ARKHAN 10K 2008 Annual report

ARKHAN Inactive 10-K2008 FY Annual report

Content analysis

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, 2008

¨	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 ¨ No x

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

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

Indicate by check mark 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, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “small reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the 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, 2008, was approximately $1.8 billion.

The number of outstanding shares of the registrant’s common stock on February 25, 2009 was 39,295,258 shares.

DOCUMENTS INCORPORATED BY REFERENCE: None

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	30
	Item 1B: Unresolved Staff Comments	62
	Item 2: Properties	62
	Item 3: Legal Proceedings	65
	Item 4: Submission of Matters to a Vote of Security Holders	65

PART II	Item 5: Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	65
	Item 6: Selected Financial Data	66
	Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations	68
	Item 7A: Quantitative and Qualitative Disclosures about Market Risk	92
	Item 8: Financial Statements and Supplementary Data	100
	Item 9: Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	152
	Item 9A: Controls and Procedures	153
	Item 9B: Other Information	155

PART III	Item 10: Directors, Executive Officers and Corporate Governance	155
	Item 11: Executive Compensation	155
	Item 12: Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	155
	Item 13: Certain Relationships and Related Transactions, and Director Independence Matters	155
	Item 14: Principal Accounting Fees and Services	155

PART IV	Item 15: Exhibits and Financial Statement Schedules	156

SIGNATURES		159

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, the Appalachian Basin and Indiana’s New Albany Shale, which we manage through our subsidiary, Atlas Energy Management, Inc., under the supervision of ATN’s board of directors;

•

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

Our ownership interest in ATN consists of the following:

•

all of the outstanding Class A units, representing 1,293,486 units at December 31, 2008, 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

•

29,952,996 common units, including 600,000 purchased in May 2008 in a private placement transaction, representing approximately 47.3% of the outstanding common units at December 31, 2008, or a 46.3% 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 or any of such four quarters.

Our ownership interest in APL consists of 1,112,000 common units, purchased in June 2008 in a private placement transaction, representing approximately 2.4% of the outstanding common units of APL at December 31, 2008, or a 2.1% ownership interest.

Our ownership interest in AHD consists of 17,808,109 common units, including 308,109 purchased in a June 2008 private placement transaction, representing approximately 64.4% of the outstanding common units of AHD at December 31, 2008. 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”);

•

5,754,253 common units, representing approximately 12.5% of the outstanding common units at December 31, 2008, or a 11.0% ownership interest in APL; and

•

10,000 $1,000 par value 12.0% cumulative convertible preferred limited partner units, representing an approximate 3.2% ownership interest in APL based upon the market value of APL’s common units at December 31, 2008.

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 17 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.

ATN is an independent developer and producer of natural gas and oil, with operations in northern the Appalachian Basin, where ATN focuses on the development of the Marcellus Shale, Michigan’s Antrim Shale, and Indiana’s New Albany Shale. ATN’s Appalachian Basin major operations are located in eastern Ohio, western Pennsylvania, and north central Tennessee, and additional operations in New York, West Virginia and Kentucky. ATN specializes in the development of these natural gas basins because they provide repeatable, low-risk drilling opportunities. ATN is a leading sponsor and manager of tax-advantaged, direct investment natural gas and oil partnerships in the United States. ATN’s focus is to increase its own reserves, production, and cash flows through a balanced mix of generating new opportunities of geologic prospects, natural gas and oil exploitation and development, and sponsorship of investment partnerships. ATN generates both upfront and ongoing fees from the drilling, production, servicing, and administration of its wells in these partnerships.

As of December 31, 2008, ATN had the following key assets:

Appalachia gas and oil operations

•

proved reserves of 373.9 billion cubic feet equivalents (“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 8,462 gross productive gas and oil wells;

•

overriding royalty interests in approximately 624 gross productive gas and oil wells;

•

net daily production of 35.6 million cubic feet equivalents per day (“MMcfed”); and

•

approximately 950,530 gross (904,890 net) acres, of which approximately 640,430 gross (633,490 net) acres are undeveloped; included in the undeveloped acreage is 556,438 Marcellus Shale acres in Pennsylvania, New York and West Virginia, of which approximately 274,495 acres are located in ATN’s core Marcellus Shale position in southwestern Pennsylvania.

Michigan gas and oil operations

•

proved reserves of 617.0 Bcfe;

•

direct and indirect working interests in approximately 2,458 gross producing gas and oil wells;

•

manage total proved reserves of 1,003 Bcfe;

•

overriding royalty interest in approximately 93 gross producing gas and oil wells;

•

net daily production was 59.7 MMcfed; and

•

approximately 345,680 gross (273,280 net) acres, of which approximately 42,390 gross (33,100 net) acres are undeveloped.

Indiana gas and oil operations

•

proved reserves of 10.3 Bcfe;

•

direct and indirect working interests in approximately 5 gross producing gas and oil wells;

•

overriding royalty interest in approximately 93 gross producing gas and oil wells;

•

net daily production was 0.2 MMcfed; and

•

approximately 161,140 gross (119,670 net) acres, of which approximately 160,480 gross (119,185 net) acres, are undeveloped.

Partnership management business

•

ATN investment partnership business, which includes equity interests in 94 investment partnerships and a registered broker-dealer which acts as the dealer-manager of ATN’s investment partnership offerings; and

•

managed total Appalachia proved reserves of 706 Bcfe.

In June 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, were 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.

In the third quarter of 2008, ATN established a position in the New Albany Shale of southwestern Indiana by acquiring 114,000 net acres for approximately $15.0 million in cash and entering into a farm out agreement that will give it the rights to an additional 78,000 net acres (121,000 gross acres). These transactions afford ATN the opportunity to drill on 284,000 gross acres, including the 121,000 gross acre farm out. Using capital from its syndicated oil and gas investment programs, ATN began drilling in 2008 and plans to have over 100 horizontal wells drilled by the completion of 2009.

ATN’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.

Geographic and Geologic Overview

Marcellus Shale Overview. 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 our acreage in western Pennsylvania. As of February 19, 2009, ATN controls approximately 556,000 Marcellus Shale acres in Pennsylvania, New York and West Virginia, and it continues to expand its position. As of that date, ATN had drilled 126 vertical wells, 5 horizontal wells and is currently producing 105 wells into a pipeline. The remaining 26 wells are scheduled to be completed and turned into line in the first half of 2009. ATN is currently focused on approximately 274,000 of its existing Marcellus Shale acres in southwestern Pennsylvania, where it has drilled all but two of its Marcellus wells and has now, through this drilling, largely delineated its acreage. Almost all of this acreage in southwestern Pennsylvania has or is expected to have ample pipeline capacity using ATN’s or APL’s gas gathering infrastructure

Over the last 4 months, ATN has made great strides in optimizing its completion practices for vertical Marcellus Shale wells. ATN has initiated a multiple stage completion process that isolates various portions of the Marcellus package, giving a more effective stimulation of the reservoir. This technique has been used on 15 wells to date, and has consistently illustrated better-than-average peak 24-hour, 30-day, and 60-day cumulative production results. It is anticipated that, where applicable, that all future vertical wells will be stimulated in this fashion. With 8 multiple stage wells on line at year end, Wright & Company, Inc., our independent petroleum engineering consultants assigned an average EUR of 1.423 Bcf per well. As of this date, ATN has successfully drilled, cased, and cemented 3 additional horizontal wells in Washington County PA, with 2 of these wells stimulated and currently flowing back frac fluid.

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, 2008, the average premium over NYMEX for natural gas delivered to our primary delivery points in the Appalachian Basin was $0.24 per MMBtu. In addition, ATN’s Appalachian gas production also has the advantage of a high energy content, ranging from 1.0 to 1.15 Dth per Mcf. Historically, because ATN’s gas sales contracts yield upward adjustments from index based pricing for throughput with an energy content above 1.0 Dth per Mcf. This higher energy content resulted in realized premiums averaging 1.06% over normal pipeline quality gas for the twelve months ended December 31, 2008.

During the first several years of production, shallow 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. While the wells in this area are characterized by modest initial volumes and pressures, their geological features also account for the low annual decline rates demonstrated by vertical wells in the region, many of which are expected to produce for 30 years or more. Shallow reserves in the Appalachian Basin are typically in blanket formations and have a high degree of step-out development success. The primary pay zone throughout this region is the Devonian Shale formation. As the step-out 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.

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 the Antrim was purposely targeted for production on a large scale. The Antrim Shale is a low risk, organically rich black shale formation that is naturally fractured and primarily contains biogenic methane and water. Antrim production rates vary according to the intensity of the fracturing in the area immediately surrounding individual wells. The fractures provide the conduits for free gas and associated water to flow to the borehole through the black shale which otherwise has low permeability. Moreover, the fractures assist in the release of gas absorbed 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. Each well’s gas is transported 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.

New Albany Shale Overview.The Devonian aged New Albany Shale is a blanket formation found at depths of 500 to 3,000 feet, with thicknesses ranging from 100 to 200 feet. Like the Antrim, the New Albany Shale in southwestern Indiana where ATN’s leasehold acreage is located is in the “biogenic gas window.” However, unlike the Antrim Shale, where natural fracture patterns are low angle, the natural fracture patterns in the New Albany Shale are vertically oriented. This vertical fracture orientation lends itself to a horizontal drilling approach.

Horizontal Drilling Overview

The value potential for many of ATN’s Appalachian properties may be enhanced by the use of horizontal drilling, which has been found to provide advantages in extracting natural gas in various environments, including shale and other tight reservoirs that are challenging to produce efficiently. In general, horizontal wells use directional drilling to create one or more lateral legs designed to allow the well bore to stay in contact with the reservoir longer and to intersect more vertical fractures in the formation than conventional methods. While substantially more expensive, horizontal drilling may improve overall returns on investment by increasing recovery volumes and rates, limiting the number of wells necessary to develop an area through conventional drilling and reducing the costs and surface disturbances of multiple vertical wells.

Gas and Oil Production

The gas and oil wells in each geological basin in which ATN operates shares a relatively predictable production profile, producing high quality natural gas at low pressures from several pay zones. Wells in each region generally demonstrate moderate annual production declines throughout their economic life, which may continue for 30 years or more without significant remedial work or the use of secondary recovery techniques. ATN increased its production volumes for the year ended December 31, 2008 by 59% over prior year levels to a record 34.9 Mmcfe. The following table shows ATN’s total net oil and gas production volumes during the last three years:


	Years Ended December 31,
	2008	2007		2006
Production per day⁽¹⁾:
Appalachia⁽²⁾:
Natural gas (Mcfd)	33,023	27,156		24,511
Oil (Bbl)	423	418		413

Total (Mcfed)	35,561	29,666		26,989

Michigan:
Natural gas (Mcfd)	59,606	59,737	⁽³⁾	—
Oil (Bbl)	11	4		—

Total (Mcfed)	59,672	59,761		—

Total:
Natural gas (Mcfd)	92,629	86,893		24,511
Oil (bpd)	434	422		413

Total (Mcfed)	95,227	89,425		26,989

⁽¹⁾

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

⁽²⁾	Appalachia includes our production located in Pennsylvania, Ohio, New York, West Virginia, and Tennessee.

⁽³⁾	Amounts represent production volumes related to ATN’s Michigan acquisition from the acquisition date (June 29, 2007).

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 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 20% to 31% of the overall capitalization in a particular partnership. ATN also receives an additional interest in each partnership, typically 7% to 10%, for which ATN does not make any additional capital contribution, for a total interest in its partnerships ranging from 27% to 40%.

During the last three years, ATN raised over $1.0 billion from outside investors for participation in its drilling partnerships. Net proceeds from these programs are used to fund the investors’ share of drilling and completion costs under ATN’s drilling contracts with the programs. ATN recognizes revenues from drilling operations on the percentage-of-completion method as the wells are drilled, rather than when funds are received. ATN’s fund raising activities of sponsored drilling programs during the last three years are summarized in the following table (amounts in thousands):


	Drilling Program Capital
Years Ended December 31,	Investor Contributions		ATN Contributions		Total Capital
2008	$	438.4	$	146.3	$	584.7
2007		363.3		137.6		500.9
2006		218.5		65.2		283.7

Total	$	1,020.2	$	349.1	$	1,369.3

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 shows the number of gross and net development wells ATN drilled for itself and its investment partnerships during the last three years. ATN did not drill any exploratory wells during the years ended December 31, 2008, 2007 and 2006.


Years Ended December 31,	Gross	Net⁽¹⁾	ATN share of net	Dry Gross	Net⁽¹⁾
Appalachia
2008	830	786	279	8	3
2007	1,106	1,021	378	11	4
2006	711	655	235	4	1

Total	2,647	2,462	892	23	8

Michigan/Indiana
2008	173	143	140	—	—
2007	115	92	92	—	—
2006	—	—	—	—	—

Total	288	235	232	—	—

⁽¹⁾	Includes (i) ATN’s percentage interest in wells in which it has a direct ownership interest and (ii) ATN’s percentage interest in the wells based on its percentage interest in its investment partnerships.

ATN does not operate any of the rigs or related equipment used in its drilling operations, relying instead on specialized subcontractors or joint venture partners for all drilling and completion work. This enables it to streamline its operations and conserve capital for investments in new wells, infrastructure and property acquisitions, while generally retaining control over all geological, drilling, engineering and operating decisions. Other than its Marcellus Shale and horizontal wells, the geological characteristics of ATN’s Appalachian and Michigan properties enable it to drill most of its vertical wells in seven to ten days, although ATN usually defers completion operations until Atlas Pipeline’s gathering lines are in place. ATN performs regular inspection, testing and monitoring functions on its operated wells and Atlas Pipeline’s gathering systems with its own personnel.

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 an 18% mark-up on those costs incurred to drill and complete the well. Prior to ATN’s investment program that was recently formed in November 2008, the mark-up was 15%.

•

Administration and oversight.For each well drilled by an investment partnership, ATN receives a fixed fee of approximately $15,700 for non-Marcellus Shale wells and $62,241 for Marcellus Shale wells. Prior to ATN’s investment program that was recently formed in November 2008, the fixed fee was $15,000 for non-Marcellus Shale wells and $60,000 for Marcellus Shale 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.Each partnership pays ATN a gathering fee. ATN, in turn, pays this gathering fee to APL, pursuant to the terms of our contribution agreement with ATN. Therefore, 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. 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. Currently, under ATN’s investment partnership that was formed in November 2008, approximately 85% of the subscription proceeds received have been used to pay 100% of the partnership’s intangible drilling costs. For example, an investment of $10,000 generally permits the investor to deduct from taxable ordinary income approximately $8,500 in the year in which the investor invests. Under prior ATN partnership agreements, approximately 90% of the subscription proceeds received were used to pay 100% of the partnership’s intangible drilling costs.

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 typically¹/8^th(12.5%) resulting in a 87.5% net revenue interest to ATN, and in Michigan this amount is typically¹/6^th (16.67%) resulting in an 83.3% net revenue interest to ATN. In certain instances, this royalty amount may increase to¹/6^thin the Appalachian Basin and to³/16^th (18.75%) in Michigan when leases are taken from larger landowners or mineral owners such as coal and timber companies.

In almost all of the areas ATN operates in the Appalachian Basin, Michigan and Indiana, 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.

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 from¹/32^ndto¹/16^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%.

The interests in some of our operated properties and of natural gas and oil leases retain the option to participate in the drilling of wells on leases farmed out or assigned to ATN for a retained working interest of up to 50% of the wells drilled on the covered acreage. In this event, ATN’s working interest ownership will be reduced by the amount retained by the third party. In all other instances, ATN anticipates owning a 100% working interest in newly drilled wells.

Contractual Revenue Arrangements

•

East Ohio Gas Company, National Fuel Gas Distribution, Columbia of Ohio, and Peoples Natural Gas Company, which are local distribution companies; and

•

National Fuel Gas Supply, Columbia Gas Transmission Corporation, Tennessee Gas Pipeline Company, and Texas Eastern Transmission Company, which are interstate pipelines.

A portion of 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, 2008, we anticipate that ATN and its affiliates, including its investment partnerships, will sell approximately 16% of their Appalachian natural gas production during the year ending December 31, 2009 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, 2008, ATN received an average price, before the effects of financial hedges, of $9.63 per Mcf of natural gas, compared to $7.71 per Mcf in fiscal 2007 and $7.90 per Mcf in fiscal 2006 in our Appalachian operations.

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 Energy Company, 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.

Based on the most recent monthly production data available to ATN as of December 31, 2008, we anticipate that ATN and its affiliates will sell approximately 49% of their Michigan natural gas production during the year ending December 31, 2009 under the DTE agreements in most cases at NYMEX pricing. During the year ended December 31, 2008, ATN’s Michigan operations received an average of $9.01 per Mcf of natural gas, before the effects of financial hedges.

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.

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

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 and Permian Basins and the Golden Trend 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 and treatment services in Oklahoma and Texas. APL also provides interstate gas transmission services in southeastern Oklahoma, Arkansas, southern Kansas 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 500 million cubic feet per day (“MMcfd”);

•

eight natural gas processing plants with aggregate capacity of approximately 810 MMcfd and one treating facility with a capacity of approximately 200 MMcfd, located in Oklahoma and Texas; and

•

9,100 miles of active natural gas gathering systems located in Oklahoma, Arkansas, Kansas and Texas, which transport gas from wells and central delivery points in the Mid-Continent region to APL’s natural gas processing and treating plants or Ozark Gas Transmission, as well as third-party pipelines.

Through its Appalachian operations, APL owns and operates 1,835 miles of active natural gas gathering systems located in eastern Ohio, western New York, western Pennsylvania and northeastern Tennessee. 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:

•

In July 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. 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. AHD also agreed that the resulting allocation of incentive distribution rights back to APL would be after AHD receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter. APL funded the remaining purchase price from $830.0 million of proceeds from a 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. 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 has an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system which began on June 15, 2008 and ended November 1, 2007, and up to an additional 7.4% interest beginning on June 15, 2009 and ending on November 1, 2009 (the aggregate 22.0% additional interest can be entirely purchased during the period beginning June 15, 2009 and ending on November 1, 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 22.0% interest if fully exercised. APL will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercises the purchase options; 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.

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 7,800 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 subject to the availability of adequate capital resources and liquidity, which increase distributable cash flow.

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 certain regions of 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 natural gas liquids (“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 generally exceeded this minimum. The balance of the Appalachian system natural gas APL transports is for third-party operators generally under fixed-fee contracts.

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 purchases contracted under keep-whole arrangements are generally low in liquids content and meet 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 9,900 miles of intrastate natural gas gathering systems, including approximately 800 miles of inactive pipeline, located in Oklahoma, Arkansas, southeastern Missouri, Kansas, northern and western Texas and the Texas panhandle, and eight 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 7,800 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 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 and Ozark Gas Transmission.

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 interconnects with intrastate pipelines, including Enogex, BP’s Vastar gathering system, Arkansas Oklahoma Gas Corporation, Arkansas Western Gas Company, ONEOK Gas Transmission, our own Ozark Gas Gathering system and other producer owned gas gathering systems.

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, 2008, the combined gathering systems had approximately 4,295 miles of natural gas gathering pipelines with approximately 3,520 receipt points.

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 600 miles of natural gas pipelines located in the Anadarko Basin in western Oklahoma and the Texas panhandle, including the Atoka and Granite Wash plays. The Elk City and Sweetwater gathering system connects to over 600 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, 2008, consists of approximately 2,650 miles of gas gathering pipeline and approximately 2,700 receipt points 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.

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 had the right to increase its ownership interest in the Midkiff/Benedum system by an additional 14.6% which began June 15, 2008 and ended November 1, 2008 and an additional 7.4% beginning June 15, 2009 and ending November 1, 2009 (the aggregate 22.0% additional interest can be entirely purchased during the period beginning June 15, 2009 and ending on November 1, 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 be 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 282 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, 2008, the gathering system had approximately 1,200 miles of active pipeline with approximately 650 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, Chester and Chaney Dell plants, all of which are active cryogenic natural gas processing facilities. The Chaney Dell system’s processing operations have total capacity of approximately 250 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. The Chaney Dell plant, which was idled in the fourth quarter of 2006 when the Waynoka plant began operations, was reactivated in January 2008 because of drilling activity in the Anadarko Basin, adding 22 MMcfd of additional processing capacity.

Midkiff/Benedum. The Midkiff/Benedum system processes natural gas through the Midkiff and Benedum processing plants. The Midkiff plant is a 110 MMcfd cryogenic facility in Reagan County, Texas. The Benedum plant is a 43 MMcfd cryogenic facility in Upton County, Texas and includes eight compressors for inlet and residue recompression. APL’s Midkiff/Benedum processing operations have an aggregate processing capacity of approximately 153 MMcfd.

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 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, Sweetwater and Prentiss facilities are on the same gathering system and are referred to as APL’s Elk City/Sweetwater operations. 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 180 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. During July 2008, APL completed a 60 MMcfd expansion of the Sweetwater plant to a total processing capacity of 180 MMcfd. Through this expansion, APL extended the system’s reach into the Granite Wash play in the Hemphill County, Texas area, which it believes will continue to increase its natural gas processing and throughput volumes.

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 20 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, 2008, 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 several creditworthy purchasers downstream of its processing plants at first-of-month price indices as published inInside FERC. Additionally, swing gas, which is natural gas that is sold at non-contracted prices during a current month, is sold daily at variousPlatt’s Gas Daily midpoint pricing points. The Velma plant has access to ONEOK Gas Transportation, LLC, an intrastate pipeline, and Southern Star Central Gas Pipeline, Inc., an interstate pipeline. The Elk City/Sweetwater plants have access to six major interstate and intrastate downstream pipelines: Natural Gas Pipeline Company of America, Panhandle Eastern Pipe Line Company, LP, Northern Natural Gas Company, CenterPoint Energy, Inc., ANR Pipeline Company and ONEOK Gas Transportation, LLC. The Chaney Dell, Chester and Waynoka plants have access to Panhandle Eastern Pipe Line Company, LP, while the Chaney Dell and Chester plants also have access to Southern Star Central Gas Pipeline, Inc. The Midkiff/Benedum plants have access to Northern Natural Gas Company and El Paso Natural Gas Company. As negotiated in specific agreements, third-party producers are allowed to deliver their gas in-kind to the above listed delivery points at all facilities.

We sell our 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 in 2013, the Chaney Dell agreement has an initial term expiring September 1, 2009, and the Midkiff/Benedum agreement expires in 2013. All NGL agreements 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 our account to EnerWest Trading Company, LLC. Condensate collected at the Elk City/Sweetwater plants and around the Elk City/Sweetwater gathering system is sold to Petro Source Partners, L.P. Condensate collected at the Chaney Dell plants and around the Chaney Dell gathering system is sold to Plains Marketing. Condensate collected at the Midkiff/Benedum plants and around the Midkiff/Benedum gathering system is 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 financial 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 manages 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 derivative instruments in revenue when it sells the associated physical residue natural gas or NGLs. Any gain or loss realized as a result of the financial instrument settlement is substantially offset in the market when APL sell the physical residue natural gas or NGLs. APL applies the provisions of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” to its derivative instruments. It determines gains or losses on open and closed derivative transactions as the difference between the derivative contract price and the physical price. This mark-to-market methodology uses daily closing NYMEX prices when applicable and an internally-generated algorithm for commodities that are not traded on a market. To insure that these derivative instruments will be used solely for managing price risks and not for speculative purposes, APL has established a committee to review its derivative instruments for compliance with its policies and procedures.

For additional information on APL’s derivative activities and a summary of APL’s outstanding derivative instruments as of December 31, 2008, please see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk.”

APL’s Appalachian Basin Operations

APL owns and operates approximately 1,835 miles of intrastate gas gathering systems located in eastern Ohio, western New York, western Pennsylvania and northeastern Tennessee. APL’s Appalachian operations serve approximately 7,440 wells with an average throughput of 87.3 MMcfd of natural gas for the year ended December 31, 2008. 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., East Tennessee Natural Gas, Citizens Gas Utility District 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 transports 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, 2008, APL connected 4,461 new wells to its Appalachian gathering system, 685 of which were added through acquisitions of other gathering systems. For the year ended December 31, 2008, APL connected 741 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, 2008, APL received gathering fees averaging $1.40 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.

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 ONEOK Field Services, Carrerra Gas Company, Compano Energy, LLC, Enogex, LLC., Eagle Rock Midstream Resources, L.P., Enbridge, Inc., Hiland Partners, MarkWest Energy Partners, L.P., Mustang Fuel Corporation, DCP Midstream, J.L. Davis and Targa Resources. 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

•

the 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 and Texas Gas Transmission’s interstate systems are the nearest direct competitors.

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, 2008, APL connected 59 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.

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 unit holders 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 unit holders.

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 unit holders. APL’s common unit holders 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 unit holders 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 unit holders.

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.

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 64.4% 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.

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 unit holders. APL’s common unit holders 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 unit holders 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 unit holders.

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 is sold under contract to various purchasers. For the year December 31, 2008, 2007 and 2006, gas sales to Hess Corporation (formerly First Energy Solutions Corp.) accounted for 10%, 10% and 18%, respectively, of ATN’s total Appalachian gas and oil production revenues. For the year ended December 31, 2008 and the six months ended December 31, 2007, sales to DTE accounted for 49% and 46% of ATN’s Michigan oil and gas production revenues, respectively. No other single customer accounted for more than 10% of ATN’s total revenues during these periods.

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 2008, Chesapeake Energy Corporation, Pioneer, Sandridge Energy, Inc., Conoco Phillips, XTO Energy Inc., Henry Petroleum, L.P., Linn Energy, LLC and Apache Corporation supplied APL’s Mid-Continent systems with a majority of their natural gas supply. For the year ended December 31, 2008, there were three APL customers who accounted for approximately 37% of its 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 and water treatment facilities;

•

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 ATN’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, 2008, 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 2009, or that will otherwise have a material impact on our financial position or results of operations.

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, tribal lands 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, 2008, 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 2009, 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.

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. These permits may require pretreatment of produced waters before discharge. Compliance with such permits and requirements may be costly. 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.

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 manner in which water necessary to develop wells is managed;

•

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.

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 4.9% 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. While Pennsylvania has historically not imposed a severance tax, its governor recently proposed a tax of 5% on the value of natural gas at the wellhead plus $0.047 per MCF beginning October 1, 2009. 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 rules has not had a material adverse effect on APL’s operations but there is no assurance that this 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 natural gas companies includes:

•

rate structures;

•

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;

•

transactions involving the assignment of interstate pipeline capacity;

•

interactions with marketing affiliates; 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 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 fund its operations, pay required debt service on its credit facilities and make distributions to us, as general partner, and its common unit holders.

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.

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 on 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 (“LNG”) 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 with respect to LNG terminals and interstate natural gas pipelines; 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 has been

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 were 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, 2008, we employed 978 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 atwww.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 atwww.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.

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

ITEM 1A:

RISK FACTORS

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 year ended December 31, 2008, this excess amount was approximately $13.3 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 indemnified Atlas Energy through 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.

Risks Related to Atlas Energy

Atlas Energy may not have sufficient cash flow from operations to pay quarterly distributions 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 quarterly distributions. 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 unit holders and the holders of the management incentive interests. The amount of cash it can distribute principally depends upon the amount of cash it generates 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 collectability 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 initial quarterly distribution amount.

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;

•

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, 2008, the NYMEX Henry Hub natural gas index price ranged from a high of $13.11 per MMBtu to a low of $6.47 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $134.02 per Bbl to a low of $42.04 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, 2008 reserve report, its average annual decline rate for proved developed producing reserves is approximately 7.8% during the first five years, approximately 5.3% in the next five years and less than 5.5% thereafter. Because ATN’s total estimated proved reserves include proved undeveloped reserves at December 31, 2008, 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.

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 receives 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. 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;

•

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 any future acquisitions with its operations and in realizing all of the anticipated benefits of these acquisitions.

ATN 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;

•

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.

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 June 2007 DTE Gas & Oil acquisition has significantly increased Atlas Energy’s size, redefined its business plan, expanded its geographic market and resulted in large increases 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 January 15 2009, Atlas Energy had drilled 121 wells to the Marcellus Shale, 121 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 and requires greater volumes of water than conventional gas wells. The management of water and the treatment of produced water from Marcellus Shale wells may be more costly than the management of produced water from other geologic formations.

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 1, 2009, it had total debt of approximately $873.7 million, consisting of $406.7 million of senior notes and $467.0 million of borrowings under its credit facility. 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;

•

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.

Changes in tax laws may impair ATN’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 ATN 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 ATN’s investment partnerships less attractive and, thus, reduce its ability to obtain funding from this significant source of capital funds.

Recently proposed severance taxes in Pennsylvania could materially increase ATN’s liabilities.

In 2008, ATN’s liabilities for severance taxes in the states in which we operate, other than Pennsylvania, were approximately $12.2 million. While Pennsylvania has historically not imposed a severance tax, with a focus on its budget deficit and the increasing exploitation of the Marcellus Shale, Pennsylvania’s governor recently proposed a tax of 5% of the value of natural gas at the wellhead plus $0.047 per Mcf beginning October 1, 2009. If adopted, these taxes may materially increase ATN’s operating costs in Pennsylvania.

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. During the fourth quarter of 2008, we began development drilling activities for us and our partnership investors in Indiana. Accordingly, the amount of development activities it undertakes 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 $218.5 million, $363.3 million and $438.4 million in calendar years 2006, 2007 and 2008, 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.

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 the year ended December 31, 2008 natural gas sales to Hess Corporation accounted for approximately 10% of its total Appalachian oil and gas revenues. In Michigan, during year ended December 31, 2008, gas under contracts to a former affiliate of Atlas Gas & Oil, which expire at various dates through 2012, accounted for approximately 49% 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 unit holders 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.

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, including produced waters, 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, 2008, Atlas Energy had identified over 3,626 potential drilling locations in Appalachia. 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. Of the 3,626 potential shallow drilling locations, Atlas Energy’s independent petroleum engineering consultants have not assigned any proved reserves to the 358 proved undeveloped locations. Of the remaining drilling locations it has identified 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.

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

Leases covering approximately 85,140 of Atlas Energy’s 422,900 net acres, or 20%, are scheduled to expire on or before December 31, 2009. An additional 33% that are scheduled to expire in the years 2010 and 2011. If Atlas Energy is unable to renew these leases or any leases scheduled for expiration beyond December 31, 2009, 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 future distribution payments on its debt.

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.

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 and oil has been volatile and unpredictable for many years. To limit exposure to changing natural gas and oil prices, Atlas Energy uses financial and physical hedges for its natural gas, and to a lesser extent, its oil 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, and to a lesser extent, its oil production, Atlas Energy has reduced, but not eliminated, the potential effects of changing natural gas and oil prices on its cash flow from operations for those periods. Furthermore, while intended to help reduce the effects of volatile natural gas and oil prices, such transactions, depending on the hedging instrument used, may limit its potential gains if natural gas and oil 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 94 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.

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.

ATN may issue additional units without the approval of the common unit holders, which would dilute the common unit holder’s existing ownership interests.

ATN’s limited liability company agreement permits it to issue an unlimited number of units of any type, including common units, without the approval of its unit holders. The issuance of additional units or other equity securities may have the following effects:

•

the proportionate ownership of the existing common unit holders’ interest in it may decrease;

•

the amount of cash distributed on each common unit may decrease;

•

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

•

the market price of the common units may decline.

An increase in interest rates may cause the market price of ATN’s common units to decline.

Like all equity investments, an investment in ATN’s common units is subject to risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly-traded limited liability company interests. Reduced demand for ATN’s common units resulting from investors seeking other investment opportunities may cause the trading price of its common units to decline.

Unit holders may have liability to repay distributions.

Under certain circumstances, unit holders may have to repay amounts wrongfully returned or distributed to them. Under Section 18-607 of the Delaware Revised Limited Liability Company Act, ATN may not make a distribution to the common unit holders if the distribution would cause ATN’s liabilities to exceed the fair value of its assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, unit holders who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited liability company for the distribution amount. A purchaser of common units who becomes a unit holder is liable for the obligations of the transferring unit holder to make contributions to the limited liability company that are known to such purchaser of units at the time it became a member and for unknown obligations if the liabilities could be determined from ATN’s limited liability company agreement.

If ATN’s unit price declines, the common unit holders could lose a significant part of their investment.

The market price of ATN’s common units could be subject to wide fluctuations in response to a number of factors, most of which ATN cannot control including:

•

Changes in securities analysts’ recommendations and their estimates of ATN’s financial performance;

•

The public’s reaction to ATN’s press releases, announcements and its filings with the SEC;

•

Fluctuations in broader securities market prices and volumes, particularly among securities of natural gas and oil companies and securities of publicly-traded limited partnerships and limited liability companies;

•

Changes in market valuations of similar companies;

•

Departures of key personnel;

•

Commencement of or involvement in litigation;

•

Variations in ATN’s quarterly results of operations or those of other natural gas and oil companies;

•

Variations in the amount of ATN’s quarterly cash distributions;

•

Future issuances and sales of ATN’s units; and

•

Changes in general conditions in the U.S. economy, financial markets or the natural gas and oil industry.

In recent years the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of ATN’s common units.

If the holders of ATN’s common units vote to eliminate the special voting rights of the holders of its Class A units, the Class A units will automatically convert into common units on a one-for-one basis and we will have the option of converting the management incentive interests into common units at their fair market value, which may be dilutive to you.

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

ATN’s tax treatment depends on its status as a partnership for federal income tax purposes, as well as its not being subject to entity-level taxation by individual states. If the IRS were to treat ATN as a corporation for federal income tax purposes or ATN 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 ATN’s common units depends largely on its being treated as a partnership for federal income tax purposes. ATN have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects it. If ATN were treated as a corporation for federal income tax purposes, ATN 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 you would generally be taxed as corporate distributions, and no income, gain, loss, deduction or credit would flow through to you. Because a tax may be imposed on ATN as a corporation, its cash available for distribution to its unit holders could be reduced. Therefore, ATN’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 ATN’s common units. Current law or its business may change so as to cause ATN to be treated as a corporation for federal income tax purposes or otherwise subject it 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 it as an entity, the cash available for distribution to you would be reduced. ATN’s limited liability company agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects it to taxation as a corporation or otherwise subjects it to entity-level taxation for federal, state or local income tax purposes, the cash distribution amounts and the incentive distribution amounts will be adjusted to reflect the impact of that law on it.

ATN’s common unit holders may be required to pay taxes on income from it even if they do not receive any cash distributions from it.

ATN’s common unit holders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of its taxable income, whether or not they receive cash distributions from it. ATN’s common unit holders may not receive cash distributions from it equal to their share of its taxable income or even equal to the actual tax liability that results from their share of its taxable income.

A successful IRS contest of the federal income tax positions ATN take may harm the market for its common units, and the costs of any contest will reduce cash available for distribution.

ATN have not requested a ruling from the IRS with respect to its treatment as a partnership for federal income tax purposes or any other matter that affects it. The IRS may adopt positions that differ from the positions ATN take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions ATN take and a court may disagree with some or all of those positions. Any contest with the IRS may lower the price at which its common units trade. In addition, ATN’s costs of any contest with the IRS will result in a reduction in cash available for distribution to its unit holders and thus will be borne indirectly by its unit holders.

Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts, or IRAs, and non-U.S. persons raises issues unique to them. For example, virtually all of ATN’s income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to such a unit holder. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of ATN’s taxable income.

ATN will treat each purchaser of its common units as having the same tax benefits without regard to the common units purchased.

The IRS may challenge this treatment, which could reduce the value of the common units. Because ATN cannot match transferors and transferees of common units, ATN will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could reduce the amount of tax benefits available to its unit holders. It also could affect the timing of these tax benefits or the amount of gain on the sale of common units and could have a negative impact on the value of ATN’s common units or result in audits of and adjustments to its unit holders’ tax returns.

Tax gain or loss on the disposition of ATN’s common units could be more or less than expected because prior distributions in excess of allocations of income will decrease the tax basis in its units.

If ATN’s common unit holders sell any of their common units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those units. Prior distributions to them in excess of the total net taxable income they were allocated for a common unit, which decreased their tax basis in that unit, will, in effect, become taxable income to them if the unit is sold at a price greater than their tax basis in that unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to them. In addition, they may incur a tax liability in excess of the amount of cash they receive from the sale.

ATN’s common unit holders may be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in its common units.

In addition to federal income taxes, ATN’s common unit holders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which ATN do business or own property now or in the future, even if they do not reside in any of those jurisdictions. ATN’s common unit holders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, they may be subject to penalties for failure to comply with those requirements. It is the responsibility of each unit holder to file all United States federal, foreign, state and local tax returns that may be require of such unit holder. ATN’s counsel has not rendered an opinion on the state or local tax consequences of an investment in the common units.

ATN prorate its items of income, gain, loss and deduction between transferors and transferees of its units each month based upon the ownership of its units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing IRS Treasury Regulations, and, accordingly, ATN’s counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury Regulations were issued, ATN may be required to change the allocation of items of income, gain, loss and deduction among its unit holders.

A unit holder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, the unit holder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unit holder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, the unit holder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unit holder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of ATN’s income, gain, loss or deduction with respect to those units may not be reportable by the unit holder and any cash distributions received by the unit holder as to those units could be fully taxable as ordinary income. ATN’s counsel has not rendered an opinion regarding the treatment of a unit holder where common units are loaned to a short seller to cover a short sale of common units; therefore, unit holders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

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 unit holder 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.

Risks Related to Atlas Pipeline Holdings

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

AHD depends upon cash distributions from APL to fund its operations, pay its debt service on its credit facilities and make distributions to its unitholders. The amounts of cash that APL generates may not be sufficient for it to pay distributions to AHD 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 we discuss in “Risks relating to APL’s Business,” many of 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 unit holders 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.

Economic conditions and instability in the financial markets could negatively impact APL’s business which could impact the cash AHD has to make distributions to its unitholders.

APL’s operations are affected by the continued financial crisis and related turmoil in the global financial system. The consequences of an economic recession and the current credit crisis include a lower level of economic activity and increased volatility in energy prices. This has resulted in a decline in energy consumption and lower market prices for oil and natural gas, and may result in a reduction in drilling activity in APL’s service area or in wells currently connected to APL’s pipeline system being shut in by their operators until prices improve. Any of these events may adversely affect APL’s revenues and its ability to fund capital expenditures and, in turn, may impact the cash that AHD has available to fund its operations, pay debt service on its credit facility and make distributions to its unitholders.

Recent instability in the financial markets, as a result of recession or otherwise, has increased the cost of capital while the availability of funds from those markets has diminished significantly. This may affect APL’s ability to raise capital and reduce the amount of cash available to fund its operations. APL relies on its cash flow from operations and its credit facility to execute its growth strategy and to meet its financial commitments and other short-term liquidity needs. AHD cannot be certain that additional capital will be available to APL to the extent required and on acceptable terms. Disruptions in the capital and credit markets could negatively impact its access to liquidity needed for its business and impact its flexibility to react to changing economic and business conditions. Any disruption could require APL to take measures to conserve cash until the markets stabilize or until it can arrange alternative credit arrangements or other funding for its business needs. Such measures could include reducing or delaying business activities, reducing its operations to lower expenses, reducing other discretionary uses of cash, and reducing or eliminating future distributions to its unitholders. The source of AHD’s earnings and cash flow currently consists exclusively of cash distributions from APL. If APL reduces or eliminates its distributions, AHD would be forced to reduce or eliminate distributions to its unitholders and may be unable to make required debt service payments under its credit facility which would result in lenders foreclosing on some portion, or all, of AHD’s interest in APL. Moreover, APL may be unable to execute its growth strategy, take advantage of business opportunities or to respond to competitive pressures, any of which could negatively impact its and AHD’s business as it depends on APL for its growth as we describe in “AHD depends 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 unit holders of APL, AHD’s ability to pursue business opportunities independently is limited,” under “Risks Relating to AHD’s Business”.

The current economic situation could have an adverse impact on APL’s producers, key suppliers or other customers, or on AHD’s or APL’s lenders, causing them to fail to meet their obligations to AHD or APL. Market conditions could also impact APL’s derivative instruments. If a counterparty is unable to perform its obligations and the derivative instrument is terminated, APL’s cash flow and ability to pay distributions could be impacted which in turn affects AHD’s ability to make required debt service payments on its credit facility and the amount of distributions that AHD is able to make to its unitholders. The uncertainty and volatility of the global financial crisis may have further impacts on APL’s, and consequently AHD’s, business and financial condition that AHD and APL currently cannot predict or anticipate.

AHD’s and APL’s debt levels and restrictions in AHD’s and APL’s credit facilities could limit their ability to fund operations, pay required debt service on their credit facilities and make distributions to its unit holders.

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 unit holders. 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. If it cannot, its ability to make distributions to AHD and consequently, AHD’s ability to fund its operations, pay required debt service and make distributions to its unitholders could be reduced or eliminated.

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 unit holders. 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 unit holders 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 unit holders are not entitled to receive such payments in the future.

AHD’s distributions to its unit holders are not cumulative. Consequently, if AHD does not pay distributions on its common units with respect to any fiscal quarter, AHD’s unit holders 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, AHD’s ability to fund its operations, pay required debt service on its credit facility and, thereafter, to make distributions to its

unit holders 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 unit holders 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 unit holders 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 unit holders will depend on numerous factors, many of which are beyond AHD’s control or the control of its general partner.

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 unit holders.

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 unit holders 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. AHD also agreed that the resulting allocation of incentive distribution rights back to APL would be after AHD receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 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 unit holders 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 unit holders 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 distributions from APL with respect to any particular quarter only if APL distributes more than $0.42 per common unit for such quarter. Furthermore, as described in the immediately preceding 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. AHD also agreed that the resulting allocation of incentive distribution rights back to APL would be after AHD receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 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;

•

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 unit holders 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 unit holders due to a number of factors, including increases in its general and administrative expenses, increases in principal or interest payments on its outstanding debt, reductions in distributions from APL, 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 unit holders, 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 unit holders. The establishment of those reserves could result in a reduction in cash distributions to AHD’s unit holders from current levels pursuant to AHD’s stated cash distribution policy;

•

AHD’s partnership agreement, including the 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 and the amount of distributions paid under APL’s cash distribution policy. The decision by APL to make any distribution to its unit holders is at the discretion of APL’s general partner, taking into consideration the terms of its partnership agreement; and

•

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 unit holders 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 unit holders, and there is no guarantee that its unit holders 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 completely depends 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. The occurrence of any of these events may impact the cash that AHD has available to fund its operations, pay required debt service on its credit facility and make distributions to its unit holders. Moreover, the incurrence of additional debt to finance its growth strategy would result in increased interest expense to APL, which in turn may impact the cash it has available to distribute to its unit holders.

AHD depends 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 unit holders of APL, AHD’s ability to pursue business opportunities independently is 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 unit holders which would make it difficult for AHD to engage in any business activity that is competitive with APL. Those fiduciary duties apply to AHD because it controls the general partner through its ability to elect all of its directors. While there may be circumstances in which AHD may satisfy these fiduciary duties and still 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 unit holders 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 unit holders of APL the right to remove the general partner of APL upon the affirmative vote of holders of 66²/3% 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.

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 unit holders, 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 unit holders 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 unit holders’ 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.

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 unit holders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to AHD’s unit holders. Because a tax would be imposed upon AHD as a corporation, AHD’s cash available for distribution to its unit holders 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 unit holders 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 funding its operations, paying required debt service on its credit facility or making distributions to its unit holders.

APL 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, based upon estimated unhedged market prices of $0.76 per gallon, $6.50 per mmbtu and $55.00 per barrel for NGLs, natural gas and condensate, respectively, would change its gross margin for the twelve-month period ended December 31, 2009, excluding the effect of minority interests in APL’s net income, by approximately $25.3 million. Additionally, changes in natural gas prices may indirectly impact APL’s profitability since prices can influence drilling activity and well operations, and could cause operators of wells currently connected to APL’s pipeline system or that APL expects will be connected to its system to shut them in until prices improve, thereby affecting 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 therefore completely depends upon the ability of APL to make distributions to its partners,” under “Risks Relating to Atlas Pipeline Holdings”. Oil and natural gas prices have been extremely volatile recently and have declined substantially. On December 19, 2008, the price of oil on the New York Mercantile Exchange fell to $33.87 per barrel for January 2009 delivery, declining to an approximate 5-year low and from a high of $147.27 per barrel in July 2008. 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 risk management 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, derivative instruments are subject to inherent risks, which are described in “— APL’s price risk management strategies may fail to protect it and could reduce its gross margin and cash flow.”

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 declining 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. A decrease in exploration and development activities in the fields served by APL’s gathering and processing facilities and pipeline transportation systems could result if there is a sustained decline in natural gas prices, which in turn, would lead to a reduced utilization of those assets. The decline in the credit markets, the lack of availability of credit, debt or equity financing and the decline in natural gas prices may result in a reduction of producers’ exploratory drilling. 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, drilling costs, governmental regulation and the availability and cost of capital. In a low price environment, such as currently exists, producers may determine to shut in wells already connected to APL’s systems until prices improve. 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 NGLs.

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 ATLS. Moreover, APL’s agreements with most of the producers with which its Mid-Continent operations do business generally do not require them to dedicate significant amounts of undeveloped acreage to APL’s systems. While APL does have some undeveloped acreage dedicated on its systems, most notably with its partner Pioneer on our Midkiff/Benedum system, 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, will reduce APL’s gross margin and cash flows.

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 2008, Chesapeake Energy Corporation, Pioneer, Sandridge Energy, Inc., Conoco Phillips, XTO Energy Inc., Henry Petroleum, L.P., Linn Energy, LLC and Apache Corporation 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. DCP Midstream, LLC, ONEOK, Inc., Carrera Gas Company, Copano Energy, LLC and Enogex, LLC. 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., Markwest Energy Partners, L.P. and Enogex LLC. operate competing gathering systems and processing plants. CenterPoint Energy, Inc.’s and Texas Gas Transmission’s interstate systems are the nearest direct competitors 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;

•

delays in obtaining any required regulatory approvals of third party consents;

•

the imposition of conditions on any acquisition by a regulatory authority;

•

an inability to integrate successfully or timely the businesses we acquire;

•

the assumption of unknown liabilities;

•

limitations on rights to indemnity from the seller;

•

the diversion of management’s attention from other business concerns;

•

increased demands on existing personnel;

•

customer or key employee losses at the acquired businesses; and

•

the failure to realize expected growth or profitability.

The scope and cost of these risks may ultimately be materially greater than estimated at the time of the acquisition. Further, 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 make or 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 has an active, on-going program to identify 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 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 pipeline safety-related records and procedures;

•

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’s investment in the interconnection of its Elk City/Sweetwater and Chaney Dell systems and the additional overhead costs it 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 its operations could harm its business or future prospects, and result in significant decreases in its 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.

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 these acquisitions, 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 fund its operations, pay required debt service on its credit facilities and make distributions to its common unit holders.

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.

APL recently completed construction of an expansion to its Sweetwater natural gas processing plant, from which it expects to generate additional incremental cash flow. APL also continues to expand the natural gas gathering system surrounding Sweetwater in order to maximize its plant throughput. In addition to the risks discussed above, expected incremental revenue from the Sweetwater natural gas processing plant could be reduced or delayed due to the following reasons:

•

difficulties in obtaining equity or debt financing for additional construction and operating costs;

•

difficulties in obtaining permits or other regulatory or third-party consents;

•

additional construction and operating costs exceeding budget estimates;

•

revenue being less than expected due to lower commodity prices or lower demand;

•

difficulties in obtaining consistent supplies of natural gas; and

•

terms in operating agreements that are not favorable to APL.

If APL is unable to obtain new rights-of-way or the cost of renewing existing rights-of-way increases, then 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 changed interpretations of existing laws, could subject APL’s gathering and processing operations 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.

Even if APL’s gathering and processing operations are not generally subject to regulation under the Natural Gas Act, 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 interstate natural gas pipeline 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.

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.

FERC’s rate-making policies 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;

•

transactions involving the assignment of interstate pipeline capacity;

•

construction of new facilities;

•

acquisition, extension or abandonment of services or facilities;

•

accounts and records, as well as periodic reporting requirements; 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 could impair Ozark Gas Transmission’s ability to compete for business, increase the costs it incurs in its operations, limit 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.

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 fail to comply with all applicable FERC administered statutes, rules, regulations and orders, it could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, 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.

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 delays in receiving regulatory approvals or may receive approvals that are subject to material conditions;

•

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 debt and 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 may issue additional units, which may increase the risk of not having sufficient available cash to maintain or increase its per unit distribution level.

APL has wide discretion to issue additional units, including units that rank senior to its common units as to quarterly cash distributions, on the terms and conditions established by its general partner. The payment of distributions on these additional units may increase the risk that APL will not be able to maintain or increase its per unit distribution level. To the extent new units are senior to its common units, their issuance will increase the uncertainty of the payment of distributions on the common units.

APL’s price risk management 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 price risk management activities will vary in scope based upon the level and volatility of natural gas and NGL prices and other changing market conditions. APL’s price risk management activity may fail to protect or could harm it because, among other things:

•

entering into derivative instruments can be expensive, particularly during periods of volatile prices;

•

available derivative instruments may not correspond directly with the risks against which APL seeks protection;

•

the duration of the derivative instrument may not match the duration of the risk against which APL seeks protection; and

•

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

Due to the accounting of APL’s derivative contracts, increases in prices for natural gas, crude oil and NGLs could result in non-cash balance sheet reductions.

With the objective of enhancing the predictability of future revenues, from time to time APL enters into natural gas, natural gas liquids and crude oil derivative contracts. APL accounts for these derivative contracts by applying the provisions of SFAS No. 133. Due to the mark-to-market accounting treatment for these derivative contracts, APL could recognize incremental derivative liabilities between reporting periods resulting from increases or decreases in reference prices for natural gas, crude oil and NGLs, which could result in APL recognizing a non-cash loss in our consolidated statements of operations or through accumulated other comprehensive income (loss) and a consequent non-cash decrease in our stockholders’ equity between reporting periods. Any such decrease could be substantial. In addition, APL may be required to make a cash payment upon the termination of any of these derivative contracts.

APL’s hedging activities do not eliminate its exposure to fluctuations in commodity prices and interest rates and may reduce its cash flow and subject our earnings to increased volatility.

APL’s operations expose it to fluctuations in commodity prices. APL utilizes derivative contracts related to the future price of crude oil, natural gas and NGLs with the intent of reducing the volatility of its cash flows due to fluctuations in commodity prices. APL also has exposure to interest rate fluctuations as a result of variable rate debt under its term loan and revolving credit facility. APL has entered into interest rate swap agreements to convert a portion of this variable rate debt to a fixed rate obligation, thereby reducing its exposure to market rate fluctuations.

APL has entered into derivative transactions related to only a portion of its crude oil, natural gas and NGL volume and its variable rate debt. As a result, it will continue to have direct commodity price risk and interest rate risk with respect to the unhedged portion of these items. To the extent APL hedges its commodity price and interest rate risk using certain derivative contracts, APL will forego the benefits it would otherwise experience if commodity prices or interest rates were to change in its favor.

Even though APL’s hedging activities are monitored by management, these activities could reduce its cash flow in some circumstances, including if the counterparty to the hedging contract defaults on its contract obligations, if there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices received or, with regard to commodity derivatives, if production is less than expected. With respect to commodity derivative contracts, if the actual amount of production is lower than the amount that is subject to its derivative instruments, APL might be forced to satisfy all or a portion of derivative transactions without the benefit of the cash flow from its sale of the underlying physical commodity, resulting in a reduction of its cash flow. In addition, APL has entered into proxy hedges with respect to its NGLs, typically using crude oil derivative contracts, based upon the historical price correlation between crude oil and NGLs. Certain of these proxy hedges could become less effective as a result of significant increases in the price of crude oil and less significant increases in the price of ethane and propane. If these proxy hedges remain less effective, its settlement of the contracts could result in significant costs to APL.

The accounting standards regarding hedge accounting are complex, and even when APL engages in hedging transactions that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our financial statements may reflect volatility due to these derivatives, even when there is no underlying economic impact at that point. In addition, it is not always possible for APL to engage in a derivative transaction that completely mitigates its exposure to commodity prices and interest rates. Our financial statements may reflect a gain or loss arising from an exposure to commodity prices and interest rates for which APL is unable to enter into a completely effective hedge transaction.

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.

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.

APL’s control of the Chaney Dell and Midkiff/Benedum systems is limited by provisions of the limited liability company operating agreements with Anadarko and, with respect to the Midkiff/Benedum system, the operation and expansion agreement with Pioneer.

The managing member of each of the limited liability companies which owns the interests in the Chaney Dell and Midkiff/Benedum systems is APL’s subsidiary. However, the consent of Anadarko is required for specified extraordinary transactions, such as admission of new members, engaging in transactions with APL’s affiliates not approved by the company conflicts committee, incurring debt outside the ordinary course of business and disposing of company assets above specified thresholds. The Midkiff/Benedum system is also governed by an operation and expansion agreement with Pioneer which gives system owners having at least a 60% interest in the system the right to approve the annual operating budget and capital investment budget and to impose other limitations on the operation of the system. Thus, a holder of a greater than

40% interest in the system would effectively have a veto right over the operation of the system. Pioneer currently owns an approximate 27% interest in the system but, pursuant to the purchase option agreement, has the right to acquire up to an additional 22% interest.

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, Philadelphia 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.

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 Atlas Energy’s percentage interests in the oil and gas properties owned by investment partnerships in which Atlas Energy owns partnership interests. All of the reserves are generally located in the Appalachian Basin in Michigan’s Lower Peninsula and in the southwestern corner of Indiana. 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 based its estimates of proved reserves upon the following weighted average prices as of the dates indicated:


	At December 31,
	2008		2007		2006
Natural gas (per Mcf)	$	5.71	$	6.93	$	6.33
Oil (per Bbl)	$	44.80	$	90.30	$	57.26

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 Atlas Energy’s 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 Atlas Energy’s independent petroleum engineering firm in preparing their reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, the reserves set forth in the following tables ultimately may not be produced and the proved undeveloped reserves may not be developed within the

periods anticipated. Please read “Item1A: Risk factors”. You should not construe the estimated PV-10 and standardized measure values as representative of the current or future fair market value of Atlas Energy’s 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. The following table presents ATN’s reserve information for the previous three years. Atlas Energy bases the estimates on operating methods and conditions prevailing as of the dates indicated.


	Proved natural gas and oil reserves for Atlas Energy at December 31,
	2008		2007		2006
Natural gas reserves (Mmcf):
Proved developed reserves		586,655		594,709		107,683
Proved undeveloped reserves⁽¹⁾		404,150		290,050		60,859

Total proved reserves of natural gas		990,805		884,759		168,542

Oil reserves (Mbbl):
Proved developed reserves		1,686		1,977		2,064
Proved undeveloped reserves		48		6		4

Total proved reserves of oil		1,734		1,983		2,068

Total proved reserves (Mmcfe)		1,001,209		896,657		180,950

PV-10 estimate of cash flows of proved reserves (in thousands):
Proved developed reserves	$	1,016,882	$	1,264,309	$	279,330
Proved undeveloped reserves		115,059		216,869		4,111

Total PV-10 estimate	$	1,131,941	$	1,481,178	$	283,441

Standardized measure of discounted future cash flows (in thousands)⁽²⁾	$	924,741	$	1,144,990	$	205,520

(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:


	Proved natural gas and oil reserves for Atlas Energy Resources at December 31,
	2008			2007			2006
PV-10 value	$	1,131,941		$	1,481,178		$	283,441
Income tax effect		(207,200	)		(336,188	)		(77,921	)

Standardized measure	$	924,741		$	1,144,990		$	205,520

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, 2008, 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	509	366
Gas wells	10,448	5,583

Total	10,957	5,949

(1)

Includes Atlas Energy’s proportionate interest in wells owned by 94 investment partnerships for which Atlas Energy serves as managing general partner and various joint ventures. Does not include royalty or overriding interests in 717 wells.

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, 2008. The information in this table includes Atlas Energy’s proportionate interest in acreage owned by its investment partnerships.


	Developed acreage⁽¹⁾		Undeveloped acreage⁽²⁾
	Gross⁽³⁾	Net⁽⁴⁾	Gross⁽³⁾	Net⁽⁴⁾
Arkansas	2,560	403	—	—
Indiana	673	483	160,480	119,185
Kansas	160	20	—	—
Kentucky	924	462	9,060	4,530
Louisiana	1,819	206	—	—
Michigan	303,290	240,180	42,390	33,100
Mississippi	40	3	—	—
Montana	—	—	2,650	2,650
New York	20,517	14,989	45,035	45,035
North Dakota	639	96	—	—
Ohio	113,529	95,408	31,984	31,984
Oklahoma	4,323	468	—	—
Pennsylvania	140,692	140,692	428,476	428,476
Tennessee	19,303	17,785	108,783	108,783
Texas	4,520	329	—	—
West Virginia	1,078	539	14,362	11,948
Wyoming	—	—	80	80

	614,067	512,063	843,300	785,771

(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 $3.9 million in fiscal 2008 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.

Atlas Pipeline and Atlas Pipeline Holdings

As of December 31, 2008, AHD’s assets consisted principally of its ownership interests in APL and it maintained no separate properties. As of December 31, 2008, APL’s principal facilities in Appalachia include approximately 1,835 miles of 2 to 12 inch diameter pipeline. APL’s principal facilities in the Mid-Continent area consist of eight natural gas processing plants, one treating facility, and approximately 9,900 miles of active and inactive 2 to 42 inch diameter pipeline. Substantially all of APL’s gathering systems and transmission pipeline are constructed within rights-of-way granted by property owners named in the appropriate land records. In a few cases, property for gathering system purposes was purchased in fee. All of APL’s compressor stations are located on property owned in fee or on property obtained via long-term leases or surface easements.

APL’s property or rights-of-way are subject to encumbrances, restrictions and other imperfections. These imperfections have not interfered, and we do not expect that they will materially interfere, with the conduct of APL’s business. In many instances, lands over which rights-of-way have been obtained are subject to prior liens which have not been subordinated to the right-of-way grants. In a few instances, APL’s rights-of-way are revocable at the election of the land owners. In some cases, not all of the owners named in the appropriate land records have joined in the right-of-way grants, but in substantially all such cases signatures of the owners of majority interests have been obtained. Substantially all permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets, and state highways, where necessary, although in some instances these permits are revocable at the election of the grantor. Substantially all permits have also been obtained from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election.

Certain of APL’s rights to lay and maintain pipelines are derived from recorded gas well leases, for wells that are currently in production; however, the leases are subject to termination if the wells cease to produce. In some of these cases, the right to maintain existing pipelines continues in perpetuity, even if the well associated with the lease ceases to be productive. In addition, because many of these leases affect wells at the end of lines, these rights-of-way will not be used for any other purpose once the related wells cease to produce.

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

No matters were submitted to a vote of our shareholders during the year ended December 31, 2008.

PART II

ITEM 5:

MARKET FOR REGISTRANT’S COMMON EQUITY, 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.” At the close of business on February 24, 2009, there were 39,295,679 shares of common stock outstanding at a closing price of $10.66 held by 250 holders of record. 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 and the cash dividends declared:


	High⁽¹⁾		Low⁽¹⁾		Cash Dividends Declared⁽¹⁾
Year ended December 31, 2008
Fourth quarter	$	34.58	$	11.00	$	0.05
Third quarter	$	46.25	$	30.32	$	0.05
Second quarter	$	75.09	$	44.00	$	0.03
First quarter	$	63.61	$	45.94	$	0.03
Year ended December 31, 2007
Fourth quarter	$	62.83	$	51.01	$	0.03
Third quarter	$	57.43	$	44.05	$	0.03
Second quarter	$	74.90	$	48.12	$	0.02
First quarter	$	57.66	$	48.48	$	0.02

(1)

Quarterly share prices have been adjusted to reflect the 3-for-2 stock splits on May 30, 2008 and May 25, 2007.

On April 23, 2008, 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, 2008, received one additional share of common stock for each two shares of common stock they owned on that date. The shares were distributed on May 30, 2008, and the adjusted per share stock price was reported by the NASDAQ Stock Market, effective May 28, 2007.

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 should be read together with our consolidated financial statements and notes thereto included within Item 8, “Financial Statements and Supplementary Data” and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report. We have derived the selected financial data set forth in the table for each of the years ended December 31, 2008, 2007 and 2006 and at December 31, 2008 and 2007 from our consolidated financial statements appearing elsewhere in this report, which have been audited by Grant Thornton LLP, independent registered public accounting firm. We derived the financial data as of December 31, 2006 and 2005 and September 30, 2005 and 2004 and for the three months ended December 31, 2005, and the fiscal years ended September 30, 2005 and 2004 from our consolidated financial statements, which were audited by Grant Thornton LLP and are not included within this report.


	Years Ended December 31,								Three Months Ended December 31,			Years Ended September 30,
	2008			2007			2006		2005			2005		2004
	(in thousands, except per share data)
Statement of operations data:
Revenues:
Well construction and completion	$	415,036		$	321,471		$	198,567	$	42,145		$	134,338	$	86,880
Gas and oil production		311,850			180,125			88,449		24,086			63,499		48,526
Transmission, gathering and processing		1,446,650			823,646			435,259		128,878			262,829		34,483
Administration and oversight		19,362			18,138			11,762		2,964			9,875		8,396
Well services		20,482			17,592			12,953		2,561			9,552		8,430
Gain (loss) on mark-to-market derivatives		(63,480	)		(153,325	)		2,316		(138	)		1,887		(255	)

Total revenues		2,149,900			1,207,647			749,306		200,496			481,980		186,460


Costs and expenses:
Well construction and completion		359,609			279,540			172,666			36,648			116,816			75,548
Gas and oil production		48,194			24,184			8,499			1,721			6,044			5,265
Transmission, gathering and processing		1,165,394			635,987			361,045			109,889			229,816			27,870
Well services		10,654			9,062			7,337			1,487			5,167			4,399
General and administrative		59,091			111,636			46,517			9,453			23,961			14,971
Net expense reimbursement - affiliate		951			930			1,237			163			602			1,050
Depreciation, depletion and amortization		185,552			107,917			45,643			10,324			24,895			14,700
Goodwill and other asset impairment loss		698,508			—			—			—			—			—

Total costs and expenses		2,527,953			1,169,256			642,944			169,685			407,301			143,803

Operating income (loss)		(378,053	)		38,391			106,362			30,811			74,679			42,657

Other income (expense)
Interest expense		(142,917	)		(92,611	)		(27,313	)		(6,147	)		(11,467	)		(2,881	)
Gain on early extinguishment of debt		19,867			—			—			—			—			—
Minority interests		479,431			93,476			(18,283	)		(6,745	)		(14,773	)		(4,961	)
Other, net		11,368			10,722			8,564			691			4,519			(2,219	)

Total other income (expense)		367,749			11,587			(37,032	)		(12,201	)		(21,721	)		(10,061	)
Income (loss) before income taxes and cumulative effect of accounting change		(10,304	)		49,978			69,330			18,610			52,958			32,596
Provision (benefit) for income taxes		(4,146	)		14,642			27,308			6,886			20,018			11,409

Net income (loss) before cumulative effect of accounting change		(6,158	)		35,336			42,022			11,724			32,940			21,187
Cumulative effect of accounting change (net of tax of $2,530)		—			—			3,825			—			—			—

Net income (loss)	$	(6,158	)	$	35,336		$	45,847		$	11,724		$	32,940		$	21,187

Net income (loss) per common share
Basic	$	(0.15	)	$	0.87		$	1.03		$	0.26		$	0.73		$	0.54

Diluted	$	(0.15	)	$	0.83		$	1.01		$	0.26		$	0.73		$	0.54


Balance sheet data (at period end):
Property, plant and equipment, net	$	3,967,969		$	3,442,036		$	884,812		$	658,347		$	505,967		$	313,091
Total assets		4,825,249			4,904,367			1,379,838			1,056,180			759,711			423,709
Total debt, including current portion		2,413,082			1,994,456			324,151			298,781			191,727			135,625
Total stockholders’ equity		411,515			413,163			271,341			130,425			120,351			91,003

Cash flow data:
Net cash provided by (used in) operating activities	$	(53,661	)	$	189,976		$	42,209		$	52,769		$	112,045		$	50,043
Net cash used in investing activities		(637,212	)		(3,503,723	)		(180,071	)		(194,941	)		(294,891	)		(181,789	)
Net cash provided by financing activities		649,909			3,273,881			268,108			179,046			171,935		$	135,566

ITEM 7:

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this report.

General

•

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

Our ownership interest in ATN consists of the following:

•

29,952,996 common units, including 600,000 purchased in May 2008 in a private placement, representing approximately 47.3% of the outstanding common units at December 31, 2008, or a 46.3% ownership interest in ATN.

•

Our ownership interest in APL consists of 1,112,000 common units purchased in June 2008 in a private placement transaction, representing approximately 2.4% of the outstanding common units of APL at December 31, 2008, or a 2.1% ownership interest (see “Recent Developments”).

Our ownership interest in AHD consists of 17,808,109 common units, including 308,109 purchased in a June 2008 private placement, representing approximately 64.4% of the outstanding common units of AHD at December 31, 2008. 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, AHD, the holder of 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. AHD also agreed that the resulting allocation of incentive distribution rights back to APL would be after AHD receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter (“IDR Adjustment Agreement”); and

•

5,754,253 common units, representing approximately 12.5% of the outstanding common units at December 31, 2008, or a 11.0% ownership interest in APL.

•

10,000 $1,000 par value 12.0% cumulative convertible preferred limited partner units at December 31, 2008, representing an approximate 3.2% ownership interest in APL based upon the market value of APL’s common units at December 31, 2008.

•

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.

Financial Presentation

Our principal operating activities are conducted principally through ATN, AHD, and APL, and our cash flows consist primarily of distributions received from ATN, APL and AHD on our ownership interests. Our consolidated financial statements contain the consolidated financial statements of ATN and AHD, and AHD’s consolidated financial statements include the consolidated financial statements of APL. The non-controlling minority interests in ATN, AHD and APL are reflected as income (expense) in our consolidated statements of operations and as a liability on our consolidated balance sheets. Throughout this section, when we refer to “our” consolidated financial statements, we are referring to the consolidated results for us and our wholly-owned subsidiaries and the consolidated results of ATN and AHD, including APL’s financial results, adjusted for non-controlling minority interests in ATN’s, AHD’s and APL’s net income (loss).

Atlas Energy

ATN was formed in December 2006 through our contribution of substantially all of our natural gas and oil assets and our investment partnership management business to it in connection with ATN’s initial public offering. 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. ATN is an independent developer and producer of natural gas and oil, with operations in northern Michigan’s Antrim Shale, the Appalachian Basin region of the United States, principally in western New York, eastern Ohio, western Pennsylvania and Tennessee, and Indiana’s New Albany Shale. 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, 2008, ATN had the following key assets:

Appalachia gas and oil operations

•

direct and indirect working interests in approximately 8,462 gross producing gas and oil wells;

•

overriding royalty interests in approximately 624 gross producing gas and oil wells;

•

net daily production of 35.6 million cubic feet equivalents per day (“MMcfed”); and

•

approximately 950,530 gross (904,890 net) acres, of which approximately 640,430 gross (623,490 net) acres, are undeveloped included in the undeveloped acreage is 556,438 Marcellus Shale acres in Pennsylvania, New York and West Virginia, of which approximately 274,495 acres are located in ATN’s core Marcellus Shale position in southwestern Pennsylvania;

Michigan gas and oil operations

•

proved reserves of 672.3 Bcfe;

•

direct and indirect working interests in approximately 2,458 gross producing gas and oil wells;

•

overriding royalty interest in approximately 93 gross producing gas and oil wells;

•

net daily production of 59.7 MMcfed; and

•

approximately 345,680 gross (273,280 net) acres, of which approximately 42,390 gross (33,100 net) acres, are undeveloped.

Indiana gas and oil operations

•

proved reserves of 10.3 Bcfe;

•

direct and indirect working interests in approximately 5 gross producing gas and oil wells;

•

net daily production of 0.2 MMcfed; and

•

approximately 161,140 gross (119,670 net) acres, of which approximately 160,480 gross (119,185 net) acres, are undeveloped.

Partnership management business

•

managed total proved reserves of 706 Bcfe.

Atlas Pipeline Holdings and Atlas Pipeline Partners

AHD was formed in July 2006 through our contribution of ownership interests in Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP”), the general partner of APL and our then wholly-owned subsidiary, to it in connection with AHD’s initial public offering. Concurrent with this transaction, AHD issued 3,600,000 common units, representing a 17.1% ownership interest in it 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.

APL is a leading provider of natural gas gathering services in the Anadarko, Arkoma and Permian Basins and the Golden Trend 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 and treatment services in Oklahoma and Texas. APL also provides interstate gas transmission services in southeastern Oklahoma, Arkansas, southern Kansas and southeastern Missouri. APL’s business is conducted in the midstream segment of the natural gas industry through two reportable 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 which has throughput capacity of approximately 500 million cubic feet per day (“MMcfd”);

•

eight active natural gas processing plants with aggregate capacity of approximately 815 MMcfd and one treating facility with a capacity of approximately 200 MMcfd, located in Oklahoma and Texas; and

•

Through its Appalachian operations, APL owns and operates 1,835 miles of natural gas gathering systems located in eastern Ohio, western New York, western Pennsylvania and northeastern Tennessee. 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 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.

Subsequent Events

On January 28, 2009, our Board of Directors declared a cash dividend of $0.05 per share, which was paid on February 19, 2009 to shareholders of record at the close of business on February 9, 2009.

Atlas Energy. On January 28, 2009, ATN declared a quarterly cash distribution of $0.61 per unit on its outstanding common units, representing the cash distribution for the quarter ended December 31, 2008. This distribution was paid on February 13, 2009 to unitholders of record at the close of business on February 9, 2009.

Atlas Pipeline Partners. On January 26, 2009, APL declared a quarterly cash distribution of $0.38 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2008. This distribution was paid on February 13, 2009 to unitholders of record at the close of business on February 9, 2009.

On January 27, 2009, APL and Sunlight Capital, the holder of its outstanding Class A Preferred Units, agreed to amend certain terms of its existing preferred unit agreement. The amendment (a) increased the dividend yield from 6.5% to 12% per annum, effective January 1, 2009, (b) changed the conversion commencement date from May 8, 2008 to April 1, 2009, (c) changed the conversion price from $43.00 to $22.00, enabling the APL Class A Preferred Units to be converted at the lesser of $22.00 or 95% of the market value of the common units, and (d) changed the call redemption price from $53.22 to $27.25. Simultaneously with the execution of the amendment, APL issued Sunlight Capital $15.0 million of its 8.125% senior unsecured notes due 2015 to redeem 10,000 APL Class A Preferred Units. APL also agreed that it will redeem an additional 10,000 APL Class A Preferred Units for cash at the liquidation value on April 1, 2009. If Sunlight does not exercise its conversion right on or before June 2, 2009, APL redeem the then-remaining 10,000 APL Class A Preferred Units for cash or one-half for cash and one-half for APL’s common limited partner units on July 1, 2009.

Atlas Pipeline Holdings.On January 26, 2009, AHD declared a quarterly cash distribution of $0.06 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2008. This distribution was paid on February 19, 2009 to unitholders of record on February 9, 2009.

Recent Developments

In September 2008, our Board of Directors approved a stock repurchase agreement of up to $50.0 million at a price not to exceed $36.00 per share. The daily repurchase amount was limited to 50,000 shares. We purchased 595,292 of its shares during September and October 2008 for a total purchase price of $20.0 million under this program. In addition, we utilized the remaining $20.0 million of availability under a stock repurchase agreement approved on September 12, 2005 to purchase 560,291 shares in August and September 2008. The weighted average purchase price for the shares repurchased during the year was $34.64 per share.

In June 2008, we purchased 1,112,000 APL common limited partner units and 308,109 AHD common limited partner units in a private placement transaction at per unit amounts of $36.02 and $32.50, respectively. APL used the proceeds of $40.1 million to fund the early termination of certain crude oil derivative agreements. AHD used the proceeds of $10.0 million to fund the purchase of an additional 278,000 APL common units.

In May 2008, we purchased 600,000 of ATN’s Class B common units in a private placement transaction at a price of $42.00 per common unit, increasing our ownership to 29,952,996 common units. ATN’s proceeds of $25.2 million were used to repay a portion of its outstanding balance under its revolving credit facility.

Atlas Energy. In the third quarter of 2008, ATN established a position in the New Albany Shale of southwestern Indiana by acquiring 120,000 net acres for approximately $15.0 million in cash and entering into a farm out agreement that will give it the rights to an additional 78,000 net acres (121,000 gross acres). These transactions afford ATN the opportunity to drill on 284,000 gross acres, including the 121,000 gross acre farm out. Using capital from its syndicated oil and gas investment programs, ATN began drilling in 2008 and plans to have over 100 horizontal wells drilled by the completion of 2009.

In June 2008, ATN entered into a $19.6 million agreement with Miller Petroleum, Inc. (“Miller”) whereby Miller assigned (i) 100% of the working interest in its oil and gas leases comprising 27,620 acres in the Koppers North and Koppers South section of Campbell County, Tennessee, (ii) 100% of the working interest in 8 existing wells, and (iii) 100% of the working interest in its oil and gas leases comprising 1,952 acres adjacent to the Koppers acreage. The agreement also provides Miller with an option to participate up to 25% in up to 10 wells to be drilled on the assigned acreage. In addition, ATN entered into two agreements with Miller whereby (i) Miller will provide drilling services to ATN for a two-year term and (ii) ATN or its affiliates will transport and process natural gas for Miller from its existing wells.

In May 2008, ATN sold 2,070,000 of its Class B common units at $41.50 per common unit in a public offering for net proceeds of $82.5 million, after underwriting expenses of $3.4 million. The net proceeds of the offering were used to repay a portion of ATN’s outstanding balance under its revolving credit facility.

Atlas Pipeline and Atlas Pipeline Holdings.In December 2008, APL sold 10,000 newly-created 12% cumulative convertible Class B preferred units of limited partner interest (the “APL Class B Preferred Units”) to AHD for cash consideration of $1,000 per APL Class B Preferred Unit pursuant to a purchase agreement. AHD has the right, before March 30, 2009, to purchase an additional 10,000 APL Class B Preferred Units on the same terms. APL used the proceeds from the sale of the APL Class B Preferred Units for general partnership purposes. The APL Class B Preferred Units will receive distributions of 12% per annum, paid quarterly to AHD on the same date as the distribution payment date for APL common units. See “—Issuance of APL Preferred Units – APL Class B Convertible Preferred Units”).

In December 2008, APL repurchased approximately $60.0 million in face amount of its senior unsecured notes for an aggregate purchase price of approximately $40.1 million plus accrued interest of approximately $2.0 million. The senior unsecured notes repurchased were comprised of $33.0 million in face amount of APL’s 8.125% senior unsecured notes and approximately $27.0 million in face amount of its 8.75% senior unsecured notes. All of the senior unsecured notes repurchased have been retired and are not available for re-issue.

In June 2008, APL sold 5,750,000 common limited partner units in a public offering at a price of $37.52 per unit, yielding net proceeds of approximately $206.6 million. Concurrently, APL sold 278,000 common limited partner units to AHD in a private placement transaction at a price of $36.02 per unit, resulting in net proceeds of approximately $10.0 million. APL also received a capital contribution from AHD of $5.4 million for it to maintain its 2.0% general partner interest in APL. APL utilized the net proceeds from the sale and the capital contribution to fund the early termination of certain crude oil derivative agreements. In order to fund its purchase of APL’s common limited partner units, AHD sold 308,109 of its common limited partner units to us in a private placement transaction at a price of $32.50 per unit for net proceeds of $10.0 million.

The net proceeds from the public and private placement offerings of APL’s common units were utilized to fund the early termination of a majority of its crude oil derivative contracts that it entered into as proxy hedges for the prices it receives for the ethane and propane portion of its NGL equity volume. These hedges, which related to production periods ranging from the end of second quarter of 2008 through the fourth quarter of 2009, were put in place simultaneously with APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007 and have become less effective as a result of significant increases in the price of crude oil and less significant increases in the price of ethane and propane. APL estimates that it incurred a charge during the second quarter 2008 of approximately $10.6 million due to the decline in the price correlation of crude oil and ethane and propane. APL terminated these derivative contracts during June and July 2008 at an aggregate net cost of approximately $264.0 million. Our net loss for the year ended December 31, 2008 includes a $197.6 million cash derivative expense, excluding the effects of APL’s and AHD’s minority interests, resulting from APL’s aggregate net payments of $274.0 million to unwind a portion of these derivative contracts.

In June 2008, APL issued $250.0 million of 10-year, 8.75% senior unsecured notes (the “APL 8.75% Notes”) in a private placement transaction. The sale of the APL 8.75% Senior Notes generated net proceeds of approximately $244.9 million, which APL utilized to repay indebtedness under its senior secured term loan and revolving credit facility.

In June 2008, APL obtained $80.0 million of increased commitments to its senior secured revolving credit facility, increasing its aggregate lender commitments to $380.0 million. In connection with this and the previously mentioned transactions, APL also amended its senior secured credit facility to, among other things, exclude from the calculation of Consolidated EBITDA the costs associated with its termination of derivative instruments to the extent such costs are financed with or paid out of the net proceeds of an equity offering. In addition, consistent with several other recent energy master limited partnership agreements, APL’s general partner’s managing board and conflicts committee approved an amendment to its limited partnership agreement which will allow the cash expenditure to terminate derivative contracts to not reduce APL’s distributable cash flow.

Acquisitions

Atlas Energy.In June 2007, ATN acquired DTE Gas & Oil Company from DTE Energy Company (“DTE” – NYSE: DTE) for $1.3 billion in cash, including related expenses. The assets acquired, which consisted principally of interests in natural gas wells in the Antrim Shale located in Michigan’s northern lower peninsula, 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 $181.2 million of its Class B common units and $416.3 million of its Class D units to investors at a weighted average negotiated price of $25.00 per unit. ATN funded the remaining purchase price from borrowings under its credit facility.

Atlas Pipeline Partners.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:

•

in Texas (the “Anadarko Assets”). 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. 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 its issuance of 6,249,995 of its common units in a private placement transaction at a negotiated purchase price of $27.00 per unit. AHD, as general partner and holder all of APL’s incentive distribution rights, 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. AHD also agreed that the resulting allocation of incentive distribution rights back to APL would be after AHD receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter. APL funded the remaining purchase price from $830.0 million of proceeds from a senior secured term loan which matures in July 2014 and borrowings under its senior secured revolving credit facility that matures in July 2013.

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, which began on June 15, 2008 and ended on November 1, 2008, and up to an additional 7.4% interest beginning on June 15, 2009 and ending on November 1, 2009 (the aggregate 22.0% additional interest can be entirely purchased during the period beginning June 15, 2009 and ending on November 1, 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 22.0% interest if fully exercised. APL will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercises the purchase options.

•

Contractual Revenue Arrangements

Atlas Energy

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. Based on recent production data available to ATN, we anticipate that ATN and its affiliates, including its investment partnerships, will sell approximately 10% 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.

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. Based on recent production data available to ATN, we anticipate that ATN and its affiliates will sell approximately 49% of their Michigan natural gas production during the year ending December 31, 2008 under the DTE agreements in most cases at NYMEX pricing.

Investment Partnerships. ATN generally funds its drilling activities through sponsorship of tax-advantaged investment partnerships. 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. 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 ($60,000 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.

•

Atlas Pipeline Partners

APL’s revenue primarily 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 natural gas liquids (“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 regulated transmission pipeline is recognized at the time the transportation service is provided. Revenue associated with the physical sale of natural gas is comprised of firm transportation rates and, to the extent capacity is available following the reservation of firm system capacity, interruptible transportation rates, and recognized upon physical delivery of the natural gas. In connection with its gathering and processing operations, APL enters into the following types of contractual relationships with its producers and shippers:

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 purchases contracted under keep-whole agreements are generally low in liquids content and meet 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.

Recent Trends and Uncertainties

Currently, there is an unprecedented uncertainty in the financial markets. This uncertainty presents additional potential risks to us and our subsidiaries. These risks include the availability and costs associated with our and our subsidiaries’ borrowing capabilities and raising additional capital, and an increase in the volatility of our and our subsidiaries’ common equity market price. While we and our subsidiaries do not currently have any plans to access the capital markets, should we decide to do so in the near future, the terms, size, and cost of new debt or equity could be less favorable than in previous transactions.

Atlas Energy. Realized pricing of ATN’s oil and natural 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 natural gas and oil production has been volatile and unpredictable for many years. Significant factors that may impact future commodity prices include developments in the issues currently impacting Iraq and Iran and the Middle East in general; the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to continue to manage oil supply through export quotas; and overall North American gas supply and demand fundamentals, including the impact of increasing liquefied natural gas deliveries to the United States. Although we cannot predict the occurrence of events that will affect future commodity prices or the degree to which these prices will be affected, the prices for commodities that we produce will generally approximate market prices in the geographic region of the production. In order to address, in part, volatility in commodity prices, ATN has implemented a hedging program that is intended to reduce the volatility in its revenues. This program mitigates, but does not eliminate, ATN’s sensitivity to short-term changes in commodity prices. See Item 3, “Quantitative and Qualitative Disclosures About Market Risk”.

Although the number of natural gas wells drilled in the United States has increased overall in recent years, a corresponding increase in production has not been realized, primarily as a result of smaller discoveries and the decline in production from existing wells. We believe that an increase in United States drilling activity, additional sources of supply such as liquefied natural gas, and imports of natural gas will be required for the natural gas industry to meet the expected increased demand for, and to compensate for the slowing production of, natural gas in the United States. The areas in which ATN operates are experiencing significant drilling activity as a result of new drilling for deeper natural gas formations and the implementation of new exploration and production techniques.

While we anticipate continued high levels of exploration and production activities in the areas in which ATN operates, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new natural gas reserves. Drilling activity generally decreases as natural gas prices decrease. We have no control over the level of drilling activity in the areas of ATN’s operations.

Atlas Pipeline Partners.The midstream natural gas industry links the exploration and production of natural gas and the delivery of its components to end-use markets and provides natural gas gathering, compression, dehydration, treating, conditioning, processing, fractionation and transportation services. This industry group is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.

APL faces competition for natural gas transportation and in obtaining natural gas supplies for its processing and related services operations. Competition for natural gas supplies is based primarily on the location of gas-gathering facilities and gas-processing plants, operating efficiency and reliability, and the ability to obtain a satisfactory price for products recovered. Competition for customers is based primarily on price, delivery capabilities, flexibility, and maintenance of high-quality customer relationships. Many of APL’s competitors operate as master limited partnerships and enjoy a cost of capital comparable to and, in some cases lower than, APL. Other competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than APL. Smaller local distributors may enjoy a marketing advantage in their immediate service areas. We believe the primary difference between APL and some of its competitors is that APL provides an integrated and responsive package of midstream services, while some of its competitors provide only certain services. We believe that offering an integrated package of services, while remaining flexible in the types of contractual arrangements that APL offers producers, allows APL to compete more effectively for new natural gas supplies in its regions of operations.

As a result of APL’s POP and keep-whole contracts, its results of operations and financial condition substantially depend upon the price of natural gas and NGLs. APL believes that future natural gas prices will be influenced by supply deliverability, the severity of winter and summer weather and the level of United States economic growth. Based on historical trends, APL generally expects NGL prices to follow changes in crude oil prices over the long term, which we believe will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. The number of active oil and gas rigs has increased in recent years, mainly due to recent

significant increases in natural gas prices, which could result in sustained increases in drilling activity during the current and future periods. However, energy market uncertainty could negatively impact North American drilling activity in the short term. Lower drilling levels over a sustained period would have a negative effect on natural gas volumes gathered and processed.

Results of Operations

The following table illustrates selected operational information for the periods indicated:


	Years Ended December 31,
	2008			2007			2006
Atlas Energy:
Production revenues (in thousands)⁽¹⁾
Gas^{(2) (3)}	$	297,145		$	169,314		$	79,016
Oil	$	14,705		$	10,768		$	9,433

Production volume^{(1) (2) (4) (5)}
Gas (mcfd)		92,629			86,893			24,511
Oil (bpd)		434			422			413

Total (mcfed) Oil(bpd)		95,227			89,425			26,989

Average sales prices^{(1) (5)}:
Gas (per mcf)^{(3) (6) (7)}	$	9.13		$	8.66		$	8.83
Oil (per bbl)⁽⁸⁾	$	92.35		$	70.16		$	62.30

Production costs^{(1) (5) (9)}:
Lease operating expenses	$	0.85		$	0.77		$	0.83
As a percent of production revenues per mcf		10	%		14	%		9	%
Production taxes per mcfe		0.35			0.21			0.03

Total production costs per mcfe	$	1.20		$	0.98		$	0.86

Depletion per Mcfe^{(1) (5)}	$	2.64		$	2.49		$	2.08

Atlas Pipeline Partners:
Appalachia system throughput volume (mcfd)⁽⁵⁾		87,299			68,715			61,892

Velma system gathered gas volume (mcfd)⁽⁵⁾		63,196			62,497			60,682

Elk City/Sweetwater system gathered gas volume (mcfd)⁽⁵⁾		280,860			298,200			277,063

Chaney Dell system gathered gas volume (mcfd)^{(5) (10)}		276,715			259,270			—

Midkiff/Benedum system gathered gas volume (mcfd)^{(5) (10)}		144,081			147,240			—

NOARK Ozark Gas Transmission throughput volume (mcfd)⁽⁵⁾		442,464			326,651			249,581


Combined throughput volume (mcfd)⁽⁵⁾		1,294,615			1,162,573			649,218

(1)	Atlas Energy acquired its Michigan assets in June 2007, and production volume from these assets have only been included from that date.

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

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

(4)

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

(5)

“Mcf” and “mcfd” represents thousand cubic feet and thousand cubic feet per day; “mcfe” and “mcfed” represents thousand cubic feet equivalent and thousand cubic feet equivalent per day, and “bbl” and “bpd” represents barrels and barrels per day. Barrels are converted to mcfe using the ratio of six mcf’s to one barrel.

(6)	Atlas Energy’s average sales price before the effects of financial hedging was $9.23, $7.22 and $7.90 per mcf for the years ended December 31, 2008, 2007 and 2006, respectively.

(7)	Includes $12.4 million and $12.3 million of derivative proceeds which were not included as revenue in the years ended December 31, 2008 and 2007, respectively. There were no derivative proceeds which were not included as revenue in the year ended December 31, 2006.

(8)	Atlas Energy’s average sales price for oil before the effects of financial hedging was $91.79 per barrel for the year ended December 31, 2008. There were no oil financial hedges in effect for the years ended December 31, 2007 and 2006.

(9)	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.

(10)	Atlas Pipeline acquired the Chaney Dell and Midkiff/Benedum systems in July 2007, and production volume from these systems has only been included from that date.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Natural Gas and Oil Production. Our natural gas and oil production revenues were $311.9 million for the year ended December 31, 2008, an increase of $131.8 million from $180.1 million for the prior year. Total production volumes increased to 95.2 mmcfe per day for the year ended December 31, 2008 compared with 89.4 mmcfe per day for the prior year. ATN’s Michigan assets, acquired in June 2007, accounted for $183.9 million of natural gas and oil production revenue for the year ended December 31, 2008, an increase of $102.8 million when compared with the prior year. ATN’s Appalachian assets had natural gas and oil production revenue of $128.0 million for the year ended December 31, 2008, an increase of $29.0 million or 29%, compared with $99.0 million for the prior year. The increase in revenue related to ATN’s Appalachia assets is primarily related to an increase in volumes of 5.9 mmcfe per day, or 20% when compared with the prior year.

Natural gas and oil production expenses were $48.2 million for the year ended December 31, 2008, an increase of $24.0 million from $24.2 million for the prior year. The increase was attributable to an increase of $19.9 million from ATN’s Michigan assets and a $4.1 million increase from Appalachia production expenses due to an increase in the number of wells ATN owns.

Well Construction and Completion. Our well construction and completion revenues were $415.0 million for the year ended December 31, 2008, an increase of $93.5 million from $321.5 million for the prior year. Well construction and completion expenses increased $80.1 million to $359.6 million for the year ended December 31, 2008 from $279.5 million from the prior year. The increases in these categories is primarily due to the increase in the number of ATN’s Marcellus Shale wells drilled in 2008, which are drilled at a higher cost than other Appalachian wells. ATN drilled 776 net wells for the year ended December 31, 2008 compared with 1,014 for the prior year. For a majority of the wells that it drills, ATN receives a 15% to 18% mark-up on those costs incurred to drill and complete the well in connection with its partnership management activities.

Administration and Oversight and Well Services. Administration and oversight fee revenues were $19.4 million for the year ended December 31, 2008 compared with $18.1 million for the year ended December 31, 2007, an increase of $1.3 million or 7%. Well services revenues were $20.5 million for the year ended December 31, 2008 compared with $17.6 million for the prior year, an increase of $2.9 million or 16%. The increase in administration and oversight fee revenue was due to an increase in the number of ATN’s Marcellus shale wells drilled, for which it earns higher fees from its partnership management activities in comparison to conventional wells. The increase in well services revenue was due to an increase in the number of wells operated by ATN’s drilling investment partnerships, for which ATN earns fees for its partnership management activities.

Transmission, Gathering and Processing. Our transmission, gathering and processing revenues were $1,446.7 million for the year ended December 31, 2008, an increase of $623.1 million from $823.6 million for the prior year. Transmission, gathering and processing expenses were $1,165.4 million for the year ended December 31, 2008, an increase of $529.4 million from $636.0 million for the prior year. These increases were due principally to a full year of revenues and expenses associated with APL’s Chaney Dell and Midkiff/Benedum systems, which were acquired in July 2007, and the effect of higher average realized commodity prices and higher volumes on its other systems. APL’s Chaney Dell and Midkiff/Benedum systems accounted for a $518.2 million increase in transmission, gathering and processing revenues and a $476.2 million increase in transmission, gathering and processing expenses when comparing the year ended December 31, 2008 to the prior year. APL’s average gross natural gas gathered volume for the year ended December 31, 2008 was 1.29 billion cubic feet per day (“bcfd”) compared with 1.16 bcfd for the prior year, an increase of 0.13 bcfd or 11% due principally to the acquisition of the Chaney Dell and Midkiff/Benedum systems and higher volumes on its other systems.

Gain (Loss) on Mark-to-Market Derivatives. Loss on mark-to-market derivatives was $63.5 million for the year ended December 31, 2008 compared with $153.3 million for the prior year. This favorable movement was due to a $356.8 million favorable movement in APL’s non-cash mark-to-market adjustments on derivatives, partially offset by a net cash loss of $200.0 million and a non-cash derivative loss of $39.2 million related to the early termination of a portion of APL’s derivative contracts (see “—Recent Developments”), and an unfavorable movement of $1.5 million related to APL’s cash settlements on derivatives that were not designated as hedges. The 356.8 million favorable movement in non-cash mark-to-market adjustments on derivatives was due principally to a decrease in forward crude oil market prices from December 31, 2007 to December 31, 2008 and their favorable mark-to-market impact on certain non-hedge derivative contracts APL has for production volumes in future periods. For example, average forward crude oil market prices, which are the basis for adjusting the fair value of APL’s crude oil derivative contracts, at December 31, 2008 were $56.94 per barrel, a decrease of $32.95 per barrel from average forward crude oil market prices at December 31, 2007 of $89.89 per barrel. APL enters into derivative instruments principally to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. See further discussion of derivatives under Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” and under Note 9 under Item 8, “Financial Statements and Supplementary Data”.

Other Income, Costs and Expenses.General and administrative expenses, including amounts reimbursed to affiliates, decreased $52.6 million to $60.0 million for the year ended December 31, 2008 compared with $112.6 million for the prior year. The decrease was primarily related to a $66.8 million decrease in non-cash compensation expense, partially offset by $14.2 million of higher costs incurred in managing our operations. The decrease in non-cash compensation expense was principally attributable to a $69.7 million gain recognized during the year ended December 31, 2008 for certain APL common unit awards for which the ultimate amount to be issued was determined after the completion of our 2008 fiscal year and is based upon the financial performance of APL’s acquired assets. The gain was the result of a significant change in APL’s common unit market price at December 31, 2008 when compared with the December 31, 2007 price, which was utilized in the calculation of the non-cash compensation expense for these awards. Non-cash compensation expense of $46.4 million for the year ended December 31, 2007 included $33.4 million recognized in connection with these common unit awards as a result of the effect APL’s Chaney Dell and Midkiff/Benedum acquisition had on the calculation of the awards. The $14.2 million increase in other general and administrative costs between periods was principally related to a $13.3 million increase in salary, wages and benefits.

Depreciation, depletion and amortization increased to $185.6 million for the year ended December 31, 2008 compared with $107.9 million for the prior year due primarily to the depreciation and depletion associated with ATN’s acquired Michigan assets and APL’s acquired Chaney Dell and Midkiff/Benedum system assets and ATN’s and APL’s expansion capital expenditures incurred between the periods.

Goodwill and other asset impairment loss of $698.5 million for the year ended December 31, 2008 consisted of a $676.9 million impairment charge to APL’s goodwill as a result of its annual goodwill impairment test and a $21.6 million write-off of costs related to an APL expansion project. The goodwill impairment resulted from the reduction of APL’s estimate of the fair value of its goodwill in comparison to its carrying amount at December 31, 2008. The estimate of fair value of goodwill was impacted by many factors, including the significant deterioration of commodity prices and global economic conditions during the fourth quarter of 2008. APL’s estimates were subjective and based upon numerous assumptions about future operations and market conditions, which are subject to change. The costs incurred consisted of APL’s preliminary construction and engineering costs as well as a vendor deposit for the manufacture of pipeline which expired in accordance with a contractual arrangement. APL management is pursuing other strategic alternatives for this project.

Interest expense increased to $142.9 million for the year ended December 31, 2008 as compared with $92.6 million for the prior year. This $50.3 million increase was primarily due to interest associated with a full year’s interest expense on the borrowings of ATN to partially finance the acquisition of its Michigan assets in June 2007 and of APL to partially finance the acquisition of the Chaney Dell and Midkiff/Benedum systems during July 2007, partially offset by lower variable interest rates between periods.

Gain on early extinguishment of debt of $19.9 million for the year ended December 31, 2008 resulted from APL’s repurchase of approximately $60.0 million in face amount of its senior unsecured notes for an aggregate purchase price of approximately $40.1 million plus accrued interest of approximately $2.0 million. The notes repurchased were comprised of $33.0 million in face amount of APL’s 8.125% senior unsecured notes and approximately $27.0 million in face amount of its 8.75% senior unsecured notes. All of APL’s senior unsecured notes repurchased have been retired and are not available for re-issue.

Minority interest income for the year ended December 31, 2008, which represents non-controlling, non-affiliated ownership interests in ATN, AHD and APL, was $479.4 million compared with $93.5 million for the prior year. The change between periods is principally due to a $437.6 million decrease in APL’s net loss, a $25.3 million increase in ATN’s net income, a decrease in our ownership interest in AHD to 64% for the year ended December 31, 2008 compared with 83% for the first half of the prior year, and a decrease in our ownership interest in ATN to 51% for the year ended December 31, 2008 compared with 80% for the first half of the prior year. The decrease in APL’s net loss was the result of a $676.9 goodwill impairment loss, offset by a favorable movement of $115.9 million from the impact of certain net losses recognized on derivatives from the prior year, a full year’s operating results from the Chaney Dell and Midkiff/Benedum systems which were acquired in July 2007, and a $19.9 million gain APL recognized in 2008 for the early extinguishment of debt. ATN’s increase in net income between periods was principally due to a full year’s operating results from its Michigan assets which were acquired in June 2007 and higher Appalachia production volumes and prices. The decrease in our ownership interest in AHD was due to its private placement of common units to third parties to partially finance its capital contribution to APL to maintain its 2% general partner interest in relation to APL’s private placement of common units to third parties to partially finance its acquisition of the Chaney Dell and Midkiff/Benedum systems in 2007. The decrease in our ownership interest in ATN was due to its private placement of common units to third parties to partially finance its acquisition of its Michigan assets in 2007.

Benefit from income taxes was $4.1 million for the year ended December 31, 2008 compared with a provision for income taxes of $14.6 million for the prior year. The change in our provision (benefit) for income taxes was due primarily to a decrease in net income (loss) before taxes between periods. Our effective income tax rates were 40% and 29% for the years ended December 31, 2008 and 2007, respectively. The increase in our effective income tax rate for the year ended December 31, 2008 is a result of a reduction in tax benefits related to depletion and tax-exempt interest income relative to income (loss) before taxes.

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

Natural Gas and Oil Production. Our natural gas and oil production revenues were $180.1 million for the year ended December 31, 2007, an increase of $91.7 million from $88.4 million for the prior year. Total production volumes increased to 89.4 mmcfe per day for the year ended December 31, 2007 compared with 27.0 mmcfe per day for the prior year. ATN’s Michigan assets, acquired in June 2007, accounted for $93.4 million of natural gas and oil production revenue for the year ended December 31, 2007. ATN’s Appalachian assets had natural gas and oil production revenue of $99.01 million for the year ended December 31, 2007, an increase of $10.6 million or 12% compared with $88.4 million for the prior year. The increase in revenue for ATN’s Appalachia assets is primarily related to an increase in volumes of 2.7 mmcfe per day, or 10% when compared with the prior year.

Natural gas and oil production expenses were $24.2 million in the year ended December 31, 2007, an increase of $15.7 million from $8.5 million for the prior year. This increase was attributable to $14.6 million of production costs associated with ATN’s Michigan assets during 2007 and higher Appalachia production expenses associated with an increase in the number of wells ATN owns.

Well Construction and Completion.Our well construction and completion revenues were $321.5 million for the year ended December 31, 2007, an increase of $122.9 million from $198.6 million for the prior year. Well construction and completion expenses increased $106.8 million to $279.5 million for the year ended December 31, 2007 from $172.7 million for the prior year. The increase in these categories is primarily due to the increase in the number of ATN wells drilled for the year ended December 31, 2007 in comparison to the prior year. ATN drilled 1,014 net wells for the year ended December 31, 2007 compared with 647 for the prior year. For a majority of the wells that it drills, ATN receives a 15% mark-up on those costs incurred to drill and complete the well in connection with its partnership management activities.

Administration and Oversight and Well Services. Administration and oversight fee revenues were $18.1 million for the year ended December 31, 2007 compared with $11.8 million for the prior year, an increase of $6.3 million or 53%. Well services revenues were $17.6 million for the year ended December 31, 2007 compared with $13.0 million for the prior year, an increase of $4.6 million or 35%. The increase in administration and oversight fee revenue was due to an increase in the number of ATN wells drilled, for which ATN earns fees through its partnership management activities. The increase in well services revenue was due to an increase in the number of wells operated by ATN’s drilling investment partnerships, for which ATN earns fees for its partnership management activities.

Transmission, Gathering and Processing.Our transmission, gathering and processing revenues were $823.6 million for the year ended December 31, 2007, an increase of $388.3 million from $435.3 million for the prior year. Transmission, gathering and processing expenses were $636.0 million for the year ended December 31, 2007, an increase of $275.0 million

from $361.0 million for the prior year. These increases were due principally to the revenues and expenses associated with APL’s Chaney Dell and Midkiff/Benedum systems, which were acquired in July 2007, and the effect of higher average realized commodity prices and higher volumes on its other systems. APL’s Chaney Dell and Midkiff/Benedum systems accounted for a $348.2 million increase in transmission, gathering and processing revenues and a $257.8 million increase in transmission, gathering and processing expenses when comparing the year ended December 31, 2007 to the prior year. APL’s average gross natural gas gathered volume for the year ended December 31, 2007 was 1.16 billion cubic feet per day (“bcfd”) compared with 0.65 bcfd for the prior year, an increase of 0.51 bcfd or 78% due principally to the acquisition of the Chaney Dell and Midkiff/Benedum systems and higher volumes on its other systems.

Gain (Loss) on Mark-to-Market Derivatives. Loss on mark-to-market derivatives was $153.3 million for the year ended December 31, 2007 compared with a gain of $2.3 million for the prior year. This unfavorable movement was due to a $143.1 million unfavorable movement in non-cash mark-to-market adjustments and an unfavorable movement of $10.2 million related to non-qualified derivative cash settlements. The 143.1 million unfavorable movement in non-cash mark-to-market adjustments was due principally to an increase in forward crude oil market prices from December 31, 2006 to December 31, 2007 and their unfavorable mark-to-market impact on certain non-qualified derivative contracts APL has for production volumes in future periods. For example, average forward crude oil market prices, which are the basis for adjusting the fair value of APL’s crude oil derivative contracts, at December 31, 2007 were $89.89 per barrel, an increase of $15.11 per barrel from average forward crude oil market prices at September 30, 2007 of $74.78 per barrel. APL enters into derivative instruments principally to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. See further discussion of derivatives under Item 7A, “Quantitative and Qualitative Disclosures About Market Risk”.

Other Income, Costs and Expenses.General and administrative expenses, including amounts reimbursed to affiliates, increased $64.8 million to $112.6 million for the year ended December 31, 2007 compared with $47.8 million for the prior year. The increase was primarily related to a $36.4 million increase in non-cash compensation expense and $28.4 million of higher costs incurred in managing our operations. The increase in non-cash compensation expense was principally attributable to vesting of APL phantom and common unit awards in 2007, which were based upon the financial performance of APL’s acquired assets, including the Chaney Dell and Midkiff/Benedum system acquired in July 2007. The $28.4 million increase in other general and administrative costs between periods was principally related to a $16.2 million increase in salary, wages and benefits and a $7.1 million increase in audit, tax and other professional fees, including $3.9 million of fees related to hedges associated with ATN’s acquisition of its Michigan assets.

Depreciation, depletion and amortization increased to $107.9 million for the year ended December 31, 2007 compared with $45.6 million for the prior year due primarily to the depreciation and depletion associated with ATN’s acquired Michigan assets and APL’s acquired Chaney Dell and Midkiff/Benedum system assets and ATN’s and APL’s expansion capital expenditures incurred between the periods.

Interest expense increased to $92.6 million for the year ended December 31, 2007 as compared with $27.3 million for the prior year. This $65.3 million increase was primarily due to interest associated with borrowings by ATN and APL to partially finance the acquisition of ATN’s Michigan assets in June 2007 and APL’s Chaney Dell and Midkiff/Benedum systems during July 2007.

Minority interest expense for the year ended December 31, 2007, which represents non-controlling, non-affiliated ownership interests in ATN, AHD and APL, was $93.5 million compared with income of $18.3 million for the prior year. The change between periods is principally due to decrease in our ownership interests in ATN and AHD and a $59.3 million increase in ATN’s net income between periods, partially offset by a $178.0 million decrease in APL’s net income. These amounts were partially offset by a $59.3 million increase in ATN’s net income between periods. The decrease in our ownership interests in ATN was principally due to the completion of its initial public offering in December 2006, whereby we sold an approximate 19% ownership interest in ATN. ATN subsequently completed additional sales of common units to further reduce our ownership interest during June 2007. The decrease in our ownership interests in AHD was principally due to the completion of its initial public offering in July 2006, whereby we sold an approximately 17% ownership interest in AHD. AHD subsequently completed additional sales of common units to further reduce our ownership interest during July 2007. The increase in ATN’s net income between periods was principally due to the operating results from its Michigan assets, which were acquired in June 2007, and higher Appalachia production volumes and prices. The decrease in APL’s net income between periods was the result of an unfavorable movement of $175.2 million from the impact of certain net losses recognized on derivatives during 2007, partially offset operating results from the Chaney Dell and Midkiff/Benedum systems, which were acquired in July 2007.

Provision for income taxes decreased to $14.6 million for the year ended December 31, 2007 compared with $27.3 million for the prior year due primarily to a decrease in net income between periods. Our effective income tax rates were 29% and 39% for the years ended December 31, 2007 and 2006, respectively. The decrease in our effective income tax rate for 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.

Liquidity and Capital Resources

General

Our primary sources of liquidity are distributions received with respect to our ownership interests in ATN, APL and AHD. Our primary cash requirements are for our general and administrative expenses and other expenditures, which we expect to fund through distributions received and cash on hand. Our operations principally occur through our subsidiaries, whose sources of liquidity are discussed in more detail below.

Atlas Energy. ATN’s primary sources of liquidity are cash generated from operations, capital raised through investment partnerships and borrowings under its credit facility. ATN’s primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures and quarterly distributions to its unitholders. In general, we expect ATN to fund:

•

cash distributions and maintenance capital expenditures through existing cash, cash flows from operating activities, and the temporary use of funds raised in its investment partnerships in the period before it invests these funds;

•

expansion capital expenditures and working capital deficits through the retention of cash, additional borrowings and capital raised through investment partnerships; and

•

debt principal payments through additional borrowings as they become due or by the issuance of additional common units.

During the years ended December 31, 2008 and 2007, ATN raised $438.4 million and $363.3 million through its investment partnerships. At December 31, 2008, ATN had $467.0 million of outstanding borrowings under its credit facility, with a borrowing base of $697.5 million. In addition to the availability under its credit facility, ATN has a universal shelf registration statement on file with the Securities and Exchange Commission, which allows it to issue an unlimited amount of equity or debt securities.

Atlas Pipeline Holdings. AHD’s primary sources of liquidity are distributions received with respect to its ownership interests in APL and borrowings under its credit facility. Its primary cash requirements are for its general and administrative expenses, capital contributions to APL to maintain or increase its ownership interest and quarterly distributions to its common unitholders. AHD expects to fund its general and administrative expenses through distributions received from APL and its capital contributions to APL through the retention of cash and borrowings under its credit facility. At December 31, 2008, AHD had $46.0 million outstanding and $4.0 million of remaining committed capacity under its credit facility, subject to covenant limitations (see Note 7 under Item 1, “Financial Statements”).

Atlas Pipeline Partners.APL’s primary sources of liquidity are cash generated from operations and borrowings under its credit facility. APL’s primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures and quarterly distributions to its common unitholders and general partner. In general, we expect APL to fund:

•

cash distributions and maintenance capital expenditures through existing cash and cash flows from operating activities;

•

expansion capital expenditures and working capital deficits through the retention of cash and additional borrowings; and

•

debt principal payments through additional borrowings as they become due or by the issuance of additional limited partner units.

At December 31, 2008, APL had $302.0 million of outstanding borrowings under its $380.0 million credit facility and $5.9 million of outstanding letters of credit, which are not reflected as borrowings on our consolidated balance sheet, with $72.1 million of remaining committed capacity under its credit facility, subject to covenant limitations.

We believe that we and our subsidiaries have sufficient liquid assets, cash from operations and borrowing capacity to meet our and their financial commitments, debt service obligations, contingencies and anticipated capital expenditures. However, we and our subsidiaries are subject to business and operational risks that could adversely affect our cash flow. We and our subsidiaries may supplement our cash generation with proceeds from financing activities, including borrowings under our subsidiaries’ credit facilities and other borrowings and the issuance of additional common shares and units.

Recent instability in the financial markets, as a result of recession or otherwise, has increased the cost of capital while the availability of funds has diminished significantly. This may affect APL’s ability to raise capital and reduce the amount of cash available to fund its operations. APL relies on its cash flow from operations and its credit facility to execute its growth strategy and to meet its financial commitments and other short-term liquidity needs. We cannot be certain that additional capital will be available to the extent required and on acceptable terms.

Cash Flows – Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Net cash used in operating activities of $53.7 million for the year ended December 31, 2008 represented a decrease of $243.7 million from $190.0 million of net cash provided by operating activities for the prior year. The decrease was derived principally from a $136.7 million increase in cash distributions paid to minority interests and a $90.1 million decrease in net income excluding non-cash items. The decrease due to cash distributions to minority interests is due mainly to increases in ATN’s, AHD’s and APL’s common units outstanding and their cash distribution amount per common unit. The non-cash charges which impacted net income include unfavorable increases minority interest income of $386.0 million, non-cash loss on derivatives of $351.8 million, gain on early extinguishment of debt of $19.9 million and non-cash compensation related to long-term incentive plans of $66.8 million, partially offset by favorable increases of $698.5 for goodwill and other asset impairment and $77.6 million for depreciation, depletion and amortization. The movement in net non-cash loss on derivative value between periods resulted from commodity price movements during the year ended December 31, 2008 and the unfavorable non-cash impact it had on our net income, which was due to the mark-to-market of derivative contracts APL has for future periods. The increase in depreciation, depletion and amortization resulted from ATN’s acquisition of its Michigan assets in June 2007 and APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007. The movement in minority interests in net income was due to a decrease in APL’s net income and our ownership interests in AHD and ATN between periods, partially offset by an increase in ATN’s net income.

Net cash used in investing activities of $637.2 million for the year ended December 31, 2008 represented a decrease of $2,866.5 million from $3,503.7 million used in investing activities for the prior year. This decrease was principally due to a $3,188.4 million reduction in net cash paid for acquisitions related ATN’s acquisition of AGO in June 2007 and APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007, the current year $31.4 million post-closing purchase price adjustment of APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems, and a $9.4 million decrease in our cash paid for investments in Lightfoot. These decreases were partially offset by a $330.5 million increase in capital expenditures for ATN and APL. See further discussion of capital expenditures under “—Capital Requirements”.

Net cash provided by financing activities of $649.9 million for the year ended December 31, 2008 represented a decrease of $2,624.0 million from $3,273.9 million of net cash provided by financing activities for the prior year. This decrease was principally due to an $821.6 million net reduction in APL, ATN, and AHD credit facility borrowings, a $1,431.5 million decrease in net proceeds from APL, ATN and AHD equity offerings, and a $1,073.8 million increase in repayments of APL long-term debt. These amounts were partially offset by a $652.0 million increase in net proceeds from the issuance of APL and ATN long-term debt and a decrease of $40.4 million in our purchases of our common stock.

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

Net cash provided by operating activities of $190.0 million for the year ended December 31, 2007 represented an increase of $147.8 million from $42.2 million of net cash provided by operating activities for the prior year. The increase was derived principally from a $151.3 million increase in net income excluding non-cash items, a $38.6 million favorable movement in deferred taxes, and a $23.9 million favorable movement in working capital, partially offset by a $66.0 million increase in cash distributions paid to minority interests. The increase in net income excluding non-cash items was principally due to higher operating results of ATN through the acquisition of its Michigan assets in June 2007 and of APL through the acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007. The non-cash charges which impacted net income include favorable movements for non-cash derivative expense of $157.7, minority interests in net income of $111.8

million, depreciation, depletion and amortization of $62.3 million, non-cash compensation related to long-term incentive plans of $36.4 million, and amortization of deferred financings costs of $6.7 million. The movement in non-cash derivative expense between periods resulted from commodity price movements during the year ended December 31, 2007 and the unfavorable non-cash impact it had on our net income, which was principally due to the mark-to-market of derivative contracts APL has for future periods. The movement in minority interests in net income was due to an increase in APL’s and ATN’s net income and a decrease in our ownership interests in AHD and ATN between periods. The increase in depreciation, depletion and amortization resulted from ATN’s acquisition of its Michigan assets in June 2007 and APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007. The increase in non-cash compensation expense was principally attributable to vesting of APL phantom and common unit awards in 2007, which were based upon the financial performance of APL’s acquired assets, including the Chaney Dell and Midkiff/Benedum system acquired in July 2007. The decrease due to cash distributions to minority interests is due mainly to increases in ATN’s, AHD’s and APL’s common units outstanding and their cash distribution amount per common unit.

Net cash used in investing activities of $3,503.7 million for the year ended December 31, 2007 represented an increase of $3,323.6 million from $180.1 million used in investing activities for the prior year. This decrease was principally due to a $3,127.0 million increase in net cash paid for acquisitions related ATN’s acquisition of Atlas Gas and Oil in June 2007 and APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007, a $177.0 million increase in capital expenditures for ATN and APL, a $10.4 million increase in our cash paid for investments in Lightfoot, and a $7.5 million decrease in net proceeds from asset sales. See further discussion of capital expenditures under “—Capital Requirements”.

Net cash provided by financing activities of $3,273.9 million for the year ended December 31, 2007 represented an increase of $3,005.8 million from $268.1 million of net cash provided by financing activities for the prior year. This increase was principally due to a $1,668.2 million net increase in APL, ATN, and AHD credit facility borrowings, and a $1,437.0 million increase in net proceeds from APL, ATN and AHD equity offerings. These amounts were partially offset by a $50.6 million increase in purchases of our common stock and a $36.6 million decrease in net proceeds from the issuance of APL long-term debt.

Capital Requirements

Our principal assets are our ownership interests in ATN, APL and AHD, through which our operating activities occur. As such, we do not have any separate capital requirements apart from those entities, other than our commitment to invest a maximum of $20.0 million in Lightfoot, of which, we have already invested $10.7 million at December 31, 2008. AHD, whose principal assets are its ownership interests in APL, does not have any separate capital requirements apart from APL. A more detailed discussion of ATN’s and APL’s capital requirements is provided below.

Atlas Energy. ATN’s capital requirements consist primarily of:

•

maintenance capital expenditures — capital expenditures ATN makes on an ongoing basis to maintain its capital asset base and its current production volumes at a steady level; and

•

expansion capital expenditures — capital expenditures ATN makes 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.

Atlas Pipeline Partners.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.

The following table summarizes our consolidated maintenance and expansion capital expenditures, excluding amounts paid for acquisitions, for the periods presented (in thousands):


	For the Year Ended December 31,
	2008		2007		2006
Atlas Energy
Maintenance capital expenditures⁽¹⁾	$	51,900	$	43,450	$	—
Expansion capital expenditures⁽¹⁾		289,075		153,285		—

Total	$	340,975	$	196,735	$	75,635


Atlas Pipeline Partners
Maintenance capital expenditures	$	6,674	$	9,115	$	4,649
Expansion capital expenditures		319,260		130,532		79,067

Total	$	325,934	$	139,647	$	83,716


Consolidated
Maintenance capital expenditures⁽¹⁾	$	58,574	$	52,565	$	—
Expansion capital expenditures⁽¹⁾		608,335		283,817		—

Total	$	666,909	$	336,382	$	159,351

⁽¹⁾	ATN did not characterize capital expenditures as maintenance or expansion and did not plan capital expenditures in a manner intended to maintain or expand its asset base or production before its initial public offering in December 2006.

Atlas Energy. ATN’s expansion capital expenditures increased to $289.1 million for the year ended December 31, 2008 due principally to higher capital contributions to its investment drilling partnerships and increased acquisitions of leasehold acreage. ATN maintenance capital expenditures for the year ended December 31, 2008 were $51.9 million due primarily to a full year of maintenance capital expenditures associated with its Michigan assets, which were acquired in June 2007.

ATN’s expansion capital expenditures increased to $153.3 million for the year ended December 31, 2007 due principally to higher capital contributions to its investment drilling partnerships and increased acquisitions of leasehold acreage. ATN maintenance capital expenditures for the year ended December 31, 2007 were $43.5 million due primarily to the maintenance capital expenditures associated with its Michigan assets, which were acquired in June 2007.

Atlas Pipeline Partners. APL’s expansion capital expenditures increased to $319.3 million for the year ended December 31, 2008 due principally to the expansion of APL’s gathering systems and upgrades to processing facilities and compressors to accommodate new wells drilled in its service areas, including the construction of a 60 MMcfd expansion of APL’s Sweetwater processing plant. The decrease in maintenance capital expenditures for the year ended December 31, 2008 when compared with the prior year was due to fluctuations in the timing of APL’s scheduled maintenance activity.

APL’s expansion capital expenditures increased to $130.5 million for the year ended December 31, 2007 due principally to the expansion of APL’s gathering systems and upgrades to processing facilities and compressors to accommodate new wells drilled in its service areas. The increase in maintenance capital expenditures for the year ended December 31, 2007 when compared with the prior year was due to the maintenance capital requirements for APL’s Chaney Dell and Midkiff/Benedum systems, which were acquired in July 2007, and fluctuations in the timing of APL’s other scheduled maintenance activity.

As of December 31, 2008, we are committed to expend approximately $93.0 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

Off Balance Sheet Arrangements

As of December 31, 2008, our off balance sheet arrangements are limited to ATN’s guarantee of Crown Drilling of Pennsylvania, LLC’s $5.1 million credit agreement, ATN’s and APL’s letters of credit outstanding of $1.2 million and $5.9 million, respectively, ATN’s estimated capital contribution for the drilling and completion related to Atlas Resources Public #18-2008 Program is approximately $41.1 million and their commitments to expend approximately $93.0 million on capital projects. In addition, we are committed to invest a total of $20.0 million in Lightfoot, of which $10.7 million has been invested as of December 31, 2008.

Contractual Obligations and Commercial Commitments

The following table summarizes our contractual obligations at December 31, 2008 (in thousands):


	Payments Due By Period
	Total		Less than 1 Year		1 – 3 Years		4 – 5 Years		After 5 Years
Contractual cash obligations:
Total debt	$	2,406,427	$	—	$	46,000	$	769,000	$	1,591,427
Interest on total debt⁽¹⁾		916,554		131,620		260,770		232,201		291,963
Derivative-based obligations		64,319		26,559		35,078		2,682		—
Operating leases		25,903		8,131		10,177		3,742		3,853

Total contractual cash obligations	$	3,413,203	$	166,310	$	352,025	$	1,007,625	$	1,887,243

(1)	Based on the interest rates of ATN’s, APL’s and AHD’s respective debt components as of December 31, 2008.


	Amount of Commitment Expiration Per Period
	Total		Less than 1 Year		1 – 3 Years		4 – 5 Years		After 5 Years
Other commercial commitments:
Standby letters of credit	$	7,084	$	7,084	$	—	$	—	$	—
Other commercial commitments		139,241		134,656		1,116		1,001		2,468

Total commercial commitments	$	146,325	$	141,740	$	1,116	$	1,001	$	2,468

Issuance of Subsidiary Common Units

We account for offerings by our subsidiaries in accordance with Staff Accounting Bulletin No. 51, “Accounting by the Parent in Consolidation for Sales of Stock by a Subsidiary” (“SAB 51”). We have adopted a policy to recognize gains on such transactions as a credit to equity rather than as income. These gains represent our portion of the excess net offering price per unit of each of our subsidiaries’ units to the book carrying amount per unit.

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 cumulative 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.

Atlas Energy

In May 2008, ATN sold 2,070,000 of its Class B common units in a public offering at $41.50 per common unit, yielding net proceeds of approximately $82.5 million. The net proceeds were used to repay a portion of ATN’s outstanding balance under its revolving credit facility. A gain of $17.7 million, net of an income tax provision of $8.7 million, was recorded in our consolidated equity as an increase to paid-in capital as well as a corresponding adjustment of $26.4 million to minority interest in accordance with SAB 51 upon completion of the offering.

In May 2008, ATN sold 600,000 of its Class B common units to us in a private placement at $42.00 per common unit for net proceeds to ATN of $25.2 million. The net proceeds were used by ATN to repay a portion of its outstanding balance under its revolving credit facility.

In June 2007, Atlas Energy issued 24,001,009 common units (an approximate 31% interest in ATN at that time) 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 in accordance with SAB 51 upon completion of the offering.

us. 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 in accordance with SAB 51 upon completion of the offering.

Atlas Pipeline Partners and Atlas Pipeline Holdings

In June 2008, APL sold 5,750,000 common units in a public offering at a price of $37.52 per unit, yielding net proceeds of approximately $206.6 million. Also in June 2008, we purchased 308,109 AHD common units and 1,112,000 APL common limited partner units through a private placement transaction at a price of $32.50 and $36.02 per unit, respectively, for net proceeds of approximately $10.0 million and $40.1 million, respectively. APL also received a capital contribution from AHD of $5.4 million for AHD to maintain its 2.0% general partner interest in it. APL utilized the net proceeds from both the sales of common units and the capital contribution from AHD to fund the early termination of certain derivative agreements (see “—Recent Developments”).

In July 2007, APL sold 25,568,175 common units through a private placement to investors at a negotiated purchase price of $44.0 per unit, yielding net proceeds of approximately $1,125 billion. Of the 25,568,175 common units sold by APL, 3,835,227 common units were purchased by AHD for $168.8 million. APL also received a capital contribution from AHD of $23.1 million for AHD to maintain its 2.0% general partner interest in APL. AHD funded this capital contribution and other transaction costs through borrowings under its revolving credit facility of $25.0 million. APL utilized the net proceeds from the sale to partially fund the acquisition of the Chaney Dell and Midkiff/Benedum systems.

In July 2007, AHD issued 6,249,995 common units for net proceeds of $167.0 million after offering costs in a private placement offering. AHD utilized the net proceeds from the sale to partially fund its purchase of 3,835,227 common units of APL. 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 in accordance with SAB 51 upon completion of the offering.

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. 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 $65.4 million to minority interest, in the year ended December 31, 2006 in accordance with SAB 51 upon completion of the offering.

In May 2006, APL sold 500,000 common units to Wachovia Securities, which then offered the common units to public investors. The units, which were issued under a previously filed shelf registration statement, resulted in net proceeds of approximately $19.7 million, after offering costs. APL utilized the net proceeds from the sale to partially repay borrowings under its credit facility made in connection with its acquisition of the remaining 25% ownership interest in NOARK. We recognized a gain of $0.6 million, net of an income tax provision of $0.5 million, 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, in the year ended December 31, 2006 in accordance with SAB 51 upon completion of the offering.

The following table provides information about our gains on the sale of subsidiary units for the years ended December 31, 2008, 2007 and 2006 (in thousands):


Years Ended December 31,	Subsidiary	Gain		Tax Provision		Gain, net of tax
2008	ATN	$	26,368	$	8,699	$	17,669
2007	ATN		235,438		87,521		147,917
2006	ATN		76,034		31,920		44,114
2006	APL		1,078		452		626
2007	AHD		87,295		34,316		52,979
2006	AHD		65,366		27,442		37,924

Total		$	491,579	$	190,350	$	301,229

Issuance of APL Preferred Units

APL Class A Convertible Preferred Units

In March 2006, APL entered into an agreement to sell 30,000 6.5% cumulative convertible preferred units (“APL Class A Preferred Units”) representing limited partner interests to Sunlight Capital Partners, LLC (“Sunlight Capital”), an affiliate of Elliott & Associates, for aggregate gross proceeds of $30.0 million. APL also sold an additional 10,000 Class A Preferred Units to Sunlight Capital for $10.0 million in May 2006, pursuant to its right under the agreement to require Sunlight Capital to purchase such additional units. The APL Class A Preferred Units were originally entitled to receive dividends of 6.5% per annum commencing in March 2007 and paid quarterly on the same date as the distribution payment date for APL’s common units. In April 2007, APL and Sunlight Capital agreed to amend the terms of the APL Class A Preferred Units effective as of that date. The terms of the APL Class A Preferred Units were amended to entitle them to receive dividends of 6.5% per annum commencing in March 2008 and to be convertible, at Sunlight Capital’s option, into APL common units commencing May 8, 2008 at a conversion price equal to the lesser of $43.00 or 95% of the market price of APL’s common units as of the date of the notice of conversion. APL may elect to pay cash rather than issue its common units in satisfaction of a conversion request. APL has the right to call the APL Class A Preferred Units at a specified premium. The applicable redemption price under the amended agreement was increased to $53.22. If not converted into APL common units or redeemed prior to the second anniversary of the conversion commencement date, the APL Class A Preferred Units will automatically be converted into APL’s common units in accordance with the agreement. In consideration of Sunlight Capital’s consent to the amendment of the APL Class A Preferred Units, APL issued $8.5 million of its 8.125% senior unsecured notes due 2015 to Sunlight Capital. APL recorded the senior unsecured notes issued as long-term debt and minority interest on our consolidated balance sheet and, during the year ended December 31, 2007, recorded $3.8 million of this amount as minority interest on our consolidated statements of operations, which was the portion deemed to be attributable to the concessions of APL’s common limited partners and its general partner to the APL Class A preferred unitholder.

In December 2008, APL redeemed 10,000 of the APL Class A Preferred Units for $10.0 million in cash under the terms of the agreement. The redemption was recorded as a reduction of minority interest on our consolidated balance sheet. APL’s 30,000 outstanding APL Class A preferred limited partner units were convertible into approximately 5,263,158 APL common limited partner units at December 31, 2008, which is based upon the market value of APL’s common units and subject to provisions and limitations within the agreement between the parties, with an estimated fair value of approximately $31.6 million based upon the market value of APL’s common units as of that date.

On January 27, 2009, APL and Sunlight Capital agreed to a second amendment to the APL Class A Preferred Units. The amendments included an increase in the dividend yield from 6.5% to 12% per annum, effective January 1, 2009; a change in the conversion commencement date from May 8, 2008 to April 1, 2009; a change in the conversion price adjustment from $43.00 to $22.00, enabling the APL Class A Preferred Units to be converted at the lesser of $22.00 or 95% of the market value; and a change in the call redemption price from $53.22 to $27.25. Simultaneously with the agreement, APL issued Sunlight Capital $15.0 million of its 8.125% senior unsecured notes due 2015 in exchange for 10,000 of the APL Class A Preferred Units. Additionally, on April 1, 2009, APL will redeem 10,000 of the APL Class A preferred units for cash at the liquidation value. If Sunlight Capital does not exercise its conversion right on or before June 2, 2009, APL will redeem the then-remaining 10,000 APL Class A Preferred Units for cash or one-half for cash and one-half for APL’s common limited partner units on July 1, 2009.

Dividends previously paid and those to be paid on the APL Class A Preferred Units and the premium paid upon their redemption, if any, will be recognized as an adjustment to minority interest expense (income) on our consolidated statements of operations.

APL Class B Convertible Preferred Units

In December 2008, APL sold 10,000 newly-created Class B Preferred Units to AHD for cash consideration of $1,000 per APL Class B Preferred Unit (the “Face Value”). AHD has the right, before March 30, 2009, to purchase an additional 10,000 APL Class B Preferred Units on the same terms. APL used the proceeds from the sale of the APL Class B Preferred Units for general partnership purposes. The APL Class B Preferred Units will receive distributions of 12.0% per annum, paid quarterly on the same date as the distribution payment date for APL’s common units. The record date for the determination of holders entitled to receive distributions of the APL Class B Preferred Units will be the same as the record date for determination of APL common unitholders entitled to receive quarterly distributions. The APL Class B Preferred Units are convertible, at the holder’s option, into APL common units commencing on June 30, 2009 (the “APL Class B Preferred Unit Conversion Commencement Date”), provided that the holder must request conversion of at least 2,500 APL Class B Preferred Units and cannot make a conversion request more than once every 30 days. The conversion price will be the lesser of (a) $7.50 (subject to adjustment for customary events such as stock splits, reverse stock splits, stock distributions and spin-offs) and (b) 95% of the average closing price of the APL common units for the 10 consecutive trading days

immediately preceding the date of the holder’s notice to APL of its conversion election (the “Market Price”). The number of APL common units issuable is equal to the Face Value of the APL Class B Preferred Units being converted plus all accrued but unpaid distributions (the “APL Class B Preferred Unit Liquidation Value”), divided by the conversion price. Within 5 trading days of its receipt of a conversion notice, APL may elect to pay the notifying holder cash rather than issue its common units in satisfaction of the conversion request. If APL elects to pay cash for the APL Class B Preferred Units, the conversion price will be the lesser of (a) $7.50 and (b) 100% of the Market Price and the cash amount will be equal to (x) if Market Price is greater than $7.50, the number of APL common units issuable for the APL Class B Preferred Units being redeemed multiplied by the Market Price or (y) if the Market Price is less than or equal to $7.50, the APL Class B Preferred Unit Liquidation Value. APL has the right to redeem some or all of the APL Class B Preferred Units (but not less than 2,500 APL Class B Preferred Units) for an amount equal to the APL Class B Preferred Unit Liquidation Value being redeemed divided by the conversion price multiplied by $9.50.

The sale of the APL Class B Preferred Units to AHD was exempt from the registration requirements of the Securities Act of 1933. APL has agreed to file, upon demand, a registration statement to cover the resale of the APL common units underlying the APL Class B Preferred Units. AHD is entitled to receive the dividends on the APL Class B Preferred units pro rata from the December 2008 commencement date. The 10,000 outstanding APL Class B preferred limited partner units were convertible into approximately 1,754,386 APL common limited partner units at December 31, 2008, with an estimated fair value of approximately $10.5 million based upon the market value of APL’s common units as of that date.

Dividends

We paid cash dividends of $6.7 million and $3.6 million in the years ended December 31, 2008 and 2007, respectively. 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.

Environmental Regulation

ATN’s and APL’s operations are subject to federal, state and local laws and regulations governing the release of regulated materials into the environment or otherwise relating to environmental protection or human health or safety. We believe that ATN’s and APL’s operations and facilities are in substantial compliance with applicable environmental laws and regulations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of remedial requirements, and issuance of injunctions as to future compliance or other mandatory or consensual measures. ATN and APL have ongoing environmental compliance programs. However, risks of accidental leaks or spills are associated with their operations. There can be no assurance that ATN and APL will not incur significant costs and liabilities relating to claims for damages to property, the environment, natural resources, or persons resulting from the operation of ATN’s and APL’s business. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies hereunder, could result in increased costs and liabilities to ATN and APL.

Environmental laws and regulations have changed substantially and rapidly over the last 25 years, and we anticipate that there will be continuing changes. One trend in environmental regulation is to increase reporting obligations and place more restrictions and limitations on activities, such as emissions of pollutants, generation and disposal of wastes and use, storage and handling of chemical substances, that may impact human health, the environment and/or endangered species. Increasingly strict environmental restrictions and limitations have resulted in increased operating costs for ATN and APL and other similar businesses throughout the United States. It is possible that the costs of compliance with environmental laws and regulations may continue to increase. ATN and APL will attempt to anticipate future regulatory requirements that might be imposed and to plan accordingly, but there can be no assurance that ATN and APL will identify and properly anticipate each such charge, or that their efforts will prevent material costs, if any, from arising.

Changes in Prices and Inflation

Our revenues, the value of our assets, our and our subsidiaries’ ability to obtain bank loans or additional capital on attractive terms, and ATN’s ability to finance its drilling activities through drilling investment partnerships have been and will continue to be affected by changes in oil and natural gas market prices. Natural gas and oil prices are subject to significant fluctuations that are beyond our ability to control or predict.

Inflation affects the operating expenses of our operations. In addition, inflationary trends may occur if commodity prices were to increase since such an increase may cause the demand energy equipment and services to increase, thereby

increasing the costs of acquiring or obtaining such equipment and services. Increases in those expenses are not necessarily offset by increases in revenues and fees that our operations are able to charge. While we anticipate that inflation will affect our future operating costs, we cannot predict the timing or amounts of any such effects.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include depreciation and amortization, asset impairment, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired. We summarize our significant accounting policies within our consolidated financial statements included in Item 8, “Financial Statements and Supplementary Data”. The critical accounting policies and estimates we have identified are discussed below.

Impairment of Long-Lived Assets and Goodwill

Long-Lived Assets. The cost of properties, plants and equipment, less estimated salvage value, is generally depreciated on a straight-line basis over the estimated useful lives of the assets. Useful lives are based on historical experience and are adjusted when changes in planned use, technological advances or other factors indicate that a different life would be more appropriate. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively.

Long-lived assets other than goodwill and intangibles with infinite lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. A long-lived asset other than goodwill and intangibles with infinite lives is considered to be impaired when the undiscounted net cash flows expected to be generated by the asset are less than its carrying amount. Events or changes in circumstances that would indicate the need for impairment testing include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions. Additional factors impacting the economic viability of long-lived assets are discussed under “Forward Looking Statements” in this document.

As discussed below, we recognized an impairment of goodwill at December 31, 2008 related to APL. We believe this impairment of goodwill was an event that warranted assessment of APL’s long-lived assets for possible impairment. APL evaluated all of its long-lived assets, including intangible customer relationships, at December 31, 2008, and determined that the undiscounted estimated future net cash flows related to these assets continued to support the recorded values.

Goodwill and Intangibles with Infinite Lives. Goodwill and intangibles with infinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. Under the principles of SFAS No. 142, an impairment loss should be recognized if the carrying value of an entity’s reporting units exceeds its estimated fair value. Because quoted market prices for our reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units. Management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to market capitalization. The principles of SFAS No. 142 and its interpretations acknowledge that the observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity’s individual equity securities. In most industries, including ours, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, we also consider a control premium to the calculations. This control premium is judgmental and is based, among other items, on observed acquisitions in our industry. The resultant fair values calculated for the reporting units are then compared to observable metrics on large mergers and acquisitions in our industry to determine whether those valuations appear reasonable in management’s judgment.

As a result of ATN’s and APL’s impairment evaluation at December 31, 2008, we recognized a $676.9 million non-cash impairment charge within our consolidated statements of operations for the year ended December 31, 2008. The

goodwill impairment resulted from the reduction in APL’s estimated fair value of reporting units in comparison to their carrying amounts at December 31, 2008. APL’s estimated fair value of the reporting units was impacted by many factors, including the significant deterioration of commodity prices and global economic conditions during the fourth quarter of 2008. These estimates were subjective and based upon numerous assumptions about future operations and market conditions, which are subject to change. There were no goodwill impairments recognized by us during the years ended December 31, 2007 and 2006.See “—Goodwill” in Note 2 under Item 8, “Financial Statements and Supplementary Data” for information regarding our impairment of goodwill and other assets.

Fair Value of Financial Instruments

We adopted the provisions of SFAS No. 157 on January 1, 2008. SFAS No. 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS No. 157 (1) creates a single definition of fair value, (2) establishes a hierarchy for measuring fair value, and (3) expands disclosure requirements about items measured at fair value. SFAS No. 157 does not change existing accounting rules governing what can or what must be recognized and reported at fair value in our financial statements, or disclosed at fair value in our notes to the financial statements. As a result, we will not be required to recognize any new assets or liabilities at fair value.

SFAS No. 157’s hierarchy defines three levels of inputs that may be used to measure fair value:

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

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

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

We use the fair value methodology outlined in SFAS No. 157 to value the assets and liabilities recorded at fair value, including ATN’s and APL’s derivative contracts and our Supplemental Employment Retirement Plan (“SERP”). All of ATN’s and APL’s commodity derivative contracts, with the exception of APL’s NGL fixed price swaps and crude oil options, are calculated based on observable market data related to the change in price of the underlying commodity or market interest rate and, therefore, are defined as Level 2 fair value measurements. ATN’s, APL’s and AHD’s interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model, and are therefore defined as Level 2. Our SERP is calculated based on observable actuarial inputs developed by a third-party actuary and, therefore, is defined as a Level 2 fair value measurement. Valuations for APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of natural gas, crude oil, and propane prices, and, therefore, are defined as Level 3 fair value measurements. Valuations for APL’s crude oil options (including those associated with NGL sales) are based on forward price curves developed by the related financial institution based upon current quoted prices for crude oil futures, and therefore are defined as Level 3 fair value measurements.

Reserve Estimates

ATN’s estimates of proved natural gas and oil reserves and future net revenues from them are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Any significant variance in these assumptions could materially affect the estimated quantity of ATN’s reserves. As a result, ATN’s estimates of 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 ATN’s estimates or estimates contained in the reserve reports and may affect ATN’s ability to pay amounts due under its credit facilities or cause a reduction in ATN’s credit facilities. In addition, ATN’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 ATN’s control.

Asset Retirement Obligations

On an annual basis, ATN and APL estimate the costs of future dismantlement, restoration, reclamation and abandonment of its operating assets. ATN and APL also estimate the salvage value of equipment recoverable upon abandonment. We follow the provisions of Financial Accounting Standards Board, or FASB, Interpretation No. 47, or FIN 47, “Accounting for Conditional Asset Retirement Obligations”. As of December 31, 2008 and 2007, the estimate of salvage values was greater than or equal to our estimate of the costs of future dismantlement, restoration, reclamation and abandonment. Projecting future retirement cost estimates is difficult as it involves the estimation of many variables such as economic recoveries of reserves, future labor and equipment rates, future inflation rates and our subsidiaries’ credit adjusted risk free rate. A decrease in salvage values or an increase in dismantlement, restoration, reclamation and abandonment costs from those ATN and APL have estimated, or changes in their estimates or costs, could reduce our gross profit from 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. As our assets currently consist principally of our ownership interests in our subsidiaries, the following information principally encompasses their exposure to market risks unless otherwise noted. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and oil and natural gas prices. The disclosures are 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 the market risk sensitive instruments were entered into for purposes other than trading.

General

All of our and our subsidiaries’ assets and liabilities are denominated in U.S. dollars, and as a result, we do not have exposure to currency exchange risks.

We and our subsidiaries 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 and our subsidiaries manage these risks through regular operating and financing activities and periodical use of derivative financial instruments such as forward contracts and interest rate cap and swap agreements. The following analysis presents the effect on our results of operations, cash flows and financial position as if the hypothetical changes in market risk factors occurred on December 31, 2008. Only the potential impact of hypothetical assumptions is analyzed. The analysis does not consider other possible effects that could impact our and our subsidiaries’ business.

Current market conditions elevate our and our subsidiaries’ concern over counterparty risks and may adversely affect the ability of these counterparties to fulfill their obligations to our subsidiaries, if any. The counterparties related to our subsidiaries commodity and interest-rate derivative contracts are banking institutions, who also participate in their revolving credit facilities. The creditworthiness of our subsidiaries’ counterparties is constantly monitored, and we currently believe them to be financially viable. We are not aware of any inability on the part of our subsidiaries’ counterparties to perform under their contracts and believe our exposure to non-performance is remote.

Interest Rate Risk.At December 31, 2008, ATN had a senior secured revolving credit facility with a borrowing base of $697.5 million ($467.0 million outstanding, not including $1.2 million in letters of credit). The weighted average interest rate for these borrowings was 4.5% at December 31, 2008. ATN also has interest rate derivative contracts at December 31, 2008 having an aggregate notional principal amount of $150.0 million. Under the terms of this agreement, ATN will pay 3.11%, 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. This derivative contract effectively converts $150.0 million of ATN’s floating rate debt under the credit facility to fixed-rate debt. The interest rate swap agreement is effective as of December 31, 2008 and expires on January 31, 2011.

At December 31, 2008, AHD had a $50.0 million senior secured revolving credit facility ($46.0 million outstanding). The weighted average interest rate for AHD’s revolving credit facility borrowings was 3.4% at December 31, 2008. In May 2008, AHD entered into an interest rate derivative contract having an aggregate notional principal amount of $25.0 million. Under the terms of agreement, AHD will pay an interest rate of 3.01%, plus the applicable margin as defined under the terms of its revolving credit facility, and will receive LIBOR, plus the applicable margin, on the notional principal amounts. This derivative effectively converts $25.0 million of its floating rate debt under the revolving credit facility to fixed-rate debt. The interest rate swap agreement began is effective as of December 31, 2008 and expires on May 28, 2010.

At December 31, 2008, APL had a $380.0 million senior secured revolving credit facility ($302.0 million outstanding). APL also had $707.2 million outstanding under its senior secured term loan at December 31, 2008. The weighted average interest rate for APL’s revolving credit facility borrowings was 3.7% at December 31, 2008, and the weighted average interest rate for the term loan borrowings was 3.0% at December 31, 2008.

At December 31, 2008, APL had interest rate derivative contracts having aggregate notional principal amounts of $450.0 million. Under the terms of these agreements, APL will pay weighted average interest rates of 3.02%, plus the applicable margin as defined under the terms of its revolving credit facility, and will receive LIBOR, plus the applicable margin, on the notional principal amounts. These derivatives effectively convert $450.0 million of APL’s floating rate debt under its term loan and revolving credit facility to fixed-rate debt. The APL interest rate swap agreements are effective as of December 31, 2008 and expire during periods ranging from January 30, 2010 through April 30, 2010.

Holding all other variables constant, including the effect of interest rate derivatives, a hypothetical 100 basis-point, or 1% change in interest rates would change our consolidated interest expense by $7.2 million.

Commodity Price Risk. Our market risk exposure to commodities is due to the fluctuations in the price of natural gas, NGLs, condensate and oil and the impact those price movements have on the financial results of our subsidiaries. To limit its exposure to changing natural gas prices, ATN uses financial derivative instruments for a portion of its future natural gas production. APL 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. APL 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. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate are sold. Under these swap agreements, APL 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. Both ATN and APL apply the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“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 operating income, excluding minority interest and income tax effects, for the twelve-month period ending December 31, 2009 of approximately $30.1 million.

Atlas Energy. Realized pricing of ATN’s oil and natural 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 natural gas and oil production has been volatile and unpredictable for many years. To limit its exposure to changing natural gas prices, ATN enters into natural gas and oil swap 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 and oil.

ATN formally documents all relationships between derivative instruments and the items being hedged, including the risk management objective and strategy for undertaking the derivative transactions. This includes matching the natural gas and oil futures and options contracts to the forecasted transactions. ATN assesses, both at the inception of the derivative contract 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 consolidated statements of operations 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, 2008, ATN had the following interest rate and commodity derivatives:

Interest Fixed-Rate Swap


Term	Notional Amount		Type	Contract Period Ended December 31,	Fair Value Liability⁽¹⁾
					(in thousands)
January 2008- January 2011	$	150,000,000	Pay 3.11% —Receive LIBOR	2009	$	(3,481	)
				2010		(2,314	)
				2011		(47	)

					$	(5,842	)

Natural Gas Fixed Price Swaps


Production Period Ending December 31,	Volumes	Average Fixed Price		Fair Value Asset⁽²⁾
	(mmbtu)⁽⁴⁾	(per mmbtu)⁽⁴⁾		(in thousands)
2009	38,120,000	$	8.55	$	93,246
2010	26,360,000	$	8.11		25,537
2011	18,680,000	$	7.84		9,670
2012	13,800,000	$	8.05		10,851
2013	1,500,000	$	8.73		2,098

				$	141,402

Natural Gas Costless Collars


Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset⁽²⁾
		(mmbtu)⁽⁴⁾	(per mmbtu)⁽⁴⁾		(in thousands)
2009	Puts purchased	240,000	$	11.00	$	1,182
2009	Calls sold	240,000	$	15.35		—
2010	Puts purchased	3,360,000	$	7.84		3,340
2010	Calls sold	3,360,000	$	9.01		—
2011	Puts purchased	7,500,000	$	7.48		3,708
2011	Calls sold	7,500,000	$	8.44		—
2012	Puts purchased	1,020,000	$	7.00		223
2012	Calls sold	1,020,000	$	8.32		—
2013	Puts purchased	300,000	$	7.00		72
2013	Calls sold	300,000	$	8.25		—

					$	8,525

Crude Oil Fixed Price Swaps


Production Period Ending December 31,	Volumes	Average Fixed Price		Fair Value Asset⁽³⁾
	(barrel)	(per barrel)		(in thousands)
2009	59,900	$	100.14	$	2,790
2010	48,900	$	97.40		1,624
2011	42,600	$	96.44		1,141
2012	33,500	$	96.00		785
2013	10,000	$	96.06		221

				$	6,561

Crude Oil Costless Collars


Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset⁽³⁾


		(barrel)	(per barrel)		(in thousands)
2009	Puts purchased	36,500	$	85.00	$	1,200
2009	Calls sold	36,500	$	118.63		—
2010	Puts purchased	31,000	$	85.00		754
2010	Calls sold	31,000	$	112.92		—
2011	Puts purchased	27,000	$	85.00		538
2011	Calls sold	27,000	$	110.81		—
2012	Puts purchased	21,500	$	85.00		379
2012	Calls sold	21,500	$	110.06		—
2013	Puts purchased	6,000	$	85.00		100
2013	Calls sold	6,000	$	110.09		—

					$	2,971

Total ATN net derivative liability					$	153,617

⁽¹⁾	Fair value based on independent, third-party statements, supported by observable levels at which transactions are executed in the marketplace.

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

⁽³⁾	Fair value based on forward WTI crude oil prices, as applicable.

⁽⁴⁾	Mmbtu represents million British Thermal Units.

Atlas Pipeline Partners.AHD and APL formally document all relationships between hedging instruments and the items being hedged, including our risk management objective and strategy for undertaking the hedging transactions. This includes matching the derivative contracts to the forecasted transactions. Under SFAS No. 133, AHD and APL can assess, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, AHD and APL will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by AHD and APL through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in our consolidated statements of operations. For AHD’s and APL’s derivatives qualifying as hedges, we will recognize the effective portion of changes in fair value in stockholders’ equity as accumulated other comprehensive income (loss), and reclassify the portion relating to commodity derivatives to transmission, gathering and processing revenue and the portion relating to interest rate derivatives to interest expense within our consolidated statements of operations as the underlying transactions are settled. For APL’s non-qualifying derivatives and for the ineffective portion of qualifying derivatives, we will recognize changes in fair value within gain (loss) on mark-to-market derivatives in our consolidated statements of operations as they occur.

On July 1, 2008, APL elected to discontinue hedge accounting for its existing commodity derivatives which were qualified as hedges under SFAS No. 133. As such, subsequent changes in fair value of these derivatives were and will be recognized immediately within gain (loss) on mark-to-market derivatives in our consolidated statements of operations. The fair value of these commodity derivative instruments at June 30, 2008, which was recognized in accumulated other comprehensive loss within stockholders’ equity on our consolidated balance sheet, will be reclassified to our consolidated statements of operations as these contracts expire.

During the year ended December 31, 2008, APL made net payments of $274.0 million related to the early termination of derivative contracts that it principally entered into as proxy hedges for the prices received on the ethane and propane portion of its NGL equity volume. Substantially all of these derivative contracts were put into place simultaneously with the APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007 and related to production periods ranging from the end of the second quarter of 2008 through the fourth quarter of 2009. During the years ended December 31, 2008, 2007 and 2006, we recognized the following derivative activity related to APL’s termination of these derivative instruments within our consolidated statement of operations (amounts in thousands):


	Early Termination of Derivative Contracts Years Ended December 31,
	2008			2007		2006
Net cash derivative expense included within gain (loss) on mark-to-market derivatives on our consolidated statements of operations	$	(199,964	)	$	—	$	—
Net cash derivative expense included transmission, gathering and processing revenue on our consolidated statements of operations		2,322			—		—
Net non-cash derivative income (expense) included within gain (loss) on mark-to-market derivatives, net on our consolidated statements of operations		(39,218	)		—		—
Net non-cash derivative expense included within transmission, gathering and processing revenue on our consolidated statements of operations		(32,389	)		—		—

The following table summarizes AHD’s and APL’s cumulative derivative activity for the periods indicated (amounts in thousands):


	Years Ended December 31,
	2008			2007			2006
Loss from cash settlement of qualifying hedge instruments⁽¹⁾	$	(105,015	)	$	(49,393	)	$	(13,945	)
Gain/(loss) from change in market value of non-qualifying derivatives⁽²⁾		140,144			(153,363	)		4,206
Loss from de-designation of cash flow derivatives⁽²⁾		—			(12,611	)		—
Gain/(loss) from change in market value of ineffective portion of qualifying derivatives⁽²⁾		47,229			(3,450	)		1,520
Loss from cash and non-cash settlement of non-qualifying derivatives⁽²⁾		(250,853	)		(10,158	)		—
Loss from cash settlement of interest rate derivatives⁽³⁾		(1,226	)		—			—

⁽¹⁾

Included within transmission, gathering and processing revenue on our consolidated statements of operations.

⁽²⁾

Included within gain (loss) on mark-to-market derivatives, net on our consolidated statements of operations.

⁽³⁾

Included within interest expense on our consolidated statements of operations.

As of December 31, 2008, AHD had the following interest rate derivatives:

Interest Fixed-Rate Swap


Term	Notional Amount		Type	Contract Period Ended December 31,	Fair Value Liability⁽¹⁾
					(in thousands)
May 2008- May 2010	$	25,000,000	Pay 3.01% —Receive LIBOR	2009	$	(551	)
				2010		(174	)

Total net AHD derivative liability					$	(725	)

⁽¹⁾	Fair value based on independent, third-party statements, supported by observable levels at which transactions are executed in the marketplace.

As of December 31, 2008, APL had the following interest rate and commodity derivatives, including derivatives that do not qualify for hedge accounting:

Interest Fixed-Rate Swap


Term	Notional Amount		Type	Contract Period Ended December 31,	Fair Value Liability⁽¹⁾
					(in thousands)
January 2008-January 2010	$	200,000,000	Pay 2.88% —Receive LIBOR	2009	$	(4,130	)
				2010		(249	)

					$	(4,379	)


April 2008- April 2010	$	250,000,000	Pay 3.14% —Receive LIBOR	2009	$	(5,835	)
				2010		(1,513	)

					$	(7,348	)

Natural Gas Liquids Sales – Fixed Price Swaps


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Asset⁽²⁾
	(gallons)	(per gallon)		(in thousands)
2009	8,568,000	$	0.746	$	1,509

Crude Oil Sales Options (associated with NGL volume)


Production Period Ended December 31,	Crude Volume	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset/(Liability)⁽³⁾			Option Type


	(barrels)	(gallons)	(per barrel)		(in thousands)
2009	1,056,000	56,634,732	$	80.00	$	29,006		Puts purchased
2009	304,200	27,085,968	$	126.05		(22,774	)	Puts sold⁽⁴⁾
2009	304,200	27,085,968	$	143.00		44		Calls purchased⁽⁴⁾
2009	2,121,600	114,072,336	$	81.01		(1,080	)	Calls sold
2010	3,127,500	202,370,490	$	81.09		(17,740	)	Calls sold
2010	714,000	45,415,440	$	120.00		1,279		Calls purchased⁽⁴⁾
2011	606,000	32,578,560	$	95.56		(3,123	)	Calls sold
2011	252,000	13,547,520	$	120.00		646		Calls purchased⁽⁴⁾
2012	450,000	24,192,000	$	97.10		(2,733	)	Calls sold
2012	180,000	9,676,800	$	120.00		607		Calls purchased⁽⁴⁾

					$	(15,868	)

Natural Gas Sales – Fixed Price Swaps


Production Period Ended December 31,	Volumes		Average Fixed Price		Fair Value Asset⁽³⁾
Production Period Ended December 31,	Volumes		Average Fixed Price		Fair Value Asset⁽³⁾
	(mmbtu)⁽⁵⁾		(per mmbtu)⁽⁵⁾		(in thousands)
2009	5,247,000		$	8.611	$	14,326
2010	4,560,000		$	8.526		6,461
2011	2,160,000		$	8.270		2,072
2012	1,560,000		$	8.250		1,596

		��			$	24,455

Natural Gas Basis Sales


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset/(Liability)⁽³⁾
Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset/(Liability)⁽³⁾
	(mmbtu)⁽⁵⁾	(per mmbtu)⁽⁵⁾			(in thousands)
2009	5,724,000	$	(0.558	)	$	(1,220	)
2010	4,560,000	$	(0.622	)		1,106
2011	2,160,000	$	(0.664	)		367
2012	1,560,000	$	(0.601	)		316

					$	569

Natural Gas Purchases – Fixed Price Swaps


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability⁽³⁾
Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability⁽³⁾
	(mmbtu)⁽⁵⁾	(per mmbtu)⁽⁵⁾		(in thousands)
2009	14,267,000	$	8.680	$	(36,734	)
2010	8,940,000	$	8.580		(13,403	)
2011	2,160,000	$	8.270		(2,072	)
2012	1,560,000	$	8.250		(1,596	)

				$	(53,805	)

Natural Gas Basis Purchases


Production Period Ended December 31,		Volumes		Average Fixed Price			Fair Value Liability⁽³⁾
Production Period Ended December 31,		Volumes		Average Fixed Price			Fair Value Liability⁽³⁾
		(mmbtu)⁽⁵⁾		(per mmbtu)⁽⁵⁾			(in thousands)
2009			15,564,000	$	(0.654	)	$	(9,201	)
2010			8,940,000	$	(0.600	)		(3,720	)
2011			2,160,000	$	(0.700	)		(423	)
2012			1,560,000	$	(0.610	)		(383	)

							$	(13,727	)


Ethane Put Options

Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset⁽²⁾			Option Type


	(gallons)	(per gallon)		(in thousands)
2009	14,049,000	$	0.6948	$	3,234			Puts purchased

Propane Put Options

Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset⁽²⁾			Option Type


	(gallons)	(per gallon)		(in thousands)
2009	14,490,000	$	1.4154	$	9,083			Puts purchased

Isobutane Put Options

Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Liability⁽²⁾			Option Type


	(gallons)	(per gallon)		(in thousands)
2009	126,000	$	0.7500	$	(3	)		Puts purchased

Normal Butane Put Options

Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Liability⁽²⁾			Option Type


	(gallons)	(per gallon)		(in thousands)
2009	113,400	$	0.7350	$	(3	)		Puts purchased

Natural Gasoline Put Options

Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset⁽²⁾			Option Type


	(gallons)	(per gallon)		(in thousands)
2009	126,000	$	0.9650	$	5			Puts purchased

Crude Oil Sales

Production Period Ended December 31,		Volumes		Average Fixed Price			Fair Value Asset⁽³⁾
Production Period Ended December 31,		Volumes		Average Fixed Price			Fair Value Asset⁽³⁾
		(barrels)		(per barrel)			(in thousands)
2009			33,000	$	62.700		$	252

Crude Oil Sales Options


Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset/(Liability)⁽²⁾			Option Type


	(barrels)	(per barrel)		(in thousands)
2009	105,000	$	90.000	$	3,635		Puts purchased
2009	306,000	$	80.017		(6,122	)	Calls sold
2010	234,000	$	83.027		(4,046	)	Calls sold
2011	72,000	$	87.296		(546	)	Calls sold
2012	48,000	$	83.944		(489	)	Calls sold

				$	(7,568	)


	Total APL net derivative liability			$	(63,594	)

⁽¹⁾	Fair value based on independent, third-party statements, supported by observable levels at which transactions are executed in the marketplace.

⁽²⁾	Fair value based upon APL management estimates, including forecasted forward NGL prices as a function of forward NYMEX natural gas, light crude and propane prices.

⁽³⁾	Fair value based on forward NYMEX natural gas and light crude prices, as applicable.

⁽⁴⁾

Puts sold and calls purchased for 2009 represent costless collars entered into by APL as offsetting positions for the calls sold related to ethane and propane production. In addition, calls were purchased by APL for 2010 through 2012 to offset positions for calls sold. These offsetting positions were entered into to limit the loss which could be incurred if crude oil prices continued to rise.

⁽⁵⁾	Mmbtu represents million British Thermal Units.

The fair value of the derivatives is included in the Company’s Consolidated Balance sheets as follows (in thousands):


	December 31,
	2008			2007
Current portion of hedge asset	$	152,726		$	37,968
Long-term hedge asset		69,451			6,882
Current portion of hedge liability		(73,776	)		(111,223	)
Long-term hedge liability		(59,103	)		(157,850	)

Total Company net liability	$	89,298		$	(224,223	)

Atlas America.At December 31, 2008 and 2007, we reflected a net hedging liability on our consolidated balance sheet of $89.3 million and $224.0 million, respectively, as a result of ATN’s, AHD’s and APL’s derivative contracts. Of the $21.1 million net loss in accumulated other comprehensive loss at December 31, 2008, we will reclassify $13.3 million of gains to our consolidated statements of operations over the next twelve month period as these contracts expire, and $8.1 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.

ITEM 8:

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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. (a Delaware corporation) and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008. 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, 2008 and 2007, and the results of their operations and their cash flows for the each of the three years in the period ended December 31, 2008 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), Atlas America, Inc.’s internal control over financial reporting as of December 31, 2008, 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 March 2, 2009 expressed an unqualified opinion on the effectiveness of internal control over financial reporting.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

March 2, 2009

100

ATLAS AMERICA, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except share and per share data)


	December 31,
	2008			2007
ASSETS

Current assets:
Cash and cash equivalents	$	104,571		$	145,535
Accounts receivable		179,910			204,900
Current portion of derivative receivable from partnerships		3,022			213
Current portion of derivative asset		152,726			37,968
Prepaid expenses and other		27,337			22,939
Prepaid and deferred income taxes		31,343			20,642

Total current assets		498,909			432,197
Property, plant and equipment, net		3,967,969			3,442,036
Intangible assets, net		197,485			224,264
Goodwill, net		35,166			744,449
Long-term derivative receivable from partnerships		2,719			13,542
Long-term derivative asset		69,451			6,882
Other assets, net		53,550			40,997

	$	4,825,249		$	4,904,367


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	—		$	64
Accounts payable		144,845			75,524
Liabilities associated with drilling contracts		96,700			132,517
Accrued producer liabilities		67,406			80,697
Current portion of derivative liability to partnerships		34,933			9,014
Current portion of derivative liability		73,776			111,223
Accrued liabilities		88,826			90,454
Advances from affiliate		108			58

Total current liabilities		506,594			499,551
Long-term debt		2,413,082			1,994,392
Deferred income tax liability		242,058			197,106
Long-term derivative liability to partnerships		22,581			1,347
Long-term derivative liability		59,103			157,850
Other long-term liabilities		52,263			45,177
Minority interests		1,118,053			1,595,781
Commitments and contingencies

Stockholders’ equity:
Preferred stock, $0.01 par value: 1,000,000 authorized shares		—			—
Common stock, $0.01 par value: 49,000,000 authorized shares		426			290
Additional paid-in capital		412,869			390,591
Treasury stock, at cost		(147,621	)		(108,886	)
ESOP loan receivable		—			(417	)
Accumulated other comprehensive income (loss)		21,143			(5,935	)
Retained earnings		124,698			137,520

Total stockholders’ equity		411,515			413,163

	$	4,825,249		$	4,904,367

See accompanying notes to consolidated financial statements

101

ATLAS AMERICA, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)


	Years Ended December 31,
	2008			2007			2006
Revenue:
Well construction and completion	$	415,036		$	321,471		$	198,567
Gas and oil production		311,850			180,125			88,449
Transmission, gathering and processing		1,446,650			823,646			435,259
Administration and oversight		19,362			18,138			11,762
Well services		20,482			17,592			12,953
Gain (loss) on mark-to-market derivatives		(63,480	)		(153,325	)		2,316

Total revenue		2,149,900			1,207,647			749,306


Costs and expenses:
Well construction and completion		359,609			279,540			172,666
Gas and oil production		48,194			24,184			8,499
Transmission, gathering and processing		1,165,394			635,987			361,045
Well services		10,654			9,062			7,337
General and administrative		59,091			111,636			46,517
Net expense reimbursement—affiliate		951			930			1,237
Depreciation, depletion and amortization		185,552			107,917			45,643
Goodwill and other asset impairment		698,508			—			—

Total costs and expenses		2,527,953			1,169,256			642,944


Operating income (loss)		(378,053	)		38,391			106,362

Other income (expense):
Interest expense		(142,917	)		(92,611	)		(27,313	)
Gain on early extinguishment of debt		19,867			—			—
Minority interests		479,431			93,476			(18,283	)
Other, net		11,368			10,722			8,564

Total other income (expense)		367,749			11,587			(37,032	)


Income (loss) before income taxes and cumulative effect of accounting change		(10,304	)		49,978			69,330
Provision (benefit) for income taxes		(4,146	)		14,642			27,308

Net income (loss) before cumulative effect of accounting change		(6,158	)		35,336			42,022
Cumulative effect of accounting change (net of tax of $2,530)		—			—			3,825

Net income (loss)	$	(6,158	)	$	35,336		$	45,847


Net income (loss) per common share – basic
Net income (loss) before cumulative effect of accounting change	$	(0.15	)	$	0.87		$	0.94
Cumulative effect of accounting change		—			—			0.09

	$	(0.15	)	$	0.87		$	1.03

Weighted average common shares outstanding—basic		39,999			40,841			44,363


Net income (loss) per common share – diluted
Net income (loss) before cumulative effect on accounting change—diluted	$	(0.15	)	$	0.83		$	0.93
Cumulative effect of accounting change		—			—			0.08

	$	(0.15	)	$	0.83		$	1.01

Weighted average common shares outstanding—diluted		39,999			42,419			45,353

See accompanying notes to consolidated financial statements

102

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)


	Years Ended December 31,
	2008			2007			2006
Net income (loss)	$	(6,158	)	$	35,336		$	45,847
Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as cash flow hedges, net of tax provision (benefit) of ($9,874), $7,426 and ($8,631) for the years ended December 31, 2008, 2007 and 2006, respectively		15,859			(11,782	)		14,155
Less: reclassification adjustment for realized losses (gains) in net income, net of tax provision (benefit) of ($7,057), $1,486 and $127 for the years ended December 31, 2008, 2007 and 2006, respectively		10,974			(2,529	)		(197	)
Plus: amortization of additional post-retirement liability recorded upon adoption of SFAS No. 158, net of tax provision (benefit) of ($150), $7 and $267 for the years ended December 31, 2008, 2007 and 2006, respectively		245			(50	)		(416	)


Total other comprehensive income (loss)		27,078			(14,361	)		13,542

Comprehensive income	$	20,920		$	20,975		$	59,389

See accompanying notes to consolidated financial statements

103

ATLAS AMERICA, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF 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, 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
Issuance of common units	52,386		1		721		28,879			1,296			—			—			—				2,018
Other comprehensive loss	—		—		—		—			—			—			27,078			—				27,078
Repayment of ESOP loan	—		—		—		—			—			417			—			—				417
Treasury stock purchase	—		—		—		(1,155,583	)		(40,031	)		—			—			—				(40,031	)
Stock option compensation expense	—		—		4,023		—			—			—			—			—				4,023
Three-for-two stock split	13,447,521		135		(135	)	—			—			—			—			—				—
Dividends paid	—		—		—		—			—			—			—			(6,664	)			(6,664	)
Gain on sale of subsidiary units	—		—		17,669		—			—			—			—			—				17,669
Net income (loss)	—		—		—		—			—			—			—			(6,158	)			(6,158	)

Balance at December 31, 2008	42,503,119	$	426	$	412,869		(3,252,759	)	$	(147,621	)	$	—		$	21,143		$	124,698			$	411,515

See accompanying notes to consolidated financial statements

104

ATLAS AMERICA, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


	Years Ended December 31,
	2008			2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(6,158	)	$	35,336		$	45,847
Adjustments to reconcile net income (loss ) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		185,552			107,917			45,643
Goodwill and other asset impairment loss		698,508			—			—
Amortization of deferred finance costs		8,893			10,529			3,818
Non-cash loss (gain) on derivative value, net		(196,386	)		155,425			(2,316	)
Non-cash compensation (income) expense		(20,373	)		46,394			9,961
Cumulative effect of change in accounting principle		—			—			(3,825	)
Minority interests		(479,431	)		(93,476	)		18,283
(Gain) loss on asset sales and dispositions		(32	)		916			(5,679	)
Gain on early extinguishment of long-term debt		(19,867	)		—			—
Distributions paid to minority interests		(241,016	)		(104,344	)		(38,276	)
Deferred income taxes		(1,863	)		(127	)		(38,767	)
Changes in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable and prepaid expenses and other		27,588			(102,808	)		(13,726	)
Accounts payable and accrued liabilities		(11,643	)		133,424			18,694
Accounts payable and accounts receivable—affiliate		50			(59	)		2,552
Other operating assets/liabilities		2,517			849			—

Net cash provided by (used in) operating activities		(53,661	)		189,976			42,209


CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(666,909	)		(336,382	)		(159,351	)
Net cash paid for acquisitions		—			(3,156,976	)		(30,000	)
Acquisition purchase price adjustment		31,429			—			—
Investment in Lightfoot Capital Partners, L.P.		(1,009	)		(10,447	)		—
Proceeds from sale of assets		62			1,645			9,109
Other		(785	)		(1,563	)		171

Net cash used in investing activities		(637,212	)		(3,503,723	)		(180,071	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under Atlas Energy Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P. credit facilities		1,301,400			2,123,046			157,250
Repayments under Atlas Energy Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P. credit facilities		(1,356,430	)		(465,429	)		(167,857	)
Net proceeds from issuance of Atlas Energy Resources, LLC long-term debt		407,125			—			—
Net proceeds from issuance of Atlas Pipeline Partners, L.P. long-term debt		244,854			—			36,582
Repayments of Atlas Pipeline Partners, L.P. long-term debt		(162,938	)		—			—
Net proceeds from Atlas Energy Resources, LLC equity offerings		82,497			597,495			139,944
Net proceeds from Atlas Pipeline Partners, L.P. common and preferred unit offerings		196,860			946,399			59,585
Net proceeds from Atlas Pipeline Holdings, L.P. equity offerings		—			166,984			74,326
Dividends paid		(6,664	)		(3,584	)		—
Purchases of treasury stock		(40,031	)		(80,449	)		(29,856	)
Deferred financing costs and other		(16,772	)		(10,581	)		(1,866	)

Net cash provided by financing activities		649,909			3,273,881			268,108

Net change in cash and cash equivalents		(40,964	)		(39,866	)		130,246
Cash and cash equivalents, beginning of year		145,535			185,401			55,155

Cash and cash equivalents, end of year	$	104,571		$	145,535		$	185,401

See accompanying notes to consolidated financial statements

105

ATLAS AMERICA, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – BASIS OF PRESENTATION

Atlas America, Inc. (the “Company”) is a publicly traded (NASDAQ:ATLS) Delaware corporation whose assets consist primarily of cash and its ownership interests in the following entities as of December 31, 2008:

•

Atlas Energy Resources, LLC (“Atlas Energy” or “ATN”), a publicly traded Delaware limited liability company (NYSE: ATN) focuses on natural gas development and production in northern Michigan’s Antrim Shale, Indiana’s New Albany Shale and the Appalachian Basin, which the Company manages through its subsidiary, Atlas Energy Management, Inc., under the supervision of ATN’s board of directors. In December 2006, the Company contributed substantially all of its natural gas and oil assets and its investment partnership management business to ATN, a then wholly-owned subsidiary. Concurrent with this transaction, ATN issued 7,273,750 common units, representing a then 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. At December 31, 2008, the Company owned approximately 48.3% of the outstanding Class A and common units and all of the management incentive interests of ATN;

•

Atlas Pipeline Partners, L.P. (“Atlas Pipeline Partners” 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). In June 2008, the Company purchased 1,112,000 APL common limited partnership units in a private placement transaction at a net price of $36.02 per common unit (see Note 14). At December 31, 2008, the Company had a 2.1% direct ownership interest in APL;

•

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 APL. Through the Company’s ownership of AHD’s general partner, it manages AHD. In July 2006, the Company contributed its 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 then 17.1% ownership interest, 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 the Company. AHD’s cash generating assets currently consist solely of its interests in APL. At December 31, 2008, the Company owned approximately 64.4% of the outstanding common units of AHD. AHD owned a 2% general partner interest, all of the incentive distribution rights, an approximate 12.5% limited partner interest, and 10,000 $1,000 par value 12.0% cumulative convertible preferred limited partner units (representing an approximately 3.2% ownership interest based upon market value of APL’s common units at December 31, 2008) in APL at December 31, 2008; and

•

Lightfoot Capital Partners, LP (“Lightfoot LP”) and Lightfoot Capital Partners GP LLC, (“Lightfoot GP”) the general partner of Lightfoot (collectively, “Lightfoot”), entities which incubate new master limited partnerships (“MLPs”) and invest in existing MLPs. The Company has an approximate direct and indirect 18% ownership interest in Lightfoot GP and a commitment to invest a total of $20.0 million in Lightfoot LP. The Company also has direct and indirect ownership interest in Lightfoot LP. As of December 31, 2008, the Company has invested $10.7 million in Lightfoot LP.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Minority Interest

The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly-owned except for ATN and AHD, which are controlled by the Company, and APL, which is controlled by AHD. The financial statements of AHD include its accounts and the accounts of its subsidiaries, all of which are wholly-owned except for APL. The non-controlling minority ownership interests in the net income (loss) of ATN, AHD and APL are reflected within minority interests on the Company’s consolidated statements of operations, and the minority interests in the assets and liabilities of ATN, AHD and APL are reflected as a liability on the Company’s consolidated balance sheets. All material intercompany transactions have been eliminated.

106

In accordance with established practice in the oil and gas industry, the Company’s financial statements include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the energy partnerships in which ATN has an interest. Such interests typically range from 15% to 35%. The Company’s financial statements do not include proportional consolidation of the depletion or impairment expenses of the Partnerships. Rather, the Company calculates these items specific to its own economics as further explained under the heading “Oil and Gas Properties,” below. All material intercompany transactions have been eliminated.

The Company’s consolidated financial statements also include the operations of APL’s Chaney Dell natural gas gathering system and processing plants located in Oklahoma (“Chaney Dell system”) and APL’s Midkiff/Benedum natural gas gathering system and processing plants located in Texas (“Midkiff/Benedum system”). In July 2007, APL acquired control of Anadarko Petroleum Corporation’s (NYSE: APC) (“Anadarko”) 100% interest in the Chaney Dell system and its 72.8% undivided joint venture interest in the Midkiff/Benedum system (see Note 3). The transaction was effected by the formation of two joint venture companies which own the respective systems, of which APL has a 95% interest and Anadarko has a 5% interest in each. APL consolidates 100% of these joint ventures. The Company reflects Anadarko’s 5% interest in the net income of these joint ventures as minority interest on its statements of operations. The Company also reflects Anadarko’s investment in the net assets of the joint ventures as minority interest on its consolidated balance sheets. In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems, the joint ventures issued cash to Anadarko of $1.9 billion in return for a note receivable. This note receivable is reflected within minority interests on the Company’s consolidated balance sheets.

The Midkiff/Benedum joint venture has a 72.8% undivided joint venture interest in the Midkiff/Benedum system, of which the remaining 27.2% interest is owned by Pioneer Natural Resources Company (NYSE: PXD) (“Pioneer”). Due to the Midkiff/Benedum system’s status as an undivided joint venture, the Midkiff/Benedum joint venture proportionally consolidates its 72.8% ownership interest in the assets and liabilities and operating results of the Midkiff/Benedum system.

Use of Estimates

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

Reclassifications

Certain amounts in the prior year’s consolidated financial statements have been reclassified to conform to the current year presentation.

Cash Equivalents

The Company considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. These cash equivalents consist principally of temporary investments of cash in short-term money market instruments.

Receivables

Accounts receivable on our consolidated balance sheets consist solely of the trade accounts receivable associated with the operations of ATN and APL. In evaluating the realizability of their accounts receivable, management of ATN and APL perform ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of ATN and APL customers’ credit information. ATN and APL extend credit on an unsecured basis to many of its customers. At December 31, 2008 and 2007, ATN and APL had recorded no allowance for uncollectible accounts receivable on our consolidated balance sheets.

107

Property, Plant and Equipment

Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized.

ATN 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 of one barrel equals 6 Mcf.

ATN depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves and depletion rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include ATN’s costs of property interests in uncontrolled, but proportionately consolidated from investment partnerships, wells drilled solely by ATN, properties purchased and working interests with other outside operators.

Upon the sale or retirement of an ATN complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s consolidated statements of operations. Upon the sale of an ATN individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s consolidated balance sheets. Upon ATN’s 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 Company’s consolidated statements of operations. 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.

Impairment of Long-Lived Assets

The Company reviews its long-lived assets for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value. See “–Goodwill” accounting policy for information regarding the Company’s impairment charge to its goodwill during the year ended December 31, 2008.

As discussed below, the Company recognized an impairment of goodwill at December 31, 2008 related to APL. The Company believes this impairment of goodwill was an event that warranted assessment of APL’s long-lived assets for possible impairment. APL evaluated all of its long-lived assets, including intangible customer relationships, at December 31, 2008, and determined that the undiscounted estimated future net cash flows related to these assets continued to support the recorded values.

The review of ATN’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on ATN’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. ATN estimates prices based upon current contracts in place at December 31, 2008, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value, (as determined by discounted future cash flows) and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, ATN’s reserve estimates for its investment in the Partnerships are based on its own assumptions rather than its proportionate share of the limited partnership’s reserves. These assumptions include ATN’s actual capital contributions, an additional carried interest (generally 7% to 10%), a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.

ATN’s lower operating and administrative costs result from the limited partners paying to ATN their proportionate share of these expenses plus a profit margin. These assumptions could result in ATN’s calculation of depletion and impairment being different than its proportionate share of the Partnership’s calculations for these items. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated

108

reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. ATN cannot predict what reserve revisions may be required in future periods.

ATN’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the Partnerships which ATN sponsors and owns an interest in but does not control. ATN’s reserve quantities include reserves in excess of its proportionate share of reserves in a partnership which ATN may be unable to recover due to the partnership legal structure. ATN may have to pay additional consideration in the future as a well or Partnership becomes uneconomic under the terms of the Partnership agreement in order to recover these excess reserves and to acquire any additional residual interests in the wells held by other Partnership investors. The acquisition of any well interest from the Partnership by ATN is governed under the Partnership agreement and must be at fair market value supported by an appraisal of an independent expert selected by ATN.

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate ATN will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value.

Capitalized Interest

ATN and APL capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on combined borrowed funds by ATN and APL was 6.7%, 7.4% and 8.1% for the years ended December 31, 2008, 2007 and 2006, respectively. The aggregate amount of interest capitalized by ATN and APL was $13.9 million, $6.0 million and $2.6 million for the years ended December 31, 2008, 2007 and 2006, respectively.

Fair Value of Financial Instruments

For the Company’s cash and cash equivalents, accounts receivables and accounts payables, the carrying amounts of these financial instruments approximate fair values because of their short maturities and are represented in the Company’s consolidated balance sheets. For further information with regard to the Company’s financial instruments, see “Recently Adopted Accounting Standards”, Note 7, “Debt” and Note 9, “Fair Value of Financial Instruments.”

Derivative Instruments

The Company’s subsidiaries enter into certain financial contracts to manage their exposure to movement in commodity prices and interest rates. The Company applies the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”) to its derivative instruments. SFAS No. 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 the Company’s consolidated statements of operations unless specific hedge accounting criteria are met.

Intangible Assets

Customer contracts and relationships.APL has recorded intangible assets with finite lives in connection with natural gas gathering contracts and customer relationships assumed in certain consummated acquisitions (see Note 3). SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”) requires that intangible assets with finite useful lives be amortized over their 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 must be amortized over the best estimate of its useful life. At a minimum, APL will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. The estimated useful life for APL’s customer contract intangible assets is based upon the approximate average length of customer contracts in existence at the date of acquisition. The estimated useful life for APL’s customer relationship intangible assets is based upon the estimated average length of non-contracted customer relationships in existence at the date of acquisition.

Partnership management, operating contracts and non-compete agreement.ATN has recorded intangible assets with finite lives in connection with partnership management and operating contracts acquired through consummated acquisitions. In addition, ATN entered into a two-year non-compete agreement in connection with the acquisition of AGO (see Note 3). ATN amortizes contracts acquired on a declining balance and straight-line method over their respective estimated useful lives.

109

The following table reflects the components of intangible assets being amortized at December 31, 2008 and 2007 (in thousands):


	December 31,						Estimated Useful Lives In Years
	2008			2007			Estimated Useful Lives In Years
Gross Carrying Amount:
Customer contracts and relationships	$	235,382		$	235,382		7 – 20
Partnership management and operating contracts		14,343			14,343		2 – 13
Non-compete agreement		890			890		2

	$	250,615		$	250,615


Accumulated Amortization:
Customer contracts and relationships	$	(41,735	)	$	(16,179	)
Partnership management and operating contracts		(10,728	)		(9,949	)
Non-compete agreement		(667	)		(223	)

	$	(53,130	)	$	(26,351	)


Net Carrying Amount:
Customer contracts and relationships	$	193,647		$	219,203
Partnership management and operating contracts		3,615			4,394
Non-compete agreement		223			667

	$	197,485		$	224,264

Amortization expense on intangible assets was $26.8 million $12.1 million and $2.0 million for the years ended December 31, 2008, 2007 and 2006, respectively. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2009-$26.5 million; 2010-$26.3 million; 2011-$26.2 million; 2012-$25.7 million; and 2013-$24.6 million.

Goodwill

At December 31, 2008 and 2007, the Company had $35.2 million and $744.4 million, respectively, of goodwill recorded in connection with ATN and APL consummated acquisitions (see Note 3). The changes in the carrying amount of goodwill for the years ended December 31, 2008, 2007 and 2006 were as follows (in thousands):


	Years Ended December 31,
	2008			2007		2006
Balance, beginning of year	$	744,449		$	98,607	$	146,612
APL Goodwill acquired (preliminary allocation) – remaining 25% interest in NOARK acquisition		—			—		30,195
APL reduction in NOARK minority interest acquired		—			—		(118	)
APL purchase price allocation adjustment – NOARK		—			—		(78,082	)
APL purchase price allocation adjustment – Chaney Dell and Midkiff/Benedum acquisition		—			645,842		—
APL post-closing purchase price adjustment with seller and purchase price allocation adjustment – Chaney Dell and Midkiff/Benedum systems acquisition		(2,217	)		—		—
APL recovery of state sales tax initially paid on transaction – Chaney Dell and Midkiff/Benedum systems acquisition		(30,206	)		—		—
Impairment		(676,860	)		—		—

Balance, end of year	$	35,166		$	744,449	$	98,607

110

ATN and APL tests their goodwill for impairment at each year end under the principles of SFAS No. 142 by comparing its reporting unit estimated fair values to carrying values. Because quoted market prices for its reporting units are not available, ATN’s and APL’s management must apply judgment in determining the estimated fair value of these reporting units. ATN’s and APL’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to ATN’s and APL’s market capitalization. The principles of SFAS No. 142 and its interpretations acknowledge that the observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity’s individual equity securities. In most industries, including ATN’s and APL’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, ATN and APL also consider a control premium to the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in ATN’s and APL’s industry. The resultant fair values calculated for the reporting units are then compared to observable metrics on large mergers and acquisitions in ATN’s and APL’s industry to determine whether those valuations appear reasonable in management’s judgment.

As a result of its impairment evaluation at December 31, 2008, the Company recognized a $676.9 million non-cash impairment charge within its consolidated statements of operations for the year ended December 31, 2008. The goodwill impairment resulted from the reduction in APL’s estimated fair value of its reporting units in comparison to their carrying amounts at December 31, 2008. APL’s estimated fair value of its reporting units was impacted by many factors, including the significant deterioration of commodity prices and global economic conditions during the fourth quarter of 2008. These estimates were subjective and based upon numerous assumptions about future operations and market conditions, which are subject to change. There were no goodwill impairments recognized by the Company related to ATN during the year ended December 31, 2008. In addition, there were no goodwill impairments recognized by the Company during the years ended December 31, 2007 and 2006.

During the year ended December 31, 2008, APL adjusted its preliminary purchase price allocation for the acquisition of its Chaney Dell and Midkiff/Benedum systems since its July 2007 acquisition date by increasing the estimated amounts allocated to goodwill and intangible assets and reducing amounts initially allocated to property, plant and equipment (see Notes 3 and 4). Also, in April 2008, APL received a $30.2 million cash reimbursement for sales tax initially paid on its transaction to acquire the Chaney Dell and Midkiff/Benedum systems in July 2007. The $30.2 million was initially capitalized as an acquisition cost and allocated to the assets acquired, including goodwill, based upon their estimated fair values at the date of acquisition. Based upon the reimbursement of the sales tax paid in April 2008, APL reduced goodwill recognized in connection with the acquisition.

Income Taxes

The Company accounts for income taxes under the asset and liability method pursuant to SFAS No. 109, “Accounting for Income Taxes” (“SFAS No. 109”). Under SFAS 109, deferred income taxes are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value.

Stock-Based Compensation

The Company applies the provisions of SFAS No. 123(R), “Share-Based Payment,” as revised (“SFAS No. 123(R)”) to its share-based payments. Generally, the approach to accounting for share-based payments in SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the consolidated financial statements based on their fair values.

Net Income (Loss) Per Share

Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of

111

common stock outstanding during the period. Diluted net income (loss) per share is calculated by dividing net income (loss) by the sum of the weighted average number of common stock outstanding and the dilutive effect of potential shares issuable during the period, as calculated by the treasury stock method. Dilutive potential shares of common stock consist of the excess of shares issuable under the terms of the Company’s stock incentive plan over the number of such shares that could have been reacquired (at the weighted average market price of shares during the period) with the proceeds received from the exercise of the stock options (see Note 16). The following table sets forth the reconciliation of the Company’s weighted average number of common shares used to compute basic net income (loss) per share with those used to compute diluted net income (loss) per share (in thousands):


	Years Ended December 31,
	2008⁽¹⁾	2007⁽²⁾	2006⁽²⁾
Weighted average number of shares – basic	39,999	40,841	44,363
Add: effect of dilutive incentive awards	—	1,578	990

Weighted average number of common shares – diluted	39,999	42,419	45,353

(1)

For the year ended December 31, 2008, approximately 2,082 shares were excluded from the computation of diluted net income (loss) per share because the inclusion of such shares would have been anti-dilutive.

(2)

The shares for the years ended December 31, 2007 and 2006 have been restated to reflect the three-for-two stock split on May 21, 2008 and on May 25, 2007.

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 or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. The Company maintains insurance which may cover in whole or in part certain environmental expenditures. At December 31, 2008 and 2007, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

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, 2008, the Company had $112.5 million in deposits at various banks, of which $112.7 million and was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments to date.

Revenue Recognition

Atlas Energy.Certain energy activities are conducted by ATN through, and a portion of its revenues are attributable to sponsored investment partnerships. ATN contracts with the energy partnerships to drill partnership wells. The contracts require that the energy partnerships must pay ATN 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, ATN classifies the difference between the contract payments it has received and the revenue earned as a current liability titled “Liabilities Associated with Drilling Contracts” on the Company’s consolidated balance sheets. ATN recognizes well services revenues at the time the services are performed. ATN is also entitled to receive management fees according to the respective partnership agreements, and recognizes such fees as income when earned and includes them in administration and oversight revenues.

ATN 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 ATN has an interest with other producers are recognized on the basis of ATN’s percentage ownership of working interest and/or overriding royalty. Generally, ATN’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.

112

Atlas Pipeline.APL’s revenue primarily 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 natural gas liquids (“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 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, APL enters into the following types of contractual relationships with its producers and shippers:

•

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 purchases contracted under keep-whole agreements are generally low in liquids content and meet 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.

The Company accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, crude oil, and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from ATN’s and APL’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “–Use of Estimates” accounting policy for further description). The Company had unbilled revenues at December 31, 2008 and 2007 of $98.5 million and $131.7 million, respectively, which are included in accounts receivable within the Company’s consolidated balance sheets.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States, have not been recognized in the calculation of net income. These changes, other than net income, are referred to as “other comprehensive income (loss)” and for the Company includes changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges and post-retirement plan liabilities (which are presented net of taxes). The following table sets forth the components of accumulated other comprehensive loss in our consolidated balance sheet (in thousands):


	December 31,
	2008			2007
Unrealized gain (loss) on derivative contracts	$	21,398		$	(5,469	)
Post retirement plan liability		(255	)		(466	)

Accumulated other comprehensive income (loss)	$	21,143		$	(5,935	)

Recently Adopted Financial Accounting Standards

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Policies” (“SFAS No. 162”). SFAS No. 162 identifies sources of accounting principles and the framework for selecting such principles used in the preparation of financial statements of nongovernmental entities presented in conformity with U.S. generally accepted accounting principles. SFAS No. 162 is effective beginning November 15, 2008. The Company adopted the provisions of SFAS No. 162 on November 15, 2008 and it had no impact on its financial position and results of operations.

113

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—including an amendment to FASB Statement No. 115” (“SFAS No. 159”). SFAS No. 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. SFAS No. 159 is effective at the inception of an entity’s first fiscal year beginning after November 15, 2007 and offers various options in electing to apply its provisions. The Company adopted SFAS No. 159 on January 1, 2008, and has elected not to apply the fair value option to any of its financial instruments.

In December 2006, the FASB issued FASB Staff Position EITF 00-19-2, “Accounting for Registration Payment Arrangements” (“EITF 00-19-2”). EITF 00-19-2 provides guidance related to the accounting for registration payment arrangements and specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate arrangement or included as a provision of a financial instrument or arrangement, should be separately recognized and measured in accordance with SFAS No. 5, “Accounting for Contingencies” (“SFAS No. 5”). EITF 00-19-2 requires that if the transfer of consideration under a registration payment arrangement is probable and can be reasonably estimated at inception, the contingent liability under such arrangement shall be included in the allocation of proceeds from the related financing transaction using the measurement guidance in SFAS No. 5. The Company adopted EITF 00-19-2 on January 1, 2007 and it did not have an effect on its financial position or results of operations.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosures about fair value statements. In February 2008, the FASB issued FASB Staff Position SFAS No. 157-b, “Effective Date of FASB Statement No. 157”, which provides for a one-year deferral of the effective date of SFAS No. 157 with regard to an entity’s non-financial assets, non-financial liabilities or any non-recurring fair value measurement. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. The Company adopted SFAS No. 157 on January 1, 2008 with respect to its derivative instruments, which are measured at fair value within its financial statements. The provisions of SFAS No. 157 have not been applied to its non-financial assets and non-financial liabilities. See Note 9 for disclosures pertaining to the provisions of SFAS No. 157 with regard to the Company’s financial instruments.

In September 2006, the Securities and Exchange Commission staff issued Staff Accounting Bulletin No. 108, Topic 1N, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108, Topic 1N”). SAB 108, Topic 1N provides guidance on quantifying and evaluating the materiality of unrecorded misstatements. The SEC staff recommends that misstatements should be quantified using both a balance sheet and income statement approach and a determination be made as to whether either approach results in quantifying a misstatement which the registrant, after evaluating all relevant factors, considers material. The SEC staff will not object if a registrant records a one-time cumulative effect adjustment to correct misstatements occurring in prior years that previously had been considered immaterial based on the appropriate use of the registrant’s methodology. SAB 108, Topic 1N is effective for fiscal years ending on or after November 15, 2006. The Company adopted the provisions of SAB 108, Topic 1N on January 1, 2007 and it did not have an impact on its consolidated financial position or results of operations for the years ended December 31, 2007 and 2006.

Recently Issued Accounting Standards

In June 2008, the FASB issued Staff Position No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”). FSP EITF 03-6-1 applies to the calculation of earnings per share (“EPS”) described in paragraphs 60 and 61 of FASB Statement No. 128, “Earnings per Share” for share-based payment awards with rights to dividends or dividend equivalents. It states that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPS pursuant to the two-class method. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. All prior-period EPS data presented shall be adjusted retrospectively to conform to the provisions of this FSP. The Company will apply the requirements of FSP EITF 03-6-1 upon its adoption on January 1, 2009 and it currently does not expect the adoption of FSP EITF 03-6-1 to have a material impact on its financial position and results of operations.

In April 2008, the FASB issued Staff Position No. 142-3, “Determination of Useful Life of Intangible Assets” (“FSP FAS 142-3”). FSP FAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions

114

used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No 141(R), “Business Combinations” (“SFAS No. 141(R)”), and other U.S. Generally Accepted Accounting Principles. FSP FAS 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. The guidance for determining the useful life of a recognized intangible asset should be applied prospectively to intangible assets acquired after the effective date. The disclosure requirements should be applied prospectively to all intangible assets recognized as of, and subsequent to, the effective date. The Company will apply the requirements of FSP FAS 142-3 upon its adoption on January 1, 2009 and it currently does not expect the adoption of FSP FAS 142-3 to have a material impact on its financial position and results of operations.

In March 2008, the FASB ratified the EITF consensus on EITF Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (“EITF No. 07-4”), an update of EITF No. 03-6, “Participating Securities and the Two-Class Method Under FASB Statement No. 128” (“EITF No. 03-6”). EITF 07-4 considers whether the incentive distributions of a master limited partnership represent a participating security when considered in the calculation of earnings per unit under the two-class method. EITF 07-4 also considers whether the partnership agreement contains any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. EITF No. 07-4 is effective for fiscal years beginning after December 15, 2008, including interim periods within those fiscal years, and requires retrospective application of the guidance to all periods presented. Early adoption is prohibited. The Company will apply the requirements of EITF No. 07-4 upon its adoption on January 1, 2009 and does not expect it to have a material impact on its financial position or results of operations.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 amends the requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), to require enhanced disclosure about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008, with early adoption encouraged. The Company will apply the requirements of SFAS No. 161 upon its adoption on January 1, 2009 and does not expect it to have a material impact on its financial position or results of operations or related disclosures.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 amends ARB No. 51 to establish accounting and reporting standards for the noncontrolling interest (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. SFAS No. 160 also requires consolidated net income to be reported, and disclosed on the face of the consolidated statement of operations, at amounts that include the amounts attributable to both the parent and the noncontrolling interest. Additionally, SFAS No. 160 establishes a single method for accounting for changes in a parent’s ownership interest in a subsidiary that does not result in deconsolidation and that the parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008. The Company will apply the requirements of SFAS No. 160 upon its adoption on January 1, 2009 and does not expect it to have a material impact on its financial position and 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” (“SFAS No. 141”), 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, 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 does not expect it to have a material impact on its financial position and results of operations.

115

NOTE 3 – ACQUISITIONS

APL’s Chaney Dell and Midkiff/Benedum Acquisition

In July 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 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, which currently holds a 27.2% undivided joint venture interest in the Midkiff/Benedum system, whereby Pioneer has an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system, which began on June 15, 2008 and ended on November 1, 2008, and an additional 7.4% interest beginning on June 15, 2009 and ending on November 1, 2009 (the aggregate 22.0% additional interest can be entirely purchased during the period beginning June 15, 2009 and ending on November 1, 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 22.0% 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 $1.125 billion of its common units to investors at a negotiated purchase price of $44.00 per unit. Of the $1.125 billion, $168.8 million of these units were purchased by AHD. AHD funded this purchased through the private placement of $168.8 million of its common units to investors. 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 7). APL funded the remaining purchase price from $830.0 million of proceeds from a senior secured term loan which matures in July 2014 and borrowings from its senior secured revolving credit facility that matures in July 2013 (see Note 7). AHD, which holds all of the incentive distribution rights of APL as general partner, had 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. AHD also agreed that the resulting allocation of incentive distribution rights back to APL would be after AHD receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter (see Note 15).

APL’s 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 the acquisition, based on their fair values at the date of the acquisition (in thousands):


Accounts receivable	$	745
Prepaid expenses and other		4,587
Property, plant and equipment		1,030,464
Intangible assets – customer relationships		205,312
Goodwill		613,420

Total assets acquired		1,854,528
Accounts payable and accrued liabilities		(1,499	)

Net cash paid for acquisition	$	1,853,029

APL initially 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. APL tested its goodwill for impairment at December 31, 2008 and recognized an impairment charge of $676.9 million during the year ended December 31, 2008, which included the amounts recognized in connection with its Chaney Dell and Midkiff/Benedum acquisitions (see “—Goodwill” in Note 2).

In April 2008, APL received a $30.2 million cash reimbursement for state sales tax initially paid on its transaction to acquire the Chaney Dell and Midkiff/Benedum systems. The $30.2 million was initially capitalized as an acquisition cost and allocated to the assets acquired, including goodwill, based upon their estimated fair values at the date of acquisition. Based upon the reimbursement of the sales tax paid in April 2008, APL reduced goodwill recognized in connection with the acquisition. 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.

116

APL’s NOARK Acquisition

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 other 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 the Company’s consolidated financial statements from the respective dates of the acquisitions.

ATN’s DTE Gas and Oil Company Acquisition

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 $1.3 billion, including adjustments for working capital of $15.0 million and current year capital expenditures of $19.0 million. To fund the acquisition, ATN borrowed $713.9 million under its credit facility (see Note 7) and received net proceeds of $597.5 million from the private placement of its Class B common. 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 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	)

Total liabilities assumed		(30,552	)

Net assets acquired	$	1,272,518

The results of Atlas Gas and Oil’s operations are included within the Company’s consolidated financial statements from the date of acquisition.

117

The following data presents pro forma revenue, net income and net income per share for the Company for the years ended December 31, 2007 and 2006 as if the ATN and APL acquisitions discussed above and related financing transactions had occurred on January 1, 2006. The data also presents actual revenue, net income (loss) and net income (loss) per share for the Company for the year ended December 31, 2008 for comparative purposes. The Company has prepared these unaudited pro forma financial results for comparative purposes only. These pro forma financial results may not be indicative of the results that would have occurred if ATN and APL had completed these acquisitions and financing transactions at the beginning of the periods shown below or the results that will be attained in the future (in thousands, except per share data; unaudited):


	Years Ended December 31,
	2008			2007		2006
Revenue	$	2,149,900		$	1,544,767	$	1,658,225
Net income (loss)	$	(6,158	)	$	15,285	$	91,431
Net income (loss) per share:
Basic	$	(0.15	)	$	0.56	$	3.09
Diluted	$	(0.15	)	$	0.54	$	3.02

NOTE 4 – PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment (in thousands):


	December 31,						Estimated Useful Lives
	2008			2007			in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	1,214,991		$	1,043,687
Wells and related equipment		872,128			752,184

Total proved properties		2,087,119			1,795,871
Unproved properties		43,749			16,380
Support equipment		9,527			6,936

Total natural gas and oil properties		2,140,395			1,819,187
Pipelines, processing and compression facilities		1,980,805			1,638,845		15 – 40
Rights of way		178,262			168,359		20 – 40
Land, buildings and improvements		24,434			21,742		10 – 40
Other		23,026			17,730		3 – 10

		4,346,922			3,665,863
Less – accumulated depreciation, depletion and amortization		(378,953	)		(223,827	)

	$	3,967,969		$	3,442,036

During the year ended December 31, 2008, the Company recognized charges totaling $21.6 million within goodwill and other asset impairment with respect to a write-off of costs related to an APL pipeline expansion project. The costs incurred consisted of a preliminary construction and engineering costs incurred as well as a vendor deposit for the manufacture of pipeline which expired in accordance with APL’s contractual arrangement.

NOTE 5 – ASSET RETIREMENT OBLIGATIONS

The Company follows SFAS No 143, “Accounting for Retirement Asset Obligations” (“SFAS No. 143”) and FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”), which requires the Company to recognize an estimated liability for the plugging and abandonment of ATN’s oil and gas wells and related facilities. Under SFAS No. 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 No. 143 requires the Company to consider estimated salvage value in the calculation of depreciation, depletion and amortization. The Company’s asset retirement obligations consist principally of the plugging and abandonment of ATN’s oil and gas wells.

118

The estimated liability is based on ATN’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. ATN 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.

A reconciliation of the ATN’s liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands):


	Years Ended December 31,
	2008			2007			2006
Asset retirement obligations, beginning of year	$	42,358		$	26,726		$	18,499
Cumulative effect of adoption of FIN 47		—			—			8,042
Liabilities acquired (See Note 3)		—			11,109			—
Liabilities incurred		3,305			2,582			1,570
Liabilities settled		(253	)		(91	)		(194	)
Revision in estimates		—			—			(2,411	)
Accretion expense		2,726			2,032			1,220

Asset retirement obligations, end of year	$	48,136		$	42,358		$	26,726

The above accretion expense is included in depreciation, depletion and amortization in the Company’s consolidated statements of operations and the asset retirement obligation liabilities are included in other long-term liabilities in the Company’s consolidated balance sheets.

NOTE 6 – OTHER ASSETS

The following is a summary of other assets (in thousands):


	December 31,
	2008		2007
Deferred finance costs, net of accumulated amortization of $23,106 and $14,213 at December 31, 2008 and 2007, respectively	$	38,836	$	26,118
Investments		12,702		12,061
Security deposits		1,719		2,630
Other		293		188

	$	53,550	$	40,997

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreements (see Note 7). In December 2008, APL recorded $1.3 million for accelerated amortization of deferred financing costs associated with the repurchase of approximately $60.0 million in face amount of its senior unsecured notes. In June 2008, APL recorded $1.2 million for accelerated amortization of deferred financing costs associated with the retirement of a portion of its term loan with a portion of the net proceeds from its issuance of senior unsecured notes. In July 2007, APL recorded $5.0 million of accelerated amortization of deferred financing costs associated with the replacement of its previous credit facility with a new facility.

Investments at December 31, 2008 included an aggregate $10.7 million invested in Lightfoot LP. The Company owns, directly and indirectly, approximately 13% of Lightfoot LP, an entity of whom Jonathan Cohen, Vice Chairman of the Company’s Board of Directors, is the Chairman of the Board. In addition, the Company owns, directly and indirectly, approximately 18% of Lightfoot GP, the general partner of Lightfoot LP. The Company committed to invest a total of $20.0 million in Lightfoot LP. The Company has certain co-investment rights until such point as Lightfoot LP raises additional capital through a private offering to institutional investors or a public offering. Lightfoot LP has initial equity funding commitments of approximately $160.0 million and focuses its investments primarily on incubating new master limited partnerships and providing capital to existing MLPs in need of additional equity or structured debt. Lightfoot LP concentrates on assets that are MLP-qualified such as infrastructure, coal, and other asset categories. The Company accounts for its investment in Lightfoot under the equity method of accounting.

119

NOTE 7 – DEBT

Total debt consists of the following (in thousands):


	December 31,
	2008		2007
ATN revolving credit facility	$	467,000	$	740,000
ATN 10.75 % senior notes – due 2018		406,655		—
AHD revolving credit facility		46,000		25,000
APL revolving credit facility		302,000		105,000
APL term loan		707,180		830,000
APL 8.125 % senior notes – due 2015		261,197		294,392
APL 8.75 % senior notes – due 2018		223,050		—
Other debt		—		64

		2,413,082		1,994,456
Less current maturities		—		(64	)

Total long-term debt	$	2,413,082	$	1,994,392

ATN Revolving Credit Facility

At December 31, 2008, ATN had a credit facility with a syndicate of banks with a borrowing base of $697.5 million that matures in June 2012. The borrowing base will be redetermined semiannually on April 1 and October 1 subject to changes in ATN’s oil and gas reserves. Up to $50.0 million of the facility may be in the form of standby letters of credit, of which $1.2 million was outstanding at December 31, 2008, which are not reflected as borrowings on the Company’s consolidated balance sheets. The facility is secured by substantially all of ATN’s assets and is guaranteed by each of its subsidiaries and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR plus the applicable margin, elected at ATN’s option. At December 31, 2008 and 2007, the weighted average interest rate on outstanding borrowings was 2.8% and 7.2%, respectively.

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 0.75% for base rate loans and 1.00% to 1.75% for LIBOR loans.

The events which constitute an event of default for ATN’s credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against ATN in excess of a specified amount, and a change of control. In addition, the agreement limits sales, leases or transfers of assets and the incurrence of additional indebtedness. 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, 2008. The credit facility also requires ATN to maintain a ratio of current assets (as defined in the credit facility) to current liabilities (as defined in the credit facility) of not less than 1.0 to 1.0, and a ratio of total debt (as defined in the credit facility) to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”, as defined in the credit facility) of 4.0 to 1.0, decreasing to 3.75 to 1.0 commencing January 1, 2009, and decreasing to 3.5 to 1.0 commencing January 1, 2010 and thereafter. According to the definitions contained in ATN’s credit facility, ATN’s ratio of current assets to current liabilities was 1.6 to 1.0 and its ratio of total debt to EBITDA was 2.9 to 1.0 at December 31, 2008.

ATN Senior Notes

In January 2008, ATN completed a private placement of $250.0 million of its 10.75% senior unsecured notes due 2018 to institutional buyers pursuant to rule 144A under the Securities Act of 1933. In May 2008 ATN issued an additional $150.0 million of senior notes at 104.75% to par to yield 9.85% to the par call on February 1, 2016. Both issues of senior unsecured notes were subsequently registered for resale on September 19, 2008. ATN received proceeds of approximately $398.0 million from these offerings, including a $7.1 million premium and net of $9.2 million in underwriting fees. In addition, ATN received approximately $4.7 million related to accrued interest. ATN used the net proceeds to reduce the balance outstanding on its revolving credit facility. Interest on the senior notes is payable semi-annually in arrears on February 1 and

120

August 1 of each year. The senior notes are redeemable at any time at specified redemption prices, together with accrued and unpaid interest to the date of redemption. In addition, before February 1, 2011, ATN may redeem up to 35% of the aggregate principal amount of the senior notes with the proceeds of equity offerings at a stated redemption price. The senior notes are also subject to repurchase by ATN 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 ATN does not reinvest the net proceeds within 360 days. The senior notes are junior in right of payment to ATN’s secured debt, including its obligations under its credit facility. The indenture governing the senior notes contains covenants, including limitations of ATN’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. ATN is in compliance with these covenants as of December 31, 2008.

AHD 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, 2008, AHD had $46.0 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, underwriter fees and other transaction costs related to its July 2007 private placement of common units (see Note 3). 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, 2008 was 3.4%. 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, 2008.

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 us, 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). As of December 31, 2008, AHD’s combined leverage ratio was 4.9 to 1.0, its funded debt to EBITDA was 1.0 to 1.0, and its interest coverage ratio was 25.5 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 it 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

At December 31, 2008, APL had a senior secured credit facility with a syndicate of banks which consisted of a term loan which matures in July 2014 and a $380.0 million revolving credit facility which matures in July 2013. Borrowings under APL’s 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 the outstanding APL revolving credit facility borrowings at December 31, 2008 was 3.7%, and the weighted average interest rate on the outstanding APL term loan borrowings at December 31, 2008 was 3.0%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $5.9 million was outstanding at December 31, 2008. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated balance sheet.

121

In June 2008, APL entered into an amendment to its revolving credit facility and term loan agreement to revise the definition of “Consolidated EBITDA” to provide for the add-back of charges relating to APL’s early termination of certain derivative contracts (see Note 8) in calculating its Consolidated EBITDA. Pursuant to this amendment, in June 2008, APL repaid $122.8 million of its outstanding term loan and repaid $120.0 million of outstanding borrowings under the credit facility with proceeds from its issuance of $250.0 million of 10-year, 8.75% senior unsecured notes (see “APL Senior Notes”). Additionally, pursuant to this amendment, in June 2008, APL’s lenders increased their commitments for its revolving credit facility by $80.0 million to $380.0 million.

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 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, 2008. Mandatory prepayments of the amounts borrowed under the term loan portion of the credit facility are required from the net cash proceeds of debt and 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. In June 2008, APL and the underwriting bank agreed to extend the agreement through November 30, 2008 and amended the underwriting fee to be 0.50% of the aggregate principal amount of the term loan outstanding as of that date.

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 it 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 2.75 to 1.0. 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, 2008, APL’s ratio of funded debt to EBITDA was 4.7 to 1.0 and its interest coverage ratio was 4.0 to 1.0.

APL Senior Notes

At December 31, 2008, APL had $223.1 million principal amount outstanding of 8.75% senior unsecured notes due on June 15, 2018 (“APL 8.75% Senior Notes”) and $261.2 million principal amount outstanding of 8.125% senior unsecured notes due on December 15, 2015 (“APL 8.125% Senior Notes”; collectively, the “APL Senior Notes”). The APL 8.125% Senior Notes are presented combined with $0.7 million of unamortized premium received as of December 31, 2008. The APL 8.75% Senior Notes were issued in June 2008 in a private placement transaction pursuant to Rule 144A and Regulation S under the Securities Act of 1933 for net proceeds of $244.9 million, after underwriting commissions and other transaction costs. Interest on the APL Senior Notes in the aggregate 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. Prior to June 15, 2011, APL may redeem up to 35% of the aggregate principal amount of the APL 8.75% Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The APL Senior Notes in the aggregate 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.

Indentures governing the APL Senior Notes in the aggregate contain 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, 2008.

122

In connection with the issuance of the APL 8.75% Senior Notes, APL entered into a registration rights agreement, whereby it agreed to (a) file an exchange offer registration statement with the Securities and Exchange Commission for the APL 8.75% Senior Notes, (b) cause the exchange offer registration statement to be declared effective by the Securities and Exchange Commission, and (c) cause the exchange offer to be consummated by February 23, 2009. If APL did not meet the aforementioned deadline, the APL 8.75% Senior Notes would have been subject to additional interest, up to 1% per annum, until such time that APL had caused the exchange offer to be consummated. On November 21, 2008, APL filed an exchange offer registration statement for the APL 8.75% Senior Notes with the Securities and Exchange Commission, which was declared effective on December 16, 2008. The exchange offer was consummated on January 21, 2009, thereby fulfilling all of the requirements of the 8.75% Senior Notes registration rights agreement by the specified dates.

In December 2008, APL repurchased approximately $60.0 million in face amount of its APL Senior Notes for an aggregate purchase price of approximately $40.1 million plus accrued interest of approximately $2.0 million. The notes repurchased were comprised of $33.0 million in face amount of APL’s 8.125% Senior Notes and approximately $27.0 million in face amount of its 8.75% Senior Notes. All of the APL Senior Notes repurchased have been retired and are not available for re-issue.

The aggregate amount of the Company’s debt maturities is as follows (in thousands):


Years Ended December 31:
2009	$	—
2010		46,000
2011		—
2012		467,000
2013		708,655
Thereafter		1,191,427

	$	2,413,082

Cash payments for interest related to debt were $130.0 million, $81.4 million and $25.6 million for the years ended December 31, 2008, 2007 and 2006, respectively.

NOTE 8 – DERIVATIVE INSTRUMENTS

APL and ATN use a number of different derivative instruments, principally swaps, collars and options, in connection with its commodity price and interest rate risk management activities. The Company and its subsidiaries enter into financial instruments to hedge its forecasted natural gas, NGLs, crude oil and condensate sales against the variability in expected future cash flows attributable to changes in market prices. Its subsidiaries also enter into financial swap instruments to hedge certain portions of its floating interest rate debt against the variability in market interest rates. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs, crude oil and condensate is sold or interest payments on the underlying debt instrument is due. Under swap agreements, the Company and its subsidiaries receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not obligation, to purchase or sell natural gas, NGLs, crude oil and condensate at a fixed price for the relevant contract period.

The Company and its subsidiaries formally document 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 and interest derivative contracts to the forecasted transactions. The Company and its subsidiaries assess, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the Company and its subsidiaries will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by the Company and its subsidiaries through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Company’s consolidated statements of operations. For derivatives qualifying as hedges, the Company and its subsidiaries recognize the effective portion of changes in fair value in stockholders’ equity as accumulated other comprehensive income (loss), and reclassifies the portion relating to commodity derivatives to gas and oil production revenues for ATN derivatives, gathering, transmission and processing revenues for APL derivatives, and the portion relating to interest rate derivatives to interest expense within the company’s consolidated statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Company and its subsidiaries recognize changes in fair value within gain (loss) on mark-to-market derivatives in its consolidated statements of operations as they occur.

123

Derivatives are recorded on the Company’s consolidated balance sheet as assets or liabilities at fair value. The Company reflected a net derivative asset on its consolidated balance sheets of $89.3 million at December 31, 2008 and net derivative liability of $224.2 million at December 31, 2007. Of the $21.1 million of net gain in accumulated other comprehensive loss within stockholders’ equity on the Company’s consolidated balance sheet at December 31, 2008, if the fair values of the instruments remain at current market values, the Company will reclassify $13.3 million of gains to the Company’s consolidated statements of operations over the next twelve month period as these contracts expire, consisting of $18.8 million of gains primarily to gas and oil production revenues, $3.8 million of losses to gathering, transmission and processing revenues, and $1.7 million of losses to interest expense. Aggregate gains of $8.1 million will be reclassified to the Company’s consolidated statements of operations in later periods as these remaining contracts expire, consisting of $12.5 million of gains to gas and oil production revenues, $3.2 million of losses to gathering, transmission and processing revenues, and $1.2 million of losses to interest expense. Actual amounts that will be reclassified will vary as a result of future price changes.

Atlas Energy

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

ATN recognized a loss of $25.1 million, a gain of $17.6 million and a gain of $7.1 million for years ended December 31, 2008, 2007 and 2006, respectively, on settled contracts covering natural gas production. ATN recognized losses of $0.3 million for settled oil production for the year ended December 31, 2008. There were no gains or losses on oil settlements for the years ended December 31, 2007 and 2006. These gains and losses are included within gas and oil production revenue in the Company’s consolidated statements of operations. As the underlying prices and terms in ATN’s hedge contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the years ended December 31, 2008, 2007 and 2006 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

In May 2007, ATN signed a definitive agreement to acquire its Michigan assets (see Note 3). 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, ATN 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 gain (loss) on mark-to-market derivatives in our consolidated statements of operations. ATN recognized a non-cash gain of $26.3 million related to the change in value of these derivatives from May 22, 2007 through June 28, 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.

As of December 31, 2008, ATN had the following interest rate and commodity derivatives:

Interest Fixed-Rate Swap


Term	Notional Amount		Type	Contract Period Ended December 31,	Fair Value Liability⁽¹⁾
					(in thousands)
January 2008-January 2011	$	150,000,000	Pay 3.11% —Receive LIBOR	2009	$	(3,481	)
				2010		(2,314	)
				2011		(47	)

					$	(5,842	)

124

Natural Gas Fixed Price Swaps


Production Period Ending December 31,		Volumes	Average Fixed Price		Fair Value Asset⁽²⁾
		(mmbtu)⁽⁴⁾	(per mmbtu)⁽⁴⁾		(in thousands)
2009		38,120,000	$	8.55	$	93,246
2010		26,360,000	$	8.11		25,537
2011		18,680,000	$	7.84		9,670
2012		13,800,000	$	8.05		10,851
2013		1,500,000	$	8.73		2,098

					$	141,402

Natural Gas Costless Collars
Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset⁽²⁾
		(mmbtu)⁽⁴⁾	(per mmbtu)⁽⁴⁾		(in thousands)
2009	Puts purchased	240,000	$	11.00	$	1,182
2009	Calls sold	240,000	$	15.35		—
2010	Puts purchased	3,360,000	$	7.84		3,340
2010	Calls sold	3,360,000	$	9.01		—
2011	Puts purchased	7,500,000	$	7.48		3,708
2011	Calls sold	7,500,000	$	8.44		—
2012	Puts purchased	1,020,000	$	7.00		223
2012	Calls sold	1,020,000	$	8.32		—
2013	Puts purchased	300,000	$	7.00		72
2013	Calls sold	300,000	$	8.25		—

					$	8,525

*Crude Oil Fixed Price Swaps*
Production Period Ending December 31,		Volumes	Average Fixed Price		Fair Value Asset⁽³⁾
		(barrel)	(per barrel)		(in thousands)
2009		59,900	$	100.14	$	2,790
2010		48,900	$	97.40		1,624
2011		42,600	$	96.44		1,141
2012		33,500	$	96.00		785
2013		10,000	$	96.06		221

					$	6,561

125

Crude Oil Costless Collars


Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset⁽³⁾
		(barrel)	(per barrel)		(in thousands)
2009	Puts purchased	36,500	$	85.00	$	1,200
2009	Calls sold	36,500	$	118.63		—
2010	Puts purchased	31,000	$	85.00		754
2010	Calls sold	31,000	$	112.92		—
2011	Puts purchased	27,000	$	85.00		538
2011	Calls sold	27,000	$	110.81		—
2012	Puts purchased	21,500	$	85.00		379
2012	Calls sold	21,500	$	110.06		—
2013	Puts purchased	6,000	$	85.00		100
2013	Calls sold	6,000	$	110.09		—

					$	2,971

Total ATN net derivative liability					$	153,617

⁽¹⁾	Fair value based on independent, third-party statements, supported by observable levels at which transactions are executed in the marketplace.

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

⁽³⁾	Fair value based on forward WTI crude oil prices, as applicable.

⁽⁴⁾	Mmbtu represents million British Thermal Units.

In addition, $51.8 million of unrealized hedge liabilities and $3.4 million of unrealized hedge assets have been allocated to the limited partners in the Partnerships at December 31, 2008 and December 31, 2007, respectively, based on the Partnerships’ share of estimated future gas and oil production related to the hedges not yet settled and is included in the Company’s consolidated balance sheets as follows (in thousands):


	December 31,
	2008			2007
Unrealized hedge loss – short-term	$	3,022		$	213
Other assets – long-term		2,719			13,542
Accrued liabilities – short-term		(34,933	)		(9,014	)
Unrealized hedge gain – long-term		(22,581	)		(1,347	)

	$	(51,773	)	$	3,394

Interest Rate Risk Hedging Program. At December 31, 2008, ATN had debt outstanding of $467.0 million under its revolving credit facility. During the year ended December 31, 2008, ATN entered into hedging arrangements in the form of interest rate swaps to reduce the impact of volatility of changes in the London interbank offered rate (“LIBOR”). ATN has LIBOR interest rate swaps at a three-year fixed swap rate of 3.11% on $150.0 million of outstanding debt through January 2011. The swaps have been designated as cash flow hedges to minimize the risk associated with changes in the designated benchmark interest rate (in this case, LIBOR) related to forecasted payments associated with interest on the credit facility. ATN has accounted for the interest rate swaps under the “long-haul” method to measure ineffectiveness under SFAS 133. Using the change in variable cash flow method, no hedge ineffectiveness was identified. The value of ATN’s cash flow hedges included in accumulated other comprehensive loss was a net unrecognized loss of approximately $5.8 million at December 31, 2008. ATN recognized losses on settled swaps of $0.5 million for the year ended December 31, 2008. ATN did not have any interest rate swaps for the years ended December 31, 2007 and 2006.

Atlas Pipeline Holdings and Atlas Pipeline Partners

On July 1, 2008, APL elected to discontinue hedge accounting for its existing commodity derivatives which were qualified as hedges under SFAS No. 133. As such, subsequent changes in fair value of these derivatives will be recognized immediately within gain (loss) on mark-to-market derivatives in the Company’s consolidated statements of operations. The fair value of these commodity derivative instruments at December 31, 2008, which was recognized in accumulated other comprehensive loss within stockholders’ equity on the Company’s consolidated balance sheet, will be reclassified to the Company’s consolidated statements of operations in the future at the time the originally hedged physical transaction affects earnings.

During the year ended December 31, 2008, APL made net payments of $274.0 million related to the early termination of derivative contracts that were principally entered into as proxy hedges for the prices received on the ethane and propane portion of its NGL equity volume. Substantially all of these derivative contracts were put into place simultaneously with APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007 and related to production periods ranging from the end of the second quarter of 2008 through the fourth quarter of 2009. During the years ended December 31, 2008, 2007 and 2006, the Company recognized the following derivative activity related to APL’s termination of these derivative instruments within its consolidated statements of operations (amounts in thousands):


	Early termination of derivative contracts for the Years Ended December 31,
	2008			2007		2006
Net cash derivative expense included within gain (loss) on mark-to-market derivatives	$	(199,964	)	$	—	$	—
Net cash derivative income included within transmission, gathering and processing revenue		2,322			—		—
Net non-cash derivative expense included within gain on mark-to-market derivatives		(39,218	)		—		—
Net non-cash derivative expense included within transmission, gathering and processing revenue		(32,389	)		—		—

126

At December 31, 2008, AHD had an interest rate derivative contract having an aggregate notional principal amount of $25.0 million, which was designated as a cash flow hedge. Under the terms of the agreement, AHD will pay an interest rate of 3.01%, plus the applicable margin as defined under the terms of its revolving credit facility (see Note 7), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. This derivative effectively converts $25.0 million of AHD’s floating rate debt under the revolving credit facility to fixed-rate debt. The interest rate swap agreement began on May 30, 2008 and expires on May 28, 2010.

At December 31, 2008, APL has interest rate derivative contracts having aggregate notional principal amounts of $450.0 million, which were designated as cash flow hedges. Under the terms of these agreements, APL will pay weighted average interest rates of 3.02%, plus the applicable margin as defined under the terms of its revolving credit facility (see Note 7), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. These derivatives effectively convert $450.0 million of APL’s floating rate debt under its term loan and revolving credit facility to fixed-rate debt. The APL interest rate swap agreements were effective as of December 31, 2008 and expire during periods ranging from January 30, 2010 through April 30, 2010.

On June 3, 2007, APL 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, APL 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, APL 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 No. 133 at the date these derivatives were entered into because the acquisition of the Anadarko Assets had not yet been completed. Accordingly, APL recognized the instruments as non-qualifying for hedge accounting at inception with subsequent changes in the derivative value recorded within gain (loss) on mark-to-market derivatives in the Company’s consolidated statements of operations. The Company 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 No. 133. APL designated many of these instruments as cash flow hedges and evaluated these derivatives under the cash flow hedge criteria in accordance with SFAS No. 133.

During December 2007, APL 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 APL’s condensate production resulted in a $12.6 million non-cash derivative loss recognized within gain (loss) on mark-to-market derivatives in our consolidated statements of operations and a corresponding decrease in accumulated other comprehensive loss in stockholders’ equity in our consolidated balance sheet.

127

The following table summarizes AHD’s and APL’s cumulative derivative activity for the periods indicated (amounts in thousands):


	Years Ended December 31,
	2008			2007			2006
Loss from cash settlement of qualifying hedge instruments⁽¹⁾	$	(105,015	)	$	(49,393	)	$	(13,945	)
Gain/(loss) from change in market value of non-qualifying derivatives⁽²⁾		140,144			(153,363	)		4,206
Loss from de-designation of cash flow derivatives⁽²⁾		—			(12,611	)		—
Gain/(loss) from change in market value of ineffective portion of qualifying derivatives⁽²⁾		47,229			(3,450	)		1,520
Loss from cash and non-cash settlement of non-qualifying derivatives⁽²⁾		(250,853	)		(10,158	)		—
Loss from cash settlement of interest rate derivatives⁽³⁾		(1,226	)		—			—

⁽¹⁾

Included within transmission, gathering and processing revenue on the Company’s consolidated statements of operations.

⁽²⁾

Included within gain (loss) on mark-to-market derivatives, net on the Company’s consolidated statements of operations.

⁽³⁾

Included within interest expense on the Company’s consolidated statements of operations.

As of December 31, 2008, AHD had the following interest rate derivatives:

Interest Fixed-Rate Swap


Term	Notional Amount		Type	Contract Period Ended December 31,	Fair Value Liability⁽¹⁾
					(in thousands)
May 2008-May 2010	$	25,000,000	Pay 3.01% —Receive LIBOR	2009	$	(551	)
				2010		(174	)

Total net AHD derivative liability					$	(725	)

⁽¹⁾	Fair value based on independent, third-party statements, supported by observable levels at which transactions are executed in the marketplace.

As of December 31, 2008, APL had the following interest rate and commodity derivatives, including derivatives that do not qualify for hedge accounting:

Interest Fixed-Rate Swap


Term	Notional Amount		Type	Contract Period Ended December 31,	Fair Value Liability⁽¹⁾
					(in thousands)
January 2008-January 2010	$	200,000,000	Pay 2.88% —Receive LIBOR	2009	$	(4,130	)
				2010		(249	)

					$	(4,379	)


April 2008-April 2010	$	250,000,000	Pay 3.14% —Receive LIBOR	2009	$	(5,835	)
				2010		(1,513	)

					$	(7,348	)

Natural Gas Liquids Sales – Fixed Price Swaps


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Asset⁽²⁾
	(gallons)	(per gallon)		(in thousands)
2009	8,568,000	$	0.746	$	1,509

128

Crude Oil Sales Options (associated with NGL volume)


Production Period Ended December 31,	Crude Volume	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset/(Liability)⁽³⁾			Option Type
	(barrels)	(gallons)	(per barrel)		(in thousands)
2009	1,056,000	56,634,732	$	80.00	$	29,006		Puts purchased
2009	304,200	27,085,968	$	126.05		(22,774	)	Puts sold⁽⁴⁾
2009	304,200	27,085,968	$	143.00		44		Calls purchased⁽⁴⁾
2009	2,121,600	114,072,336	$	81.01		(1,080	)	Calls sold
2010	3,127,500	202,370,490	$	81.09		(17,740	)	Calls sold
2010	714,000	45,415,440	$	120.00		1,279		Calls purchased⁽⁴⁾
2011	606,000	32,578,560	$	95.56		(3,123	)	Calls sold
2011	252,000	13,547,520	$	120.00		646		Calls purchased⁽⁴⁾
2012	450,000	24,192,000	$	97.10		(2,733	)	Calls sold
2012	180,000	9,676,800	$	120.00		607		Calls purchased⁽⁴⁾

					$	(15,868	)

Natural Gas Sales – Fixed Price Swaps


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Asset⁽³⁾
	(mmbtu)⁽⁵⁾	(per mmbtu)⁽⁵⁾		(in thousands)
2009	5,247,000	$	8.611	$	14,326
2010	4,560,000	$	8.526		6,461
2011	2,160,000	$	8.270		2,072
2012	1,560,000	$	8.250		1,596

				$	24,455

Natural Gas Basis Sales


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset/(Liability)⁽³⁾
	(mmbtu)⁽⁵⁾	(per mmbtu)⁽⁵⁾			(in thousands)
2009	5,724,000	$	(0.558	)	$	(1,220	)
2010	4,560,000	$	(0.622	)		1,106
2011	2,160,000	$	(0.664	)		367
2012	1,560,000	$	(0.601	)		316

					$	569

Natural Gas Purchases – Fixed Price Swaps


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value (Liability)⁽³⁾
	(mmbtu)⁽⁵⁾	(per mmbtu)⁽⁵⁾		(in thousands)
2009	14,267,000	$	8.680	$	(36,734	)
2010	8,940,000	$	8.580		(13,403	)
2011	2,160,000	$	8.270		(2,072	)
2012	1,560,000	$	8.250		(1,596	)

				$	(53,805	)

Natural Gas Basis Purchases


Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value (Liability)⁽³⁾
	(mmbtu)⁽⁵⁾	(per mmbtu)⁽⁵⁾			(in thousands)
2009	15,564,000	$	(0.654	)	$	(9,201	)
2010	8,940,000	$	(0.600	)		(3,720	)
2011	2,160,000	$	(0.700	)		(423	)
2012	1,560,000	$	(0.610	)		(383	)

					$	(13,727	)

129

Ethane Put Options


Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset⁽²⁾		Option Type
	(gallons)	(per gallon)		(in thousands)
2009	14,049,000	$	0.6948	$	3,234	Puts purchased

Propane Put Options


Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset⁽²⁾		Option Type
	(gallons)	(per gallon)		(in thousands)
2009	14,490,000	$	1.4154	$	9,083	Puts purchased

Isobutane Put Options


Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Liability⁽²⁾			Option Type
	(gallons)	(per gallon)		(in thousands)
2009	126,000	$	0.7500	$	(3	)	Puts purchased

Normal Butane Put Options


Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Liability⁽²⁾			Option Type
	(gallons)	(per gallon)		(in thousands)
2009	113,400	$	0.7350	$	(3	)	Puts purchased

Natural Gasoline Put Options


Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset⁽²⁾		Option Type
	(gallons)	(per gallon)		(in thousands)
2009	126,000	$	0.9650	$	5	Puts purchased

Crude Oil Sales


Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Asset⁽³⁾
	(barrels)	(per barrel)		(in thousands)
2009	33,000	$	62.700	$	252

Crude Oil Sales Options


Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset/(Liability)⁽²⁾			Option Type
	(barrels)	(per barrel)		(in thousands)
2009	105,000	$	90.000	$	3,635		Puts purchased
2009	306,000	$	80.017		(6,122	)	Calls sold
2010	234,000	$	83.027		(4,046	)	Calls sold
2011	72,000	$	87.296		(546	)	Calls sold
2012	48,000	$	83.944		(489	)	Calls sold

				$	(7,568	)

Total APL net derivative liability				$	(63,594	)

⁽¹⁾	Fair value based on independent, third-party statements, supported by observable levels at which transactions are executed in the marketplace.

⁽²⁾	Fair value based upon APL management estimates, including forecasted forward NGL prices as a function of forward NYMEX natural gas, light crude and propane prices.

⁽³⁾	Fair value based on forward NYMEX natural gas and light crude prices, as applicable.

⁽⁴⁾

130

⁽⁵⁾	Mmbtu represents million British Thermal Units.

The fair value of the derivatives is included in the Company’s Consolidated Balance sheets as follows (in thousands):


	December 31,
	2008			2007
Current portion of hedge asset	$	152,726		$	37,968
Long-term hedge asset		69,451			6,882
Current portion of hedge liability		(73,776	)		(111,223	)
Long-term hedge liability		(59,103	)		(157,850	)

Total Company net liability	$	89,298		$	(224,223	)

NOTE 9 — FAIR VALUE OF FINANCIAL INSTRUMENTS

Derivative Instruments and Supplemental Employment Retirement Plan

The Company adopted the provisions of SFAS No. 157 at January 1, 2008. SFAS No. 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS No. 157’s hierarchy defines three levels of inputs that may be used to measure fair value:

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

The Company uses the fair value methodology outlined in SFAS No. 157 to value the assets and liabilities for ATN’s, APL’s and AHD’s outstanding commodity derivative contracts (see Note 8) and the Company’s Supplemental Employment Retirement Plan (“SERP”—see Note 16). ATN’s and APL’s commodity hedges, with the exception of APL’s NGL fixed price swaps and crude oil collars, are calculated based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements. ATN’s, AHD’s and APL’s interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model, and are therefore defined as Level 2 fair value measurements. The Company’s SERP is calculated based on observable actuarial inputs developed by a third-party actuary, and therefore is defined as a Level 2 fair value measurement. Valuations for APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of natural gas, crude oil, and propane prices, and therefore are defined as Level 3 fair value measurements. Valuations for APL’s crude oil options (including those associated with NGL sales) are based on forward price curves developed by the related financial institution based upon current quoted prices for crude oil futures, and therefore are defined as Level 3 fair value measurements. In accordance with SFAS No. 157, the following table represents the Company’s assets and liabilities recorded at fair value as of December 31, 2008 (in thousands):


	Level 1		Level 2			Level 3			Total
SERP liability	$	—	$	(3,209	)	$	—		$	(3,209	)
Interest rate derivatives		—		(18,294	)		—			(18,294	)
APL commodity-based derivatives		—		(42,256	)		(9,611	)		(51,867	)
ATN commodity-based derivatives		—	$	159,459			—		$	159,459

Total	$	—	$	95,700		$	(9,611	)	$	86,089

131

APL’s Level 3 fair value amount relates to its derivative contracts on NGL fixed price swaps and crude oil options. The following table provides a summary of changes in fair value of APL’s Level 3 derivative instruments as of December 31, 2008 (in thousands):


	NGL Fixed Price Swaps			Crude Oil Sales Options (associated with NGL Volume)			Crude Oil Sales Options			NGL Sales Options			Total
Balance – December 31, 2007	$	(33,624	)	$	(145,418	)	$	(24,740	)	$	—		$	(203,782	)
New options contracts		—			20,451			6,012			24,529			50,992
Cash settlements from unrealized gain (loss)⁽¹⁾		(7,396	)		224,956			(3,926	)		(12,154	)		201,480
Cash settlements from other comprehensive loss⁽¹⁾		33,895			92,432			13,406			—			139,733
Net change in unrealized gain (loss)⁽²⁾		17,321			(57,934	)		36,159			—			(4,454	)
Deferred option premium recognition		—			150			468			(59	)		559
Net change in other comprehensive loss		(8,687	)		(150,504	)		(34,948	)		—			(194,139	)

Balance – December 31, 2008	$	1,509		$	(15,867	)	$	(7,569	)	$	12,316		$	(9,611	)

(1)	Included within transmission, gathering and processing revenue on the Company’s consolidated statements of operations.

(2)	Included within gain (loss) on mark-to-market derivatives on the Company’s consolidated statements of operations.

Other Financial Instruments

The estimated fair value of the Company’s other financial instruments has been determined based upon its assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Company could realize upon the sale or refinancing of such financial instruments.

The Company’s other current assets and liabilities on its consolidated balance sheets are financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature. The estimated fair values of the Company’s long-term debt at December 31, 2008 and 2007, which consists principally of APL’s term loans, ATN and APL’s Senior Notes and borrowings under the ATN, AHD and APL’s credit facilities, were $1,911.4 million and $1,990.6 million, respectively, compared with the carrying amounts of $2,413.1 million and $1,994.4 million, respectively. The Senior Notes were valued based upon recent trading activity. The carrying value of outstanding borrowings under the credit facilities, which bear interest at a variable interest rate, approximates their estimated fair value.

NOTE 10 — 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 ATN Sponsored Investment Partnerships.ATN conducts certain activities through, and a substantial portion of its revenues are attributable to, energy limited partnerships (“Investment Partnerships”). ATN serves as general partner of the Investment Partnerships and assumes customary rights and obligations for the Investment Partnerships. As the general partner, ATN is liable for the Investment Partnerships’ liabilities and can be liable to limited partners if it breaches its responsibilities with respect to the operations of the Investment Partnerships. ATN is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Investment Partnerships’ revenue, and costs and expenses according to the respective Investment Partnership agreements.

Relationship with Resource America, Inc.In June 2005, Resource America, Inc. (“RAI”) completed its spin-off of the Company. In connection with the spin-off, RAI and the 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, 2008. 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 matters. The transition services agreement governs the provision of support services by the Company to RAI and by RAI to the Company, such general and administrative functions. The Company reimburses RAI for various costs and expenses it incurs for these services on behalf of the Company, primarily payroll and rent. For the years ended December 31, 2008, 2007 and 2006, the Company’s reimbursements to RAI totaled $1.0 million, $0.9 million, and $1.2 million, respectively. At December 31, 2008 and 2007, reimbursements to RAI totaling $0.1 million and $0.1 million, respectively, which remain to be settled between the parties, were reflected in the Company’s consolidated balance sheets as advances to/from affiliate.

132

RAI’s relationship with Anthem Securities (a wholly-owned subsidiary of the Company).Anthem Securities, Inc (“Anthem”) 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 and $1.3 million toward such operating costs of Anthem for the years ended December 31, 2007 and 2006, respectively. During the years ended December 31, 2007 and 2006, Anthem reimbursed RAI $3.2 million and $2.7 million, respectively, for costs incurred on Anthem’s behalf. During the first quarter 2007, RAI commenced its own broker-dealer operations and ceased using the services of Anthem.

NOTE 11 — COMMITMENTS AND CONTINGENCIES

General Commitments

The Company leases office space and equipment under leases with varying expiration dates through 2014. Rental expense was $10.7 million, $6.6 million and $4.4 million for the years ended December 31, 2008, 2007 and 2006, respectively. Future minimum rental commitments for the next five years are as follows (in thousands):


Years Ended December 31:
2009	$	8,131
2010		5,885
2011		4,292
2012		2,543
2013		1,199
Thereafter		3,853

	$	25,903

The Company, through ATN, 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. ATN 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. ATN may be required to subordinate a part of its net partnership revenues from its 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. As of December 31, 2008, no subordination has occurred.

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.

As of December 31, 2008, the Company is committed to expend approximately $93.0 million on pipeline extensions, compressor station upgrades, and processing facility upgrades.

Legal Proceedings

In June 2008, ATN’s wholly-owned subsidiary, Atlas America, LLC, was named as a co-defendant in the matter captionedCNX Gas Company, LLC (“CNX”) v. Miller Petroleum, Inc. (“Miller”), et al. (Chancery Court, Campbell County, Tennessee). In its complaint, CNX alleges that Miller breached a contract to assign to CNX certain leasehold rights (“Leases”) representing approximately 30,000 acres in Campbell County, Tennessee and that the Company and another defendant, Wind City Oil & Gas, LLC, interfered with the closing of this assignment on June 6, 2008. ATN purchased the Leases from Miller for approximately $19.1 million. On December 15, 2008, the Chancery Court dismissed the matter in its entirety, holding that there had been no breach of the contract by Miller and, therefore, that Atlas America could not have tortuously interfered with the contract. The Chancery Court dismissed all claims against the Company; however, CNX has appealed this decision.

One of the Company’s subsidiaries, Resource Energy, LLC, together with Resource America, Inc., (the former parent of the Company), 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 ATN. The complaint alleged that ATN 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

133

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, the Company paid $0.3 million in May 2007, upgraded certain gathering systems and capped certain transportation expenses chargeable to the landowners.

Atlas Gas & Oil Company LLC, as successor to DTE Gas & Oil Company, was one of four defendants in a personal injury action filed in Antrim County Circuit Court in northern Michigan in August 2006. The complaint alleged that plaintiff suffered serious personal injuries as a result of the defendants’ negligence. ATN paid $0.1 million to the plaintiff in October 2007 in full settlement of this action.

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

NOTE 12 — INCOME TAXES

The following table details the components of the Company’s provision (benefit) for income taxes from continuing operations for the periods indicated (in thousands):


	Years Ended December 31,
	2008			2007			2006
Provision (benefit) for income taxes:
Current:
Federal	$	(1,929	)	$	14,441		$	54,634
State		(331	)		608			11,438
Deferred		(1,886	)		(407	)		(38,764	)

	$	(4,146	)	$	14,642		$	27,308

A reconciliation between the statutory federal income tax rate and the Company’s effective income tax rate is as follows:


	Years Ended December 31,
	2008		2007		2006
Statutory tax rate	35	%	35	%	35	%
Statutory depletion	2		(1	)	(1	)
Tax exempt interest	1		(2	)	—
Section 199 deduction	1		(2	)	—
State income taxes, net of federal tax benefit	4		2		5
Other, net	(3	)	(3	)	—

	40	%	29	%	39	%

The components of the Company’s net deferred tax liability are as follows at the dates indicated:


	December 31,
	2008			2007
Deferred tax assets:
Unrealized loss on investments	$	5,363		$	7,337
Accrued expenses		15,104			13,765
Capital loss carryforwards		8,587			—
Net operating loss carryforwards		24,758			180
Valuation allowance on deferred tax assets		(155	)		(180	)
Other		308			—

		53,965			21,102

Deferred tax liabilities:
Unrealized gain on investments		(18,894	)		(3,851	)
Gain on sale of subsidiary units		(190,615	)		(181,930	)
Investment in partnerships		(55,171	)		(22,205	)

		(264,680	)		(207,986	)

Net deferred tax liability	$	(210,715	)	$	(186,884	)

134

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,
	2008			2007
Current deferred tax asset	$	31,343		$	10,222
Non-current deferred tax liability		(242,058	)		(197,106	)

	$	(210,715	)	$	(186,884	)

At December 31, 2008, the Company has a federal net operating loss carryforward of $59.8 million that will expire during 2028, and a state net operating loss carryforward of $69.5 million that will expire beginning in 2011 and ending in 2028 if unused. The Company had deferred tax assets of $24.8 million for the net operating loss carryforwards. Management believes its is more likely than not that the deferred tax asset will be fully realized. The valuation allowance is $0.2 million at December 31, 2008. The valuation allowance, all of which was established prior to 2008, is 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.

For the year ended December 31, 2008, the Company received a net cash refund from income taxes of $12.1 million compared with cash paid for income taxes of $36.9 million and $57.7 million for the years ended December 31, 2007 and 2006, respectively.

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 than 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, 2008, there were no additions, reductions or settlements in unrecognized tax benefits and the Company has no material uncertain tax positions.

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 2005. 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 13 — COMMON STOCK

Stock Repurchase Plan

In September 2008, the Company’s Board of Directors approved a stock repurchase agreement of up to $50.0 million at a price not to exceed $36.00 per share. The daily repurchase amount was limited to 50,000 shares. The Company purchased 595,292 of its shares during September and October 2008 for a total price of $20.0 million under this program. In addition, the Company utilized the remaining $20.0 million of availability under a stock repurchase agreement approved in September 2005 to purchase 560,291 shares in August and September 2008. The average price for the shares purchased during the quarter was $34.76 per share.

In September 2005, the Company’s 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.

135

Stock Splits

On April 22, 2008, the Company’s Board of Directors approved a three-for-two stock split of the Company’s common stock effected in the form of a 50% stock dividend. All shareholders of record as of May 21, 2008 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 30, 2008. Information pertaining to shares and earnings per share has been restated for the years ended December 31, 2007 and 2006 in the accompanying financial statements and notes to the consolidated financial statements to reflect this split.

On April 27, 2007, the Company’s Board of Directors approved a three-for-two 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 for the years ended December 31, 2006 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 stock 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 of common stock held on that date. The additional shares of common stock were distributed on March 10, 2006.

Dutch Auction Tender Offer

In January 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.

NOTE 14 – 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 June 2008, APL sold 5,750,000 common limited partner units in a public offering at a price of $37.52 per unit, yielding net proceeds of approximately $206.6 million. Also in June 2008, the Company purchased 308,109 AHD common units and 1,112,000 APL common limited partner units through a private placement transaction at a price of $32.50 and $36.02 per unit, respectively, for net proceeds of approximately $10.0 million and $40.1 million, respectively. AHD utilized the net proceeds from the sale to purchase 278,000 common units of APL, which in turn utilized the proceeds to partially fund the early termination of certain derivative agreements (see Note 8).

In May 2008, ATN sold 2,070,000 of its Class B common units in a public offering yielding net proceeds of approximately $82.5 million. The net proceeds were used to repay a portion of ATN’s outstanding balance under its revolving credit facility. A gain of $17.7 million, net of an income tax provision of $8.7 million, in accordance with SAB 51 was recorded in consolidated equity as an increase to paid-in capital as well as a corresponding adjustment of $26.4 million to minority interest, during the year ended December 31, 2008.

In May 2008, the Company purchased 600,000 of ATN’s Class B common units in a private placement at $42.00 per common unit, increasing the Company’s ownership of ATN’s common units to 29,952,996 common units. ATN’s net proceeds of $25.2 million were used to repay a portion of its outstanding balance under its revolving credit facility.

In July 2007, APL sold 25,568,175 common units through a private placement to investors at a negotiated purchase price of $44.00 per unit, yielding net proceeds of approximately $1.125 billion. Of the 25,568,175 common units sold by APL, 3,835,227 common units were purchased by AHD for $168.8 million. APL also received a capital contribution from AHD of $23.1 million for AHD to maintain its 2.0% general partner interest in APL. AHD funded this capital contribution and other transaction costs through borrowings under its revolving credit facility of $25.0 million. APL utilized the net proceeds from the sale to partially fund the acquisition of control of the Chaney Dell natural gas gathering system and processing plants located in Oklahoma and a 72.8% interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (see Note 3).

136

In July 2007, AHD issued 6,249,995 common units (an approximate 27% interest in it at that moment) for net proceeds of $167.0 million after offering costs in a private placement offering. In addition, in July 2007 APL issued 25,568,175 common units through a private placement to investors, of which 3,835,227 common units were purchased by AHD. A gain of $53.0 million, net of an income tax provision of $34.3 million, in accordance with SAB 51 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, during the year ended December 31, 2007.

In June 2007, ATN issued 24,001,009 Class B common (an approximate 31% interest in ATN at that moment) 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, in accordance with SAB 51 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, during the year ended December 31, 2007.

In December 2006, ATN issued 7,198,750 common units (an approximate 19.4% interest in it at that moment) 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, during the year ended December 31, 2006.

In July 2006, AHD issued 3,600,000 common units (an approximate 17.1% in it at that moment) 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, during the year ended December 31, 2006.

In May 2006, APL issued 500,000 common units (an approximate 4% interest in it at that moment) 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 $0.5 million, which was recorded in consolidated equity as a credit to paid-in capital as well as a corresponding adjustment of $0.6 million to minority interest, during the year ended December 31, 2006.

The Company has experienced sales of subsidiary units in years prior to 2006 and had not previously recorded a gain on such sales. The Company determined, 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 these cumulative gains within its December 31, 2006 financial statements.

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


Years Ended December 31,	Subsidiary	Gain		Tax Provision		Gain, net of tax
2008	ATN	$	26,368	$	8,699	$	17,669
2007	ATN		235,438		87,521		147,917
2006	ATN		76,034		31,920		44,114
2006	APL		1,078		452		626
2003 to 2005	APL		45,821		19,236		26,585
2007	AHD		87,295		34,316		52,979
2006	AHD		65,366		27,442		37,924

		$	537,400	$	209,586	$	327,814

137

NOTE 15 — CASH DISTRIBUTIONS

Atlas Energy Resources Cash Distributions.The Company is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its limited liability company agreement) for that quarter in accordance with their respective percentage interests. If Class A and Class B common unit distributions in any quarter exceed specified target levels, the Managing Member will receive management incentive interests between 15% and 50% of such distributions in excess of the specified target levels as defined in our limited liability company agreement. Distributions declared by the Company from inception through December 31, 2008 are as follows:


Date Cash Distribution Paid or Payable	For Quarter Ended	Cash Distribution Per Common Unit			Total Cash Distribution to the Company		Manager Incentive Distribution 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	December 31, 2007	$	0.57		$	17,437	$	965

May 15, 2008	March 31, 2008	$	0.59		$	18,410	$	1,214
August 14, 2008	June 30, 2008	$	0.61		$	19,060	$	1,687
November 14, 2008	September 30, 2008	$	0.61		$	19,060	$	1,687
February 13, 2009⁽²⁾	December 31, 2008	$	0.61		$	19,060	$	1,687

(1)	Represents a pro-rated cash distribution of $0.42 per unit for the period from December 18, 2006, the date of ATN’s initial public offering, through December 31, 2006.

(2)	Declared subsequent to December 31, 2008 (see Note 18).

(3)	Payable to the Company in 2010 provided ATN meets certain criteria within its partnership agreements.

Atlas Pipeline Partners Cash Distributions. APL is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter to its common unitholders and AHD, as general partner. If APL’s common unit distributions in any quarter exceed specified target levels, AHD will receive between 15% and 50% of such distributions in excess of the specified target levels. Distributions declared by APL for the period from January 1, 2007 through December 31, 2008 were as follows (in thousands, except per unit amounts):


Date Cash Distribution Paid	For Quarter Ended	APL Cash Distribution per Common Limited Partner Unit		Total APL Cash Distribution to Common Limited Partners		Total APL Cash Distribution to the General Partner
February 14, 2006	December 31, 2005	$	0.83	$	10,416	$	3,638

May 15, 2006	March 31, 2006	$	0.84	$	10,541	$	3,766
August 14, 2006	June 30, 2006	$	0.85	$	11,118	$	4,059
November 14, 2006	September 30, 2006	$	0.85	$	11,118	$	4,059
February 14, 2007	December 31, 2006	$	0.86	$	11,249	$	4,193

May 15, 2007	March 31, 2007	$	0.86	$	11,249	$	4,193
August 14, 2007	June 30, 2007	$	0.87	$	11,380	$	4,326
November 14, 2007	September 30, 2007	$	0.91	$	35,205	$	4,498
February 14, 2008	December 31, 2007	$	0.93	$	36,051	$	5,092

May 15, 2008	March 31, 2008	$	0.94	$	36,450	$	7,891
August 14, 2008	June 30, 2008	$	0.96	$	44,096	$	9,308
November 14, 2008	September 30, 2008	$	0.96	$	44,105	$	9,312
February 13, 2009⁽¹⁾	December 31, 2008	$	0.38	$	17,821	$	2,545

(1)	Declared subsequent to December 31, 2008 (see Note 18)

In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see Note 3), AHD, 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. AHD

138

also agreed that the resulting allocation of incentive distribution rights back to APL would be after AHD receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter.

Atlas Pipeline Holdings Cash Distributions.AHD has 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 unitholders. Distributions declared by AHD for the period from inception through December 31, 2008 were as follows (in thousands except per unit amounts):


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	December 31, 2007	$	0.34		$	5,950

May 20, 2008	March 31, 2008	$	0.43		$	7,525
August 19, 2008	June 30, 2008	$	0.51		$	9,082
November 19, 2008	September 30, 2008	$	0.51		$	9,082
February 19, 2009⁽¹⁾	December 31, 2008	$	0.06		$	1,068

(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, 2008 (see Note 18)

NOTE 16 — BENEFIT PLANS

Incentive Bonus Plan

The Company’s shareholders approved an Incentive Bonus Plan (“Bonus Plan”) in May 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 a limit as set by the compensation committee. 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. For the years ended December 31, 2008 and 2007, the Company recognized $7.2 million and $12.5 million, respectively, under the plan.

Stock Incentive Plan

The Company has a Stock Incentive Plan (the “Plan”) which authorizes the granting of up to 4,499,999 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 1,687,500 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

139

straight-line basis. The Company issues new shares when stock options are exercised or units are converted to shares. For the years ended December 31, 2008, 2007 and 2006, the Company received $0.4 million, $0.9 million and $32,500, respectively, from the exercise of options.

The following tables set forth the Plan activity for the years ended December 31, 2008, 2007 and 2006:


	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding at December 31, 2005	2,624,063		$	11.32

Granted	146,250		$	20.75
Exercised	(2,868	)	$	11.32		$	28
Forfeited or expired	(1,013	)	$	11.32

Outstanding at December 31, 2006	2,766,432		$	11.82		$	29,970
Granted	30,000		$	35.82
Exercised	(81,051	)	$	11.32		$	1,696
Forfeited or expired	—			—

Outstanding at December 31, 2007	2,715,381		$	12.10	7.6	$	74,275
Granted	825,000		$	32.67
Exercised	(45,030	)	$	11.32		$	969
Forfeited or expired	—			—

Outstanding at December 31, 2008	3,495,351		$	16.97	7.3	$	—

Options exercisable at December 31, 2008	2,337,642		$	11.61	6.5
Available for grant at December 31, 2008	838,160

⁽¹⁾	The non-cash compensation expense recognized for option awards for the years ending December 31, 2008, 2007 and 2006 was $3.9 million, $1.5 million and $1.3 million, respectively.

The Company used the Black-Scholes option pricing model in 2008, 2007 and 2006 to estimate the weighted average fair value of options granted. The following weighted average assumptions were used for the periods indicated:


	Years Ended December 31,
	2008			2007			2006
Expected dividend yield		0.4	%		0.4	%		0	%
Expected stock price volatility		33	%		35	%		35	%
Risk-free interest rate		2.6	%		4.7	%		4.7	%
Expected term (in years)		6.25			6.25			6.25
Fair value of stock options granted	$	11.75		$	15.08		$	9.09

Deferred Units and Restricted Shares.

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 shares 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 shares are issued to the participant, held in escrow, and paid to the participant 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.

140

The following table summarizes the activity of deferred and restricted units for the years ended December 31, 2008, 2007 and 2006:


	Units		Weighted Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2005	24,716		$	6.07

Granted	7,686		$	20.83
Vested	(5,435	)	$	4.59

Non-vested shares outstanding at December 31, 2006	26,967		$	10.57

Granted	3,221		$	27.93
Vested	(9,074	)	$	7.43
Forfeited	—			—

Non-vested shares outstanding at December 31, 2007	21,114		$	14.61

Granted	1,920		$	46.87
Vested	(10,802	)	$	9.57
Forfeited	—			—

Non-vested shares outstanding at December 31, 2008	12,232		$	24.13

⁽¹⁾

The intrinsic values for phantom unit awards vested during the years ended at December 31, 2008, 2007 and 2006 were $0.5 million, $0.2 million and $0.1 million, respectively.

⁽²⁾

The aggregate intrinsic values for phantom unit awards outstanding at December 31, 2008, 2007 and 2006 were $0.2 million, $0.8 million, and $0.6 million, respectively.

⁽³⁾

The non-cash compensation expense recognized for phantom unit awards was $0.1 million for each of the years ending December 31, 2008, 2007 and 2006.

For the years ended December 31, 2008, 2007 and 2006, the Company recorded non cash compensation expense of $4.0 million, $1.5 million and $1.4 million, respectively, for the Company’s options and units. At December 31, 2008, the Company had unamortized compensation expense related to its unvested portion of the options and units of $8.7 million that the Company expects to recognize over the next 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 the Company’s common stock from RAI stock in an even exchange. The Company loaned $0.6 million (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. 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, 2008, there were 767,378 shares allocated to participants and 49,861 shares which are unallocated. In December 2008, the remaining loan balance was forgiven by the Company’s Board of Directors. As a result, all unallocated shares will be allocated to participating employees at the end of the ESOP’s fiscal year on September 30, 2009. Participants will receive shares upon vesting, which occurs over a five year period, beginning after the participant’s second year of service. Compensation expense related to the plan amounted to $0.1 million for each of the years ended December 31, 2008, 2007 and 2006. The fair value of unearned ESOP shares was $0.7 million at December 31, 2008.

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. During the years ended December 31, 2008, 2007 and 2006, expense recognized with respect to this commitment was $1.1 million, $1.1 million and $0.4 million, respectively.

141

As of December 31, 2008 and 2007, the actuarial present value of the expected postretirement obligation due under this the SERP was $3.2 million and $2.5 million, respectively, which is included in other long-term liabilities on the Company’s consolidated balance sheets. The discount rates used were 7% and 7% at December 31, 2008 and 2007, respectively.

The following table provides information about amounts recognized in the Company’s consolidated balance sheets at the dates indicated (in thousands):


	December 31,
	2008			2007
Other liabilities	$	(3,209	)	$	(2,475	)
Accumulated other comprehensive loss		255			638
Deferred income tax asset		150			375

Net amount recognized	$	(2,804	)	$	(1,462	)

The estimated amount that will be amortized from accumulated other comprehensive loss into expense for the year ended December 31, 2009 is $0.1 million.

AHD 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. The AHD LTIP is administered by a committee (the “AHD LTIP Committee”), appointed by AHD’s board. Under the AHD LTIP, phantom units and/or unit options may be granted, at the discretion of the AHD LTIP Committee, to all or designated Participants, at the discretion of the AHD LTIP Committee. The AHD 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, 2008, AHD had 1,441,300 phantom units and unit options outstanding under the AHD LTIP, with 657,650 phantom units and unit options available for grant.

AHD Phantom Units.A phantom unit entitles a Participant to receive a common unit of AHD, without payment of an exercise price, upon vesting of the phantom unit or, at the discretion of the AHD LTIP Committee, cash equivalent to the then fair market value of a common limited partner unit of AHD. In tandem with phantom unit grants, the AHD 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. The AHD LTIP Committee will determine the vesting period for phantom units. Through December 31, 2008, phantom units granted under the AHD 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 the AHD 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 the AHD LTIP. Of the phantom units outstanding under the AHD LTIP at December 31, 2008, 55,675 units will vest within the following twelve months. All phantom units outstanding under the AHD LTIP at December 31, 2008 include DERs granted to the Participants by the AHD LTIP Committee. The amount paid with respect to AHD’s LTIP DERs was $0.4 million and $0.3 million for the years ended December 31, 2008 and 2007, respectively. There were no amounts paid with respect to AHD’s LTIP DERs during the year ended December 31, 2006. These amounts were recorded as an adjustment of minority interests on the Company’s consolidated balance sheet.

142

The following table sets forth the AHD LTIP phantom unit activity for the periods indicated:


	Years Ended December 31,
	2008			2007			2006
Outstanding, beginning of year		220,825			220,492			—
Granted⁽¹⁾		6,150			708			220,492
Matured		(675	)		(375	)		—
Forfeited		—			—			—

Outstanding, end of year		226,300			220,825			220,492


Non-cash compensation expense recognized (in thousands)	$	1,427		$	1,420		$	229

⁽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 $26.51, $37.46 and $22.56 for awards granted for the year ended December 31, 2008, 2007 and 2006, respectively.

⁽²⁾

The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2008 is $0.9 million.

⁽³⁾

The intrinsic values for phantom unit awards vested during the years ended at December 31, 2008 and 2007 were $6,000 and $14,000, respectively. There was no vesting of phantom units during the year ended December 31, 2006.

At December 31, 2008, AHD had approximately $2.2 million of unrecognized compensation expense related to unvested phantom units outstanding under AHD’s LTIP based upon the fair value of the awards.

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 the AHD LTIP Committee on the date of grant of the option. The AHD LTIP Committee also shall determine how the exercise price may be paid by the Participant. The AHD 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, 2008, unit options granted under the AHD 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 the AHD LTIP. There are 303,750 unit options outstanding under the AHD LTIP at December 31, 2008 that will vest within the following twelve months. The following table sets forth the AHD LTIP unit option activity for the periods indicated:


	Years Ended December 31,
	2008				2007				2006
	Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price



Outstanding, beginning of period		1,215,000	$	22.56		1,215,000	$	22.56		—	$	—
Granted		—		—		—		—		1,215,000		22.56
Matured		—		—		—		—		—		—
Forfeited		—		—		—		—		—		—

Outstanding, end of period⁽¹⁾⁽²⁾		1,215,000	$	22.56		1,215,000	$	22.56		1,215,000	$	22.56

Options exercisable, end of period⁽³⁾		—		—		—		—		—		—

Weighted average fair value of unit options per unit granted during the year		—		—		—		—		—	$	3.76
Non-cash compensation expense recognized (in thousands)	$	1,237			$	1,237			$	206

(1)	The weighted average remaining contractual lives for outstanding options at December 31, 2008, 2007 and 2006 were 7.9 years, 8.9 years and 9.9 years, respectively.

(2)	The aggregate intrinsic values of options outstanding at December 31, 2008, 2007 and 2006 were approximately $0.0 million, $5.6 million and $1.6 million, respectively.

(3)	There were no options exercised during the years ended December 31, 2008, 2007 and 2006, respectively.

143

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.

At December 31, 2008, AHD had approximately $1.9 million of unrecognized compensation expense related to unvested unit options outstanding under AHD’s LTIP based upon the fair value of the awards.

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 AHD’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, 2008.

A phantom unit entitles a grantee to receive a common unit, without payment of an exercise price, 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, 2008, 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, 2008, 55,228 units will vest within the following twelve months. All units outstanding under the APL LTIP at December 31, 2008 include DERs granted to the participants by the APL LTIP Committee. The amounts paid with respect to APL LTIP DERs were $0.5 million, $0.6 million and $0.4 million for the years ended December 31, 2008, 2007 and 2006, respectively. These amounts were recorded as reductions of minority interest on the Company’s consolidated balance sheet.

The following table sets forth the APL LTIP phantom unit activity for the periods indicated:


	Years Ended December 31,
	2008			2007			2006
Outstanding, beginning of year		129,746			159,067			110,128
Granted⁽¹⁾		54,796			25,095			82,091
Matured⁽²⁾		(56,227	)		(51,166	)		(31,152	)
Forfeited		(1,750	)		(3,250	)		(2,000	)

Outstanding, end of year⁽³⁾		126,565			129,746			159,067


Non-cash compensation expense recognized (in thousands)	$	2,313		$	2,936		$	2,030

⁽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 $44.28, $50.09 and $45.45 for awards granted for the years ended December 31, 2008, 2007 and 2006, respectively.

⁽²⁾

The intrinsic values for phantom unit awards exercised during the years ended at December 31, 2008, 2007 and 2006 were $2.0 million, $2.6 million and $1.3 million, respectively.

⁽³⁾

The aggregate intrinsic values for phantom unit awards outstanding at December 31, 2008, 2007 and 2006 were $0.8 million, $5.6 million and $7.6 million, respectively.

At December 31, 2008, APL had approximately $2.1 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIP based upon the fair value of the awards.

144

APL Incentive Compensation Agreements

APL has incentive compensation agreements which have granted awards to certain key employees retained from previously consummated acquisitions. These individuals were 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 common units were issued during the year ended December 31, 2007. The ultimate number of common units estimated to be issued under the incentive compensation agreements were determined principally by the financial performance of certain APL assets for the year ended December 31, 2008 and the market value of APL’s common units at December 31, 2008. The incentive compensation agreements also dictate 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 a reduction of compensation expense of $34.0 million, expense of $33.4 million, and expense of $4.3 million for the years ended December 31, 2008, 2007 and 2006, respectively, related to the vesting of awards under these incentive compensation agreements. The non-cash compensation expense adjustments for the years ended December 31, 2008 were principally attributable to changes in APL’s common unit market price, which was utilized in the calculation of the non-cash compensation expense for these awards, at December 31, 2008 when compared with the common unit market price at earlier periods and adjustments based upon the achievement of actual financial performance targets through December 31, 2008. APL follows SFAS No. 123(R) and recognized compensation expense related to these awards based upon the fair value method. During the first quarter of 2009, APL expects to issue 302,371 common units to the certain key employees covered under the incentive compensation agreements to fulfill its obligations under the terms of the agreements. No additional common units will be issued with regard to these agreements.

Atlas Energy Resources, LLC Long-Term 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 ATN’s compensation committee, which may grant awards of restricted units, phantom units or unit options for an aggregate of 3,742,000 common units. Awards granted vest 25% after three years and 100% upon the four year anniversary of grant, except for awards granted 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 unit entitles a grantee to receive a common unit of ATN upon vesting of the unit or, at the discretion of the ATN’s compensation committee, cash equivalent to the then fair market value of a common unit of ATN. In tandem with phantom unit grants, the ATN’s compensation committee may grant a distribution equivalent right (“DER”), which is the right to receive cash per restricted 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.

ATN Restricted Stock and Phantom Units. Under the ATN LTIP, 156,793, 590,950 and 47,619 units of restricted stock and phantom units were awarded in 2008, 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.

The following table summarizes the activity of restricted and phantom stock units for the years ended December 2008, 2007 and 2006:


	Units		Weighted Average Grant Date Fair Value



Non-vested shares outstanding at December 31, 2005	—		$	—
Granted	47,619		$	21.00

Non-vested shares 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 shares outstanding at December 31, 2007	624,665		$	24.42
Granted	156,793		$	21.43
Vested	(12,279	)	$	21.06
Forfeited	(350	)	$	26.47

Non-vested shares outstanding at December 31, 2008	768,829		$	23.86

145

Stock Options. For the years ended December 31, 2008, 2007 and 2006, 14,000, 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,
	2008			2007			2006
Expected life (years)		6.25			6.25			6.25
Expected volatility		27-34	%		25	%		25	%
Risk-free interest rate		2.8-4.0	%		4.7	%		4.4	%
Expected dividend yield		6.2-7.0	%		5.1-8.0	%		8.0	%
Weighted average fair value of stock options granted	$	5.69		$	2.96		$	2.14

The following table sets forth option activity for ATN for the periods indicated:


	Shares		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
Granted	14,000		$	35.36
Exercised	—			—
Forfeited or expired	(6,150	)	$	25.97

Outstanding at December 31, 2008	1,902,902		$	24.17	7.9	$	—

Options exercisable at December 31, 2008	186,876		$	21.00	7.25

Available for grant at December 31, 2008	1,046,086

The following tables summarize information about stock options outstanding and exercisable at December 31, 2008:


	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number of Shares Outstanding	Weighted Average Remaining Contractual Life in Years	Weighted Average Exercise Price		Number of Shares Exercisable	Weighted Average Exercise Price
$21.00 - 23.06	1,654,802	7.9	$	22.59	186,876	$	21.00
$30.24 - 35.00	240,600	8.5	$	34.53	—		—
$39.00 & above	7,500	9.0	$	39.79	—		—

	1,902,902	7.9	$	24.17	186,876	$	21.00

ATN recognized $5.5 million, $4.7 million and $0.3 million in compensation expense related to restricted stock units, phantom units and unit options for the years ended December 31, 2008, 2007 and 2006, respectively. ATN paid $1.4 million and $0.8 million with respect to its LTIP DERs for the years ended December 31, 2008 and 2007, respectively. These amounts were recorded as reductions of members’ equity on the Company’s Consolidated Balance Sheet. At December 31, 2008, the Company had approximately $13.7 million of unrecognized compensation expense related to the unvested portion of the restricted stock units, phantom units and options.

146

NOTE 17 — 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,
	2008			2007			2006
Gas and oil production
Revenues(a)	$	311,850		$	206,382		$	88,449
Costs and expenses		(48,194	)		(24,184	)		(8,499	)

Segment income	$	263,656		$	182,198		$	79,950


Well construction and completion
Revenues	$	415,036		$	321,471		$	198,567
Costs and expenses		(359,609	)		(279,540	)		(172,666	)

Segment income	$	55,427		$	41,931		$	25,901


Atlas Pipeline
Revenues (b)	$	1,362,500		$	629,750		$	428,324
Revenues – affiliates		43,726			33,571			26,272
Costs and expenses		(1,863,369	)		(635,675	)		(360,774	)

Segment income (loss)	$	(457,143	)	$	27,646		$	93,822


Other(c)
Revenues	$	16,788		$	16,473		$	7,694
Costs and expenses		(11,187	)		(9,374	)		(7,608	)

Segment income	$	5,601		$	7,099		$	86


Reconciliation of segment income to net income (loss) before income tax provision (benefit)
Segment income (loss)
Gas and oil production	$	263,656		$	182,198		$	79,950
Well construction and completion		55,427			41,931			25,901
Atlas Pipeline		(457,143	)		27,646			93,822
Other		5,601			7,099			86

Total segment income (loss)		(132,459	)		258,874			199,759
General and administrative expenses		(59,091	)		(111,636	)		(46,517	)
Net expense reimbursement—affiliate		(951	)		(930	)		(1,237	)
Depreciation, depletion and amortization		(185,552	)		(107,917	)		(45,643	)
Interest expense		(142,917	)		(92,611	)		(27,313	)
Gain on early extinguishment of debt		19,867			—			—
Minority interest income (expense)		479,431			93,476			(18,283	)
Other income – net		11,368			10,722			8,564

Net income (loss) before income tax provision (benefit)	$	(10,304	)	$	49,978		$	69,330


Capital expenditures
Gas and oil production	$	336,825		$	187,483		$	74,075
Well construction and completion		—			—			—
Atlas Pipeline		325,934			139,647			83,716
Corporate and other		4,150			9,252			1,560

Total capital expenditures	$	666,909		$	336,382		$	159,351

147


	December 31,
	2008		2007
Balance sheet
Goodwill:
Gas and oil production	$	21,527	$	21,527
Well construction and completion		13,639		13,639
Atlas Pipeline		—		709,283

	$	35,166	$	744,449

Total assets:
Gas and oil production	$	2,189,931	$	1,821,631
Well construction and completion		16,399		11,138
Atlas Pipeline		2,413,196		2,877,614
Corporate and other		205,723		193,984

	$	4,825,249	$	4,904,367

(a)

Revenues for the year ended December 31, 2007 include non-cash gains on mark-to-market derivatives of $26.3 million.

(b)

Includes losses on mark-to-market derivatives of $63.5 million and $179.6 million for years ended December 31, 2008 and 2007, respectively, and a gain on mark-to-market derivatives of $5.7 million for the year ended December 31, 2006.

(c)

Includes revenues and expenses from well services, transportation and administration and oversight that do not meet the quantitative threshold for reporting segment information.

Operating profit (loss) represents total revenues less costs and expenses attributable thereto. Amounts for interest, provision for possible losses and depreciation, depletion and amortization and general corporate expenses are shown in the aggregate because these measures are not significant drivers in deciding how to allocate resources and assessing performance of each defined segment.

For the year ended December 31, 2008, the Company’s APL segment had two customers that individually accounted for approximately 50% and 13% of the segment’s consolidated revenues. For the year ended December 31, 2007, the Company’s APL segment had one customer that individually accounted for approximately 50% of the segment’s consolidated revenues. For the year ended December 31, 2006, the Company’s APL segment had three customers that individually accounted for approximately 36%, 18% and 10% of the segment’s consolidated revenues. Additionally, the Company’s APL segment had one customer that individually accounted for 37% of its accounts receivable at December 31, 2008, and two customers that individually accounted for 26% and 11% of its accounts receivable at December 31, 2007. For the year ended December 31, 2008, the Company’s gas and oil production segment had one customer that accounted for approximately 12% of the segment’s consolidated revenues. No other single customer exceeded ten percent of segment revenues or accounts receivable for the years shown.

NOTE 18 – SUBSEQUENT EVENTS

Cash Dividend.On January 28, 2009, the Company announced that its Board of Directors had declared a cash dividend of $0.05 per share of common stock, payable on February 19, 2009, to holders of record on February 9, 2009.

ATN.On January 28, 2009, ATN announced that its Board of Directors had declared a cash distribution of $0.61 per common limited partner unit, payable on February 13, 2009 to holders of record on February 9, 2009.

APL.On January 26, 2009, APL announced that its Board of Directors had declared a cash distribution of $0.38 per common limited partner unit, payable on February 13, 2009 to holders of record on February 9, 2009.

On January 27, 2009, APL and Sunlight Capital, the holder of its outstanding Class A Preferred Units, agreed to amend certain terms of its existing preferred unit agreement. The amendment (a) increased the dividend yield from 6.5% to 12% per annum, effective January 1, 2009, (b) changed the conversion commencement date from May 8, 2008 to April 1, 2009, (c) changed the conversion price from $43.00 to $22.00, enabling the APL Class A Preferred Units to be converted at the lesser of $22.00 or 95% of the market value of the common units, and (d) changed the call redemption price from $53.22 to $27.25. Simultaneously with the execution of the amendment, APL issued Sunlight Capital $15.0 million of its 8.125% senior unsecured notes due 2015 to redeem 10,000 APL Class A Preferred Units. APL also agreed that it will redeem an additional 10,000 APL Class A Preferred Units for cash at the liquidation value on April 1, 2009. If Sunlight does not exercise its conversion right on or before June 2, 2009, APL will redeem the then-remaining 10,000 APL Class A Preferred Units for cash or one-half for cash and one-half for APL’s common limited partner units on July 1, 2009.

AHD.On January 26, 2009, APL announced that its Board of Directors had declared a cash distribution of $0.06 per common limited partner unit, payable on February 19, 2009 to holders of record on February 9, 2009.

148

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 December 31,
	2008			2007			2006
Revenues⁽¹⁾	$	311,850		$	206,382		$	88,449
Production costs		(48,194	)		(24,184	)		(8,499	)
Exploration expenses⁽²⁾		(6,029	)		(4,065	)		(3,016	)
Depreciation, depletion and amortization		(91,991	)		(54,383	)		(20,600	)
Income taxes		(64,598	)		(36,259	)		(22,196	)

	$	101,038		$	87,491		$	34,138

(1)	Includes unrealized gains from mark-to-market derivatives of $26.3 million during the year ended December 31, 2007.

(2)	Represents ATN’s land and leasing activities

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):


	Years Ended December 31,
	2008			2007			2006
Natural gas and oil properties:
Proved properties	$	2,087,119		$	1,795,871		$	349,882
Unproved properties		43,749			16,380			1,002
Support equipment		9,527			6,936			5,541

	$	2,140,395		$	1,819,187		$	356,425
Accumulated depreciation, depletion and amortization⁽¹⁾		(221,356	)		(136,603	)		(83,182	)

	$	1,919,039		$	1,682,584		$	273,243

(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 December 31,
	2008		2007		2006
Property acquisition costs:
Proved properties	$	63,146	$	1,243,877	$	1,322
Unproved properties		27,064		50,100		—
Exploration Costs⁽¹⁾		6,029		4,065		6,847
Development Costs		229,687		168,253		76,687

	$	325,926	$	1,466,295	$	84,856

(1)	Represents ATN’s land and leasing activities.

The development costs above for the periods above were substantially all incurred for the development of proved undeveloped properties.

Oil and Gas Reserve Information.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. All

149

reserves are located in the Appalachian Basin, in Michigan’s Lower Peninsula and in southwestern Indiana. 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.

The Company’s reconciliation of changes in proved reserve quantities is as follows (unaudited):


	Gas (Mcf)		Oil (Bbls)
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⁽¹⁾	126,613,549		23,358
Sales of reserves in-place	(62,699	)	(625	)
Purchase of reserves in–place⁽²⁾	622,851,730		48,634
Transfers to limited partnerships	(11,507,307	)	—
Revisions	(714,501	)	(2,517	)
Production	(20,963,436	)	(153,465	)

150


	Gas (Mcf)		Oil (Bbls)
Balance December 31, 2007	884,758,910		1,983,031

Extensions, discoveries and other additions⁽¹⁾	210,824,798		111,972
Sales of reserves in-place	(34,924	)	(161	)
Purchase of reserves in–place	3,461,987		794
Transfers to limited partnerships	(6,026,785	)	—
Revisions⁽³⁾	(68,276,626	)	(203,166	)
Production	(33,901,975	)	(158,529	)

Balance December 31, 2008	990,805,385		1,733,941


Proved developed reserves at:
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
December 31, 2008	586,655,301		1,685,771

(1)	Includes a significant increase in proved undeveloped reserves both due to the addition of proved undeveloped reserves for Marcellus wells.

(2)	Represents the reserves purchased from the acquisition of AGO on June 29, 2007.

(3)	Represents a decrease in the year ended December 31, 2008 price of natural gas and oil compared to the price of natural gas and oil at December 31, 2007

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 (in thousands).


	Years Ended December 31,
	2008			2007			2006
Future cash inflows	$	6,333,935		$	6,408,367		$	1,262,161
Future production costs		(2,297,091	)		(1,804,199	)		(334,062	)
Future development costs		(618,604	)		(388,111	)		(149,610	)
Future income tax expense		(756,278	)		(996,877	)		(225,082	)

Future net cash flows		2,661,962			3,219,180			553,407

Less 10% annual discount for estimated timing of cash flows		(1,737,221	)		(2,074,190	)		(347,887	)

Standardized measure of discounted future net cash flows	$	924,741		$	1,144,990		$	205,520

The future cash flows estimated to be spent to develop proved undeveloped properties in the years ended December 31, 2009, 2010, 2011 and 2012 are $200.7 million, $192.5 million, $192.0 million and $33.5 million, respectively.

151

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 December 31,
	2008			2007			2006
Balance, beginning of year	$	1,144,990		$	205,520		$	429,272
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs		(263,655	)		(155,992	)		(79,950	)
Net changes in prices and production costs		(316,970	)		45,261			(273,631	)
Revisions of previous quantity estimates		(46,767	)		(1,208	)		(30,058	)
Development costs incurred		48,092			98,424			3,426
Changes in future development costs		(35,662	)		(14,128	)		(8,505	)
Transfers to limited partnerships		(615	)		(13,998	)		(8,449	)
Extensions, discoveries, and improved recovery less related costs		41,020			170,349			44,820
Purchases of reserves in-place		5,170			957,137			660
Sales of reserves in-place, net of tax effect		(97	)		(105	)		(572	)
Accretion of discount		147,781			74,685			59,714
Net changes in future income taxes		128,987			(261,459	)		93,137
Estimated settlement of asset retirement obligations		(5,778	)		(4,523	)		(8,226	)
Estimated proceeds on disposals of well equipment		6,329			5,168			10,007
Changes in production rates (timing) and other		71,916			39,859			(26,125	)

Balance, end of year	$	924,741		$	1,144,990		$	205,520

NOTE 20 — QUARTERLY RESULTS (Unaudited)


	Fourth Quarter			Third Quarter		Second Quarter⁽¹⁾			First Quarter
	(in thousands, except per unit data)
Year ended December 31, 2008:
Revenues	$	532,438		$	780,655	$	350,083		$	486,724
Net income (loss) from continuing operations before income tax provision (benefit)		(46,194	)		38,027		(12,400	)		10,263
Net income (loss)		(28,912	)		24,103		(7,771	)		6,422
Net income (loss) per common share—basic	$	(0.74	)	$	0.60	$	(0.19	)	$	0.16
Net income (loss) per common share—diluted	$	(0.74	)	$	0.58	$	(0.19	)	$	0.15

⁽¹⁾	For the second and fourth quarter of the year ended December 31, 2008, approximately 2,013 and 2,930, respectively, stock options were excluded from the computation of diluted net income per common share because the inclusion of such units would have been anti-dilutive.


	Fourth Quarter⁽²⁾			Third Quarter		Second Quarter		First Quarter
	(in thousands, except per unit data)
Year ended December 31, 2007:
Revenues	$	366,340		$	411,526	$	214,866	$	214,915
Net income (loss) from continuing operations before income tax provision (benefit)		(4,488	)		10,199		28,000		16,267
Net income (loss)		(1,881	)		7,103		19,866		10,248
Net income (loss) per common share—basic	$	(0.04	)	$	0.18	$	0.49	$	0.24
Net income (loss) per common share—diluted	$	(0.04	)	$	0.17	$	0.48	$	0.23

⁽²⁾	For the fourth quarter of the year ended December 31, 2007, approximately 1,798 stock options were excluded from the computation of diluted net income per common share because the inclusion of such units would have been anti-dilutive.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

152

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 and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2008, 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.

Based on our evaluation under the COSO framework, management concluded that our internal control over financial reporting was effective at the reasonable assurance level as of December 31, 2008. Grant Thornton LLP, an independent registered public accounting firm, has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008, which is included herein.

There have been no changes in our internal control over financial reporting during the fourth quarter of 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

153

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

Atlas America, Inc.

We have audited Atlas America, Inc.’s (a Delaware corporation) internal control over financial reporting as of December 31, 2008, based on criteria established inInternal 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 accompanyingManagement’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on 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.

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, 2008, based on criteria established inInternal 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 its subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008 and our report dated March 2, 2009 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

March 2, 2009

154

ITEM 9B.

OTHER INFORMATION

None.

PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this item will be set forth in our definitive proxy statement with respect to our 2009 annual meeting of stockholders.

ITEM 11.

EXECUTIVE COMPENSATION

The information required by this item will be set forth in our definitive proxy statement with respect to our 2009 annual meeting of stockholders.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information required by this item will be set forth in our definitive proxy statement with respect to our 2009 annual meeting of stockholders.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this item will be set forth in our definitive proxy statement with respect to our 2009 annual meeting of stockholders.

ITEM 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this item will be set forth in our definitive proxy statement with respect to our 2009 annual meeting of stockholders.

155

PART IV

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)

The following documents are filed as part of this report:

(1)

Financial Statements

The financial statements required by this Item 15(a)(1) are set forth in Item 8.

(2)

Financial Statement Schedules

No schedules are required to be presented.

(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(a)		Master Natural Gas Gathering Agreement, dated February 2, 2000, among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource Energy, Inc. and Viking Resources Corporation⁽²⁾

10.1(b)		Natural Gas Gathering Agreement among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas Resources, Inc., Atlas Energy Group, Inc., Atlas Noble Corp., Resource Energy, Inc. and Viking Resources Corporation dated January 1, 2002⁽²⁾

10.1(c)		Amendment to Master Natural Gas Gathering Agreement and Natural Gas Gathering Agreement, dated October 25, 2005, among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource Energy, Inc., Viking Resources Corporation, Atlas Noble Corp. and Atlas Resources, Inc.⁽³⁾

10.1(d)		Amendment and Joinder to Gas Gathering Agreements, dated as of December 18, 2006, among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource Energy, LLC, Viking Resources, LLC, Atlas Noble, LLC, Atlas Resources, LLC, Atlas America, LLC, Atlas Energy Resources, LLC and Atlas Energy Operating Company, LLC⁽⁴⁾

10.2(a)		Omnibus Agreement, dated February 2, 2000, among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource Energy, Inc. and Viking Resources Corporation⁽²⁾

10.2(b)		Amendment and Joinder to Omnibus Agreement, dated as of December 18, 2006 among Atlas Pipeline, Atlas America, Resource Energy, LLC, Viking Resources, LLC, Atlas Energy Resources, LLC and Atlas Energy Operating Company, LLC⁽⁴⁾

10.3		Tax Matters Agreement between Atlas America, Inc. and Resource America, Inc. dated May 14, 2004⁽⁵⁾

10.4		Transition Services Agreement between Atlas America, Inc. and Resource America, Inc. dated May 14, 2004⁽⁵⁾

156


10.5		Employment Agreement for Edward E. Cohen dated May 14, 2004⁽⁵⁾

10.5(a)		Amendment to Employment Agreement dated as of December 31, 2008

10.6		Agreement for Services among Atlas America, Inc. and Richard Weber, dated April 5, 2006⁽⁶⁾

10.6(a)		Amendment No. 1 to Agreement for Services dated as of April 26, 2007⁽⁷⁾

10.6(b)		Amendment No. 2 to Agreement for Services dated as of December 18, 2008

10.7		Contribution, Conveyance and Assumption Agreement, dated as of December 18, 2006, among Atlas America, Inc., Atlas Energy Resources, LLC and Atlas Energy Operating Company, LLC⁽⁴⁾

10.8		Omnibus Agreement, dated as of December 18, 2006, between Atlas America, Inc. and Atlas Energy Resources, LLC⁽⁴⁾

10.9		Management Agreement, dated as of December 18, 2006, among Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC and Atlas Energy Management, Inc.⁽⁴⁾

10.10		Stock Incentive Plan

10.11		Atlas America Employee Stock Ownership Plan⁽⁸⁾

10.12		Atlas America, Inc. Investment Savings Plan⁽⁸⁾

10.13		Form of Stock Award Agreement⁽⁹⁾

10.14		Amended and Restated Annual Incentive Plan for Senior Executives⁽¹⁰⁾

10.15		Employment Agreement between Atlas America, Inc. and Jonathan Z. Cohen dated as of January 30, 2009

14.1		Insider Trading Policy⁽¹¹⁾

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 October 31, 2005

(4)	Previously filed as an exhibit to our Form 10-K for the year ended December 31, 2006

(5)	Previously filed as an exhibit to our Form 10-Q for the quarter ended June 30, 2004

(6)	Previously filed as an exhibit to our Form 10-Q for the quarter ended June 30, 2006

(7)	Previously filed as an exhibit to our Form 8-K filed May 1, 2007

157

(8)	Previously filed as an exhibit to our Form 10-K for the year ended September 30, 2005

(9)	Previously filed as an exhibit to our Form 10-Q for the quarter ended December 31, 2005

(10)	Previously filed as an exhibit to our definitive proxy statement filed May 8, 2008

(11)	Previously filed as an exhibit to our Form 8-K filed August 31, 2007

158

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.

Date: March 2, 2009	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 indicated as of March 2, 2009.


/s/ EDWARD E. COHEN		Chairman, Chief Executive Officer and President
Edward E. Cohen

/s/ JONATHAN Z. COHEN		Vice Chairman
Jonathan Z. Cohen

/s/ MATTHEW A. JONES		Chief Financial Officer
Matthew A. Jones

/s/ SEAN P. MCGRATH		Chief Accounting Officer
Sean P. McGrath

/s/ CARLTON M. ARRENDELL		Director
Carlton M. Arrendell

/s/ WILLIAM R. BAGNELL		Director
William R. Bagnell

/s/ DONALD W. DELSON		Director
Donald W. Delson

/s/ NICHOLAS A. DINUBILE		Director
Nicholas A. DiNubile

/s/ DENNIS A. HOLTZ		Director
Dennis A. Holtz

/s/ HARMON S. SPOLAN		Director
Harmon S. Spolan

159

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. sophomore Avg

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company