credit facility’s borrowing base will be redetermined semiannually on April 1 and October 1 subject to changes in ATN’s oil and gas reserves. The initial borrowing base was reduced in January 2008, upon the issuance by ATN of $250.0 million in senior unsecured notes. See Note 14 for a discussion of the sale of these notes. Up to $50.0 million of the facility may be in the form of standby letters of credit. The facility is secured by ATN’s assets and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR plus the applicable margin, elected at the Company’s option. At December 31, 2007, the weighted average interest rate on outstanding borrowings was 7.2%.

The base rate for any day equals the higher of the federal funds rate plus 0.50% or the J.P. Morgan 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.

The J.P. Morgan credit facility requires ATN to maintain specified financial ratios of current assets to current liabilities and debt to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”) as disclosed in the loan agreement. In addition, the facility limits sales, leases or transfers of assets and the incurrence of additional indebtedness. The agreement limits the distributions payable by ATN if an event of default has occurred and is continuing or would occur as a result of such distribution. ATN is in compliance with these covenants as of December 31, 2007. The facility terminates in June 2012, when all outstanding borrowings must be repaid. At December 31, 2007 and 2006, $740.0 million and $0 million, respectively, were outstanding under this facility and the previous Wachovia Bank credit facility. In addition, letters of credit of $1.1 million and $495,000 were outstanding at each date, which are not reflected as borrowings on the Company’s consolidated balance sheets.

Annual debt principal payments over the next five years ending December 31 are as follows (in thousands):

2008		$	64
2009			―
2010			25,000
2011			―
2012 and thereafter			1,969,392
		$	1,994,456

123

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 9 — INCOME TAXES

The following table details the components of the Company’s provision for income taxes from continuing operations for the periods indicated:

		Years Ended December 31,						Three Months Ended December 31,			Year Ended September 30,
		2007			2006			2005			2005
		(in thousands)
Provision for income taxes:
Current
Federal		$	14,441		$	54,634		$	5,189		$	16,913
State			608			11,438			664			830
Deferred			(407	)		(38,764	)		1,033			2,275
		$	14,642		$	27,308		$	6,886		$	20,018

A reconciliation between the statutory federal income tax rate and the Company’s effective income tax rate is as follows:

			Years Ended December 31,						Three Months Ended December 31,			Year Ended September 30,
			2007			2006			2005			2005
Statutory tax rate			35	%		35	%		35	%		35	%
Statutory depletion			(1	)		(1	)		(1	)		(2	)
Reorganization costs			—			—			—			2
Tax exempt Interest			(2	)		—			—			—
Section 199 Deduction			(2	)		—			—			—
State income taxes, net of federal tax benefit			2			5			3			2
Other, net			(3	)		—			—			1
			29	%		39	%		37	%		38	%

124

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 9 — INCOME TAXES- (Continued)

The components of the Company’s net deferred tax liability are as follows at the dates indicated:

		December 31,
		2007			2006
		(in thousands)
Deferred tax assets related to:
Unrealized loss on Investments		$	7,337		$	1,226
Accrued expenses			13,765			5,639
Net operating loss carryforwards			180			192
Valuation allowance on deferred tax assets			(180	)		(185	)
Other			—			885
		$	21,102		$	7,757
Deferred tax liabilities related to:
Unrealized gain on Investments		$	(3,851	)	$	(6,658	)
Gain on sale of subsidiary units			(181,930	)		(52,118	)
Investment in partnerships			(22,205	)		(14,954	)
Goodwill and other intangibles			—			(8,400	)
			(207,986	)		(82,130	)
Net deferred tax liability		$	(186,884	)	$	(74,373	)

Deferred income tax assets and liabilities are classified as current or long-term consistent with the classification of the related temporary difference and are recorded in the Company’s consolidated balance sheets as follows:

		December 31,
		2007			2006
		(in thousands)
Current deferred tax asset		$	10,222		$	7,934
Non-current deferred tax liability			(197,106	)		(82,307	)
		$	(186,884	)	$	(74,373	)

The Company had net operating loss carryforwards of $11.2 million at December 31, 2007, primarily related to state income taxes that will expire beginning in 2014 and ending in 2026 if unused. The Company had deferred tax assets of $180,000 for the net operating loss carryforwards and a related valuation allowance of $180,000 at December 31, 2007, all of which was established prior to 2007 based on the uncertainty of generating future taxable income in certain states during the limited period that the net operating loss carryforwards can be carried forward.

The Company adopted the provisions of FASB Interpretation 48, Accounting for Uncertainty in Income Taxes (“FIN 48”) on January 1, 2007. As required by FIN 48, which clarifies Statement 109, Accounting for Income Taxes, the Company recognizes the financial statement benefit of a tax position after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater then 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. At the adoption date, the Company applied FIN 48 to all tax positions for which the statute of limitation remained open. During the year ended December 31, 2007, there were no additions, reductions or settlements in unrecognized tax benefits. The company has no material uncertain tax positions and the implementation of FIN 48 did not have a significant impact on the consolidated financial statements of the Company.

125

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 9 — INCOME TAXES- (Continued)

The company is subject to income taxes in the U.S. federal jurisdiction and various states. Tax regulations within each jurisdiction are subject to the interpretations of the related tax laws and regulations and require significant judgment to apply. With few exceptions, the Company is no longer subject to U.S. federal, state, and local, or non-U.S. income tax examinations by tax authorities for the years before 2004.

The Company’s policy is to reflect interest and penalties related to uncertain tax positions as part of the income tax expense, when and if they become applicable.

NOTE 10 — BENEFIT PLANS

Incentive Bonus Plan. The Company’s shareholders approved an Incentive Bonus Plan (“Bonus Plan”) in 2007 for the benefit of its senior executive officers. The total amount of cash bonus awards to be made under the Bonus Plan for any plan year will be based on performance goals related to objective business criteria for such year.

For any plan year, the Company’s performance must achieve levels targeted by the Company’s compensation committee, as established at the beginning of each year, for any bonus awards to be made. Aggregate bonus awards to all participants under the Bonus Plan may not exceed 15% of the Company’s pre-tax, pre-incentive compensation net income. The compensation committee has the authority to reduce the total amount of bonus awards, if any, to be made to the eligible employees for any plan year based on its assessment of personal performance or other factors as the Board may determine to be relevant or appropriate. The compensation committee may permit participants to elect to defer awards. The Company expensed $12.5 million in 2007 in conjunction with the Bonus Plan.

Stock Incentive Plan. The Company adopted a Stock Incentive Plan (the “Plan”) in 2004 which authorized the granting of up to 3.0 million shares of the Company’s common stock to employees, affiliates, consultants and directors of the Company in the form of incentive stock options (“ISOs”), non-qualified stock options, stock appreciation rights (“SARs”), restricted stock and deferred units. The Company and its subsidiaries follow the provisions of SFAS No. 123(R), “Share-Based Payment”, as revised (“SFAS No. 123(R)”), for their stock compensation. Generally, the approach to accounting in SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values.

Stock Options. Options under the Plan become exercisable as to 25% of the optioned shares each year after the date of grant, except options totaling 1,125,000 shares awarded in fiscal 2005 to Messrs. Edward Cohen and Jonathan Cohen which are immediately exercisable, and expire not later than ten years after the date of grant. Compensation cost is recorded on a straight line basis. The Company issues new shares when options are exercised or units are converted to shares. In fiscal 2007 and 2006, the Company received $917,000 and $32,500, respectively, from the exercise of options.

126

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 10 —BENEFIT PLANS- (Continued)

Transactions for stock options issued under the Plan are summarized as follows:

								Weighted
								Average			Aggregate
					Weighted			Remaining			Intrinsic
					Average			Contractual			Value
		Shares			Exercise Price			Term (in years)			(in thousands)
Outstanding at December 31, 2005			1,749,375		$	16.98
Granted			97,500		$	31.12
Exercised			(1,912	)		—
Forfeited or expired			(675	)	$	16.98
Outstanding at December 31, 2006			1,844,288		$	17.73
Granted			20,000		$	53.73
Exercised			(54,034	)	$	16.98
Forfeited or expired			―			―
Outstanding at December 31, 2007			1,810,254		$	18.15			7.6		$	74,279
Options exercisable at December 31, 2007			1,405,392		$	17.23			7.5
Available for grant at December 31, 2007			1,112,565

The Company used the Black-Scholes option pricing model in 2007 and 2006 to estimate the weighted average fair value of options granted. The per share weighted average fair value of stock options granted during 2005 was calculated using the binomial (lattice) model. The following weighted average assumptions were used for the periods indicated:

		Years Ended December 31,
		2007				2006				2005
Expected dividend yield			0.4	%			0	%			0	%
Expected stock price volatility			35	%			35	%			37	%
Risk-free interest rate			4.7	%			4.3-4.8	%			5.1	%
Expected term (in years)			6.25				6.25				6.5
Fair value of stock options granted		$	22.62			$	12.21-14.07			$	8.37

Deferred and Restricted Units. Under the Plan, non-employee directors of the Company are awarded deferred units that vest over a four year period. Each unit represents the right to receive one share of the Company’s common stock upon vesting. Units will vest sooner upon a change in control of the Company or death or disability of a grantee, provided the grantee has completed at least six month’s service. The fair value of the grants is based on the closing stock price on the grant date, and is being charged to operations over the requisite service periods using a straight-line attribution method. Upon termination of service by a grantee, all unvested units are forfeited.

Restricted units are granted from time to time to employees of the Company. Each unit represents the right to receive one share of the Company’s common stock upon vesting. The units are issued to the Restricted Stock Plan when granted, and paid to the Company’s employees upon vesting. The units vest one-fourth at each anniversary date over a four year service period. The fair value of the grant is based on the closing price on the grant date, and is being expensed over the requisite service period using a straight line attribution method.

127

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 10 — BENEFIT PLANS - (Continued)

The following table summarizes the activity of deferred and restricted units for the periods indicated:

					Weighted
					Average
					Grant Date
		Units			Fair Value
Non-vested shares outstanding at December 31, 2005			16,477		$	9.10
Granted			5,124		$	31.24
Vested			(3,623	)	$	6.89
Non-vested shares outstanding at December 31, 2006			17,978		$	15.89
Granted			2,147		$	41.89
Vested			(5,862	)	$	10.51
Forfeited			―			―
Non-vested shares outstanding at December 31, 2007			14,263		$	21.98

For the years ended December 31, 2007 and 2006, three months ended December 31, 2005 and year ended September 30, 2005, the Company recorded non cash compensation expense of $1.5 million, $1.4 million, $272,300 and $9,400, respectively for the Company’s options and units. At December 31, 2007, the Company had unamortized compensation expense related to its unvested portion of the options and units of $3.0 million that the Company expects to recognize over four years.

Employee Stock Ownership Plan. In connection with the spin-off from RAI, the Company established an Employee Stock Ownership Plan (“ESOP”) in June 2005. The ESOP, which is a qualified non-contributory retirement plan, was established to acquire shares of the Company’s common stock for the benefit of all employees who are 21 years of age or older and have completed 1,000 hours of service. These shares have been converted to Atlas America common stock from RAI stock in an even exchange. The Company loaned $602,000 (payable in quarterly installments of $18,508 plus interest at 7.5%) to the ESOP, which was used by the ESOP to acquire the remaining 40,375 unallocated shares of RAI common stock. Contributions to the ESOP are made at the discretion of the Company’s Board of Directors. The cost of shares purchased by the ESOP but not yet allocated to participants is shown as a reduction of stockholders’ equity. The unearned benefits expense (a reduction in stockholders’ equity) will be reduced by the amount of any loan principal payments made by the ESOP to the Company. Any dividends which may be paid on allocated shares will reduce retained earnings; dividends on unearned ESOP shares will be used to service the related debt.

The common stock purchased by the ESOP with the money borrowed is held by the ESOP trustee in a suspense account. On an annual basis, as the ESOP loan is paid down, a portion of the common stock will be released from the suspense account and allocated to participating employees. As of December 31, 2007, there were 497,735 shares allocated to participants and 47,655 shares which are unallocated. Compensation expense related to the plan amounted to $109,000, $114,000, $29,000 and $30,000 for the years ended December 31, 2007, 2006, three months ended December 31, 2005 and year ended September 30, 2005, respectively. The fair value of unearned ESOP shares was $2.8 million at December 31, 2007.

Supplemental Employment Retirement Plan (“SERP”). In May 2004, the Company entered into an employment agreement with its Chairman of the Board, Chief Executive Officer and President, Edward E. Cohen, pursuant to which the Company has agreed to provide him with a SERP and with certain financial benefits upon termination of his employment. Under the SERP, Mr. Cohen will be paid an annual benefit equal to the product of (a) 6.5% multiplied by, (b) his base salary at the time of his retirement, death or other termination of employment with the Company, multiplied by, (c) the amount of years he shall be employed by the Company commencing upon the effective date of the SERP agreement, limited to an annual maximum benefit of 65% of his final base salary and a minimum of 26% of his final base salary.

128

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 10 — BENEFIT PLANS - (Continued)

During the years ended December 31, 2007 and 2006, three months ended December 31, 2005 and year ended September 30, 2005, operations were charged $1.1 million, $381,000, $40,300, and $161,000, respectively, with respect to this commitment.

As of December 31, 2007 and 2006, the actuarial present value of the expected postretirement obligation due under this the SERP was $2.5 million and $1.3 million, respectively, which is included in Other liabilities on the Company’s consolidated balance sheets. The discount rates used were 7% and 8% at December 31, 2007 and 2006, respectively.

As a result of the adoption of SFAS 158 at December 31, 2006, the Company was required to record an additional long-term liability of $683,000 for the difference between the expected postretirement benefit of $1.3 million and the accumulated postretirement obligation the Company had recognized as of December 31, 2006. The additional amount of this liability is recognized net of tax as an additional component of other comprehensive income.

The following table summarizes the incremental effects of the initial adoption of SFAS 158 to the Consolidated Balance Sheet at December 31, 2006:

		At December 31, 2006
		(in thousands)
		Before application of SFAS 158			SFAS 158 Adjustments			After application of SFAS 158
Other liabilities		$	52,313		$	683		$	52,996
Deferred tax liability			82,574			(267	)		82,307
Total liabilities		$	134,887		$	416		$	135,303
Accumulated other comprehensive income		$	8,842		$	(416	)	$	8,426
Total stockholder’s equity		$	271,757		$	(416	)	$	271,341

The following table provides information about amounts recognized in the Company’s Consolidated Balance Sheets at the dates indicated (in thousands):

		December 31,
		2007			2006
Other liabilities		$	(2,475	)	$	(1,325	)
Accumulated other comprehensive loss			638			416
Deferred income tax asset			375			267
Net amount recognized		$	(1,462	)	$	(642	)

The estimated amount that will be amortized from accumulated other comprehensive loss into expense in 2008 is $522,500.

The Atlas Pipeline Holdings Long-term Incentive Plan.

In November 2006, the Board of Directors of AHD approved and adopted AHD’s Long-Term Incentive Plan (“AHD LTIP”), which provides performance incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for AHD. AHD’s LTIP is administered by a committee (the “LTIP Committee”), appointed by AHD’s board.

129

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 10 — BENEFIT PLANS - (Continued)

Under AHD’s LTIP, phantom units and/or unit options may be granted, at the discretion of AHD’s LTIP Committee, to all or designated Participants, at the discretion of AHD’s LTIP Committee. AHD’s LTIP Committee may grant such awards of either phantom units or unit options for an aggregate of 2,100,000 common limited partner units. At December 31, 2007, AHD had 1,435,825 phantom units and unit options outstanding under AHD’s LTIP, with 663,800 phantom units and unit options available for grant.

AHD Phantom Units. A phantom unit entitles a Participant to receive a common unit of AHD upon vesting of the phantom unit or, at the discretion of AHD’s LTIP Committee, cash equivalent to the then fair market value of a common limited partner unit of AHD. In tandem with phantom unit grants, AHD’s LTIP Committee may grant a Participant a distribution equivalent right (“DER”), which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions AHD makes on a common unit during the period such phantom unit is outstanding. AHD’s LTIP Committee will determine the vesting period for phantom units. Through December 31, 2007, phantom units granted under the LTIP generally will vest 25% three years from the date of grant and 100% four years from the date of grant. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by AHD’s LTIP Committee, although no awards currently outstanding contain any such provision. Awards will automatically vest upon a change of control of AHD, as defined in AHD’s LTIP. Of the phantom units outstanding under AHD’s LTIP at December 31, 2007, 675 units will vest within the following twelve months. All phantom units outstanding under AHD’s LTIP at December 31, 2007 include DERs granted to the Participants by AHD’s LTIP Committee. The amount paid with respect to AHD’s LTIP DERs was $0.2 million and $37,000 for the years ended December 31, 2007 and 2006, respectively. This amount was recorded as a reduction of Minority Interests on the Company’s Consolidated Balance Sheets.

The following table sets forth AHD’s LTIP phantom unit activity for the periods indicated:

		Years Ended December 31,
		2007			2006
Outstanding, beginning of year			220,492			—
Granted(1)			708			220,492
Matured			(375	)		—
Forfeited			—			—
Outstanding, end of year			220,825			220,492

⁽¹⁾ The weighted average price for phantom unit awards on the date of grant, which is utilized in the calculation of compensation expense and does not represent an exercise price to be paid by the recipient, was $37.46 and $22.56 for awards granted for the year ended December 31, 2007 and 2006, respectively.

Non-cash compensation expense of $1.4 million and $229,000 was recognized for the years ended December 31, 2007 and 2006, respectively. There was no such expense in 2005. At December 31, 2007, AHD had approximately $3.6 million of unrecognized compensation expense related to unvested phantom units outstanding under AHD’s LTIP based upon the fair value of the awards.

130

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 10 — BENEFIT PLANS - (Continued)

AHD Unit Options. A unit option entitles a Participant to receive a common unit of AHD upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of AHD’s common unit as determined by AHD’s LTIP Committee on the date of grant of the option. AHD’s LTIP Committee also shall determine how the exercise price may be paid by the Participant. AHD’s LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through December 31, 2007, unit options granted under AHD’s LTIP generally will vest 25% three years from the date of grant and 100% four years from the date of grant. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by AHD’s LTIP Committee, although no awards currently outstanding contain any such provision. Awards will automatically vest upon a change of control of AHD, as defined in AHD’s LTIP. There are no unit options outstanding under AHD’s LTIP at December 31, 2007 that will vest within the following twelve months. The following table sets forth the LTIP unit option activity for the periods indicated:

		Year Ended December 31, 2007						Year Ended December 31, 2006
					Weighted						Weighted
		Number			Average			Number			Average
		of Unit			Exercise			of Unit			Exercise
		Options			Price			Options			Price
Outstanding, beginning of year			1,215,000		$	22.56			—			—
Granted			—			—			1,215,000		$	22.56
Matured			—			—			—			—
Forfeited			—			—			—			—
Outstanding, end of year(1)(2)			1,215,000		$	22.56			1,215,000		$	22.56
Options exercisable, end of year			—			—			—			—
Weighted average fair value of unit options per unit granted during the year			—					$	3.76

(1) The weighted average remaining contractual life for outstanding options at December 31, 2007 was 8.9 years.

(2) The aggregate intrinsic value of options outstanding at December 31, 2007 was approximately $5.6 million.  

AHD used the Black-Scholes option pricing model to estimate the weighted average fair value of each unit option granted with weighted average assumptions for (a) expected dividend yield of 4.0%, (b) risk-free interest rate of 4.5%, (c) expected volatility of 20.0%, and (d) an expected life of 6.9 years.

Non-cash compensation expense of $1.2 million and $206,000 was recognized for the years ended December 31, 2007 and 2006, respectively. There was no such expense in 2005. At December 31, 2007, AHD had approximately $3.1 million of unrecognized compensation expense related to unvested unit options outstanding under AHD’s LTIP based upon the fair value of the awards.

131

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 10 — BENEFIT PLANS - (Continued)

APL Long-Term Incentive Plan

APL has a Long-Term Incentive Plan (“APL LTIP”), in which officers, employees and non-employee managing board members of the General Partner and employees of the General Partner’s affiliates and consultants are eligible to participate. The APL LTIP is administered by a committee (the “APL LTIP Committee”) appointed by APL’s managing board. The APL LTIP Committee may make awards of either phantom units or unit options for an aggregate of 435,000 common units. Only phantom units have been granted under the APL LTIP through December 31, 2007.

A phantom unit entitles a grantee to receive a common unit upon vesting of the phantom unit or, at the discretion of the APL LTIP Committee, cash equivalent to the fair market value of an APL common unit. In addition, the APL LTIP Committee may grant a participant a DER, which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions APL makes on a common unit during the period the phantom unit is outstanding. A unit option entitles the grantee to purchase APL’s common limited partner units at an exercise price determined by the APL LTIP Committee at its discretion. The APL LTIP Committee also has discretion to determine how the exercise price may be paid by the participant. Except for phantom units awarded to non-employee managing board members of AHD, the APL LTIP Committee will determine the vesting period for phantom units and the exercise period for options. Through December 31, 2007, phantom units granted under the APL LTIP generally had vesting periods of four years. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the APL LTIP Committee, although no awards currently outstanding contain any such provision. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards will automatically vest upon a change of control, as defined in the APL LTIP. Of the units outstanding under the APL LTIP at December 31, 2007, 56,481 units will vest within the following twelve months. All units outstanding under the APL LTIP at December 31, 2007 include DERs granted to the participants by the APL LTIP Comittee. The amounts paid with respect to APL LTIP DERs were $0.6 million, $0.4 million, $0.1 million and $0.3 million for the years ended December 31, 2007 and 2006, three months ended December 31, 2005 and year ended September 30, 2005, respectively. These amounts were recorded as reductions of Minority Interests on the Company’s Consolidated Balance Sheets.

The following table sets forth the APL LTIP phantom unit activity for the periods indicated:

			Years Ended December 31,
			2007			2006			Three Months Ended December 31, 2005			Year Ended September 30, 2005
Outstanding, beginning of year			159,067			110,128			109,706			58,329
Granted(1)			25,095			82,091			422			66,977
Matured			(51,166	)		(31,152	)		—			(14,581	)
Forfeited			(3,250	)		(2,000	)		—			(1,019	)
Outstanding, end of year			129,746			159,067			110,128			109,706

⁽¹⁾ The weighted average price for phantom unit awards on the date of grant, which is utilized in the calculation of compensation expense and does not represent an exercise price to be paid by the recipient, was $50.09, $45.45, $43.48 and $48.62 for awards granted for the years ended December 31, 2007 and 2006, three month ended December 31, 2005 and year ended September 30, 2005, respectively.  

Non-cash compensation expense of $2.9 million, $2 million, $485,000 and $2.1 million was recognized for the years ended December 31, 2007 and 2006, three months ended December 31, 2005 and year ended September 30, 2005, respectively. At December 31, 2007, APL had approximately $2.3 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIP based upon the fair value of the awards.

132

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 10 — BENEFIT PLANS - (Continued)

APL Incentive Compensation Agreements

APL has incentive compensation agreements which have granted awards to certain key employees retained from previously consummated acquisitions. These individuals are entitled to receive common units of APL upon the vesting of the awards, which was dependent upon the achievement of certain predetermined performance targets through September 30, 2007. At September 30, 2007, the predetermined performance targets were achieved and all of the awards under the incentive compensation agreements vested. Of the total common units to be issued under the incentive compensation agreements, 58,822 were issued during the year ended December 31, 2007. The remaining common units to be issued under the incentive compensation agreements will be determined based upon the financial performance of certain Partnership assets for the year ended December 31, 2008. The incentive compensation agreements also dictates that no individual covered under the agreements shall receive an amount of common units in excess of one percent of the outstanding common units of APL at the date of issuance. Common unit amounts due to any individual covered under the agreements in excess of one percent of the outstanding common units of APL shall be paid in cash.

APL recognized compensation expense of $33.4 million, $4.3 million, $461,000, and $1.1 million for the years ended December 31, 2007 and 2006, three months ended December 31, 2005, and year ended September 30, 2005, respectively, related to the vesting of awards under these incentive compensation agreements. The increase in non-cash compensation expense in 2007 was due to an increase in common unit awards estimated by management to be issued under incentive compensation agreements to certain key employees as a result of the acquisition of the Chaney Dell and Midkiff/Benedum systems. The ultimate number of common units estimated to be issued under the incentive compensation agreements will be determined by the financial performance of certain APL assets for the year ended December 31, 2008. The vesting period for such awards concluded on September 30, 2007 and all compensation expense related to the awards was recorded as of that date. Management anticipates that adjustments will be recorded in future periods with respect to the awards under the incentive compensation agreements based upon the actual financial performance of the assets in future periods in comparison to their estimated performance. Based upon management’s estimate of the probable outcome of the performance targets at December 31, 2007, 948,847 common unit awards are ultimately expected to be issued under these agreements, which represents the amount of common units expected to be issued under the incentive compensation agreements. APL follows SFAS No. 123(R) and recognized compensation expense related to these awards based upon the fair value method.

Atlas Energy Resources, LLC Long-Term Incentive Plan

Stock Incentive Plan. In December 2006, ATN adopted a Long-Term Incentive Plan (“ATN LTIP”), which provides performance incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners. The ATN LTIP is administered by AAI’s compensation committee, which may grant awards of either restricted stock units, phantom units or unit options for an aggregate of 3,742,000 common units. Awards granted in 2007 vest 25% after three years and 100% upon the four year anniversary of grant, except for awards of 1,500 units to board members which vest 25% per year over four years. Awards granted in 2006 vest 25% per year over four years. Upon termination of service by a grantee, all unvested awards are forfeited. A restricted or phantom stock unit entitles a grantee to receive a common unit of the Company upon vesting of the restricted and phantom unit or, at the discretion of AAI’s compensation committee, cash equivalent to the then fair market value of a common unit of ATN. In tandem with phantom unit grants, AAI’s compensation committee may grant a distribution equivalent right (“DER”), which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions ATN makes on a common unit during the period such phantom unit is outstanding.

Restricted and Phantom Stock Units. Under the ATN LTIP, 590,950 and 47,619 units of restricted and phantom stock were awarded in 2007 and 2006, respectively. The fair value of the grants is based on the closing stock price on the grant date, and is being charged to operations over the requisite service periods using a straight line attribution method.

133

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 10 — BENEFIT PLANS - (Continued)

The following table summarizes the activity of restricted and phantom stock units for the periods indicated:

					Weighted
					Average
					Grant Date
		Units			Fair Value
Non-vested units outstanding at December 31, 2005			—		$	—
Granted			47,619		$	21.00
Non-vested units outstanding at December 31, 2006			47,619		$	21.00
Granted			590,950		$	24.63
Vested			(11,904	)	$	21.00
Forfeited			(2,000	)	$	23.06
Non-vested units outstanding at December 31, 2007			624,665		$	24.42

Stock Options. In fiscal 2007 and in December 2006, 1,532,000 and 373,752 unit options, respectively, were awarded under the ATN LTIP. Option awards expire 10 years from the date of grant and are generally granted with an exercise price equal to the market price of ATN’s stock at the date of grant. ATN uses the Black-Scholes option pricing model to estimate the weighted average fair value per option granted with the following assumptions:

		Years Ended December 31,
		2007			2006
Expected life (years)			6.25			6.25
Expected volatility			25	%		25	%
Risk-free interest rate			4.7	%		4.4	%
Expected dividend yield			5.1-8.0	%		8.0	%
Weighted average fair value of stock options granted		$	2.96		$	2.14

The following table sets forth option activity for ATN for the periods indicated:

		Units			Weighted Average Exercise Price			Weighted Average Remaining Contractual Term (in years)			Aggregate Intrinsic Value (in thousands)
Outstanding at December 31, 2005			—		$	—
Granted			373,752		$	21.00
Outstanding at December 31, 2006			373,752		$	21.00
Granted			1,532,000		$	24.84
Exercised			—			—
Forfeited or expired			(10,700	)	$	23.06
Outstanding at December 31, 2007			1,895,052		$	24.09			8.9		$	13,256
Options exercisable at December 31, 2006			93,438		$	21.00			9.0
Available for grant at December 31, 2007			1,210,379

134

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 10 — BENEFIT PLANS - (Continued)

The following tables summarize information about stock options outstanding and exercisable for ATN at December 31, 2007: 

			Options Outstanding									Options Exercisable
Range of Exercise Prices			Number of Units Outstanding			Weighted -Average Remaining Contractual Life in Years			Weighted- Average Exercise Price			Number of Units Exercisable			Weighted - Average Exercise Price
$21.00-$23.06			1,659,452			9.0		$	22.60			93,438		$	21.00
$34.18-$35.00			235,600			9.5		$	34.65			—			—
			1,895,052			8.9		$	24.09			93,438		$	21.00

ATN recognized $4.7 million and $337,000 in compensation expense related to restricted stock units and stock options for the years ended December 31, 2007 and 2006, respectively. There was no such expense for the three months ended December 31, 2005 or the year ended September 30, 2005. ATN paid $778,000 with respect to its LTIP DERs for the years ended December 31, 2007 and 2006. At December 31, 2007, ATN had approximately $15.8 million of unrecognized compensation expense related to the unvested portion of the restricted stock units and options.

135

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 11 — COMMITMENTS AND CONTINGENCIES

The Company leases office space and equipment under leases with varying expiration dates through 2014. Rental expense was $6.6 million, $4.4 million, $1.3 million and $2.8 million for the years ended December 31, 2007 and 2006, three months ended December 31, 2005 and year ended September 30, 2005, respectively. Future minimum rental commitments for the next five years are as follows (in thousands):

2008		$	5,402
2009			2,903
2010			2,330
2011			1,792
2012			1,423

The Company, through Atlas Energy, is the managing general partner of various energy partnerships, and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of partnership assets. Subject to certain conditions, investor partners in certain energy partnerships have the right to present their interests for purchase by the Company, as managing general partner. Atlas Energy is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based on past experience, the Company believes that any liability incurred would not be material.

Atlas Energy may be required to subordinate a part of its net partnership revenues from Atlas Energy’s energy partnerships to the receipt by investor partners of cash distributions from the energy partnerships equal to at least 10% of their subscriptions determined on a cumulative basis, in accordance with the terms of the partnership agreements.

The Company is party to employment agreements with certain executives that provide compensation and certain other benefits. The agreements also provide for severance payments under certain circumstances.

One of the Company’s subsidiaries, Resource Energy, LLC, together with Resource America, Inc. (the Company’s former parent) 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 the Company. The complaint alleged that the Company was 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, in May 2007 the Company paid $300,000, upgraded certain gathering systems and capped certain transportation expenses chargeable to the land owners.

Atlas Gas & Oil Company LLC, as successor to DTE Gas & Oil Company, is one of four defendants in a personal injury action filed in Antrim County Circuit Court in northern Michigan in August, 2006.  The complaint alleges that plaintiff suffered serious personal injuries as a result of the defendants’ negligence. A tentative settlement of this lawsuit was reached, the terms of which are subject to final approval by the court. Pursuant to the settlement terms, the Company paid $125,000 to the plaintiff in October 2007.

As of December 31, 2007, APL in committed to expend approximately $168.4 million on pipeline extensions, compressor station upgrades, and processing facility upgrades.

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

136

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 12 — OPERATIONS OF ATLAS PIPELINE

In February 2000, the Company’s natural gas gathering operations were sold to Atlas Pipeline in connection with a public offering by Atlas Pipeline of 1,500,000 common units. The Company received net proceeds of $15.3 million for the gathering systems, and Atlas Pipeline issued to the Company 1,641,026 subordinated units then constituting a 51% combined general and limited partner interest in Atlas Pipeline. A subsidiary of the Company is the general partner of Atlas Pipeline and has a 2% general partner interest on a consolidated basis. The Company’s general partner interest also includes a right to receive incentive distributions if the partnership meets or exceeds specified levels of distributions.

In connection with the Company’s sale of the gathering systems to Atlas Pipeline, the Company entered into an agreement that requires it to pay gathering fees to Atlas Pipeline for natural gas gathered by the gathering systems equal to the greater of $.35 per Mcf ($.40 per Mcf in certain instances) or 16% of the gross sales price of the natural gas transported. During all periods presented in the Company’s consolidated financial statements, the fee paid to Atlas Pipeline was calculated based on the 16% rate.

The Company’s subordinated units were a special class of limited partner interest in Atlas Pipeline under which its rights to distributions were subordinated to those of the publicly held common units. In January 2005, these subordinated units were converted to common units as Atlas Pipeline met stipulated financial tests under the terms of the partnership agreement allowing for such conversions. While the Company’s rights as the holder of the subordinated units are no longer subordinated to the rights of the common unitholders, these units have not yet been registered with the Securities and Exchange Commission, and therefore, their resale in the public market is subject to restrictions under the Securities Act.

In September 2003, Atlas Pipeline entered into an agreement with SEMCO Energy, Inc. (“SEMCO”) to purchase all of the stock of Alaska Pipeline. In order to complete the acquisition, Atlas Pipeline needed the approval of the Regulatory Commission of Alaska. The Regulatory Commission initially approved the transaction, but on June 4, 2004, it vacated its order of approval based upon a motion for clarification or reconsideration filed by SEMCO. On July 1, 2004, SEMCO sent Atlas Pipeline a notice purporting to terminate the transaction. Atlas Pipeline pursued its remedies under the acquisition agreement. In connection with the acquisition, subsequent termination and legal action, Atlas Pipeline incurred costs of approximately $4.0 million. On December 30, 2004, Atlas Pipeline entered into a settlement agreement with SEMCO settling all issues and matters related to SEMCO’s termination of the sale of Alaska Pipeline to Atlas Pipeline and SEMCO paid Atlas Pipeline $5.5 million. Atlas Pipeline recognized a gain of $1.5 million for the year ended September 30, 2005 on this settlement which is shown as arbitration settlement, net, on its consolidated statements of income.

137

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 13 — OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMERS

The Company’s operations include three reportable operating segments. These operating segments reflect the way the Company manages its operations and makes business decisions. The Company does not allocate income taxes to its operating segments. Operating segment data for the periods indicated are as follows (in thousands):

		Years Ended December 31,						Three Months Ended December 31			Year Ended September 30,
		2007			2006			2005			2005
Gas and Oil Production
Revenues (a)		$	206,382		$	88,449		$	24,086		$	63,499
Costs and Expenses			(24,184	)		(8,499	)		(1,721	)		(6,044	)
Segment Profit		$	182,198		$	79,950		$	22,365		$	57,455
Well Construction and Completion
Revenues		$	321,471		$	198,567		$	42,145		$	134,338
Costs and Expenses			(279,540	)		(172,666	)		(36,648	)		(116,816	)
Segment Profit		$	41,931		$	25,901		$	5,497		$	17,522
Atlas Pipeline
Revenues (b)		$	629,750		$	428,324		$	127,334		$	260,357
Revenues - affiliates			33,571			30,257			7,930			21,929
Costs and Expenses			(635,675	)		(360,869	)		(109,851	)		(229,764	)
Segment Profit		$	27,646		$	97,712		$	25,413		$	52,522
Reconciliation of segment profit to net income before tax
Segment profit
Gas and oil production		$	182,198		$	79,950		$	22,365		$	57,455
Well construction and completion			41,931			25,901			5,497			17,522
Atlas Pipeline			27,646			97,712			25,413			52,522
Total segment profit			251,775			203,563			53,275			127,499
General and administrative expenses			(111,636	)		(46,517	)		(9,453	)		(23,961	)
Compensation reimbursement affiliate			(930	)		(1,237	)		(163	)		(602	)
Depreciation, depletion and amortization			(107,917	)		(45,643	)		(10,324	)		(24,895	)
Other income (expense) - net (c)			18,686			(40,836	)		(14,725	)		(25,083	)
Net income before tax		$	49,978		$	69,330		$	18,610		$	52,958
Capital Expenditures
Gas and oil production		$	187,483		$	74,075		$	16,610		$	57,894
Well construction and completion			—			—			—			—
Atlas Pipeline			152,890			83,831			14,622			40,061
Corporate and other			9,252			1,560			577			1,230
		$	349,625		$	159,466		$	31,809		$	99,185

		December 31, 2007			December 31, 2006
Balance Sheet
Goodwill
Gas and oil production		$	21,527		$	21,527
Well Construction and Completion			6,389			6,389
Atlas Pipeline			709,283			63,441
Corporate and other			7,250			7,250
		$	744,449		$	98,607
Total Assets
Gas and oil production		$	1,821,631		$	377,807
Well Construction and Completion			11,138			8,335
Atlas Pipeline			2,877,518			787,128
Corporate and other			196,242			206,568
		$	4,906,529		$	1,379,838

138

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 13 — OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMERS - (Continued)

(a) Includes ineffective derivative gain of $26.3 million for the year ended December 31, 2007.

(b) Includes gain (loss) on mark-to-market derivatives of ($179.6) million, $2.3 million, ($138,000), and $1.9 million.

(c) Includes revenues and expenses from well services, transportation and administration and oversight of $7,099, ($3,804), ($2,524) and ($3,662) that do not meet the quantitative threshold for reporting segment information for the years ended December 31, 2007 and 2006, three months ended December 31, 2005 and year ended September 30, 2005, respectively.

Operating profit (loss) per segment represents total revenues less costs and expenses attributable thereto, excluding interest, provision for possible losses and depreciation, depletion and amortization, and general corporate expenses.

The Company’s NGL’s and natural gas are sold under contract to various purchasers. For the year ended December 31, 2007, sales to one customer accounted for approximately 37% of our total consolidated revenues. For the year ended December 31, 2006, sales to two customers accounted for 22% and 12% of our total consolidated revenues. For the year ended September 30, 2005, NGL sales to one customer accounted for 20% of total consolidated revenues. No other operating segments had revenues from a single customer which exceeded 10% of total revenues.

NOTE 14 — COMMON STOCK

Stock splits

On April 27, 2007, the Company’s Board of Directors approved a 3-for-2 stock split of the Company’s common stock effected in the form of a 50% stock dividend. All shareholders of record as of May 15, 2007 received one additional share of common stock for every two shares of common stock held on that date. The additional shares of common stock were distributed on May 25, 2007. Information pertaining to shares and earnings per share has been restated in the accompanying financial statements and notes to the consolidated financial statements to reflect this split.

On February 6, 2006, the Company’s Board of Directors approved a three-for-two split of the Company’s common stock effected in the form of a 50% stock dividend. All shareholders of record as of February 28, 2006 received one additional share of common stock for every two shares held on that date. The additional shares of common stock were distributed on March 10, 2006, in the form of a stock dividend.

Dutch Auction Tender Offer

On January 30, 2007, the Company announced that the Board of Directors had authorized a “Dutch Auction” tender offer for up to 1,950,000 shares of the Company’s common stock at an anticipated offer range of between $52.00 and $54.00 per share. The tender offer commenced on February 8, 2007 and expired on March 9, 2007. In connection with this offering, the Company purchased 1,486,605 shares at a cost of $80.4 million, including expenses.

Treasury Stock Repurchase Program

In November 2005, the Company announced that its Board of Directors authorized a repurchase program through which the Company might repurchase up to $50.0 million of its common stock. Repurchases were made from time to time through open market purchases or privately negotiated transactions at the discretion of the Company and in accordance with the rules of the Securities and Exchange Commission, as applicable. The Company repurchased 667,342 shares at a cost of $29.9 million during the year ended December 31, 2006.

139

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 15 - ISSUANCE OF SUBSIDIARY UNITS

The Company accounts for offerings by its subsidiaries in accordance with Staff Accounting Bulletin No. 51, Accounting by the Parent in Consolidation for Sales of Stock by a Subsidiary, (“SAB 51”). The Company has adopted a policy to recognize gains on such transactions as a credit to equity rather than as income. These gains represent the Company’s portion of the excess net offering price per unit of each of its subsidiary’s units to the book carrying amount per unit.

In July 2007, Atlas Pipeline Holdings issued 6.5 million common units (an approximate 27% interest in it) for net proceeds of $167.2 million after offering costs in a private placement offering. In addition, in July 2007 Atlas Pipeline issued 25.6 million common units through a private placement to investors, of which 3.8 million units were purchased by Atlas Pipeline Holdings. The Company has accounted for these offerings in accordance with SAB 51. Accordingly, a gain of $53.0 million, net of an income tax provision of $34.3 million was recorded in consolidated equity as an increase to paid-in capital as well as a corresponding adjustment of $87.3 million to minority interest, in the year ended December 31, 2007. The Company has adopted a policy to recognize gains on such transactions as an increase directly to equity rather than as income. This gain represents the Company’s portion of the excess net offering price per unit of each of its subsidiary’s units to the book carrying amount per unit.

In June 2007, Atlas Energy issued 24.0 million Class B common and Class D units (an approximate 31% interest in it) for net proceeds of $597.5 million after offering costs in a private placement offering. The Company has accounted for this offering in accordance with SAB 51. Accordingly, a gain of $147.9 million, net of an income tax provision of $87.5 million was recorded in consolidated equity as an increase to paid-in capital as well as a corresponding adjustment of $235.4 million to minority interest, in the six months ended June 30, 2007. This gain represents the Company’s portion of the excess net offering price per unit of its subsidiary’s units to the book carrying amount per unit.

In December 2006, Atlas Energy issued 7.3 million common units (an approximate 19.4% interest in it) for net proceeds of $139.9 million after offering costs in a private placement offering. Accordingly, in accordance with SAB 51, the Company recognized a gain of $44.1 million, net of an income tax provision of $31.9 million, which was recorded in consolidated equity as a credit to paid-in capital as well as a corresponding adjustment of $76.0 million to minority interest. .

In July 2006, Atlas Pipeline Holdings issued 3.6 million common units (an approximate 17.1% in it) resulting in net proceeds of approximately $74.3 million after offering costs. Accordingly, in accordance with SAB 51, the Company recognized a gain of $37.9 million, net of an income tax provision of $27.4 million, which was recorded in consolidated equity as a credit to paid-in capital as well as a corresponding adjustment of $65.3 million to minority interest.

In May 2006, Atlas Pipeline issued 500,000 common units (an approximate 4% interest in it) resulting in net proceeds of approximately $19.7 million after offering costs. Accordingly, the Company recognized a gain of $1.1 million, net of an income tax provision of $452,000, which was recorded in consolidated equity as a credit to paid-in capital as well as a corresponding adjustment of $626,000 to minority interest.

The Company has experienced sales of subsidiary units in years prior to 2006 and had not previously recorded a gain on such sales. It has been determined by the Company after applying Staff Accounting Bulletin No. 99, Materiality, that the recording of such gains was not material to its results of operations or financial position for such years and the Company has recorded cumulative gains in the December 31, 2006 financial statements.

140

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 15 - ISSUANCE OF SUBSIDIARY UNITS- (Continued)

The following table provides information about the current and prior year gains for the Company’s sale of subsidiary units (in thousands):  

Year Ended		Subsidiary			Gain			Tax Provision			Gain-Net of Tax
Year ended December, 31, 2007			Atlas Energy		$	235,438		$	87,521		$	147,917
Year ended December, 31, 2006			Atlas Energy			76,034			31,920			44,114
Year ended December, 31, 2006			Atlas Pipeline			1,078			452			626
Year ended December 2003 to 2005			Atlas Pipeline			45,821			19,236			26,585
Year ended December 31, 2007			AHD			87,295			34,316			52,979
Year ended December 31, 2006			AHD			65,366			27,442			37,924
					$	511,032		$	200,887		$	310,145

NOTE 16 - CASH DISTRIBUTIONS

The Company receives quarterly cash distributions from Atlas Pipeline Holdings and Atlas Energy Resources according to the policies described below.

Atlas Pipeline Holdings Cash Distributions. Upon completion of its initial public offering, AHD adopted a cash distribution policy under which it distributes, within 50 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter to its common unit holders. Distributions declared by AHD and paid to the Company from inception are as follows:

Date Cash Distribution Paid or Payable		For Quarter Ended			Cash Distribution per Common Limited Partner Unit			Total Cash Distribution to the Company (in thousands)
November 19, 2006			September 30, 2006		$	0.17	(1)	$	2,975
February 19, 2007			December 31, 2006		$	0.25		$	4,375
May 18, 2007			March 31, 2007		$	0.25		$	4,375
August 17, 2007			June 30, 2007		$	0.26		$	4,550
November 19, 2007			September 30, 2007		$	0.32		$	5,600
February 19, 2008(2)			December 31, 2007		$	0.34		$	5,950

(1) Represents a pro-rated cash distribution of $0.24 per common unit for the period from July 26, 2006, the date of the AHD’s initial public offering, through September 30, 2006.

(2) Declared Subsequent to December 31, 2007

In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see Note 3), the Partnership, which holds all of the incentive distribution rights in APL, agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter.

141

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 16 - CASH DISTRIBUTIONS - (Continued) 

Atlas Energy Resources Cash Distributions. Upon completion of its initial public offering, Atlas Energy adopted a cash distribution policy under which it distributes, within 45 days after the end of each quarter, all of its available cash (as defined in its limited liability agreement) for that quarter. Distributions declared by Atlas Energy and paid to the Company from inception are as follows:

						Cash Distribution			Total Cash			Manager
Date Cash						Per			Distribution			Incentive
Distribution			For Quarter			Common			to the			Distribution
Paid or Payable			Ended			Unit			Company			Earned (3)
									(in thousands)			(in thousands)
February 14, 2007			December 31, 2006		$	0.06	(1)	$	1,806
May 15, 2007			March 31, 2007		$	0.43		$	12,944
August 14, 2007			June 30, 2007		$	0.43		$	12,944
November 14, 2007			September 30, 2007		$	0.55		$	16,825		$	784
February 14 , 2008(2)			December 31, 2007		$	0.57		$	17,437		$	965

(1) Represents a pro-rated cash distribution of $0.42 per unit for the period from December 18, 2006, the date of Atlas Energy’s initial public offering, through December 31, 2006.

(2) Declared subsequent to December 31, 2007.

(3) Payable to the Company in 2010, provided Atlas Energy meets certain distribution levels.

NOTE 17— INVESTMENT IN LIGHTFOOT

In 2007, the Company’s subsidiary, Atlas Lightfoot, LLC, invested $10.4 million in Lightfoot Capital Partners LP (“Lightfoot”) and owns, directly and indirectly, approximately 18% of Lightfoot Capital Partners GP, LLC, the general partner of Lightfoot of whom Jonathan Cohen, Vice Chairman of the Company’s Board of Directors, is the Chairman of the Board. The Company committed to invest a total of $20.0 million in Lightfoot. The Company will also receive certain co-investment rights until such point as Lightfoot raises additional capital through a private offering to institutional investors or a public offering. Lightfoot has an initial equity funding commitments of approximately $160.0 million and intends to focus its investments primarily on incubating new master limited partnerships (“MLPs”) and providing capital to existing MLPs in need of additional equity or structured debt. Lightfoot will concentrate on assets that are MLP-qualified such as infrastructure, coal, and other asset categories and intends to form new MLPs in partnership with premier management teams in sectors that have been under-utilized by the MLP structure. The Company accounts for its investment in Lightfoot under the equity method of accounting.

NOTE 18 - SUBSEQUENT EVENTS

Cash Dividend. On January 28, 2008, the Company announced that its Board of Directors had declared a cash dividend of $0.05 per share of common stock, payable on February 14, 2008, to holders of record on February 7, 2008.

Atlas Energy bond offering. On January 18, 2008, the Company sold $250.0 million of senior unsecured notes due in 2018 in a private placement at a coupon rate of 10.75%. The Company used the proceeds of the note offering to reduce the balance outstanding on its senior secured credit facility. The Company will benefit from a reduction of 75 basis points in the interest rate on the remaining approximately $500.0 million outstanding on that credit facility, and will increase the long term availability of funds on the facility by approximately $180.0 million. Additionally, the Company entered into an interest rate swap contract for $150.0 million. Atlas Energy will swap the floating rate incurred on a portion of its 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.

Atlas Pipeline interest rate swap. During January 2008, Atlas Pipeline entered into interest rate derivative contracts having an aggregate notional principal amount of $200.0 million. Under the terms of this agreement, Atlas Pipeline will pay 2.88%, plus the applicable margin as defined under the terms of its credit facility, and will receive LIBOR plus the applicable margin, on the notional principal amount of $200.0 million. This hedge effectively converts $200.0 million of Atlas Pipeline’s floating rate debt under the credit facility to fixed-rate debt. The interest rate swap agreement begins on January 31, 2008 and expires on January 31, 2010.

142

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 19 — SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Results of operations from oil and gas producing activities during the periods indicated are as follows (in thousands):

		Years Ended						Three Months Ended			Year Ended
		December 31,						December 31,			September 30,
		2007			2006			2005			2005
Revenues (1)		$	206,382		$	88,449		$	24,086		$	63,499
Production costs			(24,184	)		(8,499	)		(1,721	)		(6,044	)
Exploration expenses			(4,065	)		(3,016	)		(17	)		(904	)
Depreciation, depletion and amortization			(54,383	)		(20,600	)		(4,477	)		(12,288	)
Income taxes			(36,259	)		(22,196	)		(6,612	)		(16,731	)
		$	87,491		$	34,138		$	11,259		$	27,532

⁽¹⁾ Includes gain from mark to market derivatives of $26.3 million.

Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to the Company’s oil and gas producing activities at the dates indicated are as follows (in thousands):

								At			At
		At December 31,						December 31,			September 30,
		2007			2006			2005			2005
Natural gas and oil properties:
Proved properties		$	1,795,871		$	349,882		$	276,033		$	258,731
Unproved properties			16,380			1,002			1,002			1,002
Support equipment			6,936			5,541			4,170			3,644
		$	1,819,187		$	356,425		$	281,205		$	263,377
Accumulated depreciation, depletion and amortization (1)			(136,603	)		(83,182	)		(71,032	)		(66,536	)
		$	1,682,584		$	273,243		$	210,173		$	196,841

⁽¹⁾ Costs related to unproved properties are excluded from amortization as they are assessed for impairment.

Costs Incurred in Oil and Gas Producing Activities. The costs incurred by the Company in its oil and gas activities during the periods indicated are as follows (in thousands): 

		Years Ended						Three Months Ended			Year Ended
		December 31,						December 31,			September 30,
		2007			2006			2005			2005
Property acquisition costs:
Proved properties		$	1,243,877		$	1,322		$	—		$	308
Unproved properties			50,100			—			—			—
Exploration Costs			4,065			6,847			1,312			904
Development Costs			168,253			76,687			17,380			72,308
		$	1,466,295		$	84,856		$	18,692		$	73,520

The development costs above for the periods above were substantially all incurred for the development of proved undeveloped properties.

143

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 19 — SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - (Continued)

Oil and Gas Reserve Information (Unaudited). The estimates of the Company’s proved and unproved gas reserves are based upon evaluations made by management and verified by Wright & Company, Inc., an independent petroleum engineering firm, as of December 31 2007, 2006 and 2005 and September 30, 2005. All reserves are located within the United States. Reserves are estimated in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board which require that reserve estimates be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

· Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

· Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

· Estimates of proved reserves do not include the following: (a) oil that may become available from known reservoirs but is classified separately as “indicated additional reservoirs”; (b) crude oil, natural gas, and NGLs, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors; (c) crude oil, natural gas and NGLs, that may occur in undrilled prospects; and (d) crude oil and natural gas, and NGLs, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operation methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

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

144

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 19 — SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - (Continued)

The Company’s reconciliation of changes in proved reserve quantities is as follows (unaudited):

		Gas (Mcf)			Oil (Bbls)
Balance September 30, 2004			142,133,365			2,274,712
Extensions, discoveries and other additions			33,364,097			95,552
Sales of reserves in-place			(226,237	)		(1,010	)
Purchase of reserves in-place			116,934			575
Transfers to limited partnerships			(7,104,731	)		(148,899	)
Revisions			(2,631,044	)		196,263
Production			(7,625,695	)		(157,904	)
Balance September 30, 2005			158,026,689			2,259,289
Extensions, discoveries and other additions			8,357,940			36,931
Sales of reserves in-place			(59,873	)		—
Purchase of reserves in-place			6,132			16
Transfers to limited partnerships			(4,740,605	)		—
Revisions			(1,690,863	)		653
Production			(1,975,070	)		(39,678	)
Balance December 31, 2005			157,924,350			2,257,211
Extensions, discoveries and other additions			46,205,382			12,920
Sales of reserves in-place			(127,472	)		(703	)
Purchase of reserves in-place			305,433			1,675
Transfers to limited partnerships			(6,671,754	)		(19,235	)
Revisions			(20,147,989	)		(33,594	)
Production			(8,946,376	)		(150,628	)
Balance December 31, 2006			168,541,574			2,067,646
Extensions, discoveries and other additions			126,613,549			23,358
Sales of reserves in-place			(62,699	)		(625	)
Purchase of reserves in-place			622,851,730			48,634
Transfers to limited partnerships			(11,507,307	)		—
Revisions			(714,501	)		(2,517	)
Production			(20,963,436	)		(153,465	)
Balance December 31, 2007			884,758,910			1,983,031
Proved developed reserves at:
September 30, 2004			95,788,656			2,125,813
September 30, 2005			104,786,047			2,116,412
December 31, 2005			108,674,675			2,122,568
December 31, 2006			107,683,343			2,064,276
December 31, 2007			594,708,965			1,977,446

145

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 19 — SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - (Continued)

The following schedule presents the standardized measure of estimated discounted future net cash flows relating to proved oil and gas reserves. The estimated future production is priced at year-end prices, adjusted only for fixed and determinable increases in natural gas and oil prices provided by contractual agreements. The resulting estimated future cash inflows are reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows are reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations (unaudited) (in thousands).

		Years Ended						Three Months Ended			Year Ended
		December 31,						December 31,			September 30,
		2007			2006			2005			2005
Future cash inflows		$	6,408,367		$	1,262,161		$	1,874,432		$	2,503,644
Future production costs			(1,804,199	)		(334,062	)		(290,600	)		(296,015	)
Future development costs			(388,111	)		(149,610	)		(107,784	)		(117,256	)
Future income tax expense			(996,877	)		(225,082	)		(445,004	)		(607,624	)
Future net cash flows			3,219,180			553,407			1,031,044			1,482,749
Less 10% annual discount for estimated timing of cash flows			(2,074,190	)		(347,887	)		(601,772	)		(876,052	)
Standardized measure of discounted future net cash flows			1,144,990		$	205,520		$	429,272		$	606,697

The future cash flows estimated to be spent to develop proved undeveloped properties in the years ended December 31, 2008, 2009, 2010 2011, and 2012 are $112.2 million, $113.1 million, $108.5 million, $37.0 million and $17.3 million respectively.

The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves after income taxes (unaudited) (in thousands):

			Years Ended						Three Months Ended			Year Ended
			December 31,						December 31,			September 30,
			2007			2006			2005			2005
Balance, beginning of year		$	205,520		$	429,272		$	606,697		$	232,998
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs			(155,992	)		(79,950	)		(21,645	)		(55,333	)
Net changes in prices and production costs			45,261			(273,631	)		(245,838	)		417,798
Revisions of previous quantity estimates			(1,208	)		(30,058	)		(4,571	)		(6,073	)
Development costs incurred			98,424			3,426			2,727			4,224
Changes in future development costs			(14,128	)		(8,505	)		(1,159	)		(1,577	)
Transfers to limited partnerships			(13,998	)		(8,449	)		(8,563	)		(24,750	)
Extensions, discoveries, and improved recovery less related costs			170,349			44,820			22,597			154,215
Purchases of reserves in-place			957,137			660			24			596
Sales of reserves in-place, net of tax effect			(105	)		(572	)		(243	)		(672	)
Accretion of discount			74,685			59,714			21,141			32,038
Net changes in future income taxes			(261,459	)		93,137			71,614			(151,882	)
Estimated settlement of asset retirement obligations			(4,523	)		(8,226	)		(848	)		(12,763	)
Estimated proceeds on disposals of well equipment			5,168			10,007			998			12,740
Other			39,859			(26,125	)		(13,659	)		5,138
Balance, end of year		$	1,144,990		$	205,520		$	429,272		$	606,697

146

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2007

NOTE 20 — QUARTERLY RESULTS (Unaudited)

Year ended December 31, 2007		March 31, 2007			June 30, 2007			September 30, 2007			December 31, 2007
		(in thousands, except per share data)
Revenues		$	214,915		$	214,866		$	411,526		$	366,340
Income from continuing operations before income taxes		$	16,267		$	28,000		$	10,199		$	(4,488	)
Net income (loss)		$	10,248		$	19,866		$	7,103		$	(1,881	)
Net income (loss) per common share - basic		$	0.54		$	0.74		$	0.26		$	(0.07	)
Net income (loss) per common share - diluted		$	0.53		$	0.71		$	0.25		$	(0.07	)

Year ended December 31, 2006		March 31, 2006			June 30, 2006			September 30, 2006			December 31, 2006
		(in thousands, except per share data)
Revenues		$	192,459		$	164,810		$	190,617		$	201,420
Income from continuing operations before income taxes		$	18,033		$	17,758		$	16,272		$	17,267
Net income		$	11,361		$	10,100		$	9,970		$	14,416
Net income per common share - basic		$	0.38		$	0.34		$	0.34		$	0.50
Net income per common share - diluted		$	0.37		$	0.33		$	0.33		$	0.49

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our Chief Executive Officer and Chief Financial Officer, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2007, our disclosure controls and procedures were effective at the reasonable assurance level.

Management’s Report on Internal Control over Financial Reporting

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

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

In conducting management’s evaluation of the effectiveness of its internal control over financial reporting, management has excluded, due to its size and complexity, the operations of Atlas Gas and Oil, LLC (AGO), which ATN acquired in June 2007, from its December 31, 2007 Sarbanes-Oxley 404 review. AGO constituted approximately 28% of our total assets as of December 31, 2007 and 8% of our total revenues for the year ended December 31, 2007. In addition, management has excluded, due to its size and complexity, the operations of APL's newly acquired Chaney Dell and Midkiff/Benedum systems, The Chaney Dell and Midkiff/Benedum systems constituted 40% of our total assets as of December 31, 2007 and 23% of our total revenues for the year ended December 31, 2007. We believe that management had sufficient cause to exclude both acquisitions in their evaluations of the effectiveness of its internal control over financial reporting based on the size, complexity, and timing of the acquisition.

Based on our evaluation under the COSO framework, management concluded that our internal control over financial reporting as of December 31, 2007 was effective.

Grant Thornton, LLP, an independent registered public accounting firm, has issued an attestation report on our internal control over financial reporting as of December 31, 2007.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

Atlas America, Inc.

We have audited Atlas America, Inc.’s (the “Company”) (a Delaware corporation) internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Atlas America, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on Atlas America, Inc.’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

As indicated in the accompanying Management’s Report on Internal Control over Financial Reporting, in conducting management’s assessment of and conclusion on the effectiveness of internal controls over financial reporting, management has excluded Atlas Energy Resources, LLC’s (a consolidated subsidiary of the Company) subsidiary Atlas Gas & Oil Company (“AGO”), which was acquired on June 29, 2007. Atlas Gas & Oil Company represented approximately 28% of Atlas America, Inc.’s total assets and approximately 8% of its total revenues at December 31, 2007. Also, as indicated in the accompanying Management’s Report on Internal Control over Financial Reporting, in conducting management’s assessment of and conclusion on the effectiveness of internal controls over financial reporting management has excluded Atlas Pipeline Holding, L.P.’s (a consolidated subsidiary of the Company) subsidiaries Atlas Pipeline Mid-Continent West OK, LLC. (“Chaney Dell”) and Atlas Pipeline Mid-Continent West Tex, LLC. (“Midkiff/Benedum”), which were acquired on July 27, 2007. The Chaney Dell and Midkiff/Benedum system represented approximately 40% of Atlas America, Inc.’s total assets and approximately 23% of its total revenues at December 31, 2007. Management did not assess the effectiveness of internal controls over financial reporting at these subsidiaries due to the transaction size and complexity and timing of the acquisitions. Our audit of internal controls over financial reporting of Atlas America, Inc. did not include an evaluation of the internal control over financial reporting of Atlas Gas & Oil Company and the Chaney Dell and Midkiff/Benedum systems.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Atlas America, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the accompanying consolidated balance sheets of Atlas America, Inc. and subsidiaries (a Delaware corporation) as of December 31, 2007 and 2006, and the related consolidated statements of income, comprehensive income, equity, and cash flows for the years ended December 31, 2007 and 2006, the three month period ended December 31, 2005 and the year ended September 30, 2005 and our report dated February 27, 2008 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

February 27, 2008

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ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Our Board of Directors is divided into three classes with directors in each class serving three year terms. There are no family relationships among the directors and executive officers except that Edward E. Cohen, our Chairman, Chief Executive Officer and President, is the father of Jonathan Z. Cohen, the Vice Chairman of our Board of Directors. The following table sets forth information regarding our executive officers and directors:

Name		Age		Position		Term Expires
Edward E. Cohen		69		Chairman, Chief Executive Officer and President		2008
Jonathan Z. Cohen		37		Vice Chairman		2010
Matthew A. Jones		46		Chief Financial Officer		—
Frank P. Carolas		48		Executive Vice President		—
Freddie M. Kotek		51		Executive Vice President		—
Jeffrey C. Simmons		49		Executive Vice President		—
Michael L. Staines		58		Executive Vice President		—
Nancy J. McGurk		52		Senior Vice President and Chief Accounting Officer		—
Carlton M. Arrendell		46		Director		2010
William R. Bagnell		45		Director		2009
Donald W. Delson		56		Director		2010
Nicholas A. DiNubile		55		Director		2009
Dennis A. Holtz		67		Director		2008
Harmon S. Spolan		72		Director		2008

Edward E. Cohen has been the Chairman of our Board of Directors, our Chief Executive Officer and President since our organization in September 2000. Mr. Cohen has been the Chairman of the Board and Chief Executive Officer of Atlas Energy Resources, LLC and its manager, Atlas Energy Management, Inc., since their formation in June 2006. Mr. Cohen has been the Chairman of the Managing Board of Atlas Pipeline Partners GP, LLC, the general partner of Atlas Pipeline Partners, L.P., since its formation in 1999, and Chairman of the Board and Chief Executive Officer of Atlas Pipeline Holdings GP, LLC, the general partner of Atlas Pipeline Holdings, L.P., since its formation in January 2006. In addition, Mr. Cohen has been Chairman of the Board of Directors of Resource America, Inc. (a publicly-traded specialized asset management company) since 1990, and was its Chief Executive Officer from 1988 until 2004, and President from 2000 until 2003; Chairman of the Board of Resource Capital Corp. (a publicly-traded real estate investment trust) since its formation in September 2005; a director of TRM Corporation (a publicly-traded consumer services company) from 1998 to July 2007; and Chairman of the Board of Brandywine Construction & Management, Inc. (a property management company) since 1994. Mr. Cohen is the father of Jonathan Z. Cohen.

Jonathan Z. Cohen has been Vice Chairman of our Board of Directors since our formation. Mr. Cohen has been Vice Chairman of the Board of Atlas Energy Resources and Atlas Energy Management since their formation in June 2006. Mr. Cohen has been Vice Chairman of the Managing Board of Atlas Pipeline Partners GP since its formation in 1999 and Vice Chairman of the Board of Atlas Pipeline Holdings GP since its formation in January 2006. Mr. Cohen has been a senior officer of Resource America since 1998, serving as the Chief Executive Officer since 2004, President since 2003 and a director since 2002. Mr. Cohen has been Chief Executive Officer, President and a director of Resource Capital Corp. since its formation in 2005, and was the trustee and secretary of RAIT Financial Trust (a publicly-traded real estate investment trust) from 1997, and its Vice Chairman from 2003, until December 2006. Mr. Cohen is a son of Edward E. Cohen.

Matthew A. Jones has been our Chief Financial Officer and the Chief Financial Officer of Atlas Pipeline Partners GP since March 2005. Mr. Jones has been the Chief Financial Officer and a director of Atlas Energy Resources since its formation in June 2006 and has been the Chief Financial Officer of Atlas Pipeline Holdings GP since January 2006 and a director since February 2006. From 1996 to 2005, Mr. Jones worked in the Investment Banking group at Friedman Billings Ramsey, concluding as Managing Director. Mr. Jones worked in Friedman Billings Ramsey’s Energy Investment Banking Group from 1999 to 2005 and in Friedman Billings Ramsey’s Specialty Finance and Real Estate Group from 1996 to 1999. Mr. Jones is a Chartered Financial Analyst.

150

Frank P. Carolas has been an Executive Vice President since January 2001 and served as a director from January 2002 until February 2004. Mr. Carolas has been a Senior Vice President of Atlas Energy Management since its formation in June 2006 and has been a Senior Vice President of Atlas Energy Resources since April 2007. Mr. Carolas was a Vice President of Resource America from April 2001 until May 2004, and has been Executive Vice President—Land and Geology and a director of Atlas Resources, LLC (Atlas Energy Resources’ wholly-owned subsidiary which acts as the managing partner of its drilling partnerships) since January 2001. Mr. Carolas is a certified petroleum geologist and has been employed by Atlas Resources and its affiliates since 1981.

Freddie M. Kotek has been an Executive Vice President since February 2004 and served as a director from September 2001 until February 2004. Mr. Kotek has been Chairman of Atlas Resources since September 2001 and Chief Executive Officer and President of Atlas Resources since January 2002. Mr. Kotek was our Chief Financial Officer from February 2004 until March 2005. Mr. Kotek was a Senior Vice President of Resource America from 1995 until May 2004, President of Resource Leasing, Inc. (a wholly-owned subsidiary of Resource America) from 1995 until May 2004.

Jeffrey C. Simmons has been an Executive Vice President since January 2001 and was a director from January 2002 until February 2004. Mr. Simmons has been a Senior Vice President of Atlas Energy Management since its formation in June 2006 and Executive Vice President—Operations and a director of Atlas Resources since January 2001. Mr. Simmons has been a Senior Vice President of Atlas Energy Resources since April 2007. Mr. Simmons was a Vice President of Resource America from April 2001 until May 2004. Mr. Simmons joined Resource America in 1986 as a senior petroleum engineer and has served in various executive positions with its and our energy subsidiaries since then.

Michael L. Staines has been an Executive Vice President since our formation. Mr. Staines has been President of Atlas Pipeline Partners GP since January 2001 and its Chief Operating Officer and a member of its Managing Board since its formation in November 1999. Mr. Staines was a Senior Vice President of Resource America from 1989 until May 2004, a director from 1989 to February 2000 and Secretary from 1989 to October 1998.

Nancy J. McGurk has been our Chief Accounting Officer since January 2001, Senior Vice President since January 2002, and served as our Chief Financial Officer from January 2001 until February 2004. Ms. McGurk has been the Chief Accounting Officer of Atlas Energy Resources since June 2006. Ms. McGurk has been Senior Vice President of Atlas Resources since January 2002 and Chief Financial Officer and Chief Accounting Officer since January 2001. Ms. McGurk was a Vice President of Resource America from 1992 until May 2004, and its Treasurer and Chief Accounting Officer from 1989 until May 2004.

Richard D. Weber has been President, Chief Operating Officer and a director of Atlas Energy Resources and President, Chief Operating Officer and a director of Atlas Energy Management since their formation in June 2006. Mr. Weber served from June 1997 until March 2006 as Managing Director and Group Head of the Energy Group of KeyBanc Capital Markets, a division of KeyCorp, and its predecessor, McDonald & Company Securities, Inc., where he oversaw activities with oil and gas producers, pipeline companies and utilities.

Independent Directors

The following directors have been determined by our board to be independent directors as defined under NASDAQ rules and the Securities Act.

Carlton M. Arrendell has been a director since February 2004. Mr. Arrendell has been a Vice President and Chief Investment Officer of Full Spectrum of NY LLC since May 2007. Prior to joining Full Spectrum, Mr. Arrendell served as a special real estate consultant to the AFL-CIO Investment Trust Corporation following six years of service as Investment Trust Corporation’s Chief Investment Officer. Mr. Arrendell is also an attorney admitted to practice law in Maryland and the District of Columbia.

William R. Bagnell has been a director since February 2004. Mr. Bagnell has been involved in the energy industry in various capacities since 1986. He has been Vice President—Energy for Planalytics, Inc. (an energy industry risk management and software company) since March 2000, and was Director of Sales for Fisher Tank Company (a national manufacturer of carbon and stainless steel bulk storage tanks) from September 1998 to January 2000. Before that, he served as Manager of Business Development for Buckeye Pipeline Partners, L.P. (a refined petroleum products transportation company) from October 1992 until September 1998. Mr. Bagnell served as an independent member of the Managing Board of Atlas Pipeline Partners GP from its formation in November 1999 until May 2004.

Donald W. Delson has been a director since February 2004. Mr. Delson has over 20 years of experience as an investment banker specializing in financial institutions. Mr. Delson has been a Managing Director, Corporate Finance Group, at Keefe, Bruyette & Woods, Inc. since 1997, and before that was a Managing Director in the Corporate Finance Group at Alex. Brown & Sons from 1982 to 1997. Mr. Delson served as an independent member of the Managing Board of Atlas Pipeline Partners GP from June 2003 until May 2004.

151

Nicholas A. DiNubile has been a director since February 2004. Dr. DiNubile has been an orthopedic surgeon specializing in sports medicine since 1982. Dr. DiNubile has served as special advisor and medical consultant to the President’s Council on Physical Fitness and as Orthopedic Consultant to the Philadelphia 76ers basketball team. Dr. DiNubile is also Clinical Assistant Professor of the Department of Orthopedic Surgery at the Hospital of the University of Pennsylvania.

Dennis A. Holtz has been a director since February 2004. Mr. Holtz maintained a corporate law practice with D.A. Holtz, Esquire & Associates in Philadelphia and New Jersey from 1988 until his retirement in January 2008.

Harmon S. Spolan has been a director since August 2006. Since January 2007, Mr. Spolan has served as of counsel to the law firm Cozen O’Connor, where he is chairman of the firm’s charitable foundation. From 1999 until January 2007, Mr. Spolan was a member of the firm and served as chairman of its Financial Services Practice Group and as co-marketing partner. Before joining Cozen O’Connor, Mr. Spolan served as President, Chief Operating Officer, and a director of JeffBanks, Inc., and its subsidiary bank for 22 years. Mr. Spolan has served as director of TRM Corporation since June 2002 and of Coleman Cable, Inc., since November, 2007.

Information Concerning the Audit Committee

Our Board of Directors has a standing Audit Committee. All of the members of the Audit Committee are independent directors as defined by NASDAQ rules. The members of the Audit Committee are Messrs. Arrendell, Bagnell and Delson, with Mr. Arrendell acting as the chairman. Our Board of Directors has determined that Mr. Delson is an “audit committee financial expert,” as defined by SEC rules. The Audit Committee reviews the scope and effectiveness of audits by the independent accountants, is responsible for the engagement of independent accountants and reviews the adequacy of our internal controls.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires our officers, directors and persons who own more than 10% of a registered class of our equity securities to file reports of ownership and changes in ownership with the SEC and to furnish us with copies of all such reports.

Based solely on our review of the reports we have received, or written representations from certain reporting persons that no filings were required for those persons, we believe that during fiscal 2007 our executive officers, directors and greater than 10% stockholders complied with all applicable filing requirements of Section 16(a) of the Securities Exchange Act.

Code of Ethics

We have adopted a code of business conduct and ethics applicable to all directors, officers and employees. We believe we meet the definition of a code of ethics under the Securities Act. Our code of business conduct and ethics is available, and any waivers we grant to the code will be available, on our web site at www.atlasamerica.com.

152

ITEM 11. EXECUTIVE COMPENSATION

COMPENSATION COMMITTEE REPORT

The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis with management and, based on its review and discussions, the Compensation Committee recommended to the board of directors that the Compensation Discussion and Analysis be included in this annual report on Form 10-K.

This report has been provided by the Compensation Committee of the Board of Directors of Atlas America, Inc.

Donald W. Delson, Chairman

Dennis A. Holtz

Carlton M. Arrendell

COMPENSATION DISCUSSION AND ANALYSIS

We are required to provide information regarding the compensation program in place as of December 31, 2007, for our CEO, CFO and the three other most highly-compensated executive officers. In this report, we refer to our CEO, CFO and the other three most highly-compensated executive officers as our “Named Executive Officers” or “NEOs.” This section should be read in conjunction with the detailed tables and narrative descriptions under “Executive Compensation.”

Our Compensation Committee is responsible for formulating and presenting recommendations to our Board of Directors with respect to the compensation of our NEOs. The Compensation Committee is also responsible for administering our employee benefit plans, including incentive plans. The Compensation Committee is comprised solely of independent directors, consisting of Messrs. Delson, Arrendell and Holtz, with Mr. Delson acting as the chairperson.

Compensation Objectives

We believe that our compensation program must support our business strategy, be competitive, and provide both significant rewards for outstanding performance and clear financial consequences for underperformance. We also believe that a significant portion of the NEOs’ compensation should be “at risk” in the form of annual and long-term incentive awards that are paid, if at all, based on individual and company accomplishment.

The compensation awarded to our NEOs for fiscal 2007 specifically was intended:

· To encourage and reward strong performance; and

· To motivate our NEOs by providing them with a meaningful equity stake in our company and our publicly-traded subsidiaries, as appropriate.

Accounting and cost implications of compensation programs are considered in program design; however, the essential consideration is that a program is consistent with our business needs.

Compensation Methodology

Our Compensation Committee makes recommendations to the board on compensation amounts during the month after the close of our fiscal year. In the case of base salaries, it recommends the amounts to be paid for that year. In the case of annual bonus and long-term incentive compensation, the committee recommends the amount of awards based on the then concluded fiscal year. We typically pay cash awards and issue equity awards in February of the following fiscal year. Our Compensation Committee has the discretion to recommend the issuance of equity awards at other times during the fiscal year. In addition, our NEOs and other employees who perform services for our publicly-traded subsidiaries, Atlas Energy Resources, Atlas Pipeline Partners and Atlas Pipeline Holdings, may receive stock-based awards from these subsidiaries, each of which have delegated compensation decisions to our Compensation Committee since none of those companies have their own employees.

Each year, our Chief Executive Officer provides the Compensation Committee with key elements of both our company’s and the NEOs’ performance as well as recommendations to assist it in determining compensation levels. The Compensation Committee focuses on our company’s equity performance, market capitalization, corporate developments, our business performance (including production of energy and replacement of reserves), and our financial position.

153

In June 2006, our Compensation Committee retained Mercer Human Resource Consulting to analyze and review the competitiveness and appropriateness of all elements of the compensation we paid to our NEOs, individually and as a group, for fiscal 2006. The purpose of retaining Mercer was to determine whether our compensation practices were within the norm for companies of similar size and focus. Because of the importance to our company of our direct-placement energy investment programs and our creation of new initiatives and entities, Mercer looked not only to the energy industry in evaluating our compensation levels but also to the financial services and alternative asset industries. Mercer’s analysis established that our fiscal 2006 compensation amounts fell between the median and the 75^th percentile of the peer group it used, which our Compensation Committee found acceptable in the context of its evaluation of the performance of the NEOs.

Ultimately, the decisions regarding executive compensation are made by the Compensation Committee after extensive discussion regarding appropriate compensation and are approved by our Board of Directors.

Elements of our Compensation Program

Our executive officer compensation package includes a combination of annual cash and long-term incentive compensation. Annual cash compensation is comprised of base salary plus cash bonus. Long-term incentives consist of a variety of equity awards. Both the annual cash incentives and long-term incentives may be performance-based.

Base Salary

Base salary is intended to provide fixed compensation to the NEOs for their performance of core duties that contributed to our success as measured by the elements of corporate performance mentioned above. Base salaries are not intended to compensate individuals for extraordinary performance or for above average company performance.

Annual Incentives

Annual incentives are intended to tie a significant portion of each of the NEO’s compensation to our annual performance and/or that of our subsidiaries or divisions for which the officer is responsible. Generally, the higher the level of responsibility of the executive within our company, the greater is the incentive component of that executive’s target total cash compensation. The Compensation Committee may recommend awards of performance-based bonuses and discretionary bonuses.

Performance-Based Bonuses—Our Annual Incentive Plan for Senior Executives, which we refer to as the Senior Executive Plan, was approved by our stockholders at our 2007 annual meeting. The Senior Executive Plan is designed to permit us to qualify for an exemption from the $1,000,000 deduction limit under Section 162(m) of the Internal Revenue Code for compensation paid to our NEOs. The Senior Executive Plan provides awards for the achievement of predetermined, objective performance measures over a specified 12-month performance period, generally our fiscal year. Awards under the Senior Executive Plan are paid in cash. The Senior Executive Plan limits the amount of annual compensation to be paid to any individual under the plan to $5,000,000 per year. Notwithstanding the existence of our Senior Executive Plan, the Compensation Committee believes that stockholder interests are best served by not restricting its discretion and flexibility in crafting compensation, even if the compensation amounts result in non-deductible compensation expense. Therefore, the Committee reserves the right to approve compensation that is not fully deductible.

In February 2007, the Compensation Committee set the performance goals for our NEOs. Specifically, the Committee decided that if our 2007 net income, which was defined as net income before income taxes and compensatory bonuses paid, exceeded $18,000,000, a bonus pool equal to 15% of the 2007 net income would be established, from which bonus awards would be made. Pursuant to the terms of the Senior Executive Plan, in determining whether and to what extent the performance target was achieved, the Compensation Committee shall use information contained in the company’s audited financial statements and other objectively determinable information. If the performance target was not achieved, no annual incentives would be awarded. The maximum award payable for fiscal 2007, expressed as a percentage of our 2007 net income, for each of the participants in the Senior Executive Plan was as follows: Edward E. Cohen, 5.03%; Jonathan Z. Cohen, 3.58%; Matthew A. Jones, 2.75%; and Richard D. Weber, 2.75%. Pursuant to the terms of the Senior Executive Plan, the Compensation Committee has the discretion to recommend the reduction, but not the increase, of the annual incentive awards.

Discretionary Bonuses—Discretionary bonuses may be awarded to recognize individual and group performance.

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Long-Term Incentives

We believe that our long-term success depends upon aligning our executives’ and stockholders’ interests. To support this objective, we provide our executives with various means to become significant stockholders, including our long-term incentive programs and those of our public subsidiaries. These awards are usually a combination of stock options, restricted units and phantom units which vest over four years to support long-term retention of executives and reinforce our longer-term goals.

Grants under our Stock Incentive Plan: Awards under our stock incentive plan, which we refer to as our Plan, may be in the form of incentive stock options, non-qualified stock options and restricted stock.

Stock Options—Our Compensation Committee has recommended for award stock options under our Plan from time to time. Stock option grants have a ten-year term and usually vest 25% per year. These stock options provide value to the recipient only if our share price is higher than on the date of the grant.

Restricted Stock—On very limited occasions, restricted stock grants have been awarded. These grants vest 25% per year on the anniversary of the date of grant. Restricted stock units reward stockholder value creation slightly differently than stock options: restricted stock units are impacted by all stock price changes, both increases and decreases.

Grants under Subsidiary Plans: As described above, our NEOs who perform services for one or more of our publicly-traded subsidiaries may receive stock-based awards under the long-term incentive plan of the appropriate subsidiary.

Supplemental Benefits, Deferred Compensation and Perquisites

We do not emphasize supplemental benefits for executives other than Mr. E. Cohen, and perquisites are discouraged. None of our NEOs have deferred any portion of their compensation.

Employment Agreements

Generally, we do not favor employment agreements unless they are required to attract or to retain executives to the organization. We have entered into employment agreements with Messrs. E. Cohen and Weber.

Determination of 2007 Compensation Amounts

As described above, after the end of our 2007 fiscal year, our Compensation Committee set the base salaries of our NEOs for the 2008 fiscal year and recommended incentive awards based on the prior year’s performance. In carrying out its function, the Compensation Committee acted in consultation with Mercer.

In determining the actual amounts to be paid to the NEOs, the Compensation Committee looked to both the individual’s performance as well as to the overall performance of our company and our publicly-held subsidiaries during fiscal 2007. The Compensation Committee acknowledged some of the key individual contributions as set forth below:

· Mr. E. Cohen was a critical force in all of our significant initiatives as well as the significant initiatives of our subsidiaries, including the successful acquisitions by both Atlas Energy Resources and Atlas Pipeline Partners, resulting in the doubling of our combined market capitalization from $3 billion to $5.9 billion by the end of December 2007.

· Mr. J. Cohen was responsible for some of our most important initiatives, including the Dutch tender auction in which we repurchased 2.25 million shares in early 2007 at $35.70 per share at a sizeable discount from recent prices which had hovered at $60 per share. Additionally, Lightfoot Capital Partners, in which we own an approximate 18% interest, and for which Mr. J. Cohen serves as Chairman, successfully commenced operations during 2007 and completed a number of significant acquisitions.

· Mr. Jones’s and Mr. J. Cohen’s financial expertise was instrumental in the successful raising of almost $2 billion in equity for the Atlas Energy Resources and Atlas Pipeline Partners acquisitions under tight time schedules and challenging market conditions. Additionally, Mr. Jones’s investment banking expertise was a significant factor in our ability to obtain over $1.5 billion in debt financing on favorable terms.

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· Mr. Weber was instrumental in Atlas Energy Resources’ acquisition of assets from DTE Energy Company, which resulted in the tripling in size of Atlas Energy Resources’ exploration and production business.

· Mr. Kotek is responsible for our direct-placement energy investment programs. In calendar year 2007, Mr. Kotek was responsible for raising $363 million in funds, representing a 67% increase in funds raised from the amount raised in calendar year 2006.

Base Salary. Consistent with its preference for having a significant portion of our NEOs’ overall compensation package be incentive compensation, the Compensation Committee decided to recommend that the company maintain base salaries for 2008 at the same levels as 2007.

Annual Incentives.

Performance-Based Bonuses. The Compensation Committee reviewed our financial statements and determined that the 2007 net income exceeded the pre-determined minimum threshold. The maximum amounts payable to each of the NEOs pursuant to the predetermined percentages was as follows: Edward E. Cohen, $5,956,778; Jonathan Z. Cohen, $4,239,615; Matthew A. Jones, $3,256,688; and Richard D. Weber, $3,256,688. However, the Compensation Committee decided, pursuant to its discretionary authority as set forth in the Senior Executive Plan, to recommend that the maximum amount for each NEO be reduced and recommended that we award cash incentive bonuses as follows: Edward E. Cohen, $5,000,000; Jonathan Z. Cohen, $4,000,000; Matthew A. Jones, $2,000,000; and Richard D. Weber, $1,500,000.

Discretionary Bonuses. Based on the record-breaking performance of our direct-placement energy investment programs, the Compensation Committee recommended that we award Mr. Kotek a cash bonus of $1,000,000. Mr. Kotek was not included in the Senior Executive Plan for 2007 and, therefore, his compensation in excess of the Section 162(m) threshold is not deductible.

 Long-Term Incentives. Additionally, the Compensation Committee recognized the importance of a long-term incentive component as a part of the 2007 compensation. The Compensation Committee recommended that we award our stock options as follows: Mr. E. Cohen—200,000 options; Mr. J. Cohen—160,000 options; Mr. M. Jones—80,000 options; Mr. Weber—60,000 options; and Mr. Kotek—40,000 options. (These awards are not reflected in the Summary Compensation Table because we did not recognize expense for them in fiscal 2007; nor are they reflected in the Grants of Plan-Based Awards table, because they were granted in fiscal 2008.) The Compensation Committee determined that it would not recommend that we make Atlas Energy Resources, Atlas Pipeline Partners or Atlas Pipeline Holdings stock-based awards to our NEOs because it felt that previous awards were adequate.

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SUMMARY COMPENSATION TABLE

The following table sets forth information concerning the compensation for fiscal 2007 for our Chief Executive Officer, Chief Financial Officer and each of our other three most highly compensated executive officers whose aggregate salary and bonus (including amounts of salary and bonus foregone to receive non cash compensation) exceeded $100,000.

Name and Principal Position		Year			Salary ($)			Bonus ($)			Stock Awards ($) (1)			Option Awards ($) (2)			Non-Equity Incentive Plan Compensation ($)			Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)			All Other Compensation ($)			Total ($)
Edward E. Cohen, Chairman of the Board and Chief Executive Officer			2007		$	900,000			—		$	2,407,901		$	810,417		$	5,000,000		$	1,150,222	(3)	$	554,777	(4)	$	10,823,317
			2006		$	600,000		$	1,400,000		$	674,625		$	84,861					$	121,769	(3)	$	41,849		$	2,923,104
Matthew A. Jones, Chief Financial Officer			2007		$	300,000			—		$	472,212		$	439,128		$	2,000,000			—		$	134,597	(5)	$	3,345,937
			2006		$	300,000		$	750,000		$	276,546		$	324,172						—		$	65,602		$	1,716,320
Jonathan Z. Cohen, Vice Chairman			2007		$	600,000			—		$	1,384,207		$	324,167		$	4,000,000			—		$	300,906	(6)	$	6,609,280
			2006		$	400,000		$	1,000,000		$	439,563		$	33,944						—		$	20,400		$	1,893,907
Freddie M. Kotek, Executive Vice President			2007		$	300,000		$	1,000,000		$	123,410		$	183,710						—		$	47,996	(7)	$	1,655,116
			2006		$	300,000		$	350,000			—		$	153,600						—		$	10,867		$	814,467
Richard D. Weber, President and Chief Operating Officer of Atlas Energy Resources, LLC			2007		$	300,000			—		$	250,000		$	463,770		$	1,500,000			—		$	2,857		$	2,516,627
			2006		$	201,923		$	800,000		$	187,504		$	347,779						—		$	26,957		$	1,564,163

(1) Represents the dollar amount of (i) expense recognized by Atlas Pipeline Holdings for financial statement reporting purposes with respect to phantom units granted under the AHD Plan; (ii) expense recognized by Atlas Pipeline Partners for financial statement reporting purposes with respect to phantom units granted under the APL Plan and its incentive compensation arrangements; and/or (iii) expense recognized by Atlas Energy Resources for financial statement reporting purposes with respect to phantom units or restricted units granted under the ATN Plan, all in accordance with FAS 123R. See note 10 to our consolidated financial statements for an explanation of the assumptions we make for this valuation.

(2) Represents the dollar amount of (i) expense we recognized for financial statement reporting purposes with respect to options granted under our Plan (see Note 10 to our consolidated financial statements), (ii) expense recognized for financial statement reporting purposes by Atlas Pipeline Holdings for options granted under the AHD Plan; and/or (iii) expense recognized for financial statement reporting purposes by Atlas Energy Resources for options granted under the ATN Plan, all in accordance with FAS 123R. See note 10 to our consolidated financial statements for an explanation of the assumptions we make for this valuation.

(3) Represents the aggregate annual change in the actual present-value of accumulated pension benefits under the Supplemental Employment Retirement Plan for Mr. E. Cohen.

(4) Includes payments on DERs of $ 156,012 with respect to the phantom units awarded under the APL Plan, $97,200 with respect to phantom units awarded under the AHD Plan, and $ 294,000 with respect to the phantom units awarded under the ATN Plan.

(5) Includes payments on DERs of $ 53,462 with respect to the phantom units awarded under the APL Plan, $ 21,600 with respect to phantom units awarded under the AHD Plan, and $ 29,400 with respect to the phantom units awarded under the ATN Plan, and $13,575 for reimbursements for rental payments on Mr. Jones’s temporary residence and $7,841 for reimbursements for lease payments on Mr. Jones’s vehicle.

(6) Represents payments on DERs of $105,306 with respect to the phantom units awarded under the APL Plan, $48,600 with respect to phantom units awarded under the AHD Plan, and $ 147,000 with respect to the phantom units awarded under the ATN Plan.

(7) Includes payments on DERs of $ 2,397 with respect to the phantom units awarded under the APL Plan, $ 29,400 with respect to the phantom units awarded under the ATN Plan.

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2007 GRANTS OF PLAN-BASED AWARDS TABLE

Name		Grant Date			Approval Date			All Other Stock Awards: Number of Shares Of Stock or Units (#)			All Other Option Awards: Number of Securities Underlying Options (#)			Exercise or Base Price of Option Awards ($ / Sh)			Grant Date Fair Value of Stock and Option Awards
Edward E. Cohen			1/24/07			1/22/07			200,000	(1)		500,000	(2)	$	23.06		$	4,612,000	(1)
																	$	1,250,000	(2) (3)
Matthew A. Jones			1/24/07			1/22/07			20,000	(1)		50,000	(2)	$	23.06		$	461,200	(1)
																	$	120,500	(2)
Jonathan Z. Cohen			1/24/07			1/22/07			100,000	(1)		200,000	(2)	$	23.06		$	2,306,000	(1)
																	$	482,000	(2)
Richard D. Weber			1/24/07			4/3/06			47, 619	(3)		373,752	(4)	$	21.00		$	999,999	(1)
																	$	900,742	(2)
Freddie Kotek			1/24/07			1/22/07			20,000	(1)		50,000	(2)	$	23.06		$	461,200	(1)
																	$	120,500	(2)

⁽¹⁾ Represents grants of phantom units under the ATN Plan, which vest 25%  on the third anniversary and 75% on the fourth anniversary of the grant, valued in accordance with FAS 123R at the closing price of Atlas Energy’s common units on the grant date of $23.06.

⁽²⁾ Represents grants of stock options under the ATN Plan, which vest 25% on the third anniversary and 75% on the fourth anniversary of the grant, valued at $ 2.41 per option using the Black-Scholes option pricing model to estimate the weighted average fair value of each unit option granted with weighted average assumptions for (a) expected dividend yield of 8.0%, (b) risk-free interest rate of 4.7%, (c) expected volatility of 25.0%, and (d) an expected life of 6.3 years.

⁽³⁾ Represents grants of phantom units under the ATN Plan, in accordance with Mr. Weber’s employment agreement, which vest 25% per year on the anniversary of the commencement of Mr. Weber’s employment on April 17, 2006, valued in accordance with FAS 123R at the closing price of Atlas Energy’s common units on the grant date of $21.00.

⁽⁴⁾ Represents grants of options under the ATN Plan, in accordance with Mr. Weber’s employment agreement, which vest 25% per year on the anniversary of the commencement of Mr. Weber’s employment on April 17, 2006, valued at $ 2.41 per option using the Black-Scholes option pricing model to estimate the weighted average fair value of each unit option granted with weighted average assumptions for (a) expected dividend yield of 8.0%, (b) risk-free interest rate of 4.7%, (c) expected volatility of 25.0%, and (d) an expected life of 6.3 years.

Employment Agreements

Edward E. Cohen

In May 2004, we entered into an employment agreement with Edward E. Cohen, who currently serves as our Chairman, Chief Executive Officer and President. The agreement requires him to devote such time to us as is reasonably necessary to the fulfillment of his duties, although it permits him to invest and participate in outside business endeavors. The agreement provided for initial base compensation of $350,000 per year, which may be increased by the Compensation Committee based upon its evaluation of Mr. Cohen’s performance. Mr. Cohen is eligible to receive incentive bonuses and stock option grants and to participate in all employee benefit plans in effect during his period of employment. The agreement has a term of three years and, until notice to the contrary, the term is automatically extended so that on any day on which the agreement is in effect it has a then-current three-year term.

The agreement provides for a Supplemental Executive Retirement Plan, or SERP, pursuant to which Mr. Cohen will receive; upon the later of his retirement or reaching the age of 70, an annual retirement benefit equal to the product of:

· 6.5% multiplied by

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· his base salary as of the time Mr. Cohen’s employment with us ceases, multiplied by

· the number of years (or portions thereof) which Mr. Cohen is employed by us but, in any case, not less than four.

The maximum benefit under the SERP is limited to 65% of his final base salary. The benefit is guaranteed to his estate for up to 10 years if he should die before receiving 10 years’ of SERP benefits. If there is a change of control, if Mr. Cohen resigns for good reason, or if we terminate his employment without cause, then the SERP benefit will be the greater of the accrued benefit pursuant to the above formula, or 40% of his final base salary.

The agreement provides the following regarding termination and termination benefits:

· Upon termination of employment due to death, Mr. Cohen’s estate will receive (a) a lump sum payment in an amount equal to his final base salary multiplied by the number of years (or portion thereof) that he shall have worked for us (but not to be greater than 3 years’ base salary or less than one year’s base salary), (b) payment of his SERP benefit and (c) automatic vesting of all stock and option awards.

· We may terminate Mr. Cohen’s employment if he is disabled for 180 days consecutive days during any 12-month period. If his employment is terminated due to disability, he will receive (a) his base salary for 3 years, and such 3 year period will be deemed a portion of his employment term for purposes of accruing SERP benefits, (b) continuation of term life and health insurance then in effect for 3 years, or an amount equal to Mr. Cohen’s after tax cost of continuing such coverage in case we cannot continue coverage, (c) payment of his SERP benefit, (d) automatic vesting of all stock and option awards and (e) after such 3 year period, any amounts payable under our long-term disability plan.

· We may terminate Mr. Cohen’s employment without cause upon 30 days’ written notice or upon a change of control after providing at least 30 days’ written notice. He may terminate his employment for good reason or upon a change of control. Good reason is defined as a reduction in his base pay, a demotion, a material reduction in his duties, relocation, his failure to be elected to our Board of Directors or our material breach of the agreement. If employment is terminated by us without cause, by Mr. Cohen for good reason or by either party in connection with a change of control, he will be entitled to either (a) if Mr. Cohen does not sign a release, severance benefits under our then current severance policy, if any, or (b) if Mr. Cohen signs a release, (i) a lump sum payment in an amount equal to 3 years of his average compensation (which we define as the average of the 3 highest years of total compensation that he shall have earned under the agreement, or if the agreement is less than three years old, the highest total compensation in any year), (ii) continuation of term life and health insurance then in effect for 3 years, or an, amount equal to Mr. Cohen’s after tax cost of continuing such coverage in case coverage by our company cannot be continued, (iii) payment of his SERP benefit and (iv) automatic vesting of all stock and option awards.

· Mr. Cohen may terminate the agreement without cause with 60 days notice to us, and if he signs a release, he will receive (a) a lump sum payment equal to one-half of one year’s base salary then in effect, (b) automatic vesting of all stock and option awards and (c) if he has reached retirement age, his SERP benefits.

· We may terminate his employment for cause (defined as a felony conviction or conviction of a crime involving fraud, embezzlement or moral turpitude, intentional and continual failure to perform his material duties after notice, or violation of confidentiality obligations), in which case he will receive only accrued amounts then owed to him.

Change of control is defined as:

· the acquisition of beneficial ownership, as defined in the Securities Exchange Act, of 25% or more of our voting securities or all or substantially all of our assets by a single person or entity or group of affiliated persons or entities, other than an entity affiliated with Mr. Cohen or any member of his immediate family;

· we consummate a merger, consolidation, combination, share exchange, division or other reorganization or transaction with an unaffiliated entity in which either (a) our directors immediately before the transaction constitute less than a majority of the board of the surviving entity, unless  ¹/2 of the surviving entity’s board were our directors immediately before the transaction and our chief executive officer immediately before the transaction continues as the chief executive officer of the surviving entity; or (b) our voting securities immediately prior to the transaction represent less than 60% of the combined voting power immediately after the transaction of us, the surviving entity or, in the case of a division, each entity resulting from the division;

· during any period of 24 consecutive months, individuals who were Board members at the beginning of the period cease for any reason to constitute a majority of the Board, unless the election or nomination for election by our stockholders of each new director was approved by a vote of at least 2/3 of the directors then still in office who were directors at the beginning of the period; or

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· our shareholders approve a plan of complete liquidation of winding up of our company, or agreement of sale of all or substantially all of our assets or all or substantially all of the assets of our primary subsidiaries to an unaffiliated entity.

In the event that any amounts payable to Mr. Cohen upon termination become subject to any excise tax imposed under Section 4999 of the Code, we must pay Mr. Cohen an additional sum such that the net amounts retained by Mr. Cohen, after payment of excise, income and withholding taxes, equals the termination amounts payable, unless Mr. Cohen’s employment terminates because of his death or disability.

If a termination event had occurred as of December 31, 2007, we estimate that the value of the benefits to Mr. Cohen would have been as follows:

Reason for termination		Lump sum severance payment			SERP(1)			Benefits(2)			Accelerated vesting of stock awards and option awards(3)			Tax gross- up(4)
Death		$	2,700,000	(5)	$	2,340,000		$	—		$	16,298,800		$	—
Disability			2,700,000	(5)		2,340,000			39,935			16,298,800			—
Termination by us without cause(6)			9,700,000	(7)		3,600,000			39,935			16,298,800			—
Termination by Mr. Cohen for good reason(6)			9,700,000	(7)		3,600,000			39,935			16,298,800			—
Change of control(6)			9,700,000	(7)		3,600,000			39,935			16,298,800			1,571,529
Termination by Mr. Cohen without cause			450,000	(5)		2,340,000			—			16,298,800			—

(1) Represents the value of vested benefits payable calculated by multiplying the per year benefit by the minimum of 10 years.

(2) Represents rates currently in effect for COBRA insurance benefits for 36 months.

(3) Represents the value of unvested and accelerated option awards and stock awards disclosed in the “Outstanding Equity Awards at Fiscal Year-End Table.” The payments relating to option awards are calculated by multiplying the number of accelerated options by the difference between the exercise price and the closing price of the applicable stock on December 31, 2007. The payments relating to stock awards are calculated by multiplying the number of accelerated shares or units by the closing price of the applicable stock on December 31, 2007.

(4) Calculated after deduction of any excise tax imposed under section 4999 of the Code, and any federal, state and local income tax, FICA and Medicare withholding taxes, taking into account the 20% excess parachute payment rate and a 42.65% combined effective tax rate.

(5) Calculated based on Mr. Cohen’s 2007 base salary.

(6) These amounts are contingent upon Mr. Cohen executing a release. If Mr. Cohen does not execute a release he would receive severance benefits under our current severance plan.

(7) Calculated based on Mr. Cohen’s 2007 base salary and bonus.

Richard D. Weber

We entered into an employment agreement in April 2006 with Richard Weber, who serves as President and Chief Operating Officer of Atlas Energy and Atlas Energy Management. The agreement has a two year term and, after the first year, the term automatically renews daily so that on any day that the agreement is in effect, the agreement will have a remaining term of one year. Mr. Weber is required to devote substantially all of his working time to Atlas Energy Management and its affiliates. The agreement provides for an annual base salary of not less than $300,000 and a bonus of not less than $700,000 during the first year. After that, bonuses will be awarded solely at the discretion of our Compensation Committee. The agreement provides for equity compensation as follows:

· Upon execution of the agreement, Mr. Weber was granted options to purchase 50,000 shares of our stock at $47.86.

· In January 2007, Mr. Weber received a grant of 47,619 shares of restricted units of Atlas Energy with a value of $1,000,000.

· In January 2007, Mr. Weber received options to purchase 373,752 common units of Atlas Energy at $21.00.

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All of the securities described above vest 25% per year on each anniversary of the date Mr. Weber commenced his employment, April 17, 2006. All securities will vest immediately upon a change of control or termination by Mr. Weber for good reason or by Atlas Energy Management other than for cause. Change of control is defined as:

· the acquisition of beneficial ownership, as defined in the Securities Exchange Act, of 50% or more of our or Atlas Energy Resources’ voting securities or all or substantially all of our or Atlas Energy Resources’ assets by a single person or entity or group of affiliated persons or entities, other than an entity of which either Mr. E. Cohen or Mr. J. Cohen is an officer, manager, director or participant;

· we or Atlas Energy Resources consummate a merger, consolidation, combination, share exchange, division or other reorganization or transaction with an unaffiliated entity after which Atlas Energy Management is not the manager of Atlas Energy Resources; or

· our or Atlas Energy Resources’ stockholders approve a plan of complete liquidation of winding up, or agreement of sale of all or substantially all of our or Atlas Energy Resources’ assets other than an entity of which either Mr. E. Cohen or Mr. J. Cohen is an officer, manager, director or participant.

The change of control triggering events relating to the possible absence of Messrs. Cohen reflects that Mr. Weber’s belief that Messrs. Cohen effectively controlled us at the time of his employment and their separation would therefore constitute a change of control.

Good reason is defined as a material breach of the agreement, reduction in his base pay, a demotion, a material reduction in his duties or his failure to be elected to the Atlas Energy Resources Board of Directors. Cause is defined as fraud in connection with his employment, conviction of a crime other than a traffic offense, material failure to perform his duties after written demand by our Board or breach of the representations made by Mr. Weber in the employment agreement if the breach impacts his ability to fully perform his duties. Disability is defined as becoming disabled by reason of physical or mental disability for more than 180 days in the aggregate or a period of 90 consecutive days during any 365-day period and the good faith determination by our Board based upon medical evidence that Mr. Weber is unable to perform his duties under his employment agreement.

Atlas Energy Management may terminate Mr. Weber without cause upon 45 days written notice or for cause upon written notice. Mr. Weber may terminate his employment for good reason or for any other reason upon 30 days’ written notice. Key termination benefits are as follows:

· If Mr. Weber’s employment is terminated due to death, (a) Atlas Energy Management will pay to Mr. Weber’s designated beneficiaries a lump sum cash payment in an amount equal to the bonus that Mr. Weber received from the prior fiscal year pro rated for the time employed during the current fiscal year, (b) Mr. Weber’s family will receive health insurance coverage for one year; and (c) all Atlas Energy Resources stock and option awards will automatically vest.

· If Mr. Weber’s employment is terminated by Mr. Weber other than for good reason, all stock and option awards will automatically vest.

· If Atlas Energy Management terminates Mr. Weber’s employment other than for cause (including termination by reason of disability), or Mr. Weber terminates his employment for good reason, (a) Atlas Energy Management will pay amounts and benefits otherwise payable to Mr. Weber as if Mr. Weber remained employed for one year, except that the bonus amount shall be prorated and based on the bonus awarded in the prior fiscal year, and (b) all stock and option awards will automatically vest.

Mr. Weber is entitled to a gross-up payment if any payments made to him would constitute an excess parachute payment under Section 280G of the Code such that the net amount Mr. Weber receives after the deduction of any excise tax, any federal, state and local income tax, and any FICA and Medicare withholding tax is the same amount he would have received had such taxes not been deducted. The agreement includes standard restrictive covenants for a period of two years following termination, including non-compete and non-solicitation provisions.

If a termination event had occurred as of December 31, 2007, we estimate that the value of the benefits to Mr. Weber would have been as follows:

Reason for termination		Lump sum severance payment			Benefits(1)			Accelerated vesting of stock awards and option awards(2)
Death		$	1,500,000	(3)	$	17,193		$	—
Disability			—			19,719			—
Termination by us other than for cause (including for disability) or by Mr. Weber for good reason			1,800,000	(4)		19,719			5,472,900
Change of control			—			—			5,472,900

⁽¹⁾ Represents rates currently in effect for COBRA insurance benefits for 12 months.

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⁽²⁾ Represents the value of unvested and accelerated option awards disclosed in the “Outstanding Equity Awards at Fiscal Year-End Table,” calculated by multiplying the number of accelerated options by the difference between the exercise price and the closing price of our stock on December 31, 2007.

⁽³⁾ Represents Mr. Weber’s 2007 bonus.

⁽⁴⁾ Calculated as the sum of Mr. Weber’s 2007 base salary and bonus.

Long-Term Incentive Plans

Our Plan

Our Plan authorizes the granting of up to 3.0 million shares of our common stock to our employees, affiliates, consultants and directors in the form of incentive stock options (“ISOs”), non-qualified stock options, stock appreciation rights (“SARs”), restricted stock and deferred units. SARs represent a right to receive cash in the amount of the difference between the fair market value of a share of our common stock on the exercise date and the exercise price, and may be free-standing or tied to grants of options. A deferred unit represents the right to receive one share of our common stock upon vesting. Awards under our Plan generally become exercisable as to 25% each anniversary after the date of grant, except that deferred units awarded to our non-executive board members vest 33 1/3% on each of the second, third and fourth anniversaries of the grant, and expire not later than ten years after the date of grant. Units will vest sooner upon a change in control of the Company or death or disability of a grantee, provided the grantee has completed at least six months service.

ATN Plan

Eligible participants in the Atlas Energy Resources Long-Term Incentive Plan (the “ATN Plan”) are the employees, directors and consultants of Atlas Energy Management and its affiliates, including us, who perform services for Atlas Energy Resources. Awards under the ATN Plan may be phantom units, unit options and tandem DERs with respect to phantom units for an aggregate of 3,600,000 common units. During 2007, the long-term incentive plan was administered by our Compensation Committee under delegation from the Atlas Energy Resources board. Awards under the ATN Plan generally become exercisable as to 25% on the third anniversary of the date of grant and 75% on the fourth anniversary of the date of grant. In May 2007, our stockholders approved an amendment to the ATN Plan which provides for performance-based awards criteria for purposes of complying with Section 162(m) of the Internal Revenue Code (“Section 162(m)”).

APL Plan

Officers, employees and non-employee managing board members of Atlas Pipeline Partners’ general partner and employees of the general partner’s affiliates and consultants are eligible to receive awards under the APL Plan of either phantom units or unit options for an aggregate of 435,000 common units. The APL Plan is administered by our Compensation Committee under delegation from the general partner’s managing board. Currently, only phantom units have been issued under the APL Plan.

A phantom unit entitles a grantee to receive a common unit upon vesting of the phantom unit or, at the discretion of the Compensation Committee, cash equivalent to the fair market value of a common unit. In addition, the Compensation Committee may grant a participant a DER, which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions Atlas Pipeline Partners makes on a common unit during the period the phantom unit is outstanding. A unit option entitles the grantee to purchase common units at an exercise price determined by the Compensation Committee at its discretion. Except for phantom units awarded to non-employee managing board members of the general partner, the Compensation Committee determines the vesting period for phantom units and the exercise period for options. Through December 31, 2007, phantom units granted under the APL Plan generally had vesting periods of four years. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could in-crease or decrease the actual award settlement, as determined by the Compensation Committee, although no awards currently outstanding contain any such provision. Phantom units awarded to non-employee managing board members of the general partner vest over a four year period. Awards will automatically vest upon a change of control, as defined in the APL Plan. In May 2007, our stockholders approved an amendment to the APL Plan which provides for performance-based awards criteria for purposes of complying with Section 162(m).

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Executive Group Incentive Program

In connection with Atlas Pipeline’s acquisition of Spectrum Field Services, Inc. (“Spectrum”) in July 2004, and its retention of certain Spectrum’s executive officers, we created an executive group incentive program for Atlas Pipeline’s Mid-Continent operations. Eligible participants in the executive group incentive program are Robert R. Firth, David D. Hall and such other of Atlas Pipeline’s officers as agreed upon by Messrs. Firth and Hall and our board. The executive group incentive program has three award components: base incentive, additional incentive and acquisition look-back incentive, as follows:

· Base incentive. An award of 29,053412 of Atlas Pipeline common units on the day following the earlier to occur of the filing of its quarterly report on Form 10-Q for the quarter ending September 30, 2007 or a change in control if the following conditions are met:

· distributable cash flow (defined as earnings before interest, depreciation, amortization and any allocation of overhead from Atlas Pipeline, less maintenance capital expenditures on the Spectrum assets) generated by the Spectrum assets, as expanded since Atlas Pipeline’s acquisition of them, has averaged at least 10.7%, on an annualized basis, of average gross long term assets (defined as total assets less current assets, closing costs associated with any acquisition and plus accumulated depreciation, depletion and amortization) over the 13 quarters ending September 30, 2007 and

· there having been no more than 2 quarters with distributable cash flow of less than 7%, on an annualized basis, of gross long term assets for that quarter.

· Additional incentive. An award of Atlas Pipeline’s common units, promptly upon the filing of its September 30, 2007 Form 10-Q, in an amount equal to 7.42% of the base incentive for each 0.1% by which average annual distributable cash flow exceeds 10.7% of average gross long term assets, as described above, up to a maximum of an additional 29,053412 common units.

· Acquisition look-back incentive. If the requirements for the base incentive have been met, an award of Atlas Pipeline common units determined by dividing (x) 1.5% of the imputed value of the Elk City system plus 1.0% of the imputed value of all Mid-Continent acquisitions completed before December 31, 2007 that were identified by members of the Mid-Continent executive group by (y) the average closing price of Atlas Pipeline common units for the 5 trading days before December 31, 2008. Imputed value of an acquisition is equal to the distributable cash flow generated by the acquired entity during the 12 months ending December 31, 2008 divided by the yield. Yield is determined by dividing (i) the sum of Atlas Pipeline’s quarterly distributions for the quarter ending December 31, 2008 multiplied by 4 by (ii) the closing price of its common units on December 31, 2008.

The executive group incentive program awards will be allocated among members of the executive group at the discretion of Mr. Firth, provided that no member may receive more than 60% of the total compensation provided under the program.

AHD Plan

The AHD Plan provides performance incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners who perform services for Atlas Pipeline Holdings. The AHD Plan is administered by our Compensation Committee under delegation from the Atlas Pipeline Holdings’ board. The Compensation Committee may grant awards of either phantom units or unit options for an aggregate of 2,100,000 common limited partner units.

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Partnership Phantom Units. A phantom unit entitles a participant to receive an Atlas Pipeline Holdings common unit upon vesting of the phantom unit or, at the discretion of the Compensation Committee, cash equivalent to the then fair market value of a common unit. In tandem with phantom unit grants, the Compensation Committee may grant a DER. The Compensation Committee determines the vesting period for phantom units. Through December 31, 2007, phantom units granted under the AHD Plan generally vest 25% three years from on the third anniversary of the date of grant and 100% four years from the 75% on the fourth anniversary of the date of grant.

Partnership Unit Options. A unit option entitles a participant to receive a common unit upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of a common unit as determined by the Compensation Committee on the date of grant of the option. The Compensation Committee determines the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through December 31, 2007, unit options granted generally will vest 25% three years fromon the third anniversary of the date of grant and 100% four years from75% on the fourth anniversary of the date of grant.

The vesting of both types of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the Compensation Committee, although no awards currently outstanding contain any such provision. Awards will automatically vest upon a change of control, as defined in the AHD Plan. In May 2007, our stockholders approved an amendment to the AHD Plan which provides for performance-based awards criteria for purposes of complying with Section 162(m).

2007 OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END TABLE 

			Option Awards									Stock Awards
			Number of Securities Underlying Unexercised Options (#)			Number of Securities Underlying Unexercised Options (#)			Option Exercise			Option Expiration			Number of Shares or Units of Stock That Have Not			Market Value of Shares or Units of Stock That Have Not
Name			Exercisable			Unexercisable			Price ($)			Date			Vested (#)			Vested ($)
Edward E. Cohen			675,000	(1)		—		$	16.98			7/1/2015			31,250	(2)	$	1,339,062	(3)
			—			500,000	(4)	$	22.56			11/10/2016			90,000	(5)	$	2,441,700	(6)
						500,000	(7)	$	23.06			1/24/2017			200,000	(8)	$	6,218,000	(9)
Matthew A. Jones			90,000	(10)		90,000	(11)	$	16.98			7/1/2015			11,250	(12)	$	482,062	(3)
			—			100,000	(13)	$	22.56			11/10/2016			20,000	(14)	$	542,600	(6)
						50,000	(15)	$	23.06			1/24/2017			20,000	(16)	$	621,800	(9
Jonathan Z. Cohen			450,000	(17)		—		$	16.98			7/1/2015			21,250	(18)	$	910,562	(3)
			—			200,000	(19)	$	22.56			11/10/2016			45,000	(20)	$	1,220,850	(6)
						200,000	(21)	$	23.06			1/24/2017			100,000	(22)	$	3,109,000	(9)
Freddie M. Kotek			45,000	(23)		45,000	(24)	$	16.98			7/1/2015			500	(25)	$	21,425	(3)
						50,000	(26)	$	23.06			1/24/2017			20,000	(27)	$	621,800	(9)
Richard D. Weber			18,750	(28)		56,250	(29)	$	31.91			4/17/2016			—			—
			93,438	(30)		280,314	(31)	$	21.00			4/17/2016			35,715	(32)	$	1,110,379	(9)

⁽¹⁾ Represents 675,000 options to purchase our stock, granted on 7/1/05 in connection with our spin-off from Resource America, which vested immediately. Reflects a 3-for-2 stock split which was effected on May 29, 2007.

⁽²⁾ Represents Atlas Pipeline Partners phantom units, which vest as follows: 3/16/08 - 5,000; 6/8/08 - 6,250; 11/1/08 - 5,000; 3/16/09 - 5,000; 11/1/09 - 5,000 and 11/1/10 - 5,000.

⁽³⁾ Based on closing market price of Atlas Pipeline Partners common units on December 31, 2007 of $42.85.

⁽⁴⁾ Represents Atlas Pipeline Holdings options, which vest as follows: 11/10/09 - 125,000 and 11/10/10 - 375,000.

⁽⁵⁾ Represents Atlas Pipeline Holdings phantom units, which vest as follows: 11/10/09 - 22,500 and 11/10/10 - 67,500.

⁽⁶⁾ Based on closing market price of Atlas Pipeline Holdings common units on December 31, 2007 of $27.13.

⁽⁷⁾ Represents Atlas Energy Resources options, which vest as follows: 1/24/10 - 125,000 and 1/24/11 - 375,000.

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⁽⁸⁾ Represents Atlas Energy Resources phantom units, which vest as follows: 1/24/10 - 50,000 and 1/24/17 - 150,000.

⁽⁹⁾ Based upon closing price of Atlas Energy Resources common units on December 31, 2007 of $31.09.

⁽¹⁰⁾ Represents 90,000 options to purchase our stock, granted on 7/1/05 in connection with our spin-off from Resource America. Reflects a 3-for-2 stock split which was effected on May 29, 2007.

⁽¹¹⁾ Represents options to purchase our stock, which vest as follows: 7/1/08 - 45,000 and 7/1/09 - 45,000.

⁽¹²⁾ Represents Atlas Pipeline Partners phantom units, which vest as follows: 3/16/08 - 3,750; 11/1/08 - 1,250; 3/16/09 - 3,750; 11/1/09 - 1,250 and 11/1/10 - 1,250.

⁽¹³⁾ Represents Atlas Pipeline Holdings options, which vest as follows: 11/10/09 - 25,000 and 11/10/10 - 75,000.

⁽¹⁴⁾ Represents Atlas Pipeline Holdings phantom units, which vest as follows: 11/10/09 - 5,000 and 11/10/10 - 15,000.

⁽¹⁵⁾ Represents Atlas Energy Resources options, which vest as follows: 1/24/10 - 12,500 and 1/24/11 - 37,500.

⁽¹⁶⁾ Represents Atlas Energy Resources phantom units, which vest as follows: 1/24/10—5,000 and 1/24/11—15,000.

⁽¹⁷⁾ Represents 450,000 options to purchase our stock, granted on 7/1/05 in connection with our spin-off from Resource America, which vested immediately. Reflects a 3-for-2 stock split which was effected on May 29, 2007.

⁽¹⁸⁾ Represents Atlas Pipeline Partners phantom units, which vest as follows: 3/16/08 - 3,125; 6/8/08 - 3,750; 11/1/08 - 3,750; 3/16/09 - 3,125; 11/1/09 - 3,750 and 11/1/10 - 3,750.

⁽¹⁹⁾ Represents Atlas Pipeline Holdings options, which vest as follows: 11/10/09 - 50,000 and 11/10/10 - 150,000.

⁽²⁰⁾ Represents Atlas Pipeline Holdings phantom units, which vest as follows: 11/10/09 - 11,250 and 11/10/10 - 33,750.

⁽²¹⁾ Represents Atlas Energy Resources options, which vest as follows: 1/24/10 - 50,000 and 1/24/11 - 150,000.

⁽²²⁾ Represents Atlas Energy Resources phantom units, which vest as follows: 1/24/10—25,000 and 1/24/11—75,000.

⁽²³⁾ Represents 45,000 options to purchase our stock, granted on 7/1/05 in connection with our spin-off from Resource America. Reflects a 3-for-2 stock split which was effected on May 29, 2007.

⁽²⁴⁾ Represents options to purchase our stock, which vest as follows: 7/1/08 - 22,500 and 7/1/09 - 22,500.

⁽²⁵⁾ Represents Atlas Pipeline Partners phantom units, which vest as follows: 3/16/08-250 and 3/16/09 - 250.

⁽²⁶⁾ Represents Atlas Energy Resources options, which vest as follows: 1/24/10 - 12,500 and 1/24/11 - 37,500.

⁽²⁷⁾ Represents Atlas Energy Resources phantom units, which vest as follows: 1/24/10—5,000 and 1/24/11—15,000.

⁽²⁸⁾ Represents 18,750 options to purchase our stock. Reflects a 3-for-2 stock split which was effected on May 29, 2007.

⁽²⁹⁾ Represents options to purchase our stock, which vest as follows: 4/17/08 - 18,750; 4/17/09 - 18,750 and 4/17/10 - 18,750.

⁽³⁰⁾ Represents 93,438 options to purchase Atlas Energy Resources common units.

⁽³¹⁾ Represents 280,314 Atlas Energy Resources options, which vest as follows: 4/17/08—93,438; 4/17/09—93,438 and 4/17/10—93,438.

⁽³²⁾ Represents Atlas Energy Resources restricted units, which vest as follows: 4/17/08—11,905; 4/17/09—11,905 and 4/17/10—11,905.

2007 OPTION EXERCISES AND STOCK VESTED TABLE

		Stock Awards
Name		Number of Shares Acquired on Vesting				Value Realized on Vesting ($)
Edward E. Cohen			16,250	(1)		$	818,500
Matthew A. Jones			5,000	(1)		$	239,375
Jonathan Z. Cohen			10,625	(1)		$	533,787
Richard D. Weber			11,904	(2)		$	330,574
Freddie M. Kotek			250	(1)		$	11,875

⁽¹⁾ Represents Atlas Pipeline Partners common units.

⁽²⁾ Represents Atlas Energy Resources common units.

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2007 PENSION BENEFITS TABLE

Name

Plan Name

Number of Years Credited Service (#)

Present Value of Accumulated Benefit ($)

Payments During Last Fiscal Year ($)

Edward E. Cohen

SERP

5

$

2,474,836

—

For a description of Mr. Cohen’s SERP, please see “Employment Agreements - Edward E. Cohen”, and for a discussion of the valuation method and material assumptions applied in quantifying the present value of the accumulated benefit, please see note 10 to our Consolidated Financial Statements.

2007 Director Compensation Table

Name		Fees earned or paid in cash ($)			Stock awards ($) (1)			Total ($)
Dennis A. Holtz		$	60,000		$	13,333		$	73,333
Carlton M. Arrendell		$	60,000		$	13,333		$	73,333
Nicholas A. DiNubile		$	60,000		$	13,333		$	73,333
William R. Bagnell		$	60,000		$	13,333		$	73,333
Donald W. Delson		$	60,000		$	13,333		$	73,333
Harmon S. Spolan		$	60,000		$	3,328		$	63,328

(1) Represents the dollar amount of expense recognized by us for financial statement reporting purposes with respect to deferred units granted under the Stock Plan (see Note 10 to our consolidated financial statements) in accordance with FAS 123R. For Messrs. Holtz, Arrendell, Bagnell and Delson, represents 247 deferred shares granted under the Stock Plan on May 14, 2007 (adjusted to 371 deferred shares as a result of a 3-for-2 stock split which was effected on May 29, 2007), having a grant date fair value, valued in accordance with FAS 123R at the closing price of our common stock on the grant date of $60.60 (adjusted to $40.40 post-split), of $15,000. The units vest one-third on each of the second, third and fourth anniversaries of the date of grant. The vesting schedule for the shares is as follows: 5/14/09 - 123; 5/14/10 -123 and 5/14/11 -135. For Mr. Spolan, represents 292 deferred shares granted under the Stock Plan on August 24, 2007, having a grant date fair value, valued in accordance with FAS 123R at the closing price of our common stock on the grant date of $51.27, of $14,971. The vesting schedule for the award is as follows: 8/24/09 - 97; 8/24/10 - 97 and 8/24/11 - 98.

Director Compensation

Effective January 1, 2007, upon approval by the full board of directors, the independent directors receive a flat fee of $60,000 per year. In addition to the cash compensation, independent directors receive an annual grant of deferred stock having a fair market value of $15,000 with a vesting schedule in which 33% of the award vests on the second, third and fourth anniversaries of the grant date.

Compensation Committee Interlocks and Insider Participation

The Compensation Committee of the Board of Directors consists of Messrs. Delson, Arrendell and Holtz. There are no Compensation Committee interlocks.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the number and percentage of shares of our common stock owned by beneficial owners of 5% or more of our common stock, by our executive officers and directors and by all of the executive officers and directors as a group as of February 25, 2008.

		Common Stock
		Amount and Nature of Beneficial Ownership (2)						Percent of Class
Beneficial Owner
Directors(1)
Carlton M. Arrendell			1,580					*
William R. Bagnell			366					*
Edward E. Cohen			2,781,960		(3)(5)			10.33	%
Jonathan Z. Cohen			1,545,360		(4)(5)			5.74	%
Donald W. Delson			1,581					*
Nicholas A. DiNubile			2,714					*
Dennis A. Holtz			2,652					*
Harmon S. Spolan			0					0
Non-Director Executive Officers(1)
Frank P. Carolas			42,774		(5)			*
Freddie M. Kotek			192,407		(5)			*
Matthew A. Jones			90,011		(5)			*
Nancy J. McGurk			57,188		(5)			*
Jeffrey C. Simmons			85,020		(5)			*
Michael L. Staines			59,541		(5)			*
All executive officers and directors as a group (14 persons)			3,891,536		(6)			14.45	%
Other Owners of More Than 5% of Outstanding Shares
Cobalt Capital Management, Inc.			2,492,230		(7)			9.26	%
Iridian Asset Management LLC			1,736,523		(8)			6.5	%
Leon G. Cooperman			2,455,641		(9)			9.1	%

* Less than 1%

(1) The business address for each director and executive officer is 1550 Coraopolis Heights Road—2^nd Floor, Moon Township, Pennsylvania 15108.

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(2) All shares reflect a 3-for-2 stock split which was effected on May 29, 2007.

(3) Includes (i) 33,636 shares held in an individual retirement account of Betsy Z. Cohen, Mr. E. Cohen’s spouse; (ii) 935,801 shares held by a charitable foundation of which Mr. E. Cohen, his spouse and their children serve as co-trustees; and (iii) 94,252 shares held in trust for the benefit of Mr. E. Cohen’s spouse and/or children. Mr. E. Cohen disclaims beneficial ownership of the above referenced shares. 86,197 and 935,801 shares are also included in the shares referred to in footnote 4 below.

(4) Includes (i) 86,197 shares held in a trust of which Mr. J. Cohen is a co-trustee and co-beneficiary and (ii) 935,801 shares held by a charitable foundation of which Mr. J. Cohen, his parents and his sibling serve as co-trustees. These shares are also included in the shares referred to in footnote 3 above. Mr. J. Cohen disclaims beneficial ownership of the above referenced shares.

(5) Includes shares issuable on exercise of options granted under our Stock Incentive Plan in the following amounts: Mr. E. Cohen — 675,000 shares; Mr. J. Cohen — 450,000 shares; Mr. Carolas — 33,750 shares; Mr. Kotek — 45,000 shares; Mr. Jones — 90,000 shares; Ms. McGurk - 4,688 shares; Mr. Simmons — 33,750 shares; and Mr. Staines — 5,625 shares.

(6) This number has been adjusted to exclude 86,197 shares and 935,801 shares which were included in both Mr. E. Cohen’s beneficial ownership amount and Mr. J. Cohen’s beneficial ownership amount.

(7) This information is based on a Schedule 13G/A filed with the SEC on February 14, 2008. The address for Cobalt Capital Management, Inc. is 237 Park Avenue, Suite 900, New York, New York 10017.

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(8) This information is based on a Schedule 13G filed with the SEC on February 4, 2008. The address for Iridian Asset Management, LLC is 276 Post Road West, Westport, CT 06880-4704.

(9) This information is based on a Schedule 13G/A filed with the SEC on February 6, 2008. The address for Mr. Cooperman is 88 Pine Street, Wall Street Plaza, 31st Floor, New York, New York 10005.

Equity Compensation Plan Information

The following table contains information about our Plan as of December 31, 2007:

								(c)
Plan category		(a) Number of securities to be issued upon exercise of equity instruments			(b) Weighted-average exercise price of outstanding equity instruments			Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders - restricted units			4,263			n/a
Equity compensation plans approved by security holders - options			1,810,254		$	18.15
Equity compensation plans approved by security holders - Total			1,814,517						1,112,565

The following table contains information about the ATN Plan as of December 31, 2007:

								(c)
Plan category		(a) Number of securities to be issued upon exercise of equity instruments			(b) Weighted-average exercise price of outstanding equity instruments			Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans not approved by security holders - phantom and restricted units			624,665			n/a
Equity compensation plans not approved by security holders - unit options			1,895,052		$	24.09
Equity compensation plans not approved by security holders - Total			2,519,717						1,210,379

The following table contains information about the AHD Plan as of December 31, 2007:

								(c)
Plan category		(a) Number of securities to be issued upon exercise of equity instruments			(b) Weighted-average exercise price of outstanding equity instruments			Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders - phantom units			220,825			n/a
Equity compensation plans approved by security holders - unit options			1,215,000		$	22.56
Equity compensation plans approved by security holders - Total			1,435,825						663,800

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The following table contains information about the APL Plan as of December 31, 2007:

								(c)
Plan category		(a) Number of securities to be issued upon exercise of equity instruments			(b) Weighted-average exercise price of outstanding equity instruments			Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders - phantom units			129,746			n/a			208,055

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

 Our board of directors has determined that the following are independent directors under NASDAQ rules: Carlton M. Arrendell, William R. Bagnell, Donald W. Delson, Nicholas A. DiNubile, Dennis A Holtz and Harmon S Spolan.

We have the following agreements with Resource America, our former parent, for which Edward E. Cohen, our Chairman, Chief Executive Officer and President, serves as Chairman and is a greater than 10% shareholder, and Jonathan Z. Cohen, our Vice Chairman, serves as Chief Executive Officer and President.

Tax Matters Agreement

As part of our initial public offering in 2004, we entered into a tax matters agreement with Resource America, which governs our respective rights, responsibilities, and obligations of after our initial public offering with respect to tax liabilities and benefits, tax attributes, tax contests and other matters regarding income taxes, non-income taxes and related tax returns.

In general, under the tax matters agreement:

· Resource America is responsible for any U.S. federal income taxes of the affiliated group for U.S. federal income tax purposes of which Resource America is the common parent. With respect to any periods beginning after our initial public offering, we are responsible for any U.S. federal income taxes attributable to us or any of our subsidiaries, including taxes payable as a result of our June 2005 spin-off from Resource America.

· Resource America is responsible for any U.S. state or local income taxes reportable on a consolidated, combined or unitary return that includes Resource America or one of its subsidiaries, on the one hand, and us or one of our subsidiaries, on the other hand. However, in the event that we or one of our subsidiaries are included in such a group for U.S. state or local income tax purposes for periods (or portions thereof) beginning after the date of our initial public offering, we are responsible for our portion of such income tax liability as if we and our subsidiaries had filed a separate tax return that included only us and our subsidiaries for that period (or portion of a period).

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· Resource America is responsible for any U.S. state or local income taxes reportable on returns that include only Resource America and its subsidiaries (excluding us and our subsidiaries), and we are responsible for any U.S. state or local income taxes filed on returns that include only us and our subsidiaries.

· Resource America and we are each responsible for any non-income taxes attributable to our business for all periods.

Resource America is primarily responsible for preparing and filing any tax return with respect to the Resource America affiliated group for U.S. federal income tax purposes and with respect to any consolidated, combined or unitary group for U.S. state or local income tax purposes that includes Resource America or any of its subsidiaries. We generally are responsible for preparing and filing any tax returns that include only us and our subsidiaries.

We have generally agreed to indemnify Resource America and its affiliates against any and all tax-related liabilities that may be incurred by them relating to the distribution to the extent such liabilities are caused by our actions. This indemnification applies even if Resource America has permitted us to take an action that would otherwise have been prohibited under the tax-related covenants as described above.

During 2007, we did not have any liability to Resource America pursuant to the tax matters agreement.

Transition Services Agreement

Also in connection with our initial public offering, we entered into a transition services agreement with Resource America which governs the provision support services between us, such as:

· cash management and debt service administration;

· accounting and tax;

· investor relations;

· payroll and human resources administration;

· legal;

· information technology;

· data processing;

· real estate management; and

· other general administrative functions.

We and Resource America will pay each other a fee for these services equal to their fair market value. The fee is payable monthly in arrears, 15 days after the close of each month. We have also agreed to pay or reimburse each other for any out-of-pocket payments, costs and expenses associated with these services. During fiscal 2007, we reimbursed Resource America $930,000 pursuant to this agreement. Certain operating expenditures totaling $58,000 that remain to be settled between are reflected in our consolidated balance sheets as advances from affiliate.

Anthem Securities, until December 2006 our wholly-owned subsidiary and now a wholly-owned subsidiary of Atlas Energy, is a registered broker-dealer which provides dealer-manager services for investment programs sponsored by Resource America’s real estate and equipment finance segments. Salaries of the personnel performing services for Anthem are paid by Resource America, and Anthem reimburses Resource America for the allocable costs of such personnel. In addition, Resource America agreed to cover some of the operating costs for Anthem’s office of supervisory jurisdiction, principally licensing fees and costs.  In fiscal 2007, Resource America paid $5.2 million toward such operating costs of Anthem and Anthem reimbursed it $3.2 million.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

For the years ended December 31, 2007 and 2006, Grant Thornton LLP’s accounting fees and services (in thousands) were as follows.

		2007			2006
Audit fees(1)		$	397		$	1,721
Audit-related fees(2)			63			18
Tax fees			209			76
All other fees			-			-
Total accounting fees and services		$	669		$	1,815

(1) Audit fees include professional services rendered for the annual audit of our financial statements and the reviews of the financial statements included in our quarterly reports on Form 10-Q.

(2) Represents fees related to the annual audit of our employee benefit plan and acquisitions in fiscal 2007 and public offering matters in fiscal 2006.

Audit Committee Pre-Approval Policies and Procedures

The Audit Committee, on at least an annual basis, reviews audit and non-audit services performed by Grant Thornton, LLP as well as the fees charged by Grant Thornton, LLP for such services. Our policy is that all audit and non-audit services must be pre-approved by the Audit Committee. All of such services and fees were pre-approved during 2007 and 2006.

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) (1) Financial Statements

Report of Independent Registered Public Accounting Firm		95
Consolidated Balance Sheets at December 31, 2007 and 2006		96
Consolidated Statements of Income for the years ended December 31,2007 and 2006, the three months ended December 31, 2005 and the year ended September 30, 2005		97
Consolidated Statements of Comprehensive Income for the years ended December 31, 2007 and 2006, the three months ended December 31, 2005 and the year ended September 30, 2005		98
Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2007 and 2006, three months ended December 31, 2005 and the year ended September 30, 2005		99
Consolidated Statements of Cash Flows for the years ended December 31, 2007 and 2006, the three months ended December 31, 2005 and the year ended September 30, 2005		100
Notes to Consolidated Financial Statements - December 31, 2007		101

(2) Financial Statement Schedules

(3) Exhibits:

Exhibit No.		Description
3.1		Amended and Restated Certificate of Incorporation(1)
3.2		Amended and Restated Bylaws(1)
4.1		Form of stock certificate(2)
10.1		Amendment to Agreement for Services with Richard Weber (3)
14.1		Insider Trading Policy(4)
21.1		Subsidiaries of Atlas America, Inc.
23.1		Consent of Grant Thornton LLP
31.1		Rule 13(a)-14(a)/15d-14(a) Certification.
31.2		Rule 13(a)-14(a)/15d-14(a) Certification.
32.1		Section 1350 Certification.
32.2		Section 1350 Certification.

(1) Previously filed as an exhibit to our Form 8-K filed June 14, 2005

(2) Previously filed as an exhibit to our registration statement on Form S-1 (registration no. 333-112653)

(3) Previously filed as an exhibit to our Form 8-K filed May 1, 2007

(4) Previously filed as an exhibit to our Form 8-K filed August 31, 2007

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SIGNATURES

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

			ATLAS AMERICA, INC. (Registrant)
Date: February 29, 2008			By:	/s/ Edward E. Cohen
				Edward E. Cohen Chairman, Chief Executive Officer and President

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

/s/ Edward E. Cohen		Chairman, Chief Executive Officer and President		February 29, 2008
Edward E. Cohen
/s/ Jonathan Z. Cohen		Vice Chairman		February 29, 2008
Jonathan Z. Cohen
/s/ Matthew A. Jones		Chief Financial Officer		February 29, 2008
Matthew A. Jones
/s/ Nancy J. McGurk		Senior Vice President and Chief Accounting Officer		February 29, 2008
Nancy J. McGurk
/s/ Carlton M. Arrendell		Director		February 29, 2008
Carlton M. Arrendell
/s/ William R. Bagnell		Director		February 29, 2008
William R. Bagnell
/s/ Donald W. Delson		Director		February 29, 2008
Donald W. Delson
/s/ Nicholas A. DiNubile		Director		February 29, 2008
Nicholas A. DiNubile
/s/ Dennis A. Holtz		Director		February 29, 2008
Dennis A. Holtz
/s/ Harmon S. Spolan		Director		February 29, 2008
Harmon S. Spolan

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