Atlas Energy Resources DEFM14A Proxy related to merger

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

SCHEDULE 14A

Proxy Statement Pursuant to Section 14(a) of the

Securities Exchange Act of 1934

Filed by the Registrantx                            Filed by a Party other than the Registrant¨

Check the appropriate box:

¨ Preliminary Proxy Statement

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x Definitive Proxy Statement

¨ Definitive Additional Materials

¨ Soliciting Material Pursuant to §240.14a-12

ATLAS ENERGY RESOURCES, LLC

(Name of Registrant as Specified In Its Charter)

N/A

(Name of Person(s) Filing Proxy Statement if other than the Registrant)

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¨ Fee computed on table below per Exchange Act Rules 14a-6(i)(1) and 0-11.

(1) Title of each class of securities to which transaction applies:

(2) Aggregate number of securities to which transaction applies:

(3) Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0-11 (Set forth the amount on which the filing fee is calculated and state how it was determined):

(4) Proposed maximum aggregate value of transaction:

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¨ Check box if any part of the fee is offset as provided by Exchange Act Rule 0-11(a)(2) and identify the filing for which the offsetting fee was paid previously. Identify the previous filing by registration statement number, or the Form or Schedule and the date of its filing.

(1) Amount previously paid:

(2) Form, Schedule or Registration Statement No.:

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(4) Date Filed:

                                             

MERGER PROPOSED — YOUR VOTE IS VERY IMPORTANT

Atlas America, Inc. (which we refer to as “Atlas America”) and Atlas Energy Resources, LLC (which we refer to as “Atlas Energy”) have agreed to a strategic combination of the two companies under the terms of an Agreement and Plan of Merger, dated as of April 27, 2009 (which we refer to as the “merger agreement”), by and among Atlas Energy, Atlas America, Atlas Energy Management, Inc. (which we refer to as “Atlas Energy Management”) and ATLS Merger Sub, LLC (which we refer to as “Merger Sub”). The merger agreement is attached hereto as Annex A. Upon the terms of the merger agreement, Merger Sub will merge with and into Atlas Energy with Atlas Energy surviving as a wholly owned subsidiary of Atlas America.

If the merger is completed, each outstanding Class B common unit of Atlas Energy (which we refer to as “Atlas Energy common units”), other than Atlas Energy common units held by Atlas America and its subsidiaries, will be converted into the right to receive 1.16 shares of common stock, par value $0.01 per share, of Atlas America. This exchange ratio is fixed and will not be adjusted to reflect unit or stock price changes prior to closing of the merger. Each Class A unit and management incentive interest of Atlas Energy, all of which are held by Atlas Energy Management, will remain outstanding. Options and other equity-based awards of Atlas Energy will convert into equivalent awards of Atlas America at the exchange ratio. Atlas America stockholders will continue to own their existing shares of Atlas America common stock. Atlas America common stock is traded on NASDAQ under the symbol “ATLS.”

Based on the estimated number of Atlas Energy common units (including Atlas Energy restricted units) outstanding on the record date for the special meetings, Atlas America expects to issue approximately 38,776,774 shares of Atlas America common stock to Atlas Energy unitholders in the merger. Upon completion of the merger, we estimate that current Atlas America stockholders will own approximately 50.4% of the outstanding Atlas America common stock, and former Atlas Energy unitholders (other than Atlas America and Atlas Energy Management, which will not receive Atlas America common stock in the merger) will own approximately 49.6% of the outstanding Atlas America common stock. In addition, based on the estimated number of Atlas Energy options and other equity-based awards outstanding on the record date for the special meetings, Atlas America expects that 3,023,279 additional shares of Atlas America common stock will be reserved for issuance in connection with Atlas America options and other equity-based awards issued in exchange for such Atlas Energy options and equity-based awards.

At the special meeting of Atlas America stockholders, Atlas America stockholders will be asked to vote on and approve the issuance of Atlas America common stock to Atlas Energy unitholders in the merger and to vote on and approve the Atlas America 2009 Stock Incentive Plan.The Atlas America board of directors recommends that its stockholders vote “FOR” the proposals before them.

At the special meeting of Atlas Energy unitholders, Atlas Energy unitholders will be asked to vote on and adopt the merger agreement and approve the transactions contemplated thereby, including the merger.The Atlas Energy board of directors, upon the unanimous recommendation of a special committee of the Atlas Energy board of directors composed solely of independent directors, recommends that its unitholders vote “FOR” the proposal before them.

Your vote is very important. Whether or not you plan to attend your company’s special meeting, please take the time to vote by completing and mailing the enclosed proxy card or voting instruction card or, if the option is available to you, by granting your proxy electronically over the Internet or by telephone.

This joint proxy statement/prospectus contains important information about Atlas America, Atlas Energy, the merger agreement, the proposed merger and the special meetings of Atlas America stockholders and Atlas Energy unitholders.We encourage you to read this entire joint proxy statement/prospectus carefully, including the section entitled “Risk Factors” beginning on page 21.

Sincerely,

Edward E. Cohen Chairman, President and Chief Executive Officer Atlas America, Inc. Richard D. Weber President and Chief Operating Officer Atlas Energy Resources, LLC

Neither the U.S. Securities and Exchange Commission nor any state securities regulator has approved or disapproved of the transactions described in this joint proxy statement/prospectus or the securities to be issued pursuant to the merger or determined if the information contained in this joint proxy statement/prospectus is accurate or adequate. Any representation to the contrary is a criminal offense.

This joint proxy statement/prospectus is dated August 21, 2009, and is being mailed to Atlas America stockholders and Atlas Energy unitholders on or about August 24, 2009.

ATLAS AMERICA, INC.

Westpointe Corporate Center One

1550 Coraopolis Heights Road, 2nd Floor

Moon Township, PA 15108

NOTICE OF SPECIAL MEETING OF STOCKHOLDERS

TO BE HELD ON SEPTEMBER 25, 2009

To the Stockholders of Atlas America, Inc.:

We are pleased to invite you to attend the special meeting of stockholders of Atlas America, Inc. (which we refer to as “Atlas America”) to be held at The Ethical Society Building, 1906 South Rittenhouse Square, Philadelphia, Pennsylvania 19103, on September 25, 2009, at 11:00 am, local time, for the following purposes:

1. To consider and vote on a proposal to approve the issuance of shares of common stock, par value $0.01 per share, of Atlas America, in connection with the merger contemplated by the Agreement and Plan of Merger, dated as of April 27, 2009, as it may be amended from time to time, by and among Atlas Energy Resources, LLC, Atlas America, Atlas Energy Management, Inc. and ATLS Merger Sub, LLC;

2. To consider and vote on a proposal to approve the Atlas America 2009 Stock Incentive Plan; and

3. To vote to adjourn or postpone the Atlas America special meeting, if necessary, to solicit additional proxies if there are not sufficient votes in favor of the foregoing.

Please refer to the attached joint proxy statement/prospectus for further information with respect to the business to be transacted at the Atlas America special meeting.

The issuance of Atlas America common stock to unitholders of Atlas Energy Resources, LLC in the merger requires the affirmative vote of holders of a majority of the votes cast on the proposal at the Atlas America special meeting. Approval of the stock issuance is a condition to completion of the merger, and the merger cannot be completed unless the proposal is approved. Approval of the other matters at the Atlas America special meeting is not a condition to completion of the merger.

The Atlas America board of directors has determined that the merger agreement and the transactions contemplated thereby, including the stock issuance, are advisable, fair to and in the best interests of Atlas America and its stockholders.

Therefore, the Atlas America board of directors unanimously recommends that you vote “FOR” the proposal to issue shares of Atlas America common stock in the merger, “FOR” the proposal to approve the Atlas America 2009 Stock Incentive Plan and “FOR” the proposal to adjourn or postpone the special meeting, if necessary, to solicit additional proxies if there are not sufficient votes in favor of the foregoing.

Only Atlas America stockholders of record at the close of business on August 18, 2009 will be entitled to notice of and to vote at the special meeting and any adjournments or postponements thereof. To vote your shares, please complete and return the enclosed proxy card or voting instruction card, or, if available, submit your voting instruction by telephone or through the Internet. You may also cast your vote in person at the special meeting. Please vote promptly whether or not you expect to attend the special meeting.

Your vote is very important. If you do not return or submit your proxy or vote in person at the Atlas America special meeting as provided in the joint proxy statement/prospectus, the effect will be the same as a vote against the proposal to approve the stock issuance.Please vote using one of the methods above to ensure that your vote will be counted. Your proxy may be revoked at any time before the vote at the Atlas America special meeting by following the procedures outlined in the accompanying joint proxy statement/prospectus. If you plan to attend the Atlas America special meeting, you will need to bring a form of personal identification with you. If your shares of Atlas America common stock are held of record by a bank, broker or other nominee, you also need to bring an account statement indicating that you beneficially own the shares as of the record date, or a letter from the record holder indicating that you beneficially own the shares as of the record date, and if you wish to vote at the Atlas America special meeting you must first obtain from the record holder a proxy issued in your name (such statement/letter and proxy are required in addition to your personal identification).

By Order of the Board of Directors,

LISA WASHINGTON

Secretary

August 21, 2009

ATLAS ENERGY RESOURCES, LLC

Westpointe Corporate Center One

1550 Coraopolis Heights Road, 2nd Floor

Moon Township, PA 15108

NOTICE OF SPECIAL MEETING OF UNITHOLDERS

TO BE HELD ON SEPTEMBER 25, 2009

To the Unitholders of Atlas Energy Resources, LLC:

We are pleased to invite you to attend a special meeting of unitholders of Atlas Energy Resources, LLC (which we refer to as “Atlas Energy”) to be held at the Sofitel Philadelphia, 120 South 17^th Street, Philadelphia, Pennsylvania 19103 on September 25, 2009, at 9:00 am, local time, unless adjourned or postponed to a later time, to consider and vote upon a proposal to adopt an Agreement and Plan of Merger, dated as of April 27, 2009, as it may be amended from time to time, by and among Atlas Energy, Atlas America, Inc. (which we refer to as “Atlas America”), Atlas Energy Management, Inc. and ATLS Merger Sub, LLC, and approve the transactions contemplated thereby, including the merger. The merger agreement contemplates that ATLS Merger Sub, LLC will merge with and into Atlas Energy, and Atlas Energy will survive as a wholly owned subsidiary of Atlas America.

The chairman of the Atlas Energy board of directors, or other chairman of the Atlas Energy special meeting, has full authority to adjourn the Atlas Energy special meeting, whether for lack of a quorum or any other reason, and may elect to do so to solicit additional proxies if there are not sufficient votes in favor of the foregoing.

Please refer to the attached joint proxy statement/prospectus for further information with respect to the business to be transacted at the Atlas Energy special meeting.

Consummation of the merger requires, among other approvals and consents, the affirmative vote of the holders of a majority of the outstanding Atlas Energy common units and the holders of a majority of the Atlas Energy Class A units.

Each of (1) a special committee of the Atlas Energy board of directors consisting solely of independent directors, and (2) the Atlas Energy board of directors, with all of the interested and potentially interested directors abstaining or recusing themselves, and based upon the unanimous recommendation of the Atlas Energy special committee, determined that the merger agreement and the transactions contemplated thereby, including the merger, are advisable, fair and reasonable to, and in the best interests of, Atlas Energy and the Atlas Energy unitholders that are not affiliated with Atlas America.Therefore, upon the unanimous recommendation of the Atlas Energy special committee, the Atlas Energy board of directors recommends that Atlas Energy unitholders vote “FOR” the proposal to adopt the merger agreement and approve the transactions contemplated thereby, including the merger.

Only Atlas Energy Class A and common unitholders of record at the close of business on August 18, 2009 will be entitled to notice of and to vote at the special meeting and any adjournments or postponements thereof. To vote your shares, please complete and return the enclosed proxy card or voting instruction card, or, if available, submit your voting instruction by telephone or through the Internet. You may also cast your vote in person at the special meeting. Please vote promptly whether or not you expect to attend the special meeting.

Your vote is very important. If you do not return or submit your proxy or vote in person at the Atlas Energy special meeting as provided in the joint proxy statement/prospectus, the effect will be the same as a vote against the proposal to adopt the merger agreement.Please vote using one of the methods above to ensure that your vote will be counted. Your proxy may be revoked at any time before the vote at the Atlas Energy special meeting by following the procedures outlined in the accompanying joint proxy statement/prospectus. If you plan to attend the Atlas Energy special meeting, you will need to bring a form of personal identification with you. If your Atlas Energy units are held of record by a bank, broker or other nominee, you also need to bring an account statement indicating that you beneficially own the units as of the record date, or a letter from the record holder indicating that you beneficially own the units as of the record date, and if you wish to vote at the Atlas Energy special meeting you must first obtain from the record holder a proxy issued in your name (such statement/letter and proxy are required in addition to your personal identification).

By Order of the Board of Directors,

LISA WASHINGTON

Secretary

August 21, 2009

ADDITIONAL INFORMATION

This joint proxy statement/prospectus incorporates important business and financial information about Atlas Energy from other documents that are not included in or delivered with this joint proxy statement/prospectus. This information is available to you without charge upon your request. You can obtain the documents incorporated by reference into this joint proxy statement/prospectus by requesting them in writing or by telephone at the following addresses and telephone numbers:

Atlas Energy Resources, LLC

Attn: Investor Relations

Westpointe Corporate Center One

1550 Coraopolis Heights Road

Moon Township, PA 15108

(412) 262-2830

or if you are an Atlas America stockholder:	or if you are an Atlas Energy unitholder:
105 Madison Avenue New York, New York 10016 proxy@mackenziepartners.com Call Collect: (212) 929-5500 or Toll-Free (800) 322-2885	199 Water Street, 26th Floor New York, NY 10038 atninfo@georgeson.com Call Collect: (212) 806-6859 or Toll-Free (800) 255-4617

Investors may also consult Atlas America’s or Atlas Energy’s websites for more information. Atlas America’s website iswww.atlasamerica.com. Atlas Energy’s website iswww.atlasenergyresources.com. Information included on these websites is not incorporated by reference into this joint proxy statement/prospectus.

If you would like to request any documents, please do so by September 18, 2009 in order to receive them before the special meetings.

For additional information on documents incorporated by reference in this joint proxy statement/prospectus, please see “Where You Can Find More Information.”

TABLE OF CONTENTS

QUESTIONS AND ANSWERS ABOUT THE SPECIAL MEETINGS	v
SUMMARY	1
The Companies	1
The Merger	2
The Special Meetings	8
Risk Factors	10
Comparison of Rights of Atlas America Stockholders and Atlas Energy Unitholders	10
Selected Historical Financial Data of Atlas America	12
Selected Historical Financial Data of Atlas Energy	15
Selected Unaudited Pro Forma Condensed Consolidated Financial Information	18
Comparative Historical and Pro Forma Per Share/Per Unit Information	19
Comparative Per Share/Per Unit Market Information	20
RISK FACTORS	21
Risks Relating to the Merger	21
Risks Relating to Atlas America	27
Risks Relating to the Business of Atlas Energy	29
Risks Relating to the Businesses of Atlas Pipeline Holdings and Atlas Pipeline	41
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS	58
RECENT DEVELOPMENTS	60
THE ATLAS AMERICA SPECIAL MEETING	61
General	61
Date, Time and Place	61
Purpose of the Atlas America Special Meeting	61
Recommendation of the Atlas America Board of Directors	61
Atlas America Record Date; Outstanding Shares; Shares Entitled to Vote	61
Quorum	62
Vote Required for Approval	62
Voting; Proxies	62
Participants in Atlas America’s Employee Stock Ownership Plan	63
Shares Held in Street Name	63
Changing or Revoking Proxy	63
Solicitation of Proxies	64
Assistance	64
THE ATLAS ENERGY SPECIAL MEETING	65
General	65
Date, Time and Place	65
Purpose of the Atlas Energy Special Meeting	65
Recommendation of the Atlas Energy Special Committee and the Atlas Energy Board of Directors	65
Atlas Energy Record Date; Outstanding Units; Units Entitled to Vote	65
Quorum	66
Vote Required for Approval	66
Voting; Proxies	67
Units Held in Street Name	67
Changing or Revoking Proxy	68
Solicitation of Proxies	68
No Appraisal Rights	68
Assistance	68
ATLAS ENERGY PROPOSAL / ATLAS AMERICA PROPOSAL 1: THE MERGER	69
Effects of the Merger	69
Atlas America Name Change	69

i

Background of the Merger	69
Atlas America’s Reasons for the Merger; Recommendation of the Atlas America Board of Directors	80
Atlas Energy’s Reasons for the Merger; Recommendation of the Atlas Energy Special Committee and the Atlas Energy Board of Directors	83
Opinion of Atlas America’s Financial Advisor	87
Opinion of Financial Advisor to the Atlas Energy Special Committee	91
Certain Projections	95
Interests of Atlas America Directors and Executive Officers in the Merger	97
Interests of Atlas Energy Directors and Executive Officers in the Merger	99
Board of Directors Following the Merger	100
Material U.S. Federal Income Tax Consequences	100
Accounting Treatment	102
Regulatory Approvals Required for the Merger	103
Litigation Relating to the Merger	103
Restrictions on Sales of Shares of Atlas America Common Stock by Certain Affiliates	104
Listing of Atlas America Common Stock	104
Delisting and Deregistration of Atlas Energy Common Units	104
Comparative Stock Prices, Dividends and Distributions	105
No Appraisal Rights	105
THE MERGER AGREEMENT	106
Structure and Completion of the Merger	106
Merger Consideration	106
Treatment of Equity-Based Awards	107
Exchange of Atlas Energy Common Units in the Merger	107
Conditions to the Completion of the Merger	108
Reasonable Best Efforts	110
Equityholder Approvals	111
Conduct of Business Pending Completion of the Merger	112
Other Covenants and Agreements	114
Termination of the Merger Agreement	115
Effect of Termination	116
Specific Performance	116
Fees and Expenses	116
Waiver and Amendment	116
Governing Law	116
Representations and Warranties	116
ATLAS AMERICA PROPOSAL 2: APPROVAL OF THE ATLAS AMERICA 2009 STOCK INCENTIVE PLAN	118
Administration	118
Eligibility	118
Shares Subject to the Plan	118
Stock Options and Stock Appreciation Rights	119
Restricted Stock	119
Restricted Stock Units	120
Non-Employee Director Awards	120
Other Stock-Based Awards	120
Performance Awards	120
Change in Control and Termination of Employment	121
Transferability	121
Amendment and Discontinuance	121
U.S. Federal Income Tax Consequences	121
Nonqualified Options	121

ii

Incentive Stock Options	121
New Plan Benefits	122
Vote Required; Recommendation of the Atlas America Board of Directors	122
THE COMPANIES	123
Atlas Energy Resources, LLC	123
Atlas Energy Management, Inc.	123
ATLS Merger Sub, LLC	123
INFORMATION ABOUT ATLAS AMERICA	124
General	124
Atlas Energy	126
Atlas Pipeline Holdings and Atlas Pipeline	133
Competition	141
Atlas America’s Relationship with Atlas Energy, Atlas Pipeline Holdings and Atlas Pipeline	142
Major Customers	144
Seasonal Nature of Business	144
Environmental Matters and Regulation	144
Employees	152
Properties	152
Legal Proceedings	156
Dividend Policy	157
Officers and Directors	157
Director and Executive Compensation	159
Certain Relationships and Related Transactions	179
Security Ownership of Certain Beneficial Owners and Management	182
SELECTED HISTORICAL FINANCIAL DATA OF ATLAS AMERICA	184
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF ATLAS AMERICA	187
General	187
Subsequent Events	191
Recent Developments	192
Contractual Revenue Arrangements	196
Recent Trends and Uncertainties	197
Results of Operations	199
Liquidity and Capital Resources	209
Issuance of Subsidiary Common Units	216
Dividends	218
Off-Balance Sheet Arrangements	218
Contractual Obligations and Commercial Commitments	219
Environmental Regulation	219
Changes in Prices and Inflation	220
Critical Accounting Policies and Estimates	220
Changes and Disagreements with Accountants on Accounting and Financial Disclosure	223
Quantitative and Qualitative Disclosures About Market Risk	223
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL INFORMATION	234
DESCRIPTION OF ATLAS AMERICA CAPITAL STOCK	243
Common Stock	243
Preferred Stock	243
Delaware Anti-Takeover Law and Charter and Bylaw Provisions	244
Liability and Indemnification of Officers and Directors	244
Listing	244
Transfer Agent and Registrar	244

iii

COMPARISON OF RIGHTS OF ATLAS AMERICA STOCKHOLDERS AND ATLAS ENERGY UNITHOLDERS	245
LEGAL MATTERS	257
EXPERTS	257
FUTURE EQUITYHOLDER PROPOSALS	257
Atlas America	257
Atlas Energy	258
OTHER MATTERS	258
WHERE YOU CAN FIND MORE INFORMATION	259
INDEX TO FINANCIAL STATEMENTS	F-1
Annex A     Agreement and Plan of Merger
Annex B     Opinion of J.P. Morgan Securities Inc.
Annex C     Opinion of UBS Securities LLC
Annex D     Atlas America 2009 Stock Incentive Plan

iv

QUESTIONS AND ANSWERS ABOUT THE SPECIAL MEETINGS

The following are some questions that you, as a stockholder of Atlas America or a unitholder of Atlas Energy, may have regarding the Atlas America special meeting or the Atlas Energy special meeting. Atlas America and Atlas Energy urge you to read carefully the remainder of this joint proxy statement/prospectus because the information in this section does not provide all the information that might be important to you with respect to the merger and the other matters being considered at the special meetings. Additional important information is also contained in the annexes to and the documents incorporated by reference into this joint proxy statement/prospectus.

Q: What is the proposed transaction?

A: Atlas America and Atlas Energy have agreed to combine their businesses by merging Merger Sub, a wholly owned subsidiary of Atlas America, with and into Atlas Energy under the terms of the merger agreement that is described in this joint proxy statement/prospectus and attached as Annex A to this joint proxy statement/prospectus. Atlas America, which currently beneficially owns 29,952,996 Atlas Energy common units, representing approximately 47.3% of the outstanding Atlas Energy common units, and 1,293,496 Atlas Energy Class A units, representing 100% of the outstanding Atlas Energy Class A units, is Atlas Energy’s largest unitholder. As a result of the merger and the other transactions contemplated by the merger agreement, Atlas Energy will become a wholly owned subsidiary of Atlas America.

The merger will become effective on such date and time that the certificate of merger is filed with the Secretary of State of the State of Delaware, or at such other mutually agreed to later time and date (which we refer to as the “effective time” of the merger).

Q: What will Atlas Energy unitholders receive in connection with the merger?

A: Subject to the terms and conditions of the merger agreement, if and when the merger is completed, each outstanding Atlas Energy common unit, other than treasury units and Atlas Energy common units held by Atlas America and its subsidiaries, will be cancelled and converted into the right to receive 1.16 shares of Atlas America common stock (which we refer to as the “merger consideration” and which ratio we refer to as the “exchange ratio”). The exchange ratio is fixed and will not be adjusted to reflect stock or unit price changes prior

to closing of the merger. Each Class A unit and management incentive interest of Atlas Energy, all of which are held by Atlas Energy Management, will remain outstanding. Options and other equity-based awards of Atlas Energy will convert into equivalent awards of Atlas America at the exchange ratio.

Q: What will Atlas America stockholders receive in connection with the merger?

A: Atlas America stockholders will continue to own their existing shares of Atlas America common stock.

Q: Why am I receiving these materials?

A: The merger cannot be completed without obtaining the appropriate approvals of Atlas America stockholders and Atlas Energy unitholders. Atlas America and Atlas Energy will hold separate special meetings of their respective stockholders and unitholders to obtain these approvals.

Q: What are Atlas America stockholders voting on?

A: In order to complete the merger, Atlas America stockholders must vote to approve the issuance of shares of Atlas America common stock to Atlas Energy unitholders in connection with the merger (which we refer to as the “stock issuance”).

Atlas America stockholders are also voting on a proposal to approve the Atlas America 2009 Stock Incentive Plan.

Atlas America stockholders are also voting to adjourn or postpone the Atlas America special meeting, if necessary, to solicit additional proxies if there are not sufficient votes at the time of the meeting in favor of the merger proposal.

v

Q: What are Atlas Energy unitholders voting on?

A: In order to complete the merger, Atlas Energy unitholders must vote to adopt the merger agreement and approve the merger and the other transactions contemplated by the merger agreement.

The chairman of the Atlas Energy board of directors, or other chairman of the Atlas Energy special meeting, has full authority to adjourn the special meeting of the Atlas Energy unitholders, whether for lack of a quorum or any other reason, and may elect to do so to solicit additional proxies if there are not sufficient votes in favor of the foregoing.

Q: How does the Atlas America board of directors recommend that Atlas America stockholders vote?

A: The Atlas America board of directors has determined that the merger agreement and the transactions contemplated thereby, including the stock issuance, are advisable, fair to and in the best interests of Atlas America and its stockholders. Therefore, the Atlas America board of directors recommends that Atlas America stockholders vote“FOR” the proposal to approve the stock issuance.

The Atlas America board of directors also recommends that Atlas America stockholders vote“FOR” the proposal to approve the Atlas America 2009 Stock Incentive Plan and“FOR” the proposal to adjourn or postpone the special meeting, if necessary, to solicit additional proxies if there are not sufficient votes at the time of the meeting in favor of the foregoing.

Q: How does the Atlas Energy board of directors recommend that Atlas Energy unitholders vote?

A: Based upon the unanimous recommendation of a special committee of the Atlas Energy board of directors consisting solely of independent directors (which we refer to as the “Atlas Energy special committee”), the Atlas Energy board of directors, with all of the interested and potentially interested directors abstaining or recusing themselves, recommends that Atlas Energy unitholders vote“FOR” the proposal to adopt the merger agreement and approve the transactions contemplated thereby, including the merger.

Q: When and where will the special meetings be held?

A: The Atlas America special meeting of stockholders will be held at The Ethical Society Building, 1906 South Rittenhouse Square, Philadelphia, Pennsylvania 19103, on September 25, 2009, at 11:00 am, local time.

The Atlas Energy special meeting of unitholders will be held at the Sofitel Philadelphia, 120 South 17^th Street, Philadelphia, Pennsylvania 19103, on September 25, 2009, at 9:00 am, local time.

Q: Who can attend and vote at the special meetings?

A: Atlas America Special Meeting.Only holders of record of Atlas America common stock at the close of business on August 18, 2009 (which we refer to as the “Atlas America record date”) are entitled to notice of and to vote at the Atlas America special meeting. As of August 18, 2009, there were 39,363,023 shares of Atlas America common stock outstanding and entitled to vote at the Atlas America special meeting. Each holder of Atlas America common stock is entitled to one vote for each share of Atlas America common stock owned as of the Atlas America record date.

Atlas Energy Special Meeting.Only holders of record of Atlas Energy common units and Atlas Energy Class A units at the close of business on August 18, 2009 (which we refer to as the “Atlas Energy record date”) are entitled to notice of and to vote at the Atlas Energy special meeting. As of August 18, 2009, there were (1) 63,381,249 Atlas Energy common units outstanding and entitled to vote at the Atlas Energy special meeting; and (2) 1,293,496 Atlas Energy Class A units outstanding and entitled to vote at the Atlas Energy special meeting. Each of the Atlas Energy common units and the Atlas Energy Class A units will vote separately as a class. Each holder of Atlas Energy common units and each holder of Atlas Energy Class A units is entitled to one vote for each Atlas Energy common unit and one vote for each Class A unit, respectively, owned as of the Atlas Energy record date. Atlas Energy Management will own 1,293,496, or 100% of outstanding, Atlas Energy Class A units as of the Atlas Energy record date.

vi

Q: How do I vote?

A: If you are a stockholder of record of Atlas America as of the Atlas America record date or a unitholder of record of Atlas Energy as of the Atlas Energy record date you may vote in person by attending your special meeting or, to ensure your shares or units, as appropriate, are represented at your special meeting, you may vote by:

• accessing the Internet website specified on your proxy card;

• calling the toll-free number specified on your proxy card; or

• signing and returning the enclosed proxy card in the postage paid envelope provided.

If you hold Atlas America common stock, Atlas Energy common units or Atlas Energy Class A units in the name of a bank or broker, please follow the voting instructions provided by your bank or broker to ensure that your shares are represented at your special meeting. If you are a participant in Atlas America’s Employee Stock Ownership Plan, please follow the voting instructions provided by GreatBanc Trust Company, the trustee of the plan.

Q: What constitutes a quorum?

A: Atlas America. The presence in person or by proxy of holders of Atlas America common stock representing not less than a majority of the outstanding shares of Atlas America common stock will constitute a quorum. We will also treat as present for quorum purposes abstentions and shares held by a broker as nominee (i.e., in “street name”) that are represented by proxies at the special meeting, but that the broker fails to vote on one or more matters as a result of incomplete instructions from the beneficial owner of the shares (which we refer to as “broker non-votes”).

Atlas Energy. The presence in person or by proxy of holders of (a) a majority of the outstanding Atlas Energy common units and (b) a majority of the outstanding Class A units will each constitute a quorum for their respective votes. Abstentions and broker non-votes also will be treated as present for quorum purposes.

Q: What vote is required to approve each proposal?

A: Atlas America.

• Stock Issuance. The proposal for Atlas America stockholders to approve the stock issuance requires the affirmative vote of holders of a majority of the votes cast on the proposal at the special meeting, provided that the total votes cast on the proposal represents over 50% of all shares of Atlas America common stock entitled to vote on the proposal. Accordingly, either a failure to cast a vote for this proposal or a broker non-vote could have the effect of a vote against the proposal if such failure or broker non-vote results in the total number of votes cast on the proposal not representing over 50% of all shares of common stock entitled to vote on the proposal. An abstention will be counted as a vote cast at the special meeting for purposes of this proposal and will have the same effect as a vote against the proposal.

• Atlas America 2009 Stock Incentive Plan. The proposal for Atlas America stockholders to approve the Atlas America 2009 Stock Incentive Plan requires the affirmative vote of the holders of a majority of the shares of Atlas America common stock present in person or represented by proxy at the special meeting and entitled to vote thereon. Accordingly, a failure to vote or a broker non-vote will not affect whether this proposal is approved. An abstention will be counted as present at the special meeting for purposes of this proposal and will have the same effect as a vote against the proposal.

• Authority to Adjourn the Atlas America Special Meeting. The proposal for Atlas America stockholders to adjourn or postpone the special meeting requires the affirmative vote of the holders of a majority of the shares of Atlas America common stock present in person or represented by proxy at the special meeting and entitled to vote thereon, whether or not a quorum is present. Accordingly, a failure to vote or a broker non-vote will not affect whether this proposal is approved.

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An abstention will be counted as present at the special meeting for purposes of this proposal and will have the same effect as a vote against the proposal.

Atlas Energy.

The proposal for Atlas Energy unitholders to adopt the merger agreement and approve the merger and the other transactions contemplated by the merger agreement requires the affirmative vote of: (1) the holders of a majority of the outstanding Atlas Energy common units and (2) the holders of a majority of the outstanding Atlas Energy Class A units. Accordingly, a failure to cast a vote for this proposal, a broker non-vote or an abstention will have the same effect as a vote against the proposal to adopt the merger agreement.

As of the date of this joint proxy statement/prospectus, Atlas America and its subsidiaries (other than Atlas Energy and its subsidiaries) beneficially own, within the meaning of Rule 13d-3 of the U.S. Securities Exchange Act of 1934, as amended (which we refer to as the “Exchange Act”), 29,952,996 Atlas Energy common units, representing approximately 47.3% of the outstanding Atlas Energy common units, and 1,293,496 Atlas Energy Class A units, representing 100% of the outstanding Atlas Energy Class A units. In the merger agreement, Atlas America agreed to vote all of its Atlas Energy common units and Atlas Energy Class A units in favor of the merger, provided that the Atlas Energy special committee or Atlas Energy board of directors has not changed its recommendation as of the time of the Atlas America special meeting. In addition, as of August 18, 2009, the Atlas Energy record date, Atlas America directors and executive officers and Atlas Energy directors and executive officers, taken together, beneficially owned 334,103, or approximately 0.5% of the outstanding, Atlas Energy common units. Atlas America and Atlas Energy currently expect that their respective directors and executive officers will vote their Atlas Energy common units in favor of the merger, but they have not entered into any agreement obliging them to do so. If Atlas America, the Atlas America directors and executive officers and the Atlas Energy directors

and executive officers vote all of their Atlas Energy common units in favor of the merger, 30,287,099, or approximately 47.8% of the outstanding, Atlas Energy common units will be voted in favor of the merger, and only an additional 1,403,526, or approximately 2.2% of the outstanding, Atlas Energy common units will be required to approve Atlas Energy’s proposal for the merger.

The chairman of the Atlas Energy board of directors, or other chairman of the Atlas Energy special meeting, has full authority to adjourn the special meeting of the Atlas Energy unitholders, whether for lack of a quorum or any other reason, and may elect to do so to solicit additional proxies if there are not sufficient votes in favor of the foregoing.

For purposes of determining whether a proposal has been approved, if any person or group (other than Atlas America, Atlas Energy Management and their affiliates or persons who acquired their units of Atlas Energy directly from Atlas America, Atlas Energy Management or their affiliates with the prior approval of the Atlas Energy board of directors) beneficially owns 20% or more of any class of units of Atlas Energy then outstanding, none of the Atlas Energy units owned by such person or group can be voted on any matter and will not be considered outstanding.

Q: Can I change my vote after I have delivered my proxy?

A: Yes, you can change your vote at any time before your proxy is voted at your special meeting. You can do this one of three ways:

• you can send a signed notice of revocation;

• you can grant a new, valid proxy bearing a later date; or

• if you are a holder of record, you can attend your special meeting and vote in person, which will automatically cancel any proxy previously given, or you may revoke your proxy in person, but your attendance alone will not revoke any proxy that you have previously given.

If you choose either of the first two methods, you must submit your notice of revocation or

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your new proxy to the Secretary of Atlas America or Atlas Energy, as appropriate, no later than the beginning of the applicable special meeting. If you have voted your shares by telephone or through the Internet, you may revoke your prior telephone or Internet vote by recording a different vote using the telephone or Internet, or by signing and returning a proxy card dated as of a date that is later than your last telephone or Internet vote. If your shares are held in street name by your bank or broker, you should contact your broker to change your vote.

Q: When do you expect the merger to be completed?

A: Atlas America and Atlas Energy are working to complete the merger in the third quarter of 2009. However, the merger is subject to various conditions set forth in the merger agreement, and it is possible that factors outside the control of both companies could result in the merger being completed at a later time, or not at all. Atlas America and Atlas Energy hope to complete the merger as soon as reasonably practicable following the special meetings.

Q: What do I need to do now?

A: Carefully read and consider the information contained in and incorporated by reference into this joint proxy statement/prospectus, including its annexes.

In order for your shares or units to be represented at your special meeting:

• you can attend your special meeting in person;

• you can vote through the Internet or by telephone following the instructions included on your proxy card; or

• you can indicate on the enclosed proxy card how you would like to vote and return the proxy card in the accompanying pre-addressed postage paid envelope.

Q: Do I need to do anything with my Atlas America common stock or my Atlas Energy common units now to receive the merger consideration?

A: No. If the merger is completed and you are an Atlas America stockholder as of immediately prior to the merger, you are not required to take any action with respect to your Atlas America stock certificates. If the merger is completed and you are an Atlas Energy unitholder as of immediately prior to the merger, you will be sent written instructions for exchanging your unit certificates for the merger consideration.

Q: Who can help answer my questions?

A: If you have questions about the merger or the other matters to be voted on at the special meetings or desire additional copies of this joint proxy statement/prospectus or additional proxy cards, you should contact:

If you are an Atlas America stockholder:

105 Madison Avenue

New York, New York 10016

proxy@mackenziepartners.com

Call Collect: (212) 929-5500

or

Toll-Free (800) 322-2885

If you are an Atlas Energy unitholder:

199 Water Street, 26^th Floor

New York, NY 10038

atninfo@georgeson.com

Call Collect: (212) 806-6859

or

Toll-Free (800) 255-4617

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SUMMARY

This summary highlights information contained elsewhere in this joint proxy statement/prospectus and may not contain all the information that is important to you. For a more complete description of the merger agreement and the transactions contemplated by the merger agreement, including the merger and the stock issuance, we encourage you to read carefully this entire joint proxy statement/prospectus, including the attached annexes. In addition, we encourage you to read the information incorporated by reference into this joint proxy statement/prospectus, which includes important business and financial information about Atlas Energy that has been filed with the SEC. Please see “Where You Can Find More Information.”

The Companies (see page 123)

Atlas America, Inc.

Westpointe Corporate Center One

1550 Coraopolis Heights Road, 2nd Floor

Moon Township, PA 15108

Atlas America is a publicly traded Delaware corporation whose assets currently consist principally of cash on hand and its ownership interests in the following entities:

• Atlas Energy — As of the date of this joint proxy statement/prospectus, Atlas America owns 29,952,996 Atlas Energy common units, representing approximately 47.3% of the outstanding Atlas Energy common units, and, through its wholly owned subsidiary, Atlas Energy Management, beneficially owns 1,293,496 Atlas Energy Class A units, representing 100% of the outstanding Atlas Energy Class A units, and management incentive interests in Atlas Energy. Atlas America manages Atlas Energy through Atlas America’s subsidiary, Atlas Energy Management, under the supervision of the Atlas Energy board of directors.

• Atlas Pipeline Partners, L.P. — As of the date of this joint proxy statement/prospectus, Atlas America owns approximately 2.3% of the equity of Atlas Pipeline Partners, L.P. (which we refer to as “Atlas Pipeline”), a midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachia regions. The limited partnership interests of Atlas Pipeline are traded on the New York Stock Exchange (which we refer to as the “NYSE”) under the symbol “APL.”

• Atlas Pipeline Holdings, L.P. — As of the date of this joint proxy statement/prospectus, Atlas America owns approximately 64.4% of the outstanding common units of Atlas Pipeline Holdings, which is a publicly traded Delaware limited partnership and owner of Atlas Pipeline Partners GP, LLC, the general partner of Atlas Pipeline (which we refer to as “Atlas Pipeline GP”). Atlas America manages Atlas Pipeline Holdings through Atlas America’s ownership of the general partner of Atlas Pipeline Holdings. As of the date of this joint proxy statement/prospectus, Atlas Pipeline Holdings owns a 2% general partner interest, all of the incentive distribution rights, an approximate 11.8% limited partner interest and 15,000 $1,000 par value 12.0% cumulative preferred limited partner units of Atlas Pipeline.

Atlas America has been involved in the energy industry since 1968, expanding its operations in 1998 when it acquired The Atlas Group, Inc. and in 1999 when it acquired Viking Resources Corporation, both engaged in the development and production of natural gas and oil and the sponsorship of investment partnerships. Atlas America was originally incorporated in Delaware in September 2000 to become a holding company for Resource America, Inc.’s energy assets and subsidiaries. In May 2004, Atlas America completed an initial public offering of 2,645,000 shares of its common stock. After the initial public offering, Resource America, Inc. continued to own approximately 80.2% of Atlas America. In June 2005, Resource America, Inc. spun-off its remaining ownership interest in Atlas America to Resource America, Inc.’s common stockholders in the form of a tax-free dividend. Atlas America common stock is traded on NASDAQ under the symbol “ATLS.”

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Atlas Energy Resources, LLCWestpointe Corporate Center One

1550 Coraopolis Heights Road, 2nd Floor

Moon Township, PA 15108

Atlas Energy is a publicly traded Delaware limited liability company. Atlas Energy is an independent developer and producer of natural gas and oil, with operations in the Appalachian Basin, where it focuses the Marcellus Shale and other Devonian shales, in the Michigan Basin, where it focuses on northern Michigan’s Antrim Shale, and in the Illinois Basin, where it focuses on Indiana’s New Albany Shale. Atlas Energy’s major operations in the Appalachian Basin are located in eastern Ohio, western Pennsylvania, and north central Tennessee. Atlas Energy has additional operations and interests in New York, West Virginia and Kentucky. Atlas Energy’s focus is to increase its own reserves, production, and cash flows through a mix of generating new opportunities of geologic prospects, natural gas and oil exploitation and development, and sponsorship of investment partnerships. Atlas Energy generates both upfront and ongoing fees from the drilling, production, servicing, and administration of its wells in these partnerships.

Atlas Energy was formed in June 2006 to own and operate substantially all of the natural gas and oil assets and the investment partnership management business of Atlas America. Atlas Energy Management, Inc., a wholly owned subsidiary of Atlas America, owns 100% of the Atlas Energy Class A units and management incentive interests which give Atlas Energy Management certain control

rights over Atlas Energy. Atlas Energy common units are traded on the NYSE under the symbol “ATN.”

The Merger

A copy of the merger agreement is attached as Annex A to joint proxy statement/prospectus. Atlas America and Atlas Energy encourage you to read carefully the merger agreement in its entirety because it is the principal document governing the merger.

Effects of the Merger (see page 69)

Subject to the terms and conditions of the merger agreement, at the effective time of the merger, Merger Sub, which is a wholly owned subsidiary of Atlas America, will merge with and into Atlas Energy, with Atlas Energy surviving the merger as a directly and indirectly wholly owned subsidiary of Atlas America.

Atlas America Name Change (see page 69)

At the effective time of the merger, Atlas America will be renamed “Atlas Energy, Inc.” This name change will be effected by merging a newly created, wholly owned subsidiary of Atlas America with and into Atlas America pursuant to Section 253 of Delaware General Corporation Law, which requires only the approval of the Atlas America board of directors. Atlas America will survive the merger, but as a result of such merger, Atlas America’s name will be changed to “Atlas Energy, Inc.”

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Before the Merger

After the Merger

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Merger Consideration; Treatment of Atlas Energy Equity Awards (see pages 106 and 107)

Subject to the terms and conditions of the merger agreement, if and when the merger is completed, each outstanding Atlas Energy common unit, other than treasury units and Atlas Energy common units owned by Atlas America and its subsidiaries, will be cancelled and converted into the right to receive 1.16 shares of Atlas America common stock. In addition, as of the consummation of the merger, each outstanding restricted unit, phantom unit and unit option of Atlas Energy will be converted into an equivalent restricted share, phantom share and stock option of Atlas America, respectively, with adjustments in the number of shares and exercise price to reflect the exchange ratio, but otherwise on the same terms and conditions as were applicable prior to the merger. Each Class A unit and management incentive interest of Atlas Energy held by Atlas Energy Management will remain outstanding.

Atlas America will not issue fractional shares of Atlas America common stock in the merger. Instead, Atlas Energy unitholders will receive cash for any fractional share of Atlas America common stock that they would otherwise be entitled to receive in the merger.

Atlas America stockholders will continue to own their existing shares of Atlas America common stock, which will not be affected by the merger, except that, because Atlas America will be issuing new shares of Atlas America common stock to Atlas Energy unitholders in the merger, each outstanding share of Atlas America common stock immediately prior to the merger will, after the merger, represent a smaller percentage ownership interest in Atlas America.

Upon completion of the merger, the current Atlas America stockholders will own approximately 50.4% of Atlas America, and former Atlas Energy unitholders will own approximately 49.6% of Atlas America.

Recommendation of the Atlas America Board of Directors (see page 61)

The Atlas America board of directors has determined that the merger agreement and the transactions contemplated thereby, including the stock issuance, are advisable, fair to and in the best interests of Atlas America and its stockholders. For the factors considered by the Atlas America board of directors in reaching its decision, see “Atlas America’s Reasons for the Merger; Recommendation of the Atlas America Board of Directors.”

The Atlas America board of directors unanimously recommends that Atlas America stockholders vote “FOR” the proposal to issue shares of Atlas America common stock in the merger, “FOR” the proposal to approve the Atlas America 2009 Stock Incentive Plan and “FOR” the proposal to adjourn or postpone the Atlas America special meeting, if necessary, to solicit additional proxies if there are not sufficient votes in favor of the foregoing.

Recommendation of the Atlas Energy Special Committee and the Atlas Energy Board of Directors (see page 65)

Each of (1) the Atlas Energy special committee and (2) the Atlas Energy board of directors, with all of the interested and potentially interested directors abstaining or recusing themselves, and based upon the unanimous recommendation of the Atlas Energy special committee, determined that the merger agreement and the transactions contemplated thereby, including the merger, are advisable, fair and reasonable to, and in the best interests of, Atlas Energy and the Atlas Energy unitholders that are not affiliated with Atlas America. For the factors considered by the Atlas Energy special committee and the Atlas Energy board of directors in reaching their decisions to approve the merger agreement, see “Atlas Energy’s Reasons for the Merger; Recommendation of the Atlas Energy Board of Directors.”

Based upon the unanimous recommendation of the Atlas Energy special committee, the Atlas Energy board of directors recommends that Atlas Energy unitholders vote “FOR” the proposal to adopt the merger agreement and approve the transactions contemplated thereby, including the merger.

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Opinion of Atlas America’s Financial Advisor (see page 87)

At the meeting of the Atlas America board of directors on April 26, 2009, JPMorgan rendered its oral opinion, subsequently confirmed in writing, to the Atlas America board of directors that, as of such date and based upon and subject to the factors and assumptions set forth in its opinion, the exchange ratio in the proposed merger was fair, from a financial point of view, to Atlas America.

The full text of the written opinion of JPMorgan which sets forth the assumptions made, matters considered and limits on the review undertaken, is attached as Annex B to this joint proxy statement/prospectus and is incorporated herein by reference. Atlas America stockholders are urged to read the opinion in its entirety. JPMorgan’s written opinion is addressed to the Atlas America board of directors, is directed only to the exchange ratio in the merger and does not constitute a recommendation to any Atlas America stockholder as to how such stockholder should vote at the Atlas America special meeting. The summary of the opinion of JPMorgan set forth in this joint proxy statement/prospectus is qualified in its entirety by reference to the full text of such opinion.

Opinion of Financial Advisor to the Atlas Energy Special Committee (see page 91)

In connection with the merger, the Atlas Energy special committee received a written opinion, dated April 27, 2009, from its financial advisor, UBS Securities LLC, as to the fairness, from a financial point of view and as of the date of such opinion, of the exchange ratio provided for in the merger to holders of Atlas Energy common units (other than Atlas America, officers and directors of Atlas Energy and Atlas America and their respective affiliates). The full text of UBS’ written opinion, dated April 27, 2009, is attached to this joint proxy statement/prospectus as Annex C.UBS’ opinion was provided for the benefit of the Atlas Energy special committee in connection with, and for the purpose of, its evaluation of the exchange ratio from a financial point of view and does not address any other aspect of the merger. The opinion does not

address the relative merits of the merger as compared to other business strategies or transactions that might be available with respect to Atlas Energy or Atlas Energy’s underlying business decision to effect the merger. The opinion does not constitute a recommendation to any security holder as to how such security holder should vote or act with respect to the merger. Holders of Atlas Energy common units are encouraged to read UBS’ opinion carefully in its entirety for a description of the assumptions made, procedures followed, matters considered and limitations on the review undertaken by UBS.

Interests of Atlas America Directors and Executive Officers in the Merger (see page 97)

In considering the recommendation of the Atlas America board of directors with respect to the stock issuance, Atlas America stockholders should be aware that Atlas America’s directors and executive officers have interests in the merger that may be different from, or in addition to, Atlas America’s stockholders generally. The Atlas America board of directors was aware of these interests, and considered these interests, among other matters, in evaluating and negotiating the merger agreement and the merger, and in recommending to their stockholders that they approve the stock issuance. These interests and arrangements include:

• the continued service on the board of directors of the combined company by Edward E. Cohen and Jonathan Z. Cohen, Chief Executive Officer and Vice Chairman, respectively, of both Atlas America and Atlas Energy, and the six independent directors serving on the Atlas America board of directors at the time the merger is consummated;

• Freddie M. Kotek, Executive Vice President of Atlas America, is an investor in an investment partnership to which Atlas Energy commits 15% to 25% of the total capital. In 2008, of the $585 million that was raised by the partnership, Atlas Energy committed $146 million of the capital;

• certain officers are officers of both Atlas America and Atlas Energy, including

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Matthew A. Jones as Chief Financial Officer and Sean P. McGrath as Chief Accounting Officer of both Atlas America and Atlas Energy; and

• beneficial ownership by Atlas America directors and executive officers of 330,128, or approximately 0.5% of the outstanding, Atlas Energy common units, which units will be converted into the merger consideration if the merger is completed.

Interests of Atlas Energy Directors and Executive Officers in the Merger (see page 99)

In considering the recommendation of the Atlas Energy board of directors with respect to the merger agreement, Atlas Energy unitholders should be aware that Atlas Energy’s directors and executive officers have interests in the merger that may be different from, or in addition to, Atlas Energy unitholders generally. The Atlas Energy board of directors was aware of these interests, and considered these interests, among other matters, in evaluating and negotiating the merger agreement and the merger, and in recommending to their unitholders that the proposal in favor of adopting the merger agreement be approved. These interests and arrangements include:

• the continued service on the board of directors of the combined company by Edward Cohen and Jonathan Cohen and the four independent directors serving on the Atlas Energy board of directors at the time the merger is consummated;

• certain officers are officers of both Atlas America and Atlas Energy, including Matthew A. Jones as Chief Financial Officer and Sean P. McGrath as Chief Accounting Officer of both Atlas America and Atlas Energy;

• the conversion of each outstanding restricted unit, phantom unit and unit option of Atlas Energy units into an equivalent restricted share, phantom share and stock option of Atlas America, respectively, with adjustments in the number of shares and exercise price to

reflect the exchange ratio, but otherwise on the same terms and conditions as were applicable prior to the merger; and

• beneficial ownership by Atlas Energy directors and executive officers of 5,734,819, or approximately 13.8% of the outstanding, Atlas America common stock.

Board of Directors Following the Merger (see page 100)

Pursuant to the terms of the merger agreement, at the effective time of the merger, the Atlas America board of directors will consist of 12 persons, including the 10 independent directors from the Atlas America board of directors and the Atlas Energy board of directors and Edward Cohen and Jonathan Cohen.

Material U.S. Federal Income Tax Consequences (see page 100)

The merger generally will be a taxable transaction to Atlas Energy unitholders for U.S. federal income tax purposes. The merger will not be a taxable transaction to Atlas America stockholders for U.S. federal income tax purposes. Tax matters are very complicated and the tax consequences of the merger to any particular equity holder will depend on such equity holder’s particular facts and circumstances. Atlas Energy unitholders are urged to consult their tax advisors to understand fully the tax consequences to them of the merger.

Accounting Treatment (see page 102)

Atlas America will account for the acquisition of Atlas Energy common units under Statement of Financial Accounting Standards No. 160, “Non-controlling Interests in Consolidated Financial Statements – an amendment of ARB No. 51” (which we refer to as “SFAS No. 160”). In accordance with SFAS No. 160, Atlas America will not recognize a gain or loss in its net income as a result of the transaction and it will continue to recognize the assets and liabilities of Atlas Energy at their historical values instead of valuing Atlas Energy’s assets and liabilities at their fair value at the date of completion of the merger.

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Regulatory Approvals Required for the Merger (see page 103)

Under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (which we refer to as the “HSR Act”), neither Atlas America nor Atlas Energy may complete the merger until the required information and materials are furnished to the Antitrust Division of the Department of Justice (which we refer to as the “DOJ”), and the Federal Trade Commission (which we refer to as the “FTC”), and the applicable waiting period under the HSR Act expires or is terminated. On May 8, 2009, Atlas America and Atlas Energy filed the requisite notification and report forms under the HSR Act with the DOJ and the FTC, and early termination of the waiting period was granted on May 15, 2009. No further regulatory approvals are required for completion of the merger.

Litigation Relating to the Merger (see page 103)

Atlas Energy, Atlas America and certain officers and directors of both companies are named defendants in a consolidated purported class action lawsuit brought by Atlas Energy unitholders in Delaware Chancery Court generally alleging claims of breach of fiduciary duty in connection with the merger transaction. The complaint alleges that the defendants breached purported fiduciary duties owed to the public unitholders by negotiating and executing a merger agreement that allegedly provides unfair consideration to the public unitholders and that was reached pursuant to an allegedly unfair negotiating process between the special committee of Atlas Energy and Atlas America. The complaint also alleges that the defendants have failed to disclose material information regarding the merger. The lawsuit originally sought monetary damages or injunctive relief, or both, but the plaintiffs subsequently withdrew their motion for a preliminary injunction to block the merger prior to close and have stated that they would continue to pursue the action for monetary damages subsequent to the merger. Predicting the outcome of this lawsuit is difficult. An adverse judgment for monetary damages could have a material adverse effect on the operations of the combined company after the merger. A preliminary injunction could have delayed or jeopardized the completion of the merger, and an adverse judgment

granting injunctive relief could have permanently enjoined completion of the merger. Based on the facts known to date, the defendants believe that the claims asserted against them in these lawsuits are without merit, and intend to defend themselves vigorously against the claims.

Listing of Atlas America Common Stock and Delisting and Deregistration of Atlas Energy Common Units (see pages 104)

Atlas America will apply to have the shares of Atlas America common stock to be issued in the merger approved for listing on NASDAQ, where Atlas America common stock is currently traded under the symbol “ATLS.” If the merger is completed, Atlas Energy common units will no longer be listed on the NYSE and will be deregistered under the Exchange Act.

No Appraisal Rights (see page 105)

Neither Atlas America stockholders nor Atlas Energy unitholders are entitled to appraisal rights in connection with the merger or the transactions contemplated by the merger agreement.

Completion of the Merger (see page 106)

Atlas America and Atlas Energy are working to complete the merger in the third quarter of 2009. However, the merger is subject to various conditions set forth in the merger agreement, and it is possible that factors outside the control of both companies could result in the merger being completed at a later time, or not at all. Atlas America and Atlas Energy hope to complete the merger as soon as reasonably practicable following the special meetings.

Conditions to Completion of the Merger (see page 108)

As more fully described in this joint proxy statement/prospectus and in the merger agreement, the completion of the merger depends on the satisfaction (or, where permissible, waiver) of a number of conditions. These conditions include, among others, receipt of the requisite approvals of Atlas America stockholders and Atlas Energy unitholders, satisfactory amendment of the Atlas Energy credit agreement, the correctness of all

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representations and warranties made by the parties in the merger agreement and performance by the parties of their obligations under the merger agreement (subject in each case to certain materiality standards) and the lack of injunction or other government action prohibiting the merger.

On July 10, 2009, Atlas Energy received the requisite consent from its lenders to amend the Atlas Energy credit agreement to permit the merger. The amendment will become effective upon consummation of the merger. On July 13, 2009, Atlas America held its 2009 annual shareholders’ meeting. At that meeting, the Atlas America stockholders approved an amendment to the Atlas America amended and restated certificate of incorporation (which we refer to as the “Atlas America charter”) to increase the number of authorized shares of Atlas America common stock from 49 million to 114 million (which we refer to as the “charter amendment”). With the charter amendment, Atlas America has a sufficient number of authorized shares of common stock to complete the merger. In addition, early termination of the waiting period under the HSR Act was granted on May 15, 2009. The approval of the amendment to the Atlas Energy credit agreement, the charter amendment and termination of the HSR waiting period are conditions to completion of the merger.

We cannot be certain when, or if, the other conditions to the merger will be satisfied or waived, or that the merger will be completed.

Termination of the Merger Agreement (see page 115)

Atlas America and Atlas Energy may mutually agree to terminate the merger agreement before completing the merger, even after stockholder and unitholder approval.

In addition, either Atlas America or Atlas Energy may decide to terminate the merger agreement, even after stockholder and unitholder approval, if:

• the merger is not consummated by February 28, 2010;

• a court or other governmental entity issues a final and nonappealable order or other regulation prohibiting the merger;

• Atlas America stockholders fail to approve the stock issuance;

• Atlas Energy unitholders fail to adopt the merger agreement and approve the transactions contemplated thereby, including the merger; or

• the other party breaches its representations, warranties or covenants in a way that would entitle the party seeking to terminate the agreement not to consummate the merger, subject to the right of the breaching party to cure the breach.

Either party may also terminate the merger agreement if the board of directors of the other party (and, in the case of the Atlas Energy board of directors, only with the prior approval of the Atlas Energy special committee) withdraws its approval or recommendation with respect to the merger agreement and the transactions contemplated by the merger agreement.

Fees and Expenses (see page 116)

Generally, all fees and expenses incurred in connection with the merger agreement and the transactions contemplated by the merger agreement will be paid by the party incurring those expenses, subject to the specific exceptions discussed in this joint proxy statement/prospectus.

The Special Meetings

The Atlas America Special Meeting (see page 61)

The Atlas America special meeting will be held at The Ethical Society Building, 1906 South Rittenhouse Square, Philadelphia, Pennsylvania 19103, on September 25, 2009, at 11:00 am, local time. At the Atlas America special meeting, Atlas America stockholders will be asked:

• to consider and vote on a proposal to approve the issuance of shares of Atlas America common stock in connection with the merger;

• to consider and vote on a proposal to approve the Atlas America 2009 Stock Incentive Plan; and

• to vote upon a proposal to adjourn or postpone the Atlas America special

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meeting, if necessary, to solicit additional proxies if there are not sufficient votes in favor of the foregoing.

You may vote at the Atlas America special meeting if you owned Atlas America common stock at the close of business on the Atlas America record date, August 18, 2009. On August 18, 2009, there were 39,363,023 shares of Atlas America common stock outstanding and entitled to vote. You may cast one vote for each share of Atlas America common stock you owned on the record date.

The following votes are required to approve each of the above listed proposals:

• the proposal for Atlas America stockholders to approve the stock issuance requires the affirmative vote of holders of a majority of the votes cast on the proposal at the Atlas America special meeting, provided that the total votes cast on the proposal represents over 50% of all shares of Atlas America common stock entitled to vote on the proposal;

• the proposal for Atlas America stockholders to approve the Atlas America 2009 Stock Incentive Plan requires the affirmative vote of the holders of a majority of the shares of Atlas America common stock present in person or represented by proxy at the special meeting and entitled to vote thereon; and

• the proposal for Atlas America stockholders to adjourn or postpone the special meeting requires the affirmative vote of the holders of a majority of the shares of Atlas America common stock present in person or represented by proxy at the special meeting and entitled to vote thereon, whether or not a quorum is present.

As of August 18, 2009, the Atlas America record date, Atlas America directors and executive officers beneficially owned approximately 13.4% of the outstanding shares of Atlas America common stock. Atlas America currently expects that its directors and executive officers will vote their shares in favor of the above-listed proposals, but none of

them has entered into any agreements obliging him or her to do so.

The Atlas Energy Special Meeting (see page 65)

The Atlas Energy special meeting will be held at the Sofitel Philadelphia, 120 South 17^th Street, Philadelphia, Pennsylvania 19103, on September 25, 2009, at 9:00 am, local time. At the Atlas Energy special meeting, Atlas Energy unitholders will be asked to consider and vote upon a proposal to adopt the merger agreement and approve the transactions contemplated thereby, including the merger.

The chairman of the Atlas Energy board of directors, or other chairman of the Atlas Energy special meeting, has full authority to adjourn the special meeting of the Atlas Energy unitholders, whether for lack of a quorum or any other reason, and may elect to do so to solicit additional proxies if there are not sufficient votes in favor of the foregoing.

You may vote at the Atlas Energy special meeting if you owned Atlas Energy common units at the close of business on the Atlas Energy record date, August 18, 2009. On August 18, 2009, there were 63,381,249 Atlas Energy common units outstanding and entitled to vote. You may cast one vote for each Atlas Energy common unit you owned on the record date.

The proposal for Atlas Energy unitholders to adopt the merger agreement and approve the merger and the other transactions contemplated by the merger agreement requires the affirmative vote of (1) the holders of a majority of the outstanding Atlas Energy common units and (2) the holders of a majority of the outstanding Atlas Energy Class A units, in each case, voting separately as a class.

For purposes of determining whether a proposal has been approved, if any person or group (other than Atlas America, Atlas Energy Management and their affiliates or persons who acquired their units of Atlas Energy directly from Atlas America, Atlas Energy Management or their affiliates with the prior approval of the Atlas Energy board of directors) beneficially owns 20% or more of any class of units of Atlas Energy then outstanding, none of the Atlas Energy units owned by such person or group can be voted on any matter and will not be considered outstanding.

9

As of August 18, 2009, the Atlas Energy record date, Atlas Energy directors and executive officers beneficially owned approximately 0.5% of the outstanding Atlas Energy common units. It is currently expected that Atlas Energy’s directors and executive officers will vote their units in favor of the above-listed proposals, but none of them has entered into any agreements obliging him or her to do so.

As of August 18, 2009, the Atlas Energy record date, Atlas America beneficially owned 29,952,996 Atlas Energy common units, representing approximately 47.3% of the outstanding Atlas Energy common units, and Atlas Energy Management, a wholly owned subsidiary of Atlas America, owned 1,293,496 Atlas Energy Class A units, representing 100% of the outstanding Atlas Energy Class A units. Atlas America and Atlas Energy Management agreed in the merger agreement that, so long as the Atlas Energy board of directors and Atlas Energy special committee have not changed or withdrawn their recommendation in favor of adoption of the merger agreement, they will vote all of their Atlas Energy common units and Atlas Energy Class A units to adopt the merger agreement, approve the merger and approve any other matters required to be approved by holders of Atlas Energy common units and holders of Atlas Energy Class A units for consummation of the merger.

In addition, as of August 18, 2009, the Atlas Energy record date, Atlas America directors and executive officers and Atlas Energy directors and executive officers, taken together, beneficially owned 334,103, or approximately 0.5% of the outstanding, Atlas Energy common units. Atlas America and Atlas Energy currently expect that their respective directors and executive officers will vote their Atlas Energy common units in favor of the merger, but they have not entered into any agreement obliging them to do so. If Atlas America, the Atlas America directors and executive officers and the Atlas Energy directors and executive officers vote all of their Atlas Energy common units in favor of the merger, 30,287,099, or approximately 47.8% of the outstanding, Atlas Energy common units will be voted in favor of the merger, and only an additional 1,403,526, or approximately 2.2% of the outstanding, Atlas Energy

common units will be required to approve Atlas Energy’s proposal for the merger.

Risk Factors (see page 21)

In evaluating the proposals set forth in this joint proxy statement/prospectus, you should carefully read this joint proxy statement/prospectus and especially consider the factors discussed in the section entitled “Risk Factors” on page 21.

Comparison of Rights of Atlas America Stockholders and Atlas Energy Unitholders (see page 245)

Atlas Energy unitholders receiving merger consideration will have different rights once they become Atlas America stockholders due to differences between the entity forms and governing documents of Atlas America and Atlas Energy. These differences are described in detail under “Comparison of Rights of Atlas America Stockholders and Atlas Energy Unitholders.”

Recent Developments (see page 60)

Amendment to Atlas Energy Credit Agreement

On July 10, 2009, Atlas Energy received the requisite consent from its lenders to amend the Atlas Energy credit agreement to permit the merger. The amendment will become effective upon consummation of the merger. The amendment to the Atlas Energy credit agreement is a condition to completion of the merger.

Atlas America 2009 Annual Meeting

On July 13, 2009, Atlas America held its 2009 annual shareholders’ meeting. At that meeting, the Atlas America stockholders elected Gayle P. W. Jackson and Mark C. Biderman to the Atlas America board of directors and approved an amendment to the Atlas America charter to increase the number of authorized shares of Atlas America common stock from 49 million to 114 million. With the charter amendment, Atlas America has a sufficient number of authorized shares of common stock to complete the merger. The approval of the amendment to the Atlas America charter is a condition to completion of the merger.

10

Completion of Atlas Energy Bond Offering

On July 16, 2009, Atlas Energy Operating Company, LLC and Atlas Energy Finance Corp., wholly owned subsidiaries of Atlas Energy, sold an aggregate of $200,000,000 principal amount of their 12.125% Senior Notes due 2017 in an underwritten offering. The senior notes are guaranteed by Atlas

Energy and certain of its other subsidiaries. The senior notes will bear interest at a rate of 12.125% per year, payable semiannually in arrears on February 1 and August 1 of each year, beginning on February 1, 2010. Atlas Energy applied the net proceeds of the sale of the senior notes to the repayment of a portion of the borrowings outstanding under its revolving credit facility.

11

Selected Historical Financial Data of Atlas America

In June 2006, Atlas America changed its year end from September 30 to December 31, and, therefore, the selected historical financial data below includes a transition period of the three months ended December 31, 2005, and its new year ended December 31.

The following table should be read together with Atlas America’s audited consolidated financial statements and notes thereto and Atlas America’s unaudited consolidated financial statements and notes thereto included elsewhere in this joint proxy statement/prospectus. Atlas America has 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 its audited consolidated financial statements included elsewhere in this joint proxy statement/prospectus. Such financial statements have been audited by Grant Thornton LLP, independent registered public accounting firm.

The selected financial data set forth in the table include Atlas America’s historical consolidated financial statements, which have been adjusted to reflect the following:

• in May 2009, Atlas Pipeline Partners, L.P. (NYSE: APL – “APL”), an entity in which Atlas America has a direct and indirect ownership interest and which Atlas America consolidates within its consolidated financial statements, completed the sale of its NOARK gas gathering and interstate pipeline system (“NOARK”). In accordance with FASB Statement No. 144 “Accounting for the Impairment or Disposal of Long-lived Assets” (“SFAS No. 144”), Atlas America has retrospectively adjusted its prior period consolidated financial statements to reflect the amounts related to the operations of NOARK as discontinued operations; and

• the adoption of Statement of Financial Accounting Standards No. 160, “Non-controlling Interests in Consolidated Financial Statements-an amendment of ARB No. 51.” SFAS No. 160 amends ARB No. 51 to establish accounting and reporting standards for the non-controlling interest (minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling 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 statements of operations at amounts that include the amounts attributable to both the parent and the non-controlling interest. Atlas America adopted the requirements of SFAS No. 160 on January 1, 2009, and has reflected the retrospective application for all periods presented.

	Six Months Ended June 30,						Years Ended December 31,								Three Months Ended December 31,			Years Ended September 30,
	2009			2008			2008			2007			2006		2005			2005		2004
	(in thousands, except per share data)
Statement of operations data:
Revenues:
Well construction and completion	$	175,735		$	226,479		$	415,036		$	321,471		$	198,567	$	42,145		$	134,338	$	86,880
Gas and oil production		141,922			155,182			311,850			180,125			88,449		24,086			63,499		48,526
Transmission, gathering and processing		349,737			807,417			1,384,212			767,085			367,551		108,708			262,829		34,483
Administration and oversight		6,495			10,154			19,362			18,138			11,762		2,964			9,875		8,396
Well services		9,932			10,064			20,482			17,592			12,953		2,561			9,552		8,430
Gain on asset sales		105,691			—			—			—			—		—			—		—
Equity income in joint venture		710			—			—			—			—		—			—		—
Gain (loss) on mark-to-market derivatives		(18,277	)		(404,849	)		(63,480	)		(153,325	)		2,316		(138	)		1,887		(255	)
Total revenues		771,945			804,447			2,087,462			1,151,086			681,598		180,326			481,980		186,460

12

	Six Months Ended June 30,						Years Ended December 31,									Three Months Ended December 31,			Years Ended September 30,
	2009			2008			2008			2007			2006			2005			2005			2004
	(in thousands, except per share data)
Costs and expenses:
Well construction and completion	$	149,098		$	196,939		$	359,609		$	279,540		$	172,666		$	36,648		$	116,816		$	75,548
Gas and oil production		21,089			23,047			48,194			24,184			8,499			1,721			6,044			5,265
Transmission, gathering and processing		302,890			658,516			1,153,555			617,629			315,081			96,406			229,816			27,870
Well services		4,544			5,062			10,654			9,062			7,337			1,487			5,167			4,399
General and administrative		49,553			45,945			57,787			111,180			44,312			9,614			24,563			16,021
Depreciation, depletion and amortization		100,967			85,214			178,269			100,838			39,408			9,346			24,895			14,700
Goodwill impairment loss		—			—			676,860			—			—			—			—			—
Total costs and expenses		628,141			1,014,723			2,484,928			1,142,433			587,303			155,222			407,301			143,803
Operating income (loss)		143,804			(210,276	)		(397,466	)		8,653			94,295			25,104			74,679			42,657
Other income (expense):
Interest expense		(76,568	)		(69,207	)		(144,065	)		(93,677	)		(26,439	)		(5,420	)		(11,467	)		(2,881	)
Gain on early extinguishment of debt		—			—			19,867			—			—			—			—			—
Other, net		6,135			8,024			11,383			10,696			8,176			318			4,519			(2,219	)
Total other income (expense), net		(70,433	)		(61,183	)		(112,815	)		(82,981	)		(18,263	)		(5,102	)		(6,948	)		(5,100	)
Income (loss) from continuing operations before income taxes		73,371			(271,459	)		(510,281	)		(74,328	)		76,032			20,002			67,731			37,557
Provision (benefit) for income taxes		6,263			(1,431	)		(5,021	)		13,283			26,713			6,577			20,018			11,409
Income (loss) from continuing operations		67,108			(270,028	)		(505,260	)		(87,611	)		49,319			13,425			47,713			26,148
Income from discontinued operations, net of income taxes		59,761			13,848			19,671			29,471			10,986			5,044			—			—
Income (loss) before cumulative effect of accounting change		126,869			(256,180	)		(485,589	)		(58,140	)		60,305			18,469			47,713			26,148
Cumulative effect of accounting change		—			—			—			—			3,825			—			—			—
Net income (loss)		126,869			(256,180	)		(485,589	)		(58,140	)		64,130			18,469			47,713			26,148
(Income) loss attributable to non-controlling interests		(112,858	)		254,831			479,431			93,476			(18,283	)		(6,745	)		(14,773	)		(4,961	)
Net income (loss) attributable to common stockholders	$	14,011		$	(1,349	)	$	(6,158	)	$	35,336		$	45,847		$	11,724		$	32,940		$	21,187
Net income (loss) attributable to common stockholders per share(1):
Basic:
Income (loss) from continuing operations attributable to common stockholders	$	0.25		$	(0.06	)	$	(0.19	)	$	0.82		$	1.01		$	0.24		$	0.73		$	0.54
Income (loss) from discontinued operations attributable to common stockholders		0.11			0.03			0.04			0.05			0.02			0.02			—			—
Net income (loss) attributable to common stockholders	$	0.36		$	(0.03	)	$	(0.15	)	$	0.87		$	1.03		$	0.26		$	0.73		$	0.54
Diluted:
Income (loss) from continuing operations attributable to common stockholders	$	0.24		$	(0.06	)	$	(0.19	)	$	0.78		$	0.99		$	0.24		$	0.73		$	0.54
Income (loss) from discontinued operations attributable to common stockholders		0.11			0.03			0.04			0.05			0.02			0.02			—			—
Net income (loss) attributable to common stockholders	$	0.35		$	(0.03	)	$	(0.15	)	$	0.83		$	1.01		$	0.26		$	0.73		$	0.54

13

	Six Months Ended June 30,						Years Ended December 31,									Three Months Ended December 31,			Years Ended September 30,
	2009			2008			2008			2007			2006			2005			2005			2004
	(in thousands, except per share data)
Balance sheet data (at period end):
Property, plant and equipment, net	$	3,714,402		$	3,414,243		$	3,744,815		$	3,210,785		$	884,812		$	535,933		$	508,822		$	314,582
Total assets(2)		4,581,366			5,357,106			4,845,881			4,919,052			1,379,838			1,059,751			762,566			425,200
Total debt, including current portion		2,154,589			2,069,567			2,413,082			1,994,456			324,151			298,781			191,727			135,625
Total stockholders’ equity		1,637,019			1,602,926			1,529,568			2,008,944			677,728			456,147			310,473			223,227
Book value per common share(1)		41.66			39.75			38.24			49.19			15.28			10.14			6.90			5.66
Cash flow data:
Net cash provided by (used in) operating activities(3)	$	119,655		$	15,453		$	(47,416	)	$	195,085		$	62,186		$	53,485		$	113,409		$	62,386
Net cash provided by (used in) investing activities(3)		153,800			(261,554	)		(643,893	)		(3,508,157	)		(184,157	)		(195,567	)		(296,255	)		(182,615	)
Net cash provided by (used in) financing activities		(296,620	)		341,680			649,909			3,273,881			268,108			179,046			171,935			124,049

(1) Amounts have been adjusted to reflect Atlas America’s 3-for-2 stock splits on May 30, 2008, May 25, 2007 and March 10, 2006.

(2) Certain pre-development costs and joint venture receivables previously netted with “Liabilities associated with drilling contracts” of $3.6 million, $3.6 million and $1.5 million as of December 31, 2005 and September 30, 2005 and 2004, respectively, have been reclassified from “Liabilities associated with drilling contracts” to oil and gas properties and accounts receivable to conform to the presentation of “Total assets” for all other periods presented.

(3) Net cash flows provided by operating activities and net cash flows used in investing activities have been restated for the three months ended December 31, 2005 and the fiscal years ended September 30, 2005 and 2004 to conform to the current presentation for all other periods presented (see note 2 above). As a result, net cash flows provided by operating activities have been increased by $0.7 million, $1.4 million and $12.3 million for the three months ended December 31, 2005 and the fiscal years ended September 30, 2005 and 2004, respectively, and net cash flows used in investing activities has been decreased by the same amount for the respective periods, except for the fiscal year ended September 30, 2004, which decreased net cash flows in investing activities by $0.8 million and net cash flows provided by financing activities by $11.5 million.

14

Selected Historical Financial Data of Atlas Energy

In June 2006, Atlas Energy changed its year end from September 30 to December 31, and, therefore, the selected historical financial data below includes a transition period of the three months ended December 31, 2005, and its new year ended December 31.

The following table should be read together with Atlas Energy’s audited 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 Atlas Energy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008 and Atlas Energy’s unaudited consolidated financial statements and notes thereto included within Item 1, “Financial Statements” and Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of Atlas Energy’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009. Atlas Energy has 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 its audited combined and consolidated financial statements incorporated by reference into this joint proxy statement/prospectus. Atlas Energy 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 its audited combined and consolidated financial statements, which are not included within this joint proxy statement/prospectus. Such financial statements have been audited by Grant Thornton LLP, independent registered public accounting firm. Atlas Energy derived the financial data as of June 30, 2009 and 2008 and for the six months ended June 30, 2009 and 2008 from its unaudited consolidated financial statements incorporated by reference into this joint proxy statement/prospectus.

The selected financial data set forth in the table include Atlas Energy’s historical consolidated financial statements, which have been adjusted to reflect the adoption of SFAS No. 160. SFAS No. 160 amends ARB No. 51 to establish accounting and reporting standards for the non-controlling interest (minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling 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 non-controlling interest. Atlas Energy adopted the requirements of SFAS No. 160 on January 1, 2009.

	Six Months Ended June 30,				Years Ended December 31,						Three Months Ended December 31,		Years Ended September 30,
	2009		2008		2008		2007		2006		2005		2005		2004
	(in thousands, except per share data)
Income statement data:
Revenues:
Gas and oil production	$	141,922	$	155,183	$	311,850	$	180,125	$	88,449	$	24,086	$	63,499	$	48,526
Partnership management:
Well construction and completion		175,735		226,479		415,036		321,471		198,567		42,145		134,338		86,880
Administration and oversight		6,494		10,154		19,362		18,138		11,762		2,964		9,590		8,396
Well services		9,899		10,064		20,482		17,592		12,953		2,561		9,552		8,430
Gathering(1)		10,112		10,265		20,670		14,314		9,251		1,407		4,359		4,191
Gain on mark-to-market derivatives		—		—		—		26,257		—		—		—		—
Total revenues		344,162		412,145		787,400		577,897		320,982		73,163		221,338		156,423

15

	Six Months Ended June 30,						Years Ended December 31,									Three Months Ended December 31,			Years Ended September 30,
	2009			2008			2008			2007			2006			2005			2005			2004
	(in thousands, except per share data)
Costs and expenses:
Gas and oil production(1)	$	27,294		$	28,286		$	59,579		$	32,193		$	13,881		$	2,441		$	8,165		$	7,289
Partnership management:
Well construction and completion		149,098			196,939			359,609			279,540			172,666			36,648			116,816			75,548
Well services		4,544			5,062			10,654			9,062			7,337			1,487			5,167			4,398
Gathering(1)		10,978			9,733			19,539			13,995			29,545			7,968			21,981			17,242
General and administrative		26,817			24,078			44,659			39,414			24,604			5,981			13,804			12,758
Depreciation, depletion and amortization		55,303			44,758			95,434			56,942			22,491			4,916			14,061			12,064
Total costs and expenses		278,284			308,856			589,474			431,146			270,524			59,441			179,994			129,299
Operating income		65,878			103,289			197,926			146,751			50,458			13,722			41,344			27,124
Other income (expense):
Interest expense		(28,108	)		(27,868	)		(56,306	)		(30,096	)		—			—			—			—
Other, net		79			519			1,223			881			1,369			57			79			444
Total other income (expense)		(28,029	)		(27,349	)		(55,083	)		(29,215	)		1,369			57			79			444
Income before cumulative effect of accounting change		37,849			75,940			142,843			117,536			51,827			13,779			41,423			27,568
Cumulative effect of accounting change(2)		—			—			—			—			6,355			—			—			—
Net income		37,849			75,940			142,843			117,536			58,182			13,779			41,423			27,568
Income attributable to non-controlling interests		(30	)		(38	)		(64	)		(32	)		—			—			—			—
Net income attributable to members’ interests	$	37,819		$	75,902		$	142,779		$	117,504		$	58,182		$	13,779		$	41,423		$	27,568
Net income attributable to Class B members per unit(3):
Basic	$	0.70		$	1.15		$	2.12		$	2.30		$	0.08
Diluted	$	0.70		$	1.14		$	2.11		$	2.28		$	0.08
Cash flow data:
Cash provided by (used in) operating activities(4)	$	135,741		$	66,194		$	256,604		$	235,416		$	84,622		$	44,312		$	91,889		$	54,866
Cash used in investing activities(4)		(86,189	)		(135,764	)		(347,789	)		(1,472,868	)		(79,674	)		(17,901	)		(60,419	)		(33,535	)
Cash provided by (used in) financing activities		(50,358	)		48,684			71,582			1,253,877			(17,033	)		(11,739	)		(25,401	)		(26,433	)
Capital expenditures(4)		96,413			135,670			347,656			201,169			79,721			20,758			61,979			34,743

16

	Six Months Ended June 30,				Years Ended December 31,						Three Months Ended December 31,		Years Ended September 30,
	2009		2008		2008		2007		2006		2005		2005		2004
	(in thousands, except per share data)
Balance sheet data (at period end):
Total assets(5)	$	2,304,813	$	2,081,962	$	2,291,317	$	1,905,918	$	424,077	$	318,623	$	273,257	$	199,945
Liabilities associated with drilling contracts(6)		88,909		36,520		96,883		118,017		79,320		58,990		49,932		26,457
Long-term debt, including current maturities		862,289		767,035		873,655		740,030		68		156		81		420
Total members’ equity		1,064,937		637,204		1,039,523		836,357		212,682		154,519		146,142		109,461
Book value per unit		16.80		10.37		16.66		17.10		5.81

(1) Atlas Energy charges gathering fees to its investment partnership wells that are connected to Atlas Pipeline’s gathering systems. Historically, Atlas Energy in turn paid these fees, plus an additional amount to bring the total gathering charge up to, generally, 16% of the gas sales price, to Atlas Pipeline in accordance with Atlas Energy’s gathering agreements with it. Upon the completion of Atlas Energy’s initial public offering, Atlas America assumed Atlas Energy’s obligation to pay gathering fees to Atlas Pipeline. Atlas Energy is obligated to pay the gathering fees it receives from its investment partnerships to Atlas America, with the result that Atlas Energy’s gathering revenues and expenses within its partnership management segment net to $0. 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. Atlas America E & P Operations also owned several small gathering systems. The expenses associated with these systems are shown as gathering fees on Atlas Energy’s combined statements of income. Atlas Energy does not own these gathering systems after the completion of its initial public offering.

(2) The cumulative effect of accounting change results from Atlas Energy’s adoption of FIN 47, “Accounting for Conditional Asset Retirement Obligations.”

(3) The amounts for the years ended December 31, 2008 and 2007 have been adjusted to reflect Atlas Energy’s adoption of the Financial Accounting Standards Board Staff Position No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.”

(4) Net cash flows provided by operating activities and net cash flows used in investing activities and capital expenditures have been restated for the years ended December 31, 2008, 2007 and 2006, the three months ended December 31, 2005, and the fiscal years ended September 30, 2005 and 2004 to conform to the current presentation as of June 30, 2009 (see note 4 above). As a result, net cash flows provided by operating activities have been increased by $6.7 million, $4.4 million, $4.1 million, $0.7 million, $1.4 million and $12.3 million for the years ended December 31, 2008, 2007 and 2006, the three months ended December 31, 2005, and the fiscal years ended September 30, 2005 and 2004, respectively, and net cash flows used in investing activities and capital expenditures has been decreased by the same amount for the respective periods.

(5) Certain pre-development costs and joint venture receivables previously netted with “Liabilities associated with drilling contracts” of $20.6 million, $14.7 million, $8.6 million, $3.6 million, $3.6 million and $1.5 million as of June 30 and December 31, 2008, 2007, 2006 and 2005, and September 30, 2005 and 2004, respectively, have been reclassified from “Liabilities associated with drilling contracts” to oil and gas properties and accounts receivable to conform to the presentation of “Total assets” as of June 30, 2009.

(6) The amounts previously included within “Liabilities associated with drilling contracts” in Atlas Energy’s consolidated financial statements as of December 31, 2008, 2007, 2006 and 2005, and September 30, 2005 and 2004 have been increased (decreased) by $0.2 million, $(14.5) million, $7.5 million, $(11.5), $(11.1) and $(2.9) million, respectively, have been reclassified from “Liabilities associated with drilling contracts” to oil and gas properties, accounts receivable and accrued well drilling and completion costs to conform to the presentation of “Liabilities associated with drilling contracts” as of June 30, 2009.

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Selected Unaudited Pro Forma Condensed Consolidated Financial Information

The following unaudited pro forma condensed consolidated financial data reflects Atlas America’s historical results as adjusted on a pro forma basis to give effect to (a) the merger and related transactions, (b) Atlas Pipeline’s May 2009 disposition of its subsidiaries, Atlas Arkansas Pipeline, LLC and Mid-Continent Arkansas Pipeline, LLC (which we refer to as the “NOARK Holding Companies”), which collectively own 100% of the ownership interests in NOARK Pipeline System, Limited Partnership (which we refer to as “NOARK”), which owns the NOARK gas gathering and interstate pipeline system, for $294.5 million in cash, including $2.5 million received in July 2009 upon the delivery of the audited financial statements for the NOARK system assets to the buyer in accordance with the agreement of sale, and (c) Atlas Pipeline’s June 2009 contribution of its Appalachia Basin natural gas gathering system (which we refer to as the “Appalachia System”) to Laurel Mountain Midstream, LLC (which we refer to as “Laurel Mountain”), a joint venture between Atlas Pipeline and subsidiaries of The Williams Companies, Inc. (which we refer to as “Williams”), in return for net proceeds of $87.8 million in cash, preferred distribution rights entitling Atlas Pipeline to receive payments under a $25.5 million note and a 49% ownership interest in Laurel Mountain. The unaudited pro forma consolidated condensed statement of operations information for the twelve months ended December 31, 2008 and the six months ended June 30, 2009 reflect these transactions as if they occurred as of the beginning of the respective period. The unaudited pro forma condensed consolidated balance sheet information reflects the merger and related transactions and Atlas Pipeline’s receipt of an additional $2.5 million in cash in July 2009 from the May 2009 disposition of the NOARK system assets upon the delivery of the audited financial statements for the NOARK system assets to the buyer in accordance with the agreement of sale as if the transactions occurred as of June 30, 2009.

Such unaudited pro forma condensed combined financial data is based on the historical financial statements of Atlas America and Atlas Energy and on publicly available information and certain assumptions and adjustments as discussed in the section entitled “Unaudited Pro Forma Condensed Consolidated Financial Information.” This unaudited pro forma condensed combined financial information is provided for illustrative purposes only and is not necessarily indicative of what the operating results or financial position of Atlas America or Atlas Energy would have been had the merger and related transactions been completed at the beginning of the periods or on the dates indicated, nor are they necessarily indicative of any future operating results or financial position. Atlas America or Atlas Energy may have performed differently had they been combined during the periods presented. The following should be read in connection with the section of this joint proxy statement/prospectus entitled “Unaudited Pro Forma Condensed Consolidated Financial Information” and other information included in or incorporated by reference into this joint proxy statement/prospectus.

	Six Months Ended June 30, 2009		Twelve Months Ended December 31, 2008
	(unaudited)
	(in thousands, except per share data)
Statement of Operations Data
Total revenue	$	648,837	$	2,052,925
Net income attributable to common stockholders	$	11,692	$	38,593
Net income attributable to common stockholders per share:
Basic	$	0.15	$	0.50
Diluted	$	0.15	$	0.48

	As of June 30, 2009
	(unaudited)
	(in thousands)
Balance Sheet
Total assets	$	4,581,366
Total liabilities	$	2,834,679
Stockholders’ equity	$	1,746,687

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Comparative Historical and Pro Forma Per Share/Per Unit Information

The following table sets forth selected historical per share information of Atlas America and Atlas Energy and pro forma combined per share information after giving effect to (a) the merger and related transactions, (b) Atlas Pipeline’s May 2009 disposition of the NOARK Holding Companies and (c) Atlas Pipeline’s June 2009 disposition of the Appalachia System. The unaudited pro forma condensed consolidated statement of operations information for the twelve months ended December 31, 2008 and the six months ended June 30, 2009 reflect these transactions as if they occurred as of the beginning of the respective period. The unaudited pro forma condensed consolidated balance sheet information reflects the merger and related transactions and Atlas Pipeline’s receipt of an additional $2.5 million in cash in July 2009 from the May 2009 disposition of the NOARK system assets upon the delivery of the audited financial statements for the NOARK system assets to the buyer in accordance with the agreement of sale as if the transactions occurred as of June 30, 2009.

The unaudited pro forma condensed combined financial data is based on the historical financial statements of Atlas America and Atlas Energy and on publicly available information and certain assumptions and adjustments as discussed in the section entitled “Unaudited Pro Forma Condensed Consolidated Financial Information.” This unaudited pro forma condensed combined financial information is provided for illustrative purposes only and is not necessarily indicative of what the operating results or financial position of Atlas America or Atlas Energy would have been had the merger and related transactions been completed at the beginning of the periods or on the dates indicated, nor are they necessarily indicative of any future operating results or financial position. Atlas America or Atlas Energy may have performed differently had they been combined during the periods presented. The following should be read in connection with the section of this joint proxy statement/prospectus entitled “Unaudited Pro Forma Condensed Consolidated Financial Information” and other information included in or incorporated by reference into this joint proxy statement/prospectus.

	Six Months Ended June 30, 2009		Twelve Months Ended December 31, 2008
Atlas America Historical Per Share Data
Basic earnings (loss) per common share	$	0.36	$	(0.15	)
Diluted earnings (loss) per common share	$	0.35	$	(0.15	)
Cash dividends declared per common share		—	$	0.16
Book value per common share at end of period	$	41.66	$	38.24
Atlas Energy Historical Per Unit Data
Basic earnings per common unit	$	0.70	$	2.12
Diluted earnings per common unit	$	0.70	$	2.11
Cash dividends declared per common unit		—	$	2.42
Book value per common unit at end of period	$	16.80	$	16.66
Atlas America Pro Forma Combined Per Share Data
Basic earnings per common share	$	0.15	$	0.50
Diluted earnings per common share	$	0.15	$	0.48
Cash dividends declared per common share		—	$	2.09
Book value per common share at end of period	$	22.37
Atlas Energy Equivalent Pro Forma Per Unit Data(1)
Basic earnings per common unit	$	0.17	$	0.58
Diluted earnings per common unit	$	0.17	$	0.56
Cash distributions declared per common unit		—	$	2.42
Book value per common unit at end of period	$	25.95

(1) Determined using the related Atlas America pro forma combined per share data multiplied by the exchange ratio of 1.16.

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Comparative Per Share/Per Unit Market Information

The following table presents the last reported sale price of a share of Atlas America common stock, as reported on NASDAQ, the last reported sale price of an Atlas Energy common unit, as reported on the NYSE, and the equivalent value of the merger consideration per Atlas Energy common unit, in each case, on April 24, 2009, the last full trading day prior to the public announcement of the proposed merger, and on August 20, 2009, the last trading day prior to the printing of this joint proxy statement/prospectus for which it was practicable to include this information. See “Atlas Energy Proposal / Atlas America Proposal 1: The Merger — Comparative Stock Prices and Dividends and Distributions” for further information about the historical prices of these securities.

Date	Atlas America Common Stock	Atlas Energy Common Units	Value of Merger Consideration Per Atlas Energy Common Unit(1)
April 24, 2009	$12.41	$14.35	$14.40
August 20, 2009	$23.49	$27.01	$27.25

(1) Calculated by multiplying the last reported sale price of Atlas America common stock by the 1.16 per share exchange ratio.

The market value of the shares of Atlas America common stock to be issued in exchange for Atlas Energy common units upon the completion of the merger will not be known at the time Atlas America stockholders vote on the proposal to approve the stock issuance or at the time Atlas Energy unitholders vote on the proposal to approve merger agreement and the transactions contemplated thereby, including the merger. The exchange ratio is fixed and will not be adjusted for changes in the stock or unit prices of either company before the merger is completed.

The above table shows historical stock price comparisons and the equivalent value of the merger consideration per Atlas Energy common unit. Because the market prices of Atlas America common stock and Atlas Energy common units will likely fluctuate prior to the merger, these comparisons may not provide meaningful information to Atlas America stockholders in determining whether to vote for the proposal to approve the stock issuance, or to Atlas Energy unitholders in determining whether to vote for the proposal to approve the merger agreement and the transactions contemplated thereby, including the merger. Atlas America stockholders and Atlas Energy unitholders are encouraged to obtain current market quotations for Atlas America common stock and Atlas Energy common units and to review carefully the other information contained in this joint proxy statement/prospectus or incorporated by reference into this joint proxy statement/prospectus in considering whether to approve the proposals before them. See “Where You Can Find More Information.”

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RISK FACTORS

In addition to the other information included and incorporated by reference into this joint proxy statement/prospectus, including the matters addressed in the section entitled “Cautionary Statement Regarding Forward-Looking Statements,” you should carefully consider the following risks before deciding whether to vote for adoption of the merger agreement and approval of the merger and the other transactions contemplated by the merger agreement, in the case of Atlas Energy unitholders, or for approval of the stock issuance, in the case of Atlas America stockholders. In addition, you should read and consider the risks associated with the businesses of Atlas America and Atlas Energy because these risks will also affect the combined company. The risks associated with the business of Atlas Energy can be found below and in Atlas Energy’s Annual Report on Form 10-K for the year ended December 31, 2008, as updated by subsequent Quarterly Reports on Form 10-Q, all of which are filed with the SEC and incorporated by reference into this joint proxy statement/prospectus. You should also read and consider the other information in this joint proxy statement/prospectus and the other documents incorporated by reference into this joint proxy statement/prospectus. See the section entitled “Where You Can Find More Information.”

Risks Relating to the Merger

The exchange ratio is fixed and will not be adjusted in the event of any change in either the price of Atlas America common stock or the price of Atlas Energy common units.

If the merger is completed, each Atlas Energy common unit outstanding as of immediately prior to the effective time will be converted into the right to receive 1.16 shares of Atlas America common stock. This exchange ratio was fixed in the merger agreement and will not be adjusted for changes in the market price of either Atlas America common stock or Atlas Energy common units. Changes in the price of Atlas America common stock prior to the effective time will affect the market value of the merger consideration that Atlas Energy unitholders will receive in the merger. Stock price changes may result from a variety of factors (many of which are beyond the control of Atlas America and Atlas Energy), including:

• changes in the company’s businesses, operations and prospects;

• changes in market assessments of the business, operations and prospects of the company;

• market assessments of the likelihood that the merger will be completed, including related considerations regarding regulatory approvals of the merger;

• interest rates, general market and economic conditions and other factors generally affecting the price of securities; and

• federal, state and local legislation, governmental regulation and legal developments in the businesses in which Atlas America and Atlas Energy operate.

The price of Atlas America common stock at the closing of the merger may vary from its price on the date the merger agreement was executed, on the date of this joint proxy statement/prospectus and on the date of the special meetings. As a result, the market value represented by the exchange ratio will also vary. For example, based on the range of closing prices of Atlas America common stock during the period from April 24, 2009, the last trading day before public announcement of the merger, through August 20, 2009, the latest practicable date before the date of this joint proxy statement/prospectus, the exchange ratio represented a market value ranging from a low of $14.40 to a high of $27.25 for each Atlas Energy common unit.

Because the date that the merger is completed will be later than the date of the special meetings, at the time of your special meeting, you will not know the exact market value of the Atlas America common stock that Atlas Energy unitholders will receive upon completion of the merger.

If the price of Atlas America common stock increases between the date the merger agreement was signed or the date of the Atlas America special meeting and the effective time of the merger, Atlas Energy unitholders will receive shares of Atlas America common stock that have a market value that is greater than the market value of

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such shares when the merger agreement was signed or the date of the Atlas America special meeting, respectively, and Atlas America will issue shares of its common stock with a market value greater than the market value calculated pursuant to the exchange ratio on those earlier dates. Therefore, while the exchange ratio is fixed, Atlas America stockholders cannot be sure of the market value of the consideration that will be paid to Atlas Energy unitholders upon completion of the merger.

If the price of Atlas America common stock declines between the date the merger agreement was signed or the date of the Atlas Energy special meeting and the effective time of the merger, including for any of the reasons described above, Atlas Energy unitholders will receive shares of Atlas America common stock that have a market value upon completion of the merger that is less than the market value calculated pursuant to the exchange ratio on the date the merger agreement was signed or on the date of the Atlas Energy special meeting, respectively. Therefore, while the number of Atlas America shares to be issued in the merger is fixed, Atlas Energy unitholders cannot be sure of the market value of the Atlas America common stock they will receive upon completion of the merger or the market value of Atlas America common stock at any time after the completion of the merger.

There will be material differences between the current rights of Atlas Energy unitholders and the rights they can expect to have as Atlas America stockholders.

Atlas Energy unitholders will receive Atlas America common stock in the merger and will become Atlas America stockholders. As Atlas America stockholders, their rights as stockholders will be governed by the Atlas America charter and bylaws. In addition, whereas Atlas Energy is currently a Delaware limited liability company, governed by the Delaware Limited Liability Company Act, Atlas America is a Delaware corporation, governed by the Delaware General Corporation Law. As a result, there will be material differences between the current rights of Atlas Energy unitholders and the rights they can expect to have as Atlas America stockholders, as well as differences in how stockholders and unitholders are taxed. For example, profits at Atlas Energy flow through Atlas Energy and are taxed once, at the unitholder level, regardless of whether distributions are made to Atlas Energy unitholders. After the merger, profits of the combined company will be subject to tax at the corporation level, and potentially again, if and when distributed to Atlas America stockholders at the stockholder level. In addition, after the merger, the combined company will have a classified board, with directors elected for a three-year term on a staggered basis, whereas all Atlas Energy directors are currently elected every year for an annual term. For a discussion of other material differences, see “Comparison of Rights of Atlas America Stockholders and Atlas Energy Unitholders.”

The combined company may fail to realize the anticipated cost savings, growth opportunities and synergies and other benefits anticipated from the merger, which could adversely affect the value of Atlas America common stock.

Atlas America and Atlas Energy currently operate as separate public companies. The success of the merger will depend, in part, on our ability to realize the anticipated synergies and growth opportunities from combining the businesses, as well as the projected stand-alone cost savings and revenue growth trends identified by each company. In addition, on a combined basis, Atlas America and Atlas Energy expect to benefit from operational synergies resulting from the consolidation of capabilities and elimination of redundancies as well as greater efficiencies from increased scale. Management also intends to focus on revenue synergies for the combined entity. However, management must successfully combine the businesses of Atlas America and Atlas Energy in a manner that permits these cost savings and synergies to be realized. In addition, it must achieve the anticipated savings without adversely affecting current revenues and our investments in future growth. If it is not able to successfully achieve these objectives, the anticipated cost savings, revenue growth and synergies may not be realized fully or at all, or may take longer to realize than expected.

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The receipt of the merger consideration will be taxable for U.S. federal income tax purposes and Atlas Energy unitholders could recognize tax gain or have tax liability in excess of the merger consideration received.

Atlas Energy unitholders generally will recognize gain with respect to the exchange of Atlas Energy common units for shares of Atlas America common stock in the merger in an amount equal to the excess of (1) each Atlas Energy unitholder’s “amount realized” for U.S. federal income tax purposes, which equals the sum of the fair market value of the shares of Atlas America common stock and any cash received in lieu of fractional shares (including any amounts of cash withheld), plus his or her share of Atlas Energy’s pre-merger liabilities, over (2) such Atlas Energy unitholder’s aggregate adjusted tax basis in his or her Atlas Energy common units (including basis attributable to his or her share of Atlas Energy’s pre-merger liabilities). Atlas Energy unitholders generally will recognize a loss to the extent that the amount of their basis described in clause (2) above exceeds the amount realized described in clause (1) above.

Because the “amount realized” includes the amount of Atlas Energy’s liabilities allocated to each Atlas Energy unitholder immediately prior to the merger, it is possible that the amount of gain Atlas Energy unitholders recognize, or even their resulting tax liability, could exceed the fair market value of the shares of Atlas America common stock plus any cash they receive, perhaps by a significant amount. The application of other, complicated tax rules also may give rise to adverse tax consequences to Atlas Energy unitholders. Because the tax consequences of the merger to an Atlas Energy unitholder will depend on his or her particular factual circumstances and are uncertain in some material respects, Atlas Energy unitholders should consult their tax advisors regarding the potential tax consequences of exchanging Atlas Energy common units for shares of Atlas America common stock in the merger.

Atlas Energy unitholders will be allocated taxable income and gain of Atlas Energy through the time of the merger and will not receive any additional distributions attributable to that income.

Atlas Energy unitholders will be allocated their proportionate share of Atlas Energy’s taxable income and gain for the period ending at the time of the merger. Atlas Energy unitholders will have to report such income even though they will not receive any additional cash distributions from Atlas Energy attributable to such income. Such income, however, will be included in the tax basis of the units held by such Atlas Energy unitholders, and thus reduce their gain (or increase their loss) recognized as a result of the merger.

Lawsuits have been filed against Atlas Energy, Atlas America, and certain officers and directors of both companies challenging the merger, and any adverse judgment for monetary damages could have a material adverse effect on the operations of the combined company after the merger.

Atlas Energy, Atlas America, and certain officers and directors of both companies are named defendants in a consolidated purported class action lawsuit brought by Atlas Energy unitholders in Delaware Chancery Court generally alleging claims of breach of fiduciary duty in connection with the merger transaction. The complaint alleges that the defendants breached purported fiduciary duties owed to the public unitholders by negotiating and executing a merger agreement that allegedly provides unfair consideration to the public unitholders and that was reached pursuant to an allegedly unfair negotiating process between the special committee of Atlas Energy and Atlas America. The complaint also alleges that the defendants have failed to disclose material information regarding the merger. Plaintiffs initially filed five separate purported class actions, and the Chancery Court issued an order of consolidation on June 15, 2009. Plaintiffs filed a Verified Consolidated Class Action Complaint on July 1, 2009, which has superseded all prior complaints. On July 27, 2009, the Chancery Court granted the parties’ scheduling stipulation, setting a preliminary injunction hearing for September 4, 2009. The lawsuit originally sought monetary damages or injunctive relief, or both. However, on August 7, 2009, Plaintiffs advised the Chancery Court by letter that they were not pursuing their motion for a preliminary injunction, and requested that the September 4, 2009 hearing date be removed from the Court’s calendar. Plaintiffs have advised counsel for the defendants that plaintiffs intend to continue to pursue the action for monetary damages after the merger is completed. Predicting the outcome of this lawsuit is difficult.

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One of the conditions to the completion of the merger is that no judgment, order, injunction, decision, opinion or decree issued by a court or other governmental entity that makes the merger illegal or prohibits the consummation of the merger shall be in effect. A preliminary injunction could have delayed or jeopardized the completion of the merger, and an adverse judgment granting permanent injunctive relief could have indefinitely enjoined completion of the merger. An adverse judgment for monetary damages could have a material adverse effect on the operations of the combined company after the merger.

The merger is subject to various closing conditions, and any delay in completing the merger may reduce or eliminate the benefits expected.

The merger is subject to the satisfaction of a number of other conditions beyond the parties’ control that may prevent, delay or otherwise materially adversely affect the completion of the transaction. On May 15, 2009, early termination of the waiting period under the HSR Act was granted. In July 2009, two other conditions to completion of the merger were satisfied. On July 10, 2009, Atlas Energy received the requisite consent from its lenders to amend the Atlas Energy credit agreement to permit the merger, and on July 13, 2009, the Atlas America stockholders approved an amendment to the Atlas America charter to increase the number of authorized shares of Atlas America common stock so that Atlas America has sufficient authorized shares to complete the merger. Atlas America and Atlas Energy cannot predict with certainty, however, whether and when any of the other conditions to completion of the merger will be satisfied. Any delay in completing the merger could cause the combined company not to realize, or delay the realization, of some or all of the benefits that the companies expect to achieve from the transaction.

Failure to complete the merger or delays in completing the merger could negatively affect the price of Atlas Energy common units and Atlas America common stock and each company’s future business and operations.

If the merger is not completed for any reason, Atlas America and Atlas Energy may be subject to a number of material risks, including the following:

• the individual companies will not realize the benefits expected from the merger, including a potentially enhanced financial and competitive position;

• the price of the Atlas Energy common units or the Atlas America common stock may decline to the extent that the current market price of these securities reflects a market assumption that the merger will be completed; and

• some costs relating to the merger must be paid even if the merger is not completed.

The issuance of shares of Atlas America common stock to Atlas Energy unitholders in the merger will substantially reduce the percentage ownership interests of Atlas America stockholders in Atlas America.

If the merger is completed, Atlas America and Atlas Energy expect that, based on Atlas Energy common units outstanding as of the record date for the special meetings, Atlas America will issue approximately 38.8 million shares of Atlas America common stock in the merger. In addition, approximately 3.0 million shares of Atlas America common stock will be reserved for issuance upon conversion of former Atlas Energy equity awards. As a result, the former Atlas Energy unitholders (other than Atlas America and Atlas Energy Management, which will not receive Atlas America stock in the merger) are expected to own approximately 49.6% of the outstanding shares of Atlas America common stock outstanding after the merger, and the Atlas America stockholders as of immediately prior to the merger are expected to own approximately 50.4% of the outstanding shares of Atlas America common stock outstanding after the merger. The merger will therefore result in a significant reduction in the relative percentage interests of current Atlas America stockholders in earnings, voting, liquidation value and book and market value.

The market price of the Atlas America common stock and the results of operations of Atlas America after the merger may be affected by factors different from those affecting Atlas Energy or Atlas America currently.

The businesses of Atlas America and Atlas Energy, while similar in many respects, also have some differences, and, accordingly, the results of operations of Atlas America following the merger and the market price of Atlas America common stock following the merger may be affected by factors different from those

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currently affecting the independent results of operations and market prices of each of Atlas America and Atlas Energy. As a holder of Atlas America common stock following the merger, you will be subject to the risks and liabilities affecting these other businesses, including those of Atlas Pipeline Holdings and Atlas Pipeline, as well as those of Atlas Energy. For a discussion of the businesses of Atlas America, Atlas Energy, Atlas Pipeline Holdings and Atlas Pipeline and certain factors to consider in connection with those businesses, see “Risk Factors — Risks Relating to Atlas America,” “Risk Factors — Risks Relating to the Business of Atlas Energy,” “Risk Factors — Risks Relating to the Business of Atlas Pipeline Holdings and Atlas Pipeline,” and “Information about Atlas America” and read the documents incorporated by reference in this joint proxy statement/prospectus and referred to under “Where You Can Find More Information.”

The pro forma financial statements are presented for illustrative purposes only and may not be an indication of the combined company’s financial condition or results of operations following the transaction.

The pro forma financial statements contained in this joint proxy statement/prospectus are presented for illustrative purposes only and may not be an indication of the combined company’s financial condition or results of operations following the merger for several reasons. The pro forma financial statements have been derived from the historical financial statements of Atlas America and Atlas Energy and adjustments and assumptions have been made regarding the combined company after giving effect to the transaction. The information upon which these adjustments and assumptions have been made is preliminary, and these kinds of adjustments and assumptions are difficult to make with accuracy. Moreover, the pro forma financial statements do not reflect all costs that are expected to be incurred by the combined company in connection with the transaction. As a result, the actual financial condition and results of operations of the combined company following the merger may not be consistent with, or evident from, these pro forma financial statements.

The assumptions used in preparing the pro forma financial information may not prove to be accurate, and other factors may affect the combined company’s financial condition or results of operations following the transaction. Any decline or potential decline in the combined company’s financial condition or results of operations may cause significant variations in the stock price of the combined company. See “Unaudited Pro Forma Condensed Consolidated Financial Information.”

Financial forecasts involve risks, uncertainties and assumptions, many of which are beyond the control of Atlas America and Atlas Energy. As a result, financial forecasts may not be realized and are not necessarily indicative of actual future results.

The financial forecasts of Atlas America and Atlas Energy contained in this joint proxy statement/prospectus involve risks, uncertainties and assumptions and are not a guarantee of performance. The future financial results of Atlas America, Atlas Energy and, if the merger is completed, the combined company, may materially differ from those expressed in the financial forecasts due to factors that are beyond Atlas America’s and Atlas Energy’s ability to control or predict. Neither Atlas America nor Atlas Energy can provide any assurance that the financial forecasts will be realized or that their respective future financial results will not materially vary from the financial forecasts. Because the financial forecasts cover multiple years, the information by its nature becomes subject to greater uncertainty with each successive year. The financial forecasts do not take into account any circumstances or events occurring after the date they were prepared.

More specifically, the financial forecasts:

• necessarily make numerous assumptions, many of which are beyond the control of Atlas America and Atlas Energy and may not prove to be accurate;

• do not necessarily reflect revised prospects for Atlas America’s and Atlas Energy’s businesses, changes in general business or economic conditions, or any other transaction or event that has subsequently occurred or that may occur and that was not anticipated at the time the forecasts were prepared; and

• are not necessarily indicative of actual future results, which may be significantly more favorable or less favorable than reflected in the forecasts.

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The financial forecasts were not prepared with a view toward public disclosure or compliance with published guidelines of the SEC or the American Institute of Certified Public Accountants for preparation and presentation of prospective financial information or GAAP and do not reflect the effect of any proposed or other changes in GAAP that may be made in the future. In addition, the financial forecasts were developed from historical financial statements and do not give effect to any changes or expenses as a result of the merger or any other effects of the merger. See “Atlas Energy Proposal / Atlas America Proposal 1: The Merger — Certain Projections.” Inclusion of financial forecasts in this joint proxy statement/prospectus should not be regarded as a representation to Atlas America stockholders or Atlas Energy unitholders that the financial forecasts will be achieved or would have been achieved absent the merger. Neither Atlas America nor Atlas Energy undertakes to update any such forecasts.

Some of the conditions to the merger may be waived by Atlas America or Atlas Energy without resoliciting equityholder approval of the proposals approved by them.

Some of the conditions set forth in the merger agreement may be waived by Atlas America or Atlas Energy, subject to the agreement of the other party in specific cases. See “The Merger Agreement — Waiver and Amendment.” If any conditions are waived, Atlas America and Atlas Energy will evaluate whether amendment of this joint proxy statement/prospectus and resolicitation of proxies is warranted. If the board of directors of Atlas America or Atlas Energy determines that resolicitation of their respective stockholders or unitholders is not warranted, the applicable company will have the discretion to complete the transaction without seeking further stockholder or unitholder approval.

The directors and officers of Atlas America and Atlas Energy may have interests that are in addition to, or differ from, your interests.

Certain officers and directors of Atlas America are also directors and officers of Atlas Energy. For example, Edward E. Cohen and Jonathan Z. Cohen are directors of both Atlas America and Atlas Energy. In addition, the following officers hold positions at both Atlas America and Atlas Energy:

Officer	Atlas America	Atlas Energy
Edward E. Cohen	Chairman, Chief Executive Officer, President	Chief Executive Officer
Jonathan Z. Cohen	Vice Chairman	Vice Chairman
Matthew Jones	Chief Financial Officer	Chief Financial Officer
Jeffrey C. Simmons	Executive Vice President	Senior Vice President
Frank Carolas	Executive Vice President	Senior Vice President
Sean P. McGrath	Chief Accounting Officer	Chief Accounting Officer
Daniel Herz	Senior Vice President — Corporate Development	Senior Vice President — Corporate Development
Lisa Washington	Senior Vice President, Chief Legal Officer, Secretary	Senior Vice President, Chief Legal Officer, Secretary
James D. Toth	Treasurer	Treasurer

In considering the recommendation of the Atlas America board for the proposal to approve the stock issuance or the recommendation of the Atlas Energy board for the proposal to adopt the merger agreement and approve the transactions contemplated therein, including the merger, you should consider that the executive officers and directors of Atlas America and Atlas Energy may have interests that differ from, or are in addition to, their interests as Atlas America stockholders or Atlas Energy unitholders generally. These interests include the following:

• such executive officers and directors have the right to indemnification under the respective organizational documents of such entity and the merger agreement;

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• certain directors will continue to serve on the board of directors of the combined company, including Edward E. Cohen and Jonathan Z. Cohen, Chief Executive Officer and Vice Chairman, respectively, of both Atlas America and Atlas Energy, the six independent directors serving on the Atlas America board of directors at the time the merger is consummated and the four independent directors serving on the Atlas Energy board of directors at the time the merger is consummated;

• each outstanding restricted unit, phantom unit and unit option of Atlas Energy held by such executive officers and directors will be converted in the merger into an equivalent restricted share, phantom share and stock option of Atlas America, respectively, with adjustments in the number of shares and exercise price to reflect the exchange ratio, but otherwise on the same terms and conditions as were applicable prior to the merger;

• certain Atlas America directors and executive officers own Atlas Energy common units; and

• certain Atlas Energy directors and executive officers own Atlas America common stock.

See “Atlas Energy Proposal / Atlas America Proposal 1: The Merger — Interests of Atlas America Directors and Executive Officers in the Merger” and “Atlas Energy Proposal / Atlas America Proposal 1: The Merger — Interests of Atlas Energy Directors and Executive Officers in the Merger.”

Risks Relating to Atlas America

Atlas America may pay a limited dividend or no dividend to its stockholders.

After the merger, Atlas America may pay a limited dividend, or no dividend, to its stockholders. The determination of the amount of future dividends on Atlas America common stock, if any, will be determined solely by the Atlas America board of directors, based upon its analysis of factors that it deems relevant. Generally, these factors include Atlas America’s results of operations, financial condition, capital requirements and investment opportunities.

The Amended and Restated Operating Agreement of Atlas Energy (which we refer to as the “Atlas Energy operating agreement”) requires that, within 45 days after the end of each quarter, Atlas Energy distribute all of its “available cash” to unitholders. “Available cash” is defined in the Atlas Energy operating agreement as all cash on hand at the end of the quarter plus cash on hand from working capital borrowings made after the end of the quarter, less the amount of cash that the Atlas Energy board of directors determines in its discretion is necessary or appropriate to provide for the proper conduct of business (including reserves for future capital expenditures and credit needs), comply with applicable law and any of Atlas Energy’s debt instruments or other contracts, including the merger agreement, and certain other considerations, including reserving funds for future quarterly distributions.

Following consummation of the merger, Atlas America stockholders, including former Atlas Energy unitholders who become holders of Atlas America common stock as a result of the merger, may not receive dividends.

Atlas America may issue additional shares of common stock without the approval of Atlas America stockholders, which may dilute Atlas America common stockholders’ existing ownership interests and could depress the market price of Atlas America common stock.

The Atlas America charter authorizes Atlas America to issue 114 million shares of common stock, of which approximately 78.1 million shares will be outstanding upon consummation of the merger. Atlas America may issue shares of its common stock or other securities from time to time as consideration for acquisitions and investments. If any such acquisition or investment is significant, the number of shares of Atlas America common stock, or the number or aggregate principal amount, as the case may be, of other securities that Atlas America

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may issue may in turn be substantial. The issuance of additional shares of Atlas America common stock or other securities may have the following effects:

• the proportionate ownership of the existing common stockholders’ interest in Atlas America may decrease;

• the relative voting strength of each previously outstanding share of common stock may be diminished; and

• the market price of Atlas America common stock may decline.

Atlas America may issue shares of preferred stock in the future, which could make it difficult for another company to acquire Atlas America or could otherwise adversely affect holders of Atlas America common stock, which could depress the price of Atlas America common stock.

The Atlas America charter authorizes Atlas America to issue up to 1,000,000 shares of one or more series of preferred stock. The Atlas America board of directors has the authority to determine the preferences, limitations and relative rights of shares of preferred stock and to fix the number of shares constituting any series and the designation of such series, without any further vote or action by Atlas America stockholders. Atlas America preferred stock could be issued with voting, liquidation, dividend and other rights superior to the rights of Atlas America common stock. The potential issuance of preferred stock may delay or prevent a change in control of Atlas America, discouraging bids for Atlas America common stock at a premium over the market price, and materially and adversely affect the market price and the voting and other rights of the holders of Atlas America common stock.

Atlas America could be liable for taxes in connection with its tax matters agreement with Resource America.

In connection with the initial public offering of Atlas America common stock in 2004, Atlas America entered into a tax matters agreement with Resource America, which agreement governs Atlas America’s 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 Atlas America’s initial public offering, it is responsible for any U.S. federal income taxes attributable to Atlas America or any of its 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 Atlas America or one of its subsidiaries, on the other hand. However, in the event that Atlas America or one of its subsidiaries is 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, Atlas America is responsible for its portion of such income tax liability as if it and its subsidiaries had filed a separate tax return that included only it and its 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 Atlas America and its subsidiaries), and Atlas America is responsible for any U.S. state or local income taxes filed on returns that include only Atlas America and its subsidiaries.

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Atlas America has guaranteed certain debt of Atlas Pipeline Holdings and therefore will be liable for this debt if Atlas Pipeline Holdings is unable to meet its obligations. In addition, Atlas America holds two promissory notes from Atlas Pipeline Holdings, and Atlas America may not be paid if Atlas Pipeline Holdings defaults.

On June 1, 2009, Atlas Pipeline Holdings entered into an amendment to its revolving credit facility, dated as of July 26, 2006, with Wachovia Bank, National Association, as administrative agent, and the lenders thereunder. In connection with the execution of the amendment, Atlas Pipeline Holdings agreed to immediately repay $30 million of the approximately $46 million outstanding indebtedness under the credit facility, such that approximately $16 million currently remains outstanding. Atlas Pipeline Holdings agreed to repay $4 million of the remaining $16 million on each of July 13, 2009, October 13, 2009 and January 13, 2010, with the balance of indebtedness being due on the original maturity date of April 13, 2010. In connection with the execution of this amendment, Atlas America agreed to guarantee the remaining debt outstanding under the credit facility. Accordingly, if Atlas Pipeline Holdings is unable to make such payments, Atlas America, as guarantor, will be responsible for such payment, which guaranty has a cap equal to $17.5 million. Pursuant to this guaranty, Atlas America made a $4 million payment in respect of a payment due on July 13, 2009 under the Atlas Pipeline Holdings credit agreement.

Atlas Pipeline Holdings’ $30 million repayment was funded from the proceeds of (i) a loan from Atlas America in the amount of $15 million, with an interest rate of 12% per annum and a maturity date the day following the day Atlas Pipeline Holdings pays all outstanding indebtedness due under the credit facility, and (ii) the purchase by Atlas Pipeline of $15 million of preferred equity in a newly formed subsidiary of Atlas Pipeline Holdings. Moreover, in consideration of Atlas America’s guaranty, Atlas Pipeline Holdings issued to Atlas America an additional promissory note, in which the amount payable under the note equals the interest that would be payable on a loan with a principal amount equal to the outstanding indebtedness under Atlas Pipeline Holdings’ credit facility, where the interest rate equals 3.75% per annum and accrues quarterly. The maturity date on this note is the day following the day Atlas Pipeline Holdings pays all outstanding indebtedness due under the credit facility. Both promissory notes issued by Atlas Pipeline Holdings to Atlas America are payable-in-kind until their maturity date. If Atlas Pipeline Holdings defaults on either note, Atlas America may not receive any of the principal or interest due under such notes.

Risks Relating to the Business of Atlas Energy

Atlas America is a holding company and has no direct operations and no significant assets other than cash and its ownership interests in Atlas Energy, Atlas Pipeline Holdings and Atlas Pipeline. Therefore, risks to the business of Atlas Energy are also risks to Atlas America. Set forth below are the material risks to the business and results of operations of Atlas Energy, which risks could negatively affect Atlas America’s results of operations and business.

If commodity prices decline significantly, Atlas Energy’s revenue, profitability and cash flow from operations will decline.

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;

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• 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 Atlas America expects 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.

A decrease in natural gas prices could subject Atlas Energy’s oil and gas properties to a non-cash impairment loss under generally accepted accounting principles.

Generally accepted accounting principles require oil and gas properties and other long-lived assets to be reviewed for impairment whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. Atlas Energy tests its oil and gas properties on a field-by-field basis, by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on Atlas Energy’s own economic interests and Atlas Energy’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. Atlas Energy estimates prices based on current contracts in place at the impairment testing date, adjusted for basis differentials and market related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. Accordingly, further declines in the price of natural gas may cause the carrying value of Atlas Energy’s oil and gas properties to exceed the expected future cash flows, and a non-cash impairment loss would be required to be recognized in the financial statements for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

Unless Atlas Energy replaces its reserves, its reserves and production will decline, which would reduce its cash flow from operations and income.

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 Atlas Energy’s

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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, Atlas Energy 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 Atlas Energy’s 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 recovers 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 Atlas Energy’s 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 Atlas Energy’s financial condition and results of operations. In addition, its reserves or

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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 Atlas America’s investment in Atlas Energy.

Atlas Energy will be required to make substantial capital expenditures to increase its asset base. If Atlas Energy is unable to obtain needed capital or financing on satisfactory terms, its revenues will decline.

The natural gas and oil industry is capital intensive. Atlas Energy intends to finance its future capital expenditures with capital raised through equity and debt offerings, its investment partnerships, cash flow from operations and bank borrowings. If Atlas Energy is unable to obtain sufficient capital funds on satisfactory terms, it may be unable to increase or maintain its inventory of properties and reserve base, or be forced to curtail drilling or other activities. As a result, Atlas Energy’s revenues will decline and its ability to service its debt may be diminished. If Atlas Energy does not make sufficient or effective expansion capital expenditures, including with funds from third-party sources, it will be unable to expand its business operations.

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 it has achieved historically. Any of these factors could adversely affect Atlas Energy’s future growth.

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.

Atlas Energy has an active, ongoing 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;

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• integrating internal controls, compliance under the 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 Company acquisition has substantially changed Atlas Energy’s business, making it difficult to evaluate its business based upon its historical financial information.

In June 2007, Atlas Energy acquired DTE Gas & Oil Company, now known as Atlas Gas & Oil Company, from DTE Energy Company (which we refer to as “DTE Energy”) for approximately $1.3 billion in cash. This 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, Atlas Energy’s 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 production decline rates in the Marcellus Shale than in other areas of its Appalachian operations and wells drilled to the Marcellus Shale generally 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 June 30, 2009, Atlas Energy had drilled 163 wells to the Marcellus Shale, 145 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 its 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 that could adversely affect its financial position.

Atlas Energy currently has a substantial amount of indebtedness. As of June 30, 2009, it had total debt of approximately $862.3 million, consisting of $406.3 million of senior notes and $456.0 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 Atlas Energy to satisfy its financial obligations, including making scheduled principal and interest payments on the senior notes and its other indebtedness;

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• 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 Atlas Energy’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 and investments;

• 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 and limits Atlas Energy’s ability to make capital expenditures. Atlas Energy’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 Atlas Energy were unable to repay those amounts, the lenders could proceed against the collateral granted to them to secure that indebtedness. Atlas Energy 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, Atlas Energy may not have sufficient assets to repay its credit facility and its other indebtedness, including the notes. Atlas Energy’s borrowings under its credit facility are, and are expected to continue to be, at variable rates of interest and expose it to interest rate risk. If interest rates increase, Atlas Energy’s debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and its net income would decrease.

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Changes in tax laws may impair Atlas Energy’s ability to obtain capital funds through investment partnerships.

Under current federal tax laws, there are tax benefits to investing in investment partnerships such as those Atlas Energy 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 Atlas Energy’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 Atlas Energy’s liabilities.

In 2008, Atlas Energy’s liabilities for severance taxes in the states in which it operates, 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 Atlas Energy’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, Atlas Energy began development drilling activities for it and its partnership investors in Indiana. Accordingly, the amount of development activities Atlas Energy undertakes depends in large part upon its ability to obtain investor subscriptions to invest in these partnerships. During the past three years Atlas Energy 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.

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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 unitholders may be impaired. For the six months ended June 30, 2009, Atlas Energy was required to subordinate net revenues of $0.9 million. There were no subordinated net revenues for the years ended December 31, 2008, 2007, or 2006. Atlas Energy subordinated net revenues of $0.1 million and $0.3 million in fiscal years ended September 30, 2005 and 2004, respectively.

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 flows could decline.

In Appalachia, Atlas Energy’s natural gas is sold under contracts with various purchasers. During the year ended December 31, 2008, natural gas sales to Hess Corporation (which we refer to as “Hess”) accounted for approximately 10% of Atlas Energy’s 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 Atlas Energy’s 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, Atlas Energy’s revenues and cash flows could decline in the event Atlas Energy is unable to sell to additional purchasers.

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

Laurel Mountain gathers more than 90% of Atlas Energy’s current Appalachia production and approximately 50% of its total production. The marketability of Atlas Energy’s natural gas production depends in

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part on the availability, proximity and capacity of gathering and pipeline systems owned by Laurel Mountain 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 Atlas Energy’s 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;

• the federal Resource Conservation and Recovery Act (which we refer to as the “RCRA”) and comparable state laws that impose requirements for the handling and disposal of waste, including produced waters, from its facilities; and

• the Comprehensive Environmental Response, Compensation and Liability Act (which we refer to as “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.

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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 Atlas Energy’s 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.

Atlas Energy management has specifically identified and scheduled drilling locations as an estimation of its 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 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. Atlas Energy’s 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, Atlas Energy 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, Atlas Energy’s 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.

At December 31, 2008, leases covering approximately 85,140 of Atlas Energy’s 422,900 shallow net acres, or 20%, are scheduled to expire on or before December 31, 2009. An additional 33% of Atlas Energy’s shallow net acres 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 its production would decline, which would reduce its cash flows from operations.

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;

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• 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 Atlas Energy’s 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 Atlas Energy’s 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. Atlas Energy generally limits these arrangements to smaller quantities than those projected to be available at any delivery point. In addition, Atlas Energy 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

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changing natural gas and oil prices on its cash flow from operations for those periods. However, such transactions may limit Atlas Energy’s potential gains if natural gas and oil prices were to rise substantially over the price established by the hedge. Furthermore, 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, Atlas Energy may be exposed to the risk of financial loss.

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

With the objective of enhancing the predictability of future revenues, from time to time Atlas Energy and Atlas Pipeline enter into natural gas and crude oil derivative contracts. Atlas Energy elected to designate these derivative contracts as cash flow hedges under the provisions of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Due to the mark-to-market accounting treatment for these contracts, Atlas America could recognize incremental hedge liabilities between reporting periods resulting from increases in reference prices for natural gas and crude oil, which could result in Atlas America recognizing a non-cash loss in its accumulated other comprehensive income and a consequently non-cash decrease in its stockholders’ equity between reporting periods. Any such decrease could be substantial.

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 95 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 its operations and subject it 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 Atlas Energy’s operations and limit the quantity of natural gas it may produce and sell. A major risk inherent in Atlas Energy’s 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 Atlas Energy’s ability to develop its 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 Atlas Energy’s profitability. Furthermore, Atlas Energy may be put at a competitive disadvantage to larger companies in its industry that can spread these additional costs over a greater number of wells and larger operating staff. Please read “Information about Atlas America — Environmental Matters and Regulation” for a description of the laws and regulations that affect Atlas Energy.

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Risks Relating to the Businesses of Atlas Pipeline Holdings and Atlas Pipeline

Atlas America is a holding company and has no direct operations and no significant assets other than cash and its ownership interests in Atlas Energy, Atlas Pipeline Holdings and Atlas Pipeline. Therefore, risks to the businesses of Atlas Pipeline Holdings and Atlas Pipeline are also risks to Atlas America. Atlas Pipeline Holdings is, itself, a holding company and has no direct operations and no significant assets other than its ownership interests in Atlas Pipeline. Set forth below are the material risks to the businesses and results of operations of Atlas Pipeline Holdings and Atlas Pipeline, which risks could negatively affect Atlas America’s results of operations and business.

Atlas Pipeline Holdings’ only cash generating assets are its interests in Atlas Pipeline, and its cash flow therefore completely depends upon the ability of Atlas Pipeline to make distributions to its partners. The Atlas Pipeline Credit Agreement restricts Atlas Pipeline from paying any distributions for the remainder of 2009 and conditions the payment of distributions for periods after that to satisfaction of specified financial thresholds.

Atlas Pipeline Holdings depends upon cash distributions from Atlas Pipeline to fund its operations, pay its debt service on its credit facilities and make distributions to its unitholders. The recent Second Amendment to the Atlas Pipeline Credit Agreement restricts Atlas Pipeline from paying distributions for the remainder of 2009 and permits distributions commencing with the quarter ending March 31, 2010 only if, on a pro forma basis after such payment, Atlas Pipeline’s senior secured leverage ratio is less than or equal to 2.75 to 1.00 and its minimum liquidity, defined generally as cash and cash equivalents less restricted cash plus amounts available for borrowing under the revolver portion of the credit facility, is at least $50 million. In addition, Atlas Pipeline Holdings is restricted under the Atlas Pipeline Holdings Credit Agreement from paying distributions until it repays in full the indebtedness under the credit facility.

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

• the demand for and price of its natural gas and natural gas liquids (which we refer to as “NGLs”);

• expiration of significant contracts;

• the volume of natural gas Atlas Pipeline transports;

• continued development of wells for connection to Atlas Pipeline’s gathering systems;

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

• the expenses Atlas Pipeline incurs in providing its gathering services;

• the cost of acquisitions and capital improvements;

• Atlas Pipeline’s issuance of equity securities;

• required principal and interest payments on Atlas Pipeline’s debt;

• fluctuations in working capital;

• prevailing economic conditions;

• fuel conservation measures;

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• 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 Atlas Pipeline 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 Atlas Pipeline’s general partner for the conduct of Atlas Pipeline’s business.

Atlas Pipeline is unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” under its partnership agreement. Because Atlas Pipeline will be unable to borrow money to pay distributions unless it establishes a facility that meets the definition contained in its partnership agreement, Atlas Pipeline’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 affect Atlas Pipeline’s business, which, in turn, could negatively affect the available cash for distributions to Atlas Pipeline Holdings unitholders, including Atlas America.

Atlas Pipeline’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 Atlas Pipeline’s service area or in wells currently connected to Atlas Pipeline’s pipeline system being shut in by their operators until prices improve. Any of these events may adversely affect Atlas Pipeline’s revenues and its ability to fund capital expenditures and, in turn, may impact the cash that Atlas Pipeline Holdings 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 Atlas Pipeline’s ability to raise capital and reduce the amount of cash available to fund its operations. Atlas Pipeline 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. Atlas Pipeline Holdings cannot be certain that additional capital will be available to Atlas Pipeline 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 Atlas Pipeline 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 current economic situation could have an adverse impact on Atlas Pipeline’s producers, key suppliers or other customers, or on Atlas Pipeline’s lenders, causing them to fail to meet their obligations to Atlas Pipeline Holdings or Atlas Pipeline. Market conditions could also impact Atlas Pipeline’s derivative instruments. If a

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counterparty is unable to perform its obligations and the derivative instrument is terminated, Atlas Pipeline’s cash flow and ability to pay distributions could be impacted, which in turn affects Atlas Pipeline Holdings’ ability to make required debt service payments on its credit facility and the amount of distributions that Atlas Pipeline Holdings is able to make to its unitholders. The uncertainty and volatility of the global financial crisis may have further impacts on Atlas Pipeline’s, and consequently Atlas Pipeline Holdings’, business and financial condition that Atlas Pipeline Holdings and Atlas Pipeline currently cannot predict or anticipate.

Atlas Pipeline Holdings’ and Atlas Pipeline’s debt levels and restrictions in Atlas Pipeline Holdings’ and Atlas Pipeline’s credit facilities could limit their ability to fund operations, pay required debt service on their credit facilities and make distributions to unitholders, including Atlas America.

Atlas Pipeline has a significant amount of debt. Atlas Pipeline will need a substantial portion of its cash flow to make principal and interest payments on its indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to its unitholders. If Atlas Pipeline’s operating results are not sufficient to service its current or future indebtedness, it will be forced to take actions such as 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. Atlas Pipeline 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 Atlas Pipeline Holdings and, consequently, Atlas Pipeline Holdings’ ability to fund its operations, pay required debt service and make distributions to its unitholders could be reduced or eliminated.

Atlas Pipeline Holdings’ and Atlas Pipeline’s credit facilities contain covenants limiting the ability to incur indebtedness, grant liens, engage in transactions with affiliates and make distributions to unitholders. Atlas Pipeline’s credit facility also requires Atlas Pipeline to maintain specified financial ratios and places limits on its capital expenditures. In addition, Atlas Pipeline Holdings and Atlas Pipeline are prohibited from making any distribution to their respective unitholders if such distribution would cause an event of default or otherwise violate a covenant under their respective credit facilities.

In the future, Atlas Pipeline Holdings may not have sufficient cash to pay distributions at its previous quarterly distribution level or to increase distributions.

The source of Atlas Pipeline Holdings’ earnings and cash flow currently consists exclusively of cash distributions from Atlas Pipeline. Therefore, Atlas Pipeline Holdings’ ability to fund its operations, pay required debt service on its credit facility and to make distributions to its unitholders may fluctuate based on the level of distributions Atlas Pipeline makes to its partners. The recent second amendment to the Atlas Pipeline credit agreement restricts Atlas Pipeline from paying distributions for the remainder of 2009 and permits distributions commencing with the quarter ending March 31, 2010 only if, on a pro forma basis after such payment, Atlas Pipeline’s senior secured leverage ratio is less than or equal to 2.75 to 1.00 and its minimum liquidity, defined generally as cash and cash equivalents less restricted cash plus amounts available for borrowing under the revolver portion of the credit facility, is at least $50 million. In addition, Atlas Pipeline Holdings is restricted under the Atlas Pipeline Holdings credit agreement from paying distributions until it repays in full the indebtedness under the credit facility.

Even if the credit facility permits Atlas Pipeline to pay distributions, Atlas Pipeline Holdings cannot assure unitholders that Atlas Pipeline will make quarterly distributions at its previous level or increase its quarterly distributions in the future. In addition, while Atlas Pipeline Holdings would expect to increase or decrease distributions to its unitholders if Atlas Pipeline increases or decreases distributions to Atlas Pipeline Holdings, 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 Atlas Pipeline to Atlas Pipeline Holdings.

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Atlas Pipeline Holdings’ ability to distribute cash received from Atlas Pipeline to its unitholders is limited by a number of factors, including:

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

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

• Atlas Pipeline Holdings’ general and administrative expenses, including expenses it incurs as a result of being a public company;

• expenses of Atlas Pipeline Holdings’ subsidiaries other than Atlas Pipeline, including tax liabilities of Atlas Pipeline Holdings’ corporate subsidiaries, if any;

• reserves necessary for Atlas Pipeline Holdings to make the necessary capital contributions to maintain its 2.0% general partner interest in Atlas Pipeline as required by Atlas Pipeline’s partnership agreement upon the issuance of additional partnership securities by Atlas Pipeline; and

• reserves Atlas Pipeline Holdings’ general partner believes prudent for it to maintain for the proper conduct of its business or to provide for future distributions.

Atlas Pipeline Holdings 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 prior quarterly distribution level. The actual amount of cash that is available for distribution to Atlas Pipeline Holdings unitholders will depend on numerous factors, many of which are beyond Atlas Pipeline Holdings’ control or the control of its general partner.

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

Atlas Pipeline Holdings owns Atlas Pipeline’s general partner, which owns the incentive distribution rights in Atlas Pipeline that entitles Atlas Pipeline Holdings to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed by Atlas Pipeline 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 Atlas Pipeline Holdings receives from Atlas Pipeline is provided by these incentive distributions. The Atlas Pipeline board of directors may reduce the incentive distribution rights payable to Atlas Pipeline Holdings with its consent, which Atlas Pipeline Holdings may provide without the approval of its unitholders or Atlas America. In July 2007, in connection with Atlas Pipeline’s acquisition of the Chaney Dell and Midkiff/Benedum systems, Atlas Pipeline Holdings agreed to allocate up to $5.0 million of incentive distribution rights per quarter back to Atlas Pipeline through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. Atlas Pipeline Holdings also agreed that the resulting allocation of incentive distribution rights back to Atlas Pipeline would be after Atlas Pipeline Holdings 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. We refer to this agreement as the “IDR Adjustment Agreement.”

In order to facilitate acquisitions by Atlas Pipeline, the general partner of Atlas Pipeline may elect to limit the incentive distributions Atlas Pipeline Holdings is entitled to receive with respect to a particular acquisition or unit issuance contemplated by Atlas Pipeline. This is because a potential acquisition might not be accretive to Atlas Pipeline common unitholders as a result of the significant portion of that acquisition’s cash flows which would be paid as incentive distributions to Atlas Pipeline Holdings. By limiting the level of incentive distributions in connection with a particular acquisition or issuance of units of Atlas Pipeline, the cash flows associated with that acquisition could be accretive to Atlas Pipeline common unitholders as well as substantially beneficial to Atlas Pipeline Holdings. In doing so, the managing board of Atlas Pipeline’s general partner would be required to consider both its fiduciary obligations to investors in Atlas Pipeline as well as to Atlas Pipeline Holdings. Atlas Pipeline Holdings’ partnership agreement specifically permits its general partner to authorize the

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general partner of Atlas Pipeline to limit or modify the incentive distribution rights held by Atlas Pipeline Holdings if its general partner determines that such limitation or modification does not adversely affect Atlas Pipeline Holdings’ limited partners in any material respect.

A reduction in Atlas Pipeline’s distributions will disproportionately affect the amount of cash distributions to which Atlas Pipeline Holdings is currently entitled.

Atlas Pipeline Holdings is entitled to receive incentive distributions from Atlas Pipeline with respect to any particular quarter only if Atlas Pipeline distributes more than $0.42 per common unit for such quarter. Furthermore, as described in the immediately preceding risk factor, Atlas Pipeline Holdings agreed to allocate up to $5.0 million of incentive distributions per quarter back to Atlas Pipeline through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. Atlas Pipeline Holdings also agreed that the resulting allocation of incentive distribution rights back to Atlas Pipeline would be after Atlas Pipeline Holdings 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 Atlas Pipeline Holdings receives from Atlas Pipeline 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 Atlas Pipeline to less than $0.60 per common unit per quarter would reduce Atlas Pipeline Holdings’ percentage of the incremental cash distributions from 48% to 23%, if Atlas Pipeline’s distribution is between $0.52 and $0.59, and to 13%, if Atlas Pipeline’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 Atlas Pipeline would have the effect of disproportionately reducing the amount of all incentive distributions that Atlas Pipeline Holdings receives as compared to cash distributions Atlas Pipeline Holdings receives on its 2.0% general partner interest in Atlas Pipeline and the Atlas Pipeline common units Atlas Pipeline Holdings owns.

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

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

• an increase in Atlas Pipeline Holdings’ operating expenses;

• an increase in general and administrative expenses;

• an increase in principal and interest payments on Atlas Pipeline Holdings’ outstanding debt;

• an increase in working capital requirements; or

• an increase in cash needs of Atlas Pipeline or its subsidiaries that reduces Atlas Pipeline’s distributions.

Atlas Pipeline Holdings’ cash distribution policy limits its ability to grow.

Because Atlas Pipeline Holdings 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, Atlas Pipeline Holdings’

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growth completely depends upon Atlas Pipeline’s ability to increase its quarterly distribution per unit because currently its only cash-generating assets are partnership interests in Atlas Pipeline, including incentive distribution rights. If Atlas Pipeline Holdings 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 Atlas Pipeline Holdings will be unable to maintain or increase its per unit distribution level.

Consistent with the terms of its partnership agreement, Atlas Pipeline distributes to its partners its available cash each quarter. In determining the amount of cash available for distribution, Atlas Pipeline 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 Atlas Pipeline 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 Atlas Pipeline 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 Atlas Pipeline 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 Atlas Pipeline Holdings has available to fund its operations, pay required debt service on its credit facility and make distributions to its unitholders. Moreover, the incurrence of additional debt to finance its growth strategy would result in increased interest expense to Atlas Pipeline, which in turn may impact the cash it has available to distribute to its unitholders.

Atlas Pipeline Holdings depends on Atlas Pipeline for its growth. As a result of the fiduciary obligations of Atlas Pipeline’s general partner, which is Atlas Pipeline Holdings’ wholly owned subsidiary, to the common unitholders of Atlas Pipeline, Atlas Pipeline Holdings’ ability to pursue business opportunities independently is limited.

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

Atlas Pipeline Holdings’ ability to sell its general partner interest and incentive distribution rights in Atlas Pipeline is limited.

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

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

Atlas Pipeline Holdings currently manages Atlas Pipeline through Atlas Pipeline GP, Atlas Pipeline’s general partner and Atlas Pipeline Holdings’ wholly owned subsidiary. Atlas Pipeline’s partnership agreement, however, gives common unitholders of Atlas Pipeline the right to remove the general partner of Atlas Pipeline upon the affirmative vote of holders of 66 ²/3% of outstanding Atlas Pipeline common units, excluding those held by Atlas Pipeline GP and its affiliates. If Atlas Pipeline GP were removed as general partner of Atlas Pipeline, it would receive cash or common units in exchange for its 2.0% general partner interest and the incentive

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distribution rights and would lose its ability to manage Atlas Pipeline. While the common units or cash Atlas Pipeline Holdings would receive are intended under the terms of Atlas Pipeline’s partnership agreement to fully compensate Atlas Pipeline Holdings in the event such an exchange is required, the value of these common units or investments Atlas Pipeline Holdings makes with the cash over time may not be equivalent to the value of the general partner interest and the incentive distribution rights had Atlas Pipeline Holdings retained them.

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

If Atlas Pipeline Holdings ceases to manage and control Atlas Pipeline and is deemed to be an investment company under the Investment Company Act of 1940, Atlas Pipeline Holdings would either have to register as an investment company under the Investment Company Act of 1940, obtain exemptive relief from the SEC or modify Atlas Pipeline Holdings’ 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 Atlas Pipeline Holdings’ ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from Atlas Pipeline Holdings’ affiliates, restrict Atlas Pipeline Holdings’ ability to borrow funds or engage in other transactions involving leverage and require Atlas Pipeline Holdings to add additional directors who are independent of Atlas Pipeline Holdings or its affiliates.

The value of Atlas Pipeline Holdings’ investment in Atlas Pipeline depends largely on it being treated as a partnership for federal income tax purposes, which requires that 90% or more of Atlas Pipeline’s gross income for every taxable year consist of qualifying income, as defined in Section 7704 of the Internal Revenue Code of 1986, as amended. Atlas Pipeline may not meet this requirement or current law may change so as to cause, in either event, Atlas Pipeline 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 Atlas Pipeline Holdings common units depends largely on Atlas Pipeline Holdings being treated as a partnership for federal income tax purposes. Atlas Pipeline Holdings has not requested, and does not plan to request, a ruling from the Internal Revenue Service (which we refer to as the “IRS”) on this or any other matter affecting Atlas Pipeline Holdings.

If Atlas Pipeline 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 Atlas Pipeline Holdings would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to Atlas Pipeline Holdings. As a result, there would be a material reduction in Atlas Pipeline Holdings’ anticipated cash flow, likely causing a substantial reduction in the value of Atlas Pipeline Holdings units.

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

Current law may change, causing Atlas Pipeline Holdings or Atlas Pipeline to be treated as a corporation for federal income tax purposes or otherwise subjecting Atlas Pipeline Holdings or Atlas Pipeline 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 Atlas Pipeline Holdings or Atlas Pipeline as an entity, the cash available for distribution to Atlas Pipeline Holdings unitholders would be reduced.

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Atlas Pipeline is affected by the volatility of prices for natural gas and NGL products.

Atlas Pipeline derives a majority of its revenues from percentage-of-proceeds (which we refer to as “POP”) and keep-whole contracts. As a result, Atlas Pipeline’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 Atlas Pipeline processes and sells, based upon estimated unhedged market prices of $0.79 per gallon, $5.00 per mmbtu and $69.54 per barrel for NGLs, natural gas and condensate, respectively, would change its gross margin for the twelve month period ended June 30, 2010, excluding the effect of non-controlling interests in Atlas Pipeline’s net income, by approximately $23.4 million. Additionally, changes in natural gas prices may indirectly impact Atlas Pipeline’s profitability since prices can influence drilling activity and well operations, and could cause operators of wells currently connected to Atlas Pipeline’s pipeline system or that Atlas Pipeline expects will be connected to its system to shut them in until prices improve, thereby affecting the volume of gas Atlas Pipeline 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 Atlas Pipeline’s control. 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 five-year low and from a high of $147.27 per barrel in July 2008. On August 13, 2009, the price of oil on the New York Mercantile Exchange was $70.52 per barrel. Atlas Pipeline expects this volatility to continue. This volatility may cause Atlas Pipeline’s gross margin and cash flows to vary widely from period to period. Atlas Pipeline’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 “Risk Factors — Risks Relating to the Business of Atlas Pipeline Holdings and Atlas Pipeline — Atlas Pipeline’s price risk management strategies may fail to protect it and could reduce its gross margin and cash flow.”

The amount of natural gas Atlas Pipeline 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 Atlas Pipeline’s gathering systems could, therefore, result in the amount of natural gas Atlas Pipeline 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 Atlas Pipeline’s ability to connect new supplies of natural gas to its gathering systems include Atlas Pipeline’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, Atlas Pipeline’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 Atlas Pipeline’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. Atlas Pipeline 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, Atlas Pipeline 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 Atlas Pipeline’s systems until prices improve. Because Atlas Pipeline’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.

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The amount of natural gas Atlas Pipeline 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 Atlas Pipeline delivers NGLs has service interruptions, capacity limitations or otherwise does not accept the NGLs Atlas Pipeline sells to or transports on, and Atlas Pipeline cannot arrange for delivery to other pipelines, the amount of NGLs Atlas Pipeline sells or transports may be reduced. Since Atlas Pipeline’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 Atlas Pipeline’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 Atlas Pipeline’s Appalachian operations, none of the drillers or operators in its Mid-Continent service area is an affiliate of Atlas America. Moreover, Atlas Pipeline’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 Atlas Pipeline’s systems. While Atlas Pipeline does have some undeveloped acreage dedicated on its systems, most notably with its partner Pioneer on its Midkiff/Benedum system, Atlas Pipeline 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 Atlas Pipeline’s Mid-Continent operations will, as described in “Risk Factors — Risks Relating to the Business of Atlas Pipeline Holdings and Atlas Pipeline — The amount of natural gas Atlas Pipeline transports will decline over time unless it is able to attract new wells to connect to its gathering systems,” above, will reduce Atlas Pipeline’s gross margin and cash flows.

Atlas Pipeline’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 Atlas Pipeline’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 Atlas Pipeline, Atlas Pipeline’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 Atlas Pipeline’s processing plants could harm its business.

If operations at any of Atlas Pipeline’s processing plants were to be curtailed, or closed, whether due to accident, natural catastrophe, environmental regulation or for any other reason, Atlas Pipeline’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, Atlas Pipeline’s gross margin and cash flows would be materially reduced.

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

Atlas Pipeline’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 Atlas Pipeline’s Velma service area. In Atlas Pipeline’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. Hiland Partners, DCP Midstream, Mustang Fuel Corporation and ONEOK Partners operate competing gathering systems and processing plants in Atlas Pipeline’s Chaney Dell service area. DCP Midstream, J.L. Davis and Targa Resources operate competing gathering systems and processing plants in Atlas Pipeline’s Midkiff/Benedum service area. Some of Atlas Pipeline’s competitors have

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greater financial and other resources than Atlas Pipeline does. If these companies become more active in Atlas Pipeline’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 Atlas Pipeline does not compete successfully, the amount of natural gas Atlas Pipeline transports, processes and treats will decrease, reducing its gross margin and cash flows.

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

Atlas Pipeline’s gathering systems principally serve as intermediate transportation facilities between sales lines from wells connected to Atlas Pipeline’s systems and the public utility or interstate pipelines to which Atlas Pipeline delivers natural gas. If one or more of these pipelines has service interruptions, capacity limitations or otherwise does not accept the natural gas Atlas Pipeline transports, and Atlas Pipeline cannot arrange for delivery to other pipelines, local distribution companies or end users, the amount of natural gas Atlas Pipeline transports may be reduced. Since Atlas Pipeline’s revenues depend upon the volumes of natural gas it transports, this could result in a material reduction in Atlas Pipeline’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 Atlas Pipeline’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 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 Pipeline’s future acquisition costs may be higher than those it has achieved historically. Any of these factors could adversely impact Atlas Pipeline’s future growth and its ability to make or increase distributions.

Atlas Pipeline 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.

Atlas Pipeline has an active, ongoing program to identify potential acquisitions. Atlas Pipeline’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;

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

• integrating personnel with diverse business backgrounds and organizational cultures;

• consolidating operational and administrative functions;

• integrating pipeline safety-related records and procedures;

• integrating internal controls, compliance under the 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 Atlas Pipeline’s indebtedness; and

• potential environmental or regulatory liabilities and title problems.

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

The acquisitions of Atlas Pipeline’s Chaney Dell and Midkiff/Benedum systems have significantly increased its size and substantially redefined Atlas Pipeline’s business plan, expanded its geographic market and resulted in large changes to its revenues and expenses. As a result of these acquisitions, and Atlas Pipeline’s continued plan to acquire and integrate additional companies that it believes presents attractive opportunities, Atlas Pipeline’s financial results for any period or changes in its results across periods may continue to dramatically change. Atlas Pipeline’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 Atlas Pipeline’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 unitholders.

Atlas Pipeline 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 Atlas Pipeline’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 Atlas Pipeline maintained more diverse assets.

Atlas Pipeline’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 Atlas Pipeline 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 Atlas Pipeline’s control and require the expenditure of significant amounts of capital. Any projects Atlas Pipeline undertakes may not be completed on schedule at the budgeted cost, or at all. Moreover, Atlas Pipeline’s revenues

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may not increase immediately upon the expenditure of funds on a particular project. For instance, if Atlas Pipeline 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, Atlas Pipeline may construct facilities to capture anticipated future growth in production in a region in which growth does not materialize. Since Atlas Pipeline 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 Atlas Pipeline 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 Atlas Pipeline’s expected investment return, which could impair its results of operations and financial condition. In addition, Atlas Pipeline’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.

Atlas Pipeline recently completed construction of an expansion to its Sweetwater natural gas processing plant, from which it expects to generate additional incremental cash flow. Atlas Pipeline 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 Atlas Pipeline.

If Atlas Pipeline 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 Atlas Pipeline’s existing gathering assets may require it to obtain new rights-of-way before constructing new pipelines. Atlas Pipeline 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 Atlas Pipeline 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 Atlas Pipeline’s gathering operations could increase its operating costs, decrease its revenues, or both.

Currently Atlas Pipeline’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 Atlas Pipeline’s gathering and processing operations to regulation by the Federal Energy Regulatory Commission (which we refer to as “FERC”) under the Natural Gas Act. Atlas Pipeline expects that any such regulation would increase its costs, decrease its gross margin and cash flows, or both.

Even if Atlas Pipeline’s gathering and processing operations are not generally subject to regulation under the Natural Gas Act, FERC regulation will still affect Atlas Pipeline’s business and the market for its products. FERC’s policies and practices affect a range of Atlas Pipeline’s natural gas pipeline activities, including, for example, its policies on interstate natural gas pipeline open access transportation, ratemaking, capacity release,

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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, Atlas Pipeline 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 Atlas Pipeline’s business. Matters subject to regulation include access, rates, terms of service and safety. For example, Atlas Pipeline’s gathering lines are subject to ratable take, common purchaser and similar statutes in one or more jurisdictions in which Atlas Pipeline 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, Atlas Pipeline’s revenues could decrease. Collectively, all of these statutes restrict Atlas Pipeline’s right as an owner of gathering facilities to decide with whom it contracts to purchase or transports natural gas.

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

The Department of Transportation (which we refer to as “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.

Atlas Pipeline does not believe that the cost of implementing integrity management program testing along certain segments of Atlas Pipeline’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.

Atlas Pipeline’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 Atlas Pipeline’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 Atlas Pipeline’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

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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 Atlas Pipeline’s business due to its handling of natural gas and other petroleum products, air emissions related to Atlas Pipeline’s operations, historical industry operations including releases of substances into the environment, and waste disposal practices. For example, an accidental release from one of Atlas Pipeline’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 Atlas Pipeline’s compliance costs and the cost of any remediation that may become necessary. Atlas Pipeline may not be able to recover some or any of these costs from insurance.

Atlas Pipeline may not be able to execute its growth strategy successfully.

Atlas Pipeline’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. Atlas Pipeline’s growth strategy involves numerous risks, including:

• Atlas Pipeline may not be able to identify suitable acquisition candidates;

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• Atlas Pipeline 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;

• Atlas Pipeline’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;

• Atlas Pipeline may encounter delays in receiving regulatory approvals or may receive approvals that are subject to material conditions;

• Atlas Pipeline may encounter difficulties in integrating operations and systems; and

• any additional debt Atlas Pipeline incurs to finance an acquisition may impair its ability to service its existing debt.

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

Atlas Pipeline’s ability to raise capital for acquisitions and other capital expenditures depends upon ready access to the capital markets. Historically, Atlas Pipeline 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 Atlas Pipeline is unable to access the capital markets, it may be unable to execute its strategy of growth through acquisitions.

Atlas Pipeline’s price risk management strategies may fail to protect it and could reduce its gross margin and cash flow.

Atlas Pipeline pursues various hedging strategies to seek to reduce its exposure to losses from adverse changes in the prices for natural gas and NGLs. Atlas Pipeline’s price risk management activities will vary in

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scope based upon the level and volatility of natural gas and NGL prices and other changing market conditions. Atlas Pipeline’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 Atlas Pipeline seeks protection;

• the duration of the derivative instrument may not match the duration of the risk against which Atlas Pipeline seeks protection; and

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

Due to the accounting of Atlas Pipeline’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 Atlas Pipeline enters into natural gas, natural gas liquids and crude oil derivative contracts. Atlas Pipeline 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, Atlas Pipeline 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 Atlas Pipeline recognizing a non-cash loss in its consolidated statements of operations or through accumulated other comprehensive income (loss) and a consequent non-cash decrease in stockholders’ equity between reporting periods. Any such decrease could be substantial. In addition, Atlas Pipeline may be required to make a cash payment upon the termination of any of these derivative contracts.

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

Atlas Pipeline’s operations expose it to fluctuations in commodity prices. Atlas Pipeline 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. Atlas Pipeline also has exposure to interest rate fluctuations as a result of variable rate debt under its term loan and revolving credit facility. Atlas Pipeline 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.

Atlas Pipeline 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 Atlas Pipeline hedges its commodity price and interest rate risk using certain derivative contracts, Atlas Pipeline will forego the benefits it would otherwise experience if commodity prices or interest rates were to change in its favor.

Even though Atlas Pipeline’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, Atlas Pipeline 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, Atlas Pipeline 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 Atlas Pipeline.

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The accounting standards regarding hedge accounting are complex, and even when Atlas Pipeline engages in hedging transactions that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, its 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 Atlas Pipeline to engage in a derivative transaction that completely mitigates its exposure to commodity prices and interest rates. Its financial statements may reflect a gain or loss arising from an exposure to commodity prices and interest rates for which Atlas Pipeline 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.

Atlas Pipeline’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. Atlas Pipeline may also be held liable for clean-up costs resulting from pollution which occurred before its acquisition of the gathering systems. In addition, Atlas Pipeline 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 Atlas Pipeline.

Atlas Pipeline is also subject to the requirements of the Occupational Health and Safety Administration (which we refer to as “OSHA”) and comparable state statutes. Any violation of OSHA could impose substantial costs on Atlas Pipeline.

Atlas Pipeline cannot predict whether or in what form any new legislation or regulatory requirements might be enacted or adopted, nor can Atlas Pipeline predict its costs of compliance. In general, Atlas Pipeline 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.

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

Atlas Pipeline’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 Atlas Pipeline’s pipeline infrastructure, production facilities, transmission and distribution facilities and surrounding properties.

As a result, Atlas Pipeline may be a defendant in various legal proceedings and litigation arising from its operations. Atlas Pipeline 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 Atlas Pipeline’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 Atlas Pipeline were to incur a significant liability for which it was not fully insured, its gross margin and cash flows would be materially reduced.

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Atlas Pipeline’s control of the Chaney Dell and Midkiff/Benedum systems is limited by provisions of the limited liability company operating agreements with Anadarko Petroleum Corporation 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 Atlas Pipeline’s subsidiary. However, the consent of Anadarko Petroleum Corporation (which we refer to as “Anadarko”) is required for specified extraordinary transactions, such as admission of new members, engaging in transactions with Atlas Pipeline’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.

Atlas Pipeline is not the operator of the gathering and pipeline system owned by Laurel Mountain and does not control Laurel Mountain other than through certain provisions of the limited liability company agreement with Williams.

All day-to-day operations of the Appalachia System are managed by Williams as the operating member of Laurel Mountain, the operator of the Appalachia System. Pursuant to the limited liability company agreement of Laurel Mountain, all decisions of the management committee of Laurel Mountain currently require the unanimous approval of both Atlas Pipeline and Williams. However, upon the date that any member owns more than 66 ²/3% of the outstanding ownership interests in Laurel Mountain (which we refer to as the “voting change date”), certain decisions of the management committee will require the approval of only the holders of a majority of the ownership interests, certain decisions will require the approval of more than 75% of the ownership interests, and certain decisions will require unanimous approval of the membership interests of Laurel Mountain. Dilution of a member’s ownership interests can occur when such member does not participate in capital contributions needed to fund certain capital growth projects, in which case the non-pursuing member’s percentage interest will be adjusted in proportion to the amount of the capital contribution such non-pursuing member would have been required to contribute in connection with such capital growth project. Atlas Pipeline currently owns, through a wholly owned subsidiary, a 49% interest in Laurel Mountain and has an effective veto on all decisions of the management committee of Laurel Mountain. However, there can be no assurances that Atlas Pipeline will maintain such percentage interest or that a voting change date, and the related changes in voting requirements, will not occur. For a discussion of Laurel Mountain and the Laurel Mountain limited liability company agreement, see “Information About Atlas America — Atlas Pipeline Holdings and Atlas Pipeline” and read the documents incorporated by reference in this joint proxy statement/prospectus and referred to under “Where You Can Find More Information.”

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Statements contained in this joint proxy statement/prospectus and the documents incorporated by reference into this joint proxy statement/prospectus that are not historical facts may constitute forward-looking statements, including statements relating to timing of and satisfaction of conditions to the merger, whether any of the anticipated benefits of the merger will be realized, future revenues, future net income, future cash flows, financial forecasts, future competitive positioning and business synergies, future acquisition cost savings, future expectations that the merger will be accretive to earnings per share, future market demand, future benefits to stockholders, future debt payments and future economic and industry conditions. Words such as “expect,” “estimate,” “project,” “budget,” “forecast,” “anticipate,” “intend,” “expect,” “plan,” “may,” “will,” “could,” “should,” “believe,” “predict,” “potential,” “continue” and similar expressions are also intended to identify forward-looking statements. Atlas America and Atlas Energy believe that their expectations are reasonable and are based on reasonable assumptions. However, such forward-looking statements by their nature involve risks and uncertainties that could cause actual results to differ materially from the results predicted or implied by the forward-looking statement. Some of the key factors that could cause actual results to differ from our expectations include, but are not limited to:

• the failure of Atlas Energy unitholders to adopt the merger agreement;

• the failure of Atlas America stockholders to approve the stock issuance;

• uncertainties regarding market acceptance of the combined company;

• uncertainties as to the timing of the merger;

• realized natural gas and oil prices;

• Atlas Energy’s success in efficiently developing and exploiting its current reserves and economically finding or acquiring additional recoverable reserves;

• the accuracy of Atlas Energy’s estimated natural gas and oil reserves;

• Atlas Energy’s and Atlas Pipeline’s ability to fulfill their respective substantial capital investment needs;

• Atlas Energy’s expectations with respect to acquisition activity, or difficulties encountered in connection with acquisitions, dispositions or similar transactions;

• Atlas Energy’s limited experience in drilling wells to the Marcellus Shale and less information regarding reserves and decline rates in the Marcellus Shale;

• Atlas Energy’s substantial indebtedness;

• restrictive covenants in Atlas Energy’s and Atlas Pipeline’s indebtedness that may adversely affect their operational flexibility;

• the ability of Atlas America, Atlas Energy and Atlas Pipeline to raise funds through investment;

• the effects of intense competition in the natural gas and oil industry;

• general market, labor and economic conditions and related uncertainties;

• Atlas Energy’s and Atlas Pipeline’s ability to retain certain key customers;

• Atlas Energy’s dependence on the gathering and transportation facilities of third parties, including Laurel Mountain;

• the availability of drilling rigs, equipment and crews;

• potential incurrence of 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;

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• uncertainties with respect to the success of drilling wells at identified drilling locations;

• uncertainty regarding our leasing operating expenses, general and administrative expenses and finding and development costs; and

• development of alternative energy resources.

The foregoing list of factors is not exclusive. Other factors that could cause actual results to differ from those implied by the forward-looking statements in this joint proxy statement/prospectus are more fully described in the “Risk Factors” section of this joint proxy statement/prospectus and the “Risk Factors” section of Atlas Energy’s Annual Report on Form 10-K for the year ended December 31, 2008, as updated by subsequent Quarterly Reports on Form 10-Q. Given these risks and uncertainties, you are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included or incorporated by reference in this joint proxy statement/prospectus speak only as of the date on which the statements were made. 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.

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RECENT DEVELOPMENTS

Amendment to Atlas Energy Credit Agreement

On July 10, 2009, Atlas Energy received the requisite consent from its lenders to amend the Atlas Energy credit agreement to permit the merger. After giving effect to the Atlas Energy notes offering described below, the Atlas Energy credit agreement has a current borrowing base of $600.0 million and matures in 2012. The material terms of the amendment include:

• amendments to permit the completion of the merger;

• amendments to restrict the distribution of cash from Atlas Energy, other than distributions to Atlas America in an amount equal to the income tax liability at the highest marginal rate attributable to Atlas Energy’s net income and permitted distributions of up to $40.0 million per year (and, to the extent such permitted distributions are less than $40.0 million in any year, the permitted distribution for the following year may be increased by such difference up to an additional $20.0 million); and

• amendments to provide that a change of control of Atlas America shall constitute a change of control of Atlas Energy under the credit agreement.

The amendment will become effective upon consummation of the merger and after payment of customary fees. Approval of the amendment of the Atlas Energy credit agreement is a condition to completion of the merger.

Amendment to Atlas America Charter

On July 13, 2009, Atlas America held its 2009 annual shareholders’ meeting. At that meeting, the Atlas America stockholders elected Gayle P. W. Jackson and Mark C. Biderman to the Atlas America board of directors and approved an amendment to the Atlas America charter to increase the number of authorized shares of Atlas America common stock from 49 million to 114 million. With the charter amendment, Atlas America has a sufficient number of authorized shares of common stock to complete the merger. The approval of the charter amendment is a condition to completion of the merger.

Atlas Energy Notes Offering

On July 16, 2009, Atlas Energy Operating Company, LLC and Atlas Energy Finance Corp., wholly owned subsidiaries of Atlas Energy, sold an aggregate of $200,000,000 principal amount of their 12.125% Senior Notes due 2017 in an underwritten offering. The senior notes are guaranteed by Atlas Energy and certain of its other subsidiaries. The senior notes will bear interest at a rate of 12.125% per year, payable semiannually in arrears on February 1 and August 1 of each year, beginning on February 1, 2010.

Atlas Energy applied the net proceeds of the sale of the senior notes to the repayment of a portion of the borrowings outstanding under its revolving credit facility. The credit facility’s $650.0 million borrowing base was reduced by 25% of the aggregate stated principal amount of the senior notes, or $50.0 million, to $600.0 million as a result of the offering.

The senior notes are the issuers’ unsecured, senior obligations, ranking senior in right of payment to their existing and future indebtedness that is expressly subordinated to the notes and equal in right of payment with the issuers’ existing and future unsecured indebtedness that is not by its terms subordinated to the senior notes, including the issuers’ existing 10.75% senior notes due 2018. In addition, the senior notes will rank effectively junior to the issuers’ existing and future secured indebtedness, including Atlas Energy Operating Company’s indebtedness under the revolving credit facility, to the extent of the value of the assets securing such indebtedness, and will be structurally subordinated to the existing and future indebtedness.

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THE ATLAS AMERICA SPECIAL MEETING

General

This joint proxy statement/prospectus is being provided to Atlas America stockholders as part of a solicitation of proxies by the Atlas America board of directors for use at a special meeting of Atlas America stockholders. This joint proxy statement/prospectus provides Atlas America stockholders with the information they need to know to be able to vote, or instruct their brokers or other nominees to vote, at the special meeting of Atlas America stockholders.

Date, Time and Place

The special meeting of Atlas America stockholders will be held at The Ethical Society Building, 1906 South Rittenhouse Square, Philadelphia, Pennsylvania 19103, on September 25, 2009, at 11:00 am, local time.

Purpose of the Atlas America Special Meeting

At the Atlas America special meeting, Atlas America stockholders will be asked:

• to consider and vote on a proposal to approve the issuance of shares of Atlas America common stock in connection with the merger contemplated by the merger agreement;

• to consider and vote on a proposal to approve the Atlas America 2009 Stock Incentive Plan; and

• to vote upon a proposal to adjourn or postpone the Atlas America special meeting, if necessary, to solicit additional proxies if there are not sufficient votes in favor of the foregoing.

Recommendation of the Atlas America Board of Directors

The Atlas America board of directors has determined that the merger agreement and the transactions contemplated thereby, including the stock issuance, are advisable, fair to and in the best interests of Atlas America and its stockholders.Therefore, the Atlas America board of directors recommends that Atlas America stockholders vote “FOR” the proposal to approve the stock issuance, which is necessary to complete the merger.

The Atlas America board of directors also recommends that Atlas America stockholders vote “FOR” the proposal to approve the Atlas America 2009 Stock Incentive Plan and “FOR” the proposal to adjourn or postpone the Atlas America special meeting, if necessary, to solicit additional proxies if there are not sufficient votes at the time of the meeting in favor of the foregoing.

Atlas America Record Date; Outstanding Shares; Shares Entitled to Vote

Only holders of record of Atlas America common stock at the close of business on August 18, 2009, the Atlas America record date, are entitled to notice of and to vote at the Atlas America special meeting. As of August 18, 2009, there were 39,363,023 shares of Atlas America common stock outstanding and entitled to vote at the Atlas America special meeting, held by approximately 223 holders of record. Each holder of Atlas America common stock is entitled to one vote for each share of Atlas America common stock owned as of the Atlas America record date.

A list of stockholders entitled to vote at the Atlas America special meeting will be available for inspection at the Atlas America special meeting and for ten days before the Atlas America special meeting at the Atlas America offices at Westpointe Corporate Center One, 1550 Coraopolis Heights Road, 2^nd Floor, Moon Township, Pennsylvania 15108.

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As of August 18, 2009, the Atlas America record date, Atlas America directors and executive officers beneficially owned approximately 13.4% of the outstanding shares of Atlas America common stock. It is currently expected that Atlas America’s directors and executive officers will vote their shares in favor of the above-listed proposals, but none of them has entered into any agreements obliging him or her to do so.

Quorum

The presence in person or by proxy of holders of Atlas America common stock representing not less than a majority of the shares of Atlas America common stock issued and outstanding and entitled to vote as of the Atlas America record date will constitute a quorum. A quorum must be present before a vote can be taken on the proposal to approve the stock issuance or any other matter except adjournment or postponement of the meeting due to the absence of a quorum. Abstentions and broker non-votes (shares held by a broker as nominee (i.e., in “street name”) that are represented by proxies at the special meeting, but that the broker fails to vote on one or more matters as a result of incomplete instructions from the beneficial owner of the shares) also will be treated as present for purposes of determining the presence or absence of a quorum for all matters to be considered at the Atlas America special meeting.

If a quorum is not present, Atlas America expects that the special meeting will be adjourned or postponed to solicit additional proxies. At any subsequent reconvening of the special meeting, all proxies will be voted in the same manner as the proxies would have been voted at the original convening of the special meeting, except for any proxies that have been effectively revoked or withdrawn prior to the subsequent meeting.

Vote Required for Approval

The proposal for Atlas America stockholders to approve the stock issuance requires the affirmative vote of holders of a majority of the votes cast on the proposal at the Atlas America special meeting, provided that the total votes cast on the proposal represents over 50% of all shares of Atlas America common stock entitled to vote on the proposal. Accordingly, either a failure to cast a vote for this proposal or a broker non-vote could have the effect of a vote against the proposal if such failure or broker non-vote results in the total number of votes cast on the proposal not representing over 50% of all shares of common stock entitled to vote on the proposal. An abstention will be counted as a vote cast at the special meeting for purposes of this proposal and will have the same effect as a vote against the proposal.

The proposal for Atlas America stockholders to approve the Atlas America 2009 Stock Incentive Plan requires the affirmative vote of the holders of a majority of the shares of Atlas America common stock present in person or represented by proxy at the special meeting and entitled to vote thereon. Accordingly, a failure to vote or a broker non-vote will not affect whether this proposal is approved. An abstention will be counted as present at the special meeting for purposes of this proposal and will have the same effect as a vote against the proposal.

The proposal for Atlas America stockholders to adjourn or postpone the special meeting requires the affirmative vote of the holders of a majority of the shares of Atlas America common stock present in person or represented by proxy at the special meeting and entitled to vote thereon, whether or not a quorum is present. Accordingly, a failure to vote or a broker non-vote will not affect whether this proposal is approved. An abstention will be counted as present at the special meeting for purposes of this proposal and will have the same effect as a vote against the proposal.

Voting; Proxies

You may vote by proxy or in person at the Atlas America special meeting. Votes cast by proxy or in person at the Atlas America special meeting will be tabulated and certified by Atlas America’s transfer agent.

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Voting in Person

If you plan to attend the Atlas America special meeting and wish to vote in person, you will be given a ballot at the special meeting. Please note, however, that if your shares are held in “street name,” which means your shares are held of record by a broker, bank or other nominee, and you wish to vote in person at the Atlas America special meeting, you must bring to the special meeting a proxy from the record holder of the shares authorizing you to vote at the Atlas America special meeting (such statement/letter and proxy are required in addition to your personal identification).

Voting by Proxy

A proxy card is enclosed for your use. Atlas America requests that you sign the accompanying proxy and return it promptly in the enclosed postage-paid envelope. You may also vote your shares by telephone or through the Internet. Information and applicable deadlines for voting by telephone or through the Internet are set forth on the enclosed proxy card. When the accompanying proxy is returned properly executed, the shares of Atlas America common stock represented by it will be voted at the Atlas America special meeting or any adjournment thereof in accordance with the instructions contained in the proxy. If a proxy is signed and returned without an indication as to how the shares of Atlas America common stock represented are to be voted with regard to a particular proposal, the Atlas America common stock represented by the proxy will be voted in favor of each such proposal.

As of the date of this joint proxy statement/prospectus, management has no knowledge of any business that will be presented for consideration at the Atlas America special meeting and which would be required to be set forth in this joint proxy statement/prospectus or the related Atlas America proxy card other than the matters set forth in the Atlas America Notice of Special Meeting of Stockholders. In accordance with Atlas America’s bylaws and Delaware law, business transacted at the Atlas America special meeting will be limited to those matters set forth in the notice of special meeting. Nonetheless, if any other matter is properly presented at the Atlas America special meeting for consideration, it is intended that the persons named in the enclosed proxy and acting thereunder will vote in accordance with their best judgment on such matter.

Your vote is important. Accordingly, please sign and return the enclosed proxy card whether or not you plan to attend the Atlas America special meeting in person.

Participants in Atlas America’s Employee Stock Ownership Plan

If you are a participant in Atlas America’s Employee Stock Ownership Plan, please follow the voting instructions provided to you separately by GreatBanc Trust Company, the trustee of the plan.

Shares Held in Street Name

If you hold your shares in a stock brokerage account or if your shares are held by a bank or nominee (that is, in “street name”), you must provide the record holder of your shares with instructions on how to vote your shares if you wish them to be counted. Please follow the voting instructions provided by your bank or broker. Please note that you may not vote shares held in street name by returning a proxy card directly to Atlas America or by voting in person at the special meeting unless you provide a “legal proxy,” which you must obtain from your bank or broker. Further, brokers who hold shares of Atlas America common stock on behalf of their customers may not give a proxy to Atlas America to vote those shares without specific instructions from their customers.

Changing or Revoking Proxy

You can change your vote or revoke your proxy at any time before your proxy is voted at the Atlas America special meeting by taking any of the following actions:

• you can send a signed notice of revocation;

• you can grant a new, valid proxy bearing a later date; or

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• if you are a holder of record, you can attend the Atlas America special meeting and vote in person, which will automatically cancel any proxy previously given, or you may revoke your proxy in person, but your attendance alone will not revoke any proxy that you have previously given.

If you choose either of the first two methods, you must submit your notice of revocation or your new proxy to the Secretary of Atlas America no later than the beginning of the Atlas America special meeting. If you have voted your shares by telephone or through the Internet, you may revoke your prior telephone or Internet vote by recording a different vote using the telephone or Internet, or by signing and returning a proxy card dated as of a date that is later than your last telephone or Internet vote. If your shares are held in street name by your bank or broker, you should contact your bank or broker to change your vote.

Solicitation of Proxies

In accordance with the merger agreement, the cost of proxy solicitation for the Atlas America special meeting will be borne by Atlas America. In addition to the use of the mail, proxies may be solicited by officers and directors and regular employees of Atlas America, without additional remuneration, by personal interview, telephone, facsimile or otherwise. Atlas America will also request brokerage firms, nominees, custodians and fiduciaries to forward proxy materials to the beneficial owners of shares held of record on the record date and will provide customary reimbursement to such firms for the cost of forwarding these materials. Atlas America has retained MacKenzie Partners, Inc. to assist in its solicitation of proxies at the Atlas America special meeting and 2009 annual meeting and has agreed to pay them a fee not to exceed $30,000, plus reasonable out-of-pocket expenses, for these services.

Assistance

If you need assistance completing your proxy card or have questions regarding the Atlas America special meeting, please contact MacKenzie Partners, Inc., which is assisting Atlas America with the solicitation of proxies, at 105 Madison Avenue, New York, New York 10016, proxy@mackenziepartners.com, call collect (212) 929-5500 or toll-free (800) 322-2885. Alternatively, you may contact Atlas America Investor Relations (Attn: Brian Begley) at Westpointe Corporate Center One, 1550 Coraopolis Heights Road, 2nd Floor, Moon Township, Pennsylvania 15108 or (215) 546-5005.

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THE ATLAS ENERGY SPECIAL MEETING

General

This joint proxy statement/prospectus is being provided to Atlas Energy unitholders as part of a solicitation of proxies by the Atlas Energy board of directors for use at a special meeting of Atlas Energy unitholders. This joint proxy statement/prospectus provides Atlas Energy unitholders with the information they need to know to be able to vote, or instruct their brokers or other nominees to vote, at the special meeting of Atlas Energy unitholders.

Date, Time and Place

The special meeting of Atlas Energy unitholders will be held at the Sofitel Philadelphia, 120 South 17^th Street, Philadelphia, Pennsylvania 19103, on September 25, 2009, at 9:00 am, local time.

Purpose of the Atlas Energy Special Meeting

At the Atlas Energy special meeting, Atlas Energy unitholders will be asked to consider and vote upon a proposal to adopt the merger agreement and approve the transactions contemplated thereby, including the merger.

Recommendation of the Atlas Energy Special Committee and the Atlas Energy Board of Directors

Each of (1) the Atlas Energy special committee and (2) the Atlas Energy board of directors, with all of the potentially interested directors abstaining or recusing themselves, and based upon the unanimous recommendation of the Atlas Energy special committee, determined that the merger agreement and the transactions contemplated thereby, including the merger, are advisable, fair and reasonable to, and in the best interests of, Atlas Energy and the Atlas Energy unitholders that are not affiliated with Atlas America. The special committee consisted of Mses. Ellen Warren and Jessica Davis and Mr. Walter Jones. In addition, Messrs. Edward Cohen, Jonathan Cohen, Bruce Wolf and Richard Weber recused themselves from the Atlas Energy board of directors vote.Based upon the unanimous recommendation of the Atlas Energy special committee, the Atlas Energy board of directors recommends that Atlas Energy unitholders vote “FOR” the proposal to adopt the merger agreement and approve the transactions contemplated thereby, including the merger.

Atlas Energy Record Date; Outstanding Units; Units Entitled to Vote

Only holders of record of Atlas Energy common units and Atlas Energy Class A units at the close of business on August 18, 2009, the Atlas Energy record date, are entitled to notice of and to vote at the Atlas Energy special meeting. As of August 18, 2009, there were 63,381,249 Atlas Energy common units outstanding and entitled to vote at the Atlas Energy special meeting, held by approximately 35 holders of record. In addition, Atlas Energy Management owned 1,293,496 Atlas Energy Class A units, representing 100% of the outstanding Atlas Energy Class A units. Each holder of Atlas Energy common units is entitled to one vote for each Atlas Energy common unit owned as of the Atlas Energy record date, and each holder of Atlas Energy Class A units is entitled to one vote for each Atlas Energy Class A unit owned as of the Atlas Energy record date.

Pursuant to the Atlas Energy operating agreement, if any person or group (other than Atlas America, Atlas Energy Management and their affiliates or persons who acquired their units of Atlas Energy directly from Atlas America, Atlas Energy Management or their affiliates with the prior approval of the Atlas Energy board of directors) beneficially owns 20% or more of any class of units of Atlas Energy then outstanding, all Atlas Energy units owned by such person or group cannot vote on any matter and are not considered outstanding.

A list of unitholders entitled to vote at the Atlas Energy special meeting will be available for inspection at the Atlas Energy special meeting and for ten days before the Atlas Energy special meeting at the Atlas Energy offices at Westpointe Corporate Center One, 1550 Coraopolis Heights Road, 2nd Floor, Moon Township, Pennsylvania 15108.

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As of August 18, 2009, the Atlas Energy record date, Atlas Energy directors and executive officers beneficially owned approximately 0.5% of the outstanding Atlas Energy common units. It is currently expected that Atlas Energy’s directors and executive officers will vote their units in favor of the above-listed proposals, but none of them has entered into any agreements obliging any such person or entity to do so.

Atlas America and Atlas Energy Management agreed in the merger agreement that, so long as the Atlas Energy board of directors and Atlas Energy special committee have not changed or withdrawn their recommendation in favor of adoption of the merger agreement, they will vote all of their Atlas Energy common units and Atlas Energy Class A units to adopt the merger agreement, approve the merger and approve any other matters required to be approved by holders of Atlas Energy common units and holders of Atlas Energy Class A units for consummation of the merger; provided, however, that Atlas America and Atlas Energy Management may, but will not be required to, vote their Atlas Energy common units and Atlas Energy Class A units in such manner if the Atlas Energy board of directors or Atlas Energy special committee changes its recommendation.

Quorum

The presence in person or by proxy of holders of not less than (a) a majority of the Atlas Energy common units issued, outstanding and entitled to vote as of the Atlas Energy record date and (b) a majority of the Class A units issued, outstanding and entitled to vote as of the Atlas Energy record date will each constitute a quorum for their respective votes. A quorum must be present, in person or by proxy, before a vote can be taken on the proposal to approve and adopt the merger agreement or any other matter except adjournment or postponement of the meeting due to the absence of a quorum. Abstentions and broker non-votes (units held by a broker as nominee (i.e., in “street name”) that are represented by proxies at the Atlas Energy special meeting, but that the broker fails to vote on one or more matters as a result of incomplete instructions from the beneficial owner of the units) also will be treated as present for purposes of determining the presence or absence of a quorum for all matters to be considered at the Atlas Energy special meeting.

If a quorum is not present, Atlas Energy expects that the Atlas Energy special meeting will be adjourned or postponed to solicit additional proxies. The chairman of the Atlas Energy board of directors, or other chairman of the Atlas Energy special meeting, has full authority to adjourn the special meeting of the Atlas Energy unitholders, whether for lack of a quorum or any other reason, and may elect to do so to solicit additional proxies if there are not sufficient votes in favor of the proposal. At any subsequent reconvening of the special meeting, all proxies will be voted in the same manner as the proxies would have been voted at the original convening of the Atlas Energy special meeting, except for any proxies that have been effectively revoked or withdrawn prior to the subsequent meeting.

Vote Required for Approval

The proposal for Atlas Energy unitholders to approve and adopt the merger agreement requires the affirmative vote of holders of (a) a majority of the outstanding Atlas Energy common units entitled to vote as of the Atlas Energy record date and (b) a majority of the outstanding Atlas Energy Class A units entitled to vote as of the Atlas Energy record date, in each case, voting as a separate class. An abstention will be counted as a vote cast at the Atlas Energy special meeting for purposes of this proposal and will have the same effect as a vote against the proposal.

As of August 18, 2009, the Atlas Energy record date, the Atlas America directors and executive officers and the Atlas Energy directors and executive officers, taken together, beneficially owned 334,103, or approximately 0.5% of the outstanding, Atlas Energy common units. Atlas America and Atlas Energy currently expect that their respective directors and executive officers will vote their Atlas Energy common units in favor of the merger, but they have not entered into any agreement obliging them to do so. If Atlas America, the Atlas America directors and executive officers and the Atlas Energy directors and executive officers vote all of their Atlas Energy common units in favor of the merger, 30,287,099, or approximately 47.8% of the outstanding, Atlas Energy common units will be voted in favor of the merger, and only an additional 1,403,526, or approximately 2.2% of the outstanding, Atlas Energy common units will be required to approve Atlas Energy’s proposal for the merger.

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Voting; Proxies

You may vote by proxy or in person at the Atlas Energy special meeting. Votes cast by proxy or in person at the Atlas Energy special meeting will be tabulated and certified by Atlas Energy’s transfer agent.

Voting in Person

If you plan to attend the Atlas Energy special meeting and wish to vote in person, you will be given a ballot at the Atlas Energy special meeting. You will need to bring a form of personal identification with you to the meeting. Please note, if your units are held of record by a bank, broker or other nominee, you also need to bring an account statement indicating that you beneficially own the units as of the record date, or a letter from the record holder indicating that you beneficially own the units as of the record date, and if you wish to vote at the Atlas Energy special meeting you must first obtain from the record holder a proxy issued in your name (such statement/letter and proxy are required in addition to your personal identification).

Voting by Proxy

A proxy card is enclosed for your use. Atlas Energy requests that you sign the accompanying proxy and return it promptly in the enclosed postage-paid envelope. You may also vote your units by telephone or through the Internet. Information and applicable deadlines for voting by telephone or through the Internet are set forth on the enclosed proxy card. When the accompanying proxy is returned properly executed, the Atlas Energy common units or Class A units represented by it will be voted at the Atlas Energy special meeting or any adjournment thereof in accordance with the instructions contained in the proxy. If a proxy is signed and returned without an indication as to how the Atlas Energy common units or Class A units represented are to be voted with regard to a particular proposal, the Atlas Energy common units or Class A units represented by the proxy will be voted in favor of each such proposal.

As of the date of this joint proxy statement/prospectus, management has no knowledge of any business that will be presented for consideration at the Atlas Energy special meeting and which would be required to be set forth in this joint proxy statement/prospectus or the related Atlas Energy proxy card other than the matters set forth in the Atlas Energy Notice of Special Meeting of Unitholders. In accordance with the Atlas Energy operating agreement and Delaware law, business transacted at the Atlas Energy special meeting will be limited to those matters set forth in the Atlas Energy Notice of Special Meeting of Unitholders. Nonetheless, if any other matter is properly presented at the Atlas Energy special meeting for consideration, it is intended that the persons named in the enclosed proxy and acting thereunder will vote in accordance with their best judgment on such matter.

Your vote is important. Accordingly, please sign and return the enclosed proxy card whether or not you plan to attend the Atlas Energy special meeting in person. If you do not return or submit the proxy or vote in person at the Atlas Energy special meeting as provided in this joint proxy statement/prospectus, the effect will be the same as a vote against the proposal to adopt the merger agreement.

Units Held in Street Name

If you hold your units in a stock brokerage account or if your units are held by a bank or nominee (that is, in “street name”), you must provide the record holder of your units with instructions on how to vote your units if you wish them to be counted. Please follow the voting instructions provided by your bank or broker. Please note that you may not vote units held in street name by returning a proxy card directly to Atlas Energy or by voting in person at the Atlas Energy special meeting unless you provide a “legal proxy,” which you must obtain from your bank or broker. Further, brokers who hold Atlas Energy common units or Class A units on behalf of their customers may not give a proxy to Atlas Energy to vote those units without specific instructions from their customers.

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Changing or Revoking Proxy

You can change your vote or revoke your proxy at any time before your proxy is voted at the Atlas Energy special meeting by taking any of the following actions:

• you can send a signed notice of revocation;

• you can grant a new, valid proxy bearing a later date; or

• if you are a holder of record, you can attend the Atlas Energy special meeting and vote in person, which will automatically cancel any proxy previously given, or you may revoke your proxy in person, but your attendance alone will not revoke any proxy that you have previously given.

If you choose either of the first two methods, you must submit your notice of revocation or your new proxy to the Secretary of Atlas Energy no later than the beginning of the Atlas Energy special meeting. If you have voted your units by telephone or through the Internet, you may revoke your prior telephone or Internet vote by recording a different vote using the telephone or Internet, or by signing and returning a proxy card dated as of a date that is later than your last telephone or Internet vote. If your units are held in street name by your bank or broker, you should contact your broker to change your vote.

Solicitation of Proxies

In accordance with the merger agreement, the cost of proxy solicitation for the Atlas Energy special meeting will be borne by Atlas Energy. In addition to the use of the mail, proxies may be solicited by officers and directors and regular employees of Atlas Energy, without additional remuneration, by personal interview, telephone, facsimile or otherwise. Atlas Energy will also request brokerage firms, nominees, custodians and fiduciaries to forward proxy materials to the beneficial owners of units held of record on the record date and will provide customary reimbursement to such firms for the cost of forwarding these materials. Atlas Energy has retained Georgeson Inc. to assist in its solicitation of proxies and has agreed to pay them a fee of approximately $8,500, plus reasonable expenses, for these services.

No Appraisal Rights

Unitholders who object to the proposals will not have appraisal, dissenters’ or similar rights under Delaware law. These rights would permit a unitholder to seek a judicial determination of the fair value of such unitholder’s units and to compel the purchase of such unitholder’s units for cash in that amount. If the proposals described in this joint proxy statement/prospectus are approved as described, that approval will be binding on all unitholders, and objecting unitholders will have no alternative other than selling their units if they dissent from approving such proposals.

Assistance

If you need assistance completing your proxy card or have questions regarding the Atlas Energy special meeting, please contact Georgeson Inc. which is assisting Atlas Energy with the solicitation of proxies, at 199 Water Street, 26^th Floor, New York, New York 10038, atninfo@georgeson.com, call collect (212) 806-6859 or toll-free (800) 255-4617. Alternatively, you may contact Atlas Energy Investor Relations (Attn: Brian Begley) at Westpointe Corporate Center One, 1550 Coraopolis Heights Road, 2nd Floor, Moon Township, Pennsylvania 15108 or (215) 546-5005.

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ATLAS ENERGY PROPOSAL / ATLAS AMERICA PROPOSAL 1: THE MERGER

Effects of the Merger

At the effective time of the merger, a wholly owned subsidiary of Atlas America will merge with and into Atlas Energy, with Atlas Energy continuing as the surviving company and a wholly owned subsidiary of Atlas America. If the merger is completed, each Atlas Energy common unit, other than those common units held by Atlas America and its subsidiaries, will be converted into the right to receive 1.16 shares of Atlas America common stock, with cash paid in lieu of fractional shares. This exchange ratio is fixed and will not be adjusted to reflect stock price changes prior to closing of the merger. Each Atlas Energy Class A unit and management incentive interest of Atlas Energy, all of which are held by Atlas Energy Management, will remain outstanding. Options and other equity-based awards will convert into equivalent awards of Atlas America at the exchange ratio. Atlas America stockholders will continue to own their existing shares of Atlas America common stock.

Atlas America Name Change

At the effective time of the merger, Atlas America will be renamed “Atlas Energy, Inc.” This name change will be effected by merging a newly created, wholly owned subsidiary of Atlas America with and into Atlas America pursuant to Section 253 of Delaware General Corporation Law, which requires only the approval of the Atlas America board of directors. Atlas America will survive the merger, but as a result of such merger, Atlas America’s name will be changed to “Atlas Energy, Inc.”

Background of the Merger

Atlas Energy was formed in June 2006 to own and operate substantially all of the natural gas and oil assets and the investment partnership management business of Atlas America. Atlas Energy thereafter completed an initial public offering of its common units in December 2006. After this offering, Atlas America continued to own 29,352,996 Atlas Energy common units, or approximately 80% of the outstanding Atlas Energy common units, and, through its wholly owned subsidiary, Atlas Energy Management, beneficially owned all of the Class A units and management incentive interests of Atlas Energy.

To partially fund the acquisition of DTE Gas & Oil Company in June 2007, Atlas Energy sold 7,298,181 Atlas Energy common units and 16,702,828 Class D units in a private placement. All of the Class D units automatically converted into Atlas Energy common units, on a one-for-one basis, upon the receipt of consent of Atlas Energy unitholders in November 2007. After the conversion, Atlas America owned approximately 48.35% of the outstanding Atlas Energy common units.

In May 2008, Atlas Energy sold in a public offering 2,070,000 Atlas Energy common units, and sold in a private placement an additional 600,000 Atlas Energy common units to Atlas America. As a result of such sales, as of the date of this joint proxy statement/prospectus, Atlas America beneficially owns 29,952,996, representing approximately 47.3% of the outstanding, Atlas Energy common units. In addition, Atlas Energy Management, which is a wholly owned subsidiary of Atlas America, manages Atlas Energy, and owns 1,293,496, representing 100% of the outstanding, Atlas Energy Class A units, together with all of the management incentive interests of Atlas Energy.

Atlas America and Atlas Energy continually evaluate their respective companies’ results of operations and competitive positions in the industries in which they operate, and regularly review potential strategic alternatives. As part of their ongoing review, in late 2008, members of management of Atlas America and Atlas Energy began to explore whether the current organizational and capital structures of Atlas America and Atlas Energy were optimal to finance and develop the growth opportunities in Atlas Energy’s natural gas shale assets. In particular, members of management focused on Atlas Energy’s core position in the Marcellus Shale, an organic-rich shale formation in the Appalachian Basin of eastern North America, which had only recently begun to be recognized as possibly containing one of the nation’s largest reserves of natural gas. Throughout 2007 and 2008, as the value of the Marcellus Shale was becoming clearer, Atlas Energy expanded its position in the Marcellus Shale, and, by

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February 19, 2009, Atlas Energy controlled, on a net basis, energy rights to approximately 556,000 Marcellus Shale acres in Pennsylvania, New York and West Virginia. However, the very difficult and deteriorating economic conditions, as well as the great difficulty of obtaining or even retaining funding as a result of the worldwide financial crisis and declining natural gas prices, threatened to impair Atlas Energy’s ability to fully exploit its Marcellus Shale opportunity. Members of management of Atlas America and Atlas Energy also considered the possibility that these conditions might lead to a decrease in the borrowing base under Atlas Energy’s revolving credit facility and issues regarding Atlas Energy’s liquidity and compliance with its debt covenants. Management therefore continued to consider a range of possible uses for Atlas Energy’s cash flow, including whether it should be distributed to Atlas Energy unitholders (including Atlas America), or whether it should be directed to alternative uses, such as the development of the Marcellus Shale and/or reducing outstanding debt.

In December 2008, as a result of the ongoing consideration of such strategic factors, Atlas America retained J.P. Morgan Securities Inc. and Wachtell, Lipton, Rosen & Katz to advise and assist Atlas America in exploring and evaluating its options.

On January 27, 2009, following a joint operational presentation by members of management of Atlas America and Atlas Energy regarding the operating conditions facing Atlas America and Atlas Energy, the Atlas America board of directors met with Atlas America management. At the meeting, Edward E. Cohen (Chairman, Chief Executive Officer and President of Atlas America and Chairman and Chief Executive Officer of Atlas Energy) discussed with the Atlas America board of directors the difficult and deteriorating economic conditions and the potential impact of such conditions on Atlas America and Atlas Energy. He noted that, given such circumstances, Atlas America management was exploring potential strategic alternatives, including a possible merger between Atlas America and Atlas Energy. Mr. Cohen stated that a meeting of the Atlas America board of directors would be held in the upcoming weeks to discuss such potential strategic alternatives in more detail.

On February 3, 2009, the Atlas America board of directors met with Atlas America’s management, legal counsel and financial advisor to discuss and review various strategic alternatives. Jonathan Z. Cohen (Vice Chairman of both Atlas America and Atlas Energy) and Daniel C. Herz (Senior Vice President, Corporate Development, of both Atlas America and Atlas Energy) reviewed with the Atlas America board of directors a variety of possible alternatives that Atlas America management had been exploring. Potential alternatives included: (1) Atlas America and Atlas Energy remaining in their current configurations and not changing their respective cash distribution or investment policies; (2) Atlas America and Atlas Energy remaining as separate publicly traded entities, but Atlas Energy ceasing its cash distributions to public unitholders and to Atlas America (including eliminating allocations for Atlas Energy’s management incentive interests) and/or issuing additional equity to raise cash in order to reinvest its cash in the development of the Marcellus Shale and reduce its debt; (3) Atlas America and Atlas Energy remaining as separate publicly traded entities, but Atlas Energy converting from a publicly traded limited liability company to a publicly traded corporation and ceasing its cash distributions to public unitholders and to Atlas America (including eliminating allocations for Atlas Energy’s management incentive interests) in order to invest its cash in the Marcellus Shale and reduce its debt; (4) Atlas America and Atlas Energy remaining as separate publicly traded entities, but Atlas Energy entering into a joint venture with a third party, in which the third party would contribute cash to the joint venture to invest in the development of the Marcellus Shale; and (5) Atlas America and Atlas Energy merging and ceasing any cash distributions to Atlas Energy’s unitholders, including Atlas America, so that the combined cash of the two companies (including Atlas America’s relatively significant amount of cash on hand) could be used for the development of the Marcellus Shale and the reduction of debt. No action was taken by the Atlas America board of directors at the meeting, but the Atlas America directors agreed that management should continue to explore available alternatives, including possible investment of cash flow in the development of the Marcellus Shale and a possible merger transaction between Atlas America and Atlas Energy.

On March 13, 2009 and March 17, 2009, the Atlas Energy board of directors met with members of Atlas Energy management, including Edward Cohen, Richard D. Weber (President and Chief Operating Officer of

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Atlas Energy), Jonathan Cohen, and Daniel Herz. Edward Cohen updated the Atlas Energy board of directors regarding the difficult and deteriorating economic conditions and their potential impact on Atlas Energy, including the impact on the cash flow of Atlas Energy and the ability of Atlas Energy to raise additional cash through the capital markets. He noted that, given such circumstances, Atlas Energy management was exploring potential strategic alternatives. Jonathan Cohen reviewed with the Atlas Energy board of directors the alternatives that the management had been exploring. As some of the possible alternatives involved transactions with Atlas America, the Atlas Energy board of directors at this meeting authorized the conflicts committee of the Atlas Energy board of directors, consisting of Bruce M. Wolf (Chairperson), Ellen F. Warren and Walter C. Jones, each an independent director of Atlas Energy, to consider strategic alternatives available to Atlas Energy. The Atlas Energy conflicts committee held interviews with representatives of three law firms in order to select legal counsel for the conflicts committee. The conflicts committee also identified three potential investment banking firms to serve as its financial advisor.

In the subsequent days, as the role of the Atlas Energy conflicts committee and the potential strategic alternatives to be considered by the conflicts committee were discussed in more detail, Bruce Wolf, although meeting the independence requirements necessary to serve on the Atlas Energy conflicts committee, recused himself from any participation in the review of strategic alternatives due to his ownership of shares of Atlas America common stock. Therefore, on March 23, 2009, the Atlas Energy board of directors, consistent with the provisions of the Atlas Energy operating agreement, formed a special committee of disinterested directors composed of a majority of Atlas Energy’s standing conflicts committee and consisting of Ellen Warren as Chairperson, Walter Jones and Jessica K. Davis, a newly elected independent director of Atlas Energy. The Atlas Energy special committee was charged with considering various strategic alternatives available to Atlas Energy, including those described previously, which had been identified at the March 17 meeting.

On March 23, 2009, the Atlas Energy special committee engaged K&L Gates LLP to serve as the special committee’s legal advisor. On the same day, the Atlas Energy special committee began interviews with three investment banking firms to serve as the special committee’s financial advisor, including UBS Securities LLC. After weighing, among other things, the various investment banks’ qualifications, experience in the energy industry and in special committee assignments and familiarity with Atlas Energy, the special committee subsequently engaged UBS as its financial advisor. On March 24, 2009, Atlas Energy engaged Jones Day, which regularly represents Atlas Energy, as its legal counsel.

In the following days, the members of the Atlas Energy special committee and advisors generally discussed the timeline, process, and due diligence steps in order to undertake a review of strategic alternatives. Because one of the potential alternatives involved a merger with Atlas America, the Atlas Energy special committee, with the assistance of its advisors, also began a due diligence review of Atlas America.

On March 30, 2009, the Atlas Energy special committee held a telephonic meeting, with both legal advisors and the special committee’s financial advisor present, in which it discussed with the advisors various potential strategic alternatives available to Atlas Energy. During this meeting, the Atlas Energy special committee resolved to meet with Richard Weber to review in detail Atlas Energy’s business plan and then, in a separate meeting with the advisors, to further discuss possible strategic alternatives available to Atlas Energy.

On April 2, 2009, the Atlas Energy special committee and its legal and financial advisors met at Atlas Energy’s offices in Philadelphia, at which time Richard Weber made a presentation to the special committee regarding Atlas Energy’s business plan, prospects, and various possible financial scenarios. The Atlas Energy special committee and Mr. Weber discussed Atlas Energy’s business and strategy, including potential variables in Atlas Energy’s business plan for 2009, and addressed the potential liquidity, anticipated bank borrowing base revisions and potential credit agreement covenant compliance issues faced by Atlas Energy. Mr. Weber’s discussion addressed, among other matters, Atlas Energy management’s strategy for developing the Marcellus Shale and the need for additional capital in order to accelerate drilling in light of the number of drilling opportunities available to Atlas Energy, as well as the potential impact of the recently announced joint venture

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between Atlas Pipeline and Williams, which venture would provide for new gathering contracts on favorable terms to Atlas Energy and allow Atlas Energy to build out its gathering system to facilitate drilling in the Marcellus Shale. He observed that joint venture opportunities to develop the Marcellus Shale might be considered in the future, but that management did not view pursuing joint ventures as advisable or in the best interests of Atlas Energy at that time because, among other things, asset values were unattractive and any joint venture transaction would likely take a substantial amount of time to complete. Insofar as liquidity and credit issues were concerned, Mr. Weber noted that Atlas Energy was not in a position to increase borrowings under its credit facility, that its obligations to make quarterly distributions to Atlas Energy unitholders significantly reduced cash available for operations, and that, as a limited liability company, Atlas Energy had limited access to the capital markets, in particular the equity markets. Mr. Weber’s presentation included financial models that considered the effect of reducing or eliminating cash distributions to common unitholders beginning in the first quarter of 2009, with a possible reinstatement of cash distributions in 2010. Mr. Weber, the Atlas Energy special committee and its advisors discussed various aspects of the financial scenarios presented, as well as the various strategic alternatives in the context of the current and projected commercial and financial climate for the company.

Following Mr. Weber’s presentation, the Atlas Energy special committee discussed with its advisors considerations with respect to various standalone and transactional strategic alternatives. Standalone alternatives discussed included maintaining the status quo, eliminating or reducing distributions to unitholders (including Atlas America), and converting from a publicly traded limited liability company into a publicly traded corporation, each of which was considered in terms of its potential impact on liquidity, access to capital markets, and the ability of Atlas Energy to develop its Marcellus Shale assets. It was noted that a conversion of Atlas Energy from a limited liability company to a corporation might not be permitted under certain agreements to which Atlas Energy was a party, that it could result in adverse cash flow consequences and, therefore, could be viewed negatively by creditors, and that Atlas America, whose vote would be required for such conversion, might not support the conversion. Transaction alternatives with unrelated third parties discussed included an outright sale of Atlas Energy to an unrelated third party and a joint venture. In addition to identifying possible benefits, various reasons as to why potential transactions with unrelated third parties would be unlikely or unattractive were noted. These reasons included the fact that various consents would be needed under Atlas Energy’s contracts (which consents might not be forthcoming) and that outstanding notes issued by Atlas Energy might be accelerated as a result of such transactions; that potential third-party buyers were generally conserving cash and reluctant to issue their own securities because most viewed their securities as undervalued; that potential joint venture partners were retrenching and conserving capital and potential joint venture partners might not offer attractive valuations in the current environment; and that because the approval by holders of a simple majority of both the outstanding Atlas Energy common units and the Atlas Energy Class A Units, each voting separately as a class (of which Atlas America beneficially owns approximately 47% of the Atlas Energy common units and, through Atlas Energy Management, 100% of the Atlas Energy Class A units), would be required, Atlas America could block any third-party sale (or any joint venture involving all or substantially all of the assets of or an affiliate of Atlas Energy) if Atlas America so chose, and that accordingly bids by third parties and joint ventures were unlikely to be forthcoming if Atlas America were opposed to such transactions. Moreover, the Atlas Energy special committee was aware that any joint venture to develop the Marcellus Shale would mean that the potential value of the assets sold to the joint venture would be shared with a third party, thus depriving Atlas Energy and its unitholders of the full value of such assets.

The members of the Atlas Energy special committee and the advisors then engaged in a wide-ranging discussion of both standalone and transactional alternatives. The special committee determined preliminarily to narrow the standalone alternatives under consideration to the elimination of cash distributions beginning with the first quarter of 2009, which would provide Atlas Energy with financial flexibility for further investment in the development of the Marcellus Shale and reduction of its outstanding debt. The Atlas Energy special committee also determined to explore further whether a business combination with a third party, including Atlas America, would be possible and to determine the position of Atlas America with respect to a conversion, an outright sale, a joint venture or other transactional alternative. In that regard, the Atlas Energy special committee authorized its

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financial advisor to contact Atlas America to inquire if it would be interested in exploring a business combination with Atlas Energy.

Later in the day on April 2, 2009, in accordance with the directions of the Atlas Energy special committee, representatives of the special committee’s financial advisor contacted Jonathan Cohen (in his capacity as an officer of Atlas America and not as an officer of Atlas Energy) to ask whether Atlas America would be interested in exploring a possible business combination between Atlas America and Atlas Energy. Jonathan Cohen responded that Atlas America would be interested in exploring a possible business combination, but any such business combination would have to be on terms that would be acceptable to the Atlas America board of directors. Jonathan Cohen agreed to meet with representatives of the special committee’s advisors on April 7, 2009 to discuss a process for engaging in such exploratory discussions.

On April 3, 2009, the Atlas Energy special committee held a telephonic meeting, during which members of the special committee reaffirmed the provisional conclusion that an elimination or reduction of the cash distributions would be the best standalone course of action for Atlas Energy in the absence of a preferable transactional alternative through which an improvement in Atlas Energy’s liquidity could also be achieved.

On April 7, 2009, a meeting was held among Atlas America management, including Jonathan Cohen and Daniel Herz (each acting in his capacity as an officer of Atlas America and not as an officer of Atlas Energy), and representatives from JPMorgan, Wachtell Lipton, UBS and K&L Gates. At the meeting, the Atlas Energy special committee’s advisors informed Atlas America that the Atlas Energy special committee had been having discussions with Richard Weber regarding Atlas Energy’s business plan, including the use of cash for investment, and potential strategic alternatives available to Atlas Energy, and that the special committee was specifically interested in transactions that would enable Atlas Energy to invest cash in the development of the Marcellus Shale and use Atlas America’s available cash to pay down Atlas Energy’s existing debt. In accordance with the directions of the Atlas Energy special committee, the special committee’s advisors also inquired as to whether Atlas America, as the beneficial owner of approximately 47% of the Atlas Energy common units and, through Atlas Energy Management, 100% of the Atlas Energy Class A units, would be willing either to sell its stake in Atlas Energy in a transaction with a third party or to vote to approve a conversion of Atlas Energy from a publicly traded limited liability company into a publicly traded corporation. Atlas America management indicated that Atlas America would not be interested in selling its interests or in the conversion of Atlas Energy into a separate publicly traded corporation. In Atlas America’s view, the assets and business of Atlas Energy are integral parts of Atlas America’s assets and business, and, therefore, a sale of Atlas America’s ownership interest in Atlas Energy at such time was not in the best interest of Atlas America and its stockholders. Moreover, Atlas America management indicated that Atlas America would not be interested in the conversion of Atlas Energy into a separate publicly traded corporation because such conversion could, among other things, result in adverse tax and other consequences to Atlas America. Atlas America management was then informed that the Atlas Energy special committee was in the process of performing a due diligence review of Atlas America, Atlas Energy and their respective subsidiaries to determine what transaction, if any, the Atlas Energy special committee could be interested in exploring.

On April 8, 2009, the Atlas Energy special committee held a telephonic meeting during which it received an update regarding the April 7, 2009 meeting between the special committee’s advisors and Atlas America management and its advisors. Given Atlas America’s stated position that it would not be interested in selling its interests in Atlas Energy or in the conversion of Atlas Energy into a separate publicly traded corporation, and Atlas America’s beneficial ownership of approximately 47% of the Atlas Energy common units and, through Atlas Energy Management, 100% of the Atlas Energy Class A units, the Atlas Energy special committee then discussed with its advisors next steps for a process to determine whether mutually acceptable terms for a potential business combination or other transaction could be achieved.

Shortly thereafter, the Atlas Energy special committee requested a diligence meeting with the respective managements of Atlas America and Atlas Energy. The advisors to Atlas America also requested a diligence meeting with Atlas Energy management to obtain additional diligence and information about Atlas Energy. These diligence meetings were held on April 13, 2009.

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At those April 13 meetings, the Atlas Energy special committee and its legal counsel and financial advisor, as well as Atlas America management, including Jonathan Cohen, Matthew A. Jones (Chief Financial Officer of both Atlas America and Atlas Energy) and Daniel Herz (each acting in his capacity as an officer of Atlas America and not as an officer of Atlas Energy), and Atlas America’s legal counsel and financial advisor, met with the senior management of Atlas Energy, including Richard Weber, at Atlas Energy’s offices in Philadelphia. Jones Day, regular outside counsel to Atlas Energy, was also present at the meeting. At the meeting, additional due diligence information was provided regarding Atlas Energy, including its fundraising program, its plans to drill the Marcellus Shale acreage and its liquidity situation. Atlas Energy’s senior management reviewed the business plans of Atlas Energy on a standalone basis and on the basis of a merger with Atlas America. The business plans showed the effect on the ability to accelerate development and drilling of the Marcellus Shale of borrowings under the existing Atlas Energy revolving credit facility, different levels of syndicated fundraising through drilling partnerships sponsored by Atlas Energy, the reduction or elimination of cash distributions and, in the case of the merger, the additional cash at Atlas America, and the combined company’s improved access to the capital markets. Management discussed the key drivers underlying the standalone and merger business plans. Management also discussed that, on a standalone basis, Atlas Energy is constrained in its ability to raise capital necessary for growth because of its anticipated cash distributions to unitholders and the fact that it must rely on bank credit and internal cash flow to fund operations and meet capital requirements. In the merger scenario, management observed that EBITDA growth rates would likely be superior to the standalone scenario assuming fundraising efforts yield results similar to those in 2008, the revolving credit borrowing base remains at $650 million, drilling is accelerated in the Marcellus Shale and available cash at Atlas America is used to pay down debt. The group at the meeting reviewed various financial information prepared by Atlas Energy management and discussed the alternatives to raise additional cash, including the cost and feasibility of such alternatives. These included, among others, suspending cash distributions to unitholders of Atlas Energy, including Atlas America; raising additional capital in either debt or equity markets; obtaining additional cash from Atlas America and potentially better credit opportunities afforded by merging with Atlas America; raising cash through a joint venture to exploit the Marcellus Shale; or some combination of these alternatives.

Following the April 13, 2009 diligence meetings, representatives of Atlas America’s and the Atlas Energy special committee’s respective financial advisors held a series of follow-up discussions regarding the financial analyses provided by Atlas Energy management, reflecting the alternative scenarios referred to above. In addition, representatives of the financial advisor to the Atlas Energy special committee, in accordance with the directions of the special committee, held a series of discussions with Atlas America management and representatives of Atlas America’s financial advisor regarding the businesses and equity interests of Atlas America, other than its direct and indirect equity ownership in Atlas Energy, and requested and received, on behalf of the Atlas Energy special committee, additional information prepared by Atlas America management relating to these other businesses and equity interests.

On April 14, 2009, the Atlas Energy special committee held a telephonic meeting with its legal and financial advisors. In light of the information that had been received by the Atlas Energy special committee at the April 13, 2009 meeting and prior meetings, the view of the Atlas Energy special committee was that an elimination of the cash distributions was prudent from a business standpoint and in the best interest of Atlas Energy. Atlas Energy management had advised the Atlas Energy special committee that it was concerned about potential liquidity issues and Atlas Energy’s ability to continue to comply with the financial covenants under its outstanding debt, as well as Atlas Energy’s ability to maximize the value of its Marcellus Shale leasehold position, if Atlas Energy were to continue distributing cash to its unitholders at historical levels. In addition, the Atlas Energy special committee had been advised that investors in companies that do not pay regular dividends generally desire to invest in publicly traded corporations, as opposed to publicly traded limited liability companies. One reason is that, as a limited liability company, Atlas Energy is taxed as a partnership for U.S. federal income tax purposes, and, therefore, unlike investors in a publicly traded corporation, Atlas Energy unitholders generally are required to pay tax on their allocable share of Atlas Energy’s taxable income whether or not cash distributions are made. Therefore, if Atlas Energy were to cease its distributions, while continuing to operate in the form of a separate, publicly traded limited liability company, the Atlas Energy special committee

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believed that the public equity of Atlas Energy could be negatively affected. In addition, Atlas America management had indicated that Atlas America would not be interested in a conversion of Atlas Energy into a corporation because of possible adverse tax and other consequences to Atlas America of such a conversion. It was noted that a conversion of Atlas Energy from a limited liability company to a corporation (without a merger of Atlas America and Atlas Energy) was not as attractive as a merger transaction because any conversion would be prohibited under the Atlas Energy credit agreement and would not provide many of the benefits that could be obtained through a merger, including a simplified organizational structure, synergies of combining two separate public companies, the elimination of the effect on the public Atlas Energy unitholders of Atlas America’s management incentive interests and large equity interest in Atlas Energy, and access to Atlas America’s cash on hand. Therefore, based on the information the Atlas Energy special committee had received, it believed that a conversion of Atlas Energy from a limited liability company to a corporation (without a merger of Atlas America and Atlas Energy) was neither available nor an attractive strategic alternative. The Atlas Energy special committee also viewed a sale of Atlas Energy to (or a joint venture involving all or substantially all of Atlas Energy’s assets with) an unrelated third party as unavailable and not an attractive strategic alternative, given the various issues involved, including that Atlas America was unlikely to support such transactions and, in the case of a joint venture, any joint venture transaction would likely take a substantial amount of time to complete and potential joint venture partners were unlikely to offer attractive valuations to Atlas Energy as compared to Atlas Energy drilling for its own account. The Atlas Energy special committee therefore concluded at the April 14^th meeting that a transaction with Atlas America, if properly structured and assuming an acceptable exchange ratio, could be attractive to the public unitholders of Atlas Energy. A number of factors to be taken into account regarding a transaction with Atlas America were discussed, including structuring and tax considerations, applicable provisions under various contracts of Atlas Energy and possible transaction alternatives that could be entered into with Atlas America.

The Atlas Energy special committee held a telephonic meeting on April 17, 2009 to consider further a possible transaction. The special committee discussed with its advisors structuring considerations that could affect the form and feasibility of any transaction, including the possible tax treatment of the transaction, the provisions of the indentures governing Atlas Energy’s outstanding notes, the lender consent potentially required under Atlas Energy’s credit agreement, the provisions of a potential merger agreement and the required Atlas Energy unitholder vote to approve a transaction. The Atlas Energy special committee reviewed with its advisors alternative transaction structures, including a taxable transaction and the obstacles presented in structuring a tax-free transaction. The Atlas Energy special committee reviewed the possible tax consequences of a taxable transaction on Atlas Energy unitholders other than Atlas America and Atlas Energy Management. In addition, the Atlas Energy special committee considered the advisability of seeking a higher voting standard than the simple majority vote of the Atlas Energy Class A units and the Atlas Energy common units, voting as separate classes, which was the required vote under the Atlas Energy operating agreement. The Atlas Energy special committee and its advisors discussed the process and possible timing in light of the fact that the Atlas Energy board of directors was obligated to determine if a quarterly cash dividend would be declared no later than April 27, 2009.

To facilitate a discussion between Atlas America and the Atlas Energy special committee to determine whether there was any potential basis for a transaction between Atlas America and Atlas Energy that could be supported by the Atlas America board of directors and the Atlas Energy special committee, on April 19, 2009, Wachtell Lipton provided to the Atlas Energy special committee and its advisors an outline of possible legal terms of a taxable merger transaction in which Atlas Energy would become a wholly owned subsidiary of Atlas America, with Atlas Energy unitholders (other than Atlas America and Atlas Energy Management) receiving shares of Atlas America as consideration. No exchange ratio was specified in the outline. Separately, Atlas America’s advisors contacted the Atlas Energy special committee’s advisors to request that they inquire of the special committee whether, if a merger transaction were to be of interest, an exchange ratio of 0.96 of a share of Atlas America common stock for each outstanding Atlas Energy common unit (other than Atlas Energy common units held by Atlas America) would provide a basis for a discussion of a potential transaction. Atlas America’s advisors explained that a 0.96 exchange ratio represented the average ratio of the trading price of Atlas America common shares to the trading price of Atlas Energy common units over the preceding 12 months. Atlas

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America’s advisors cautioned the advisors to the Atlas Energy special committee that discussion of a 0.96 exchange ratio did not constitute a proposal but instead was meant to facilitate a discussion between the parties to determine whether there was any possibility of agreement on terms that could be supported by the Atlas America board of directors and the Atlas Energy special committee.

At a telephonic meeting of the Atlas Energy special committee held on April 20, 2009, the special committee discussed with its financial advisor financial aspects of a potential transaction with Atlas America based on the illustrative exchange ratio of 0.96 of a share of Atlas America common stock for each outstanding Atlas Energy common unit (other than Atlas Energy common units held by Atlas America). It was noted that this illustrative exchange ratio implied that the price of one Atlas Energy common unit would be $12.49, or a 13% discount from its market price on April 17, 2009, and would mean that Atlas Energy unitholders (other than Atlas America and Atlas Energy Management), which currently owned approximately 52% of the economic ownership of Atlas Energy, would own approximately 45% of Atlas America common stock, on a pro forma basis, and stockholders of Atlas America prior to the merger would own the remaining approximately 55% of Atlas America common stock, on a pro forma basis. After discussion, the Atlas Energy special committee determined that the exchange ratio of 0.96 was inadequate and that it would not consider a merger transaction unless such transaction provided for an ownership split that was more favorable to Atlas Energy unitholders (other than Atlas America and Atlas Energy Management). Representatives of K&L Gates also reviewed with the Atlas Energy special committee the other principal terms of the proposed merger, as well as described the outline obtained from Atlas America’s legal advisor.

On April 21, 2009, in accordance with the directions of the Atlas Energy special committee, representatives of the special committee’s financial advisor contacted representatives of Atlas America’s financial advisor and conveyed the special committee’s view that an exchange ratio of 0.96 did not provide a basis to move forward. At the request of Atlas America, representatives of Atlas America’s financial advisor called representatives of the special committee’s financial advisor later that day to request that the Atlas Energy special committee provide specific feedback on the outline of possible transaction terms. Also on that day, the Atlas Energy special committee held a telephonic meeting in which it discussed with its advisors recent developments affecting the financial position of Atlas Pipeline and Atlas Pipeline Holdings, subsidiaries of Atlas America, and reductions in the levels of cash and net operating losses at Atlas America expected by Atlas America’s management. After discussion, the Atlas Energy special committee determined to pursue further discussions with Atlas America regarding a merger, but also to obtain additional information about Atlas America and its management plans and to seek an increase in the exchange ratio.

On April 22, 2009, K&L Gates provided to Wachtell Lipton comments on the outline of possible terms. K&L Gates suggested, among other terms, that the transaction should include representations and covenants regarding Atlas America’s cash on hand at closing, and pre-closing covenants restricting Atlas America’s use of cash and limiting its ability to incur or guarantee new debt or to enter into new guarantees of debt of its subsidiaries between signing and closing. In succeeding days, the respective legal and financial advisors to Atlas America and to the Atlas Energy special committee discussed a number of items pertaining to a possible transaction, including, among other things, transaction structure, the exchange ratio, lender approval provisions, minimum cash at closing provisions, operating covenants regarding cash (such as the incurrence of debt and capital expenditures), and material adverse effect, termination and voting provisions.

During the period from April 22, 2009 through April 25, 2009, the parties continued performing due diligence on each other, particularly due diligence by the Atlas Energy special committee, with the assistance of its advisors, on the businesses and equity interests of Atlas America (other than Atlas America’s direct and indirect equity holdings of Atlas Energy).

On April 23, 2009, in response to the position of the Atlas Energy special committee, representatives of Atlas America’s financial advisor contacted representatives of the Atlas Energy special committee’s financial advisor to determine whether an increased exchange ratio of 1.056 shares of Atlas America common stock for each outstanding Atlas Energy common unit might provide the Atlas Energy special committee with a basis to

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continue discussions. Representatives of Atlas America’s financial advisor explained that the 1.056 exchange ratio represented the average ratio of the closing price of Atlas America common stock to the closing price of Atlas Energy common units for the preceding six months. Representatives of Atlas America’s financial and legal advisors reiterated that discussion of a 1.056 exchange ratio was intended solely to facilitate a discussion as to whether a transaction might be possible, and remained subject to the approval of the Atlas America board of directors. In addition, such advisors explained that Atlas America would not accept any standard of approval by the Atlas Energy unitholders other than the simple majority class vote provided for in the Atlas Energy operating agreement, any closing condition tied to a minimum level of cash for Atlas America, operating covenants relating to publicly traded subsidiaries of Atlas America or any material adverse effect provision that did not relate to Atlas America (including Atlas Energy) and its subsidiaries in the aggregate. Atlas America’s advisors explained that certain of these provisions, such as requiring a standard of approval other than the simple majority class vote, were not required under the Atlas Energy operating agreement. Atlas America also was not willing to bind itself to a transaction — one that would involve restrictions on Atlas America’s conduct pending the consummation of the merger and involve substantial management resources and attention — if such transaction carried a degree of uncertainty that was not acceptable to Atlas America.

Later on April 23, 2009, the Atlas Energy special committee held a meeting to be updated on discussions between its legal and financial advisors and the legal and financial advisors of Atlas America. The special committee’s financial advisor observed that an exchange ratio of 1.056 represented an 8% discount to the closing price of Atlas Energy common units and would result in Atlas Energy unitholders (other than Atlas America and Atlas Energy Management) owning approximately 47% of Atlas America after the merger, and result in Atlas America stockholders prior to the merger owning approximately 53% of Atlas America after the merger. The Atlas Energy special committee discussed with its financial advisor financial terms of the proposed transaction, the potential impact on Atlas Pipeline Holdings and Atlas Pipeline of pending discussions with their lenders, and uncertainties in attributing significant value to Atlas Pipeline Holdings and Atlas Pipeline. The general view of the Atlas Energy special committee was that a 1.056 exchange ratio did not provide a basis to move forward. The Atlas Energy special committee directed its financial advisor to seek improved financial terms, including a higher exchange ratio. K&L Gates commented on the proposed terms of the merger, including, among other things, structure, consideration, voting requirements provisions, third-party approvals, pre-closing covenants, treatment of options, lender approval for an amendment to the Atlas Energy credit agreement, a minimum Atlas America cash closing balance, restrictions on additional indebtedness at Atlas America, events constituting a material adverse change, and termination provisions.

In the evening of April 23, 2009, in accordance with the directions of the Atlas Energy special committee, representatives of the financial advisor to the Atlas Energy special committee contacted representatives of Atlas America’s financial advisor to convey the special committee’s view that a 1.056 exchange ratio did not provide a basis to move forward.

On April 24, 2009, Edward Cohen, acting in his capacity as an officer of Atlas America and not as an officer of Atlas Energy, contacted Ellen Warren, the chair of the Atlas Energy special committee, to determine whether the Atlas Energy special committee had any questions that they wished to ask directly of him regarding a possible merger transaction, and to see whether there was any basis for the parties to move forward to discuss the remaining terms of any such transaction. Edward Cohen also called Walter Jones and Jessica Davis — the other members of the Atlas Energy special committee — by telephone for the same purpose. Ellen Warren informed Edward Cohen that she would ask representatives of the special committee’s financial advisor to contact Edward Cohen or Jonathan Cohen. Subsequently, at an Atlas Energy special committee meeting held later that day, which meeting included all members of the special committee and representatives of the special committee’s legal and financial advisors, Ellen Warren advised that Edward Cohen had called her to discuss the principal issues in the deal, including, among other things, recent developments affecting the pipeline subsidiaries of Atlas America, his views on an “at market” deal, the recently negotiated bank terms for Atlas Pipeline Holdings and Atlas Pipeline, the advance by Atlas America of $30 million to Atlas Pipeline Holdings and the expected level of cash available of approximately $50 to $60 million. Also that day, Jonathan Cohen spoke with representatives of the special

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committee’s financial advisor. During this call, the ratio of the closing price of Atlas America common stock to the closing price of Atlas Energy common units over various periods was discussed.

Following conversations between Atlas America and its advisors, Jonathan Cohen, acting in his capacity as an officer of Atlas America and not as an officer of Atlas Energy, informed representatives of the Atlas Energy special committee’s financial advisor that Atlas America likely would be willing to proceed with a transaction at an exchange ratio equal to the ratio of closing prices, rounding up to the nearest hundredth of a share, of Atlas America common stock and Atlas Energy common units on April 24, 2009, or approximately 1.16 shares of Atlas America common stock for each outstanding Atlas Energy common unit, providing a 0.3% premium, but in no event would Atlas America agree to an exchange ratio in excess of 1.16 shares. Moreover, Jonathan Cohen cautioned that an exchange ratio of 1.16 would need to be approved by the Atlas America board of directors, and that, although Jonathan Cohen would discuss this ratio favorably with the Atlas America board of directors, there could be no assurance that the Atlas America board would authorize Atlas America to proceed.

During the evening of April 24, 2009, the Atlas Energy special committee met to receive an update regarding the potential for an improved exchange ratio of 1.16 shares of Atlas America common stock for each outstanding Atlas Energy common unit. The special committee’s financial advisor observed that an exchange ratio of 1.16 represented an implied premium of 0.3% to the closing price of Atlas Energy common units on April 24, 2009 and would result in the ownership by Atlas Energy unitholders (other than Atlas America and Atlas Energy Management) of approximately 49.7% of Atlas America after the merger, and result in the ownership by Atlas America stockholders prior to the merger of approximately 50.3% of Atlas America after the merger. The special committee discussed with its financial advisor financial aspects of the proposed transaction in light of the improved exchange ratio and the fact that, based on closing prices as of April 24, 2009, the market value of Atlas Energy accounted for approximately 93% of the market value of Atlas America’s assets. Representatives from K&L Gates discussed the status of the negotiation on the legal terms of the merger. The Atlas Energy special committee, with the assistance of its advisors, again reviewed both qualitative and quantitative considerations relating to a merger transaction. After discussion, the Atlas Energy special committee directed its advisors to engage in further negotiations with Atlas America about a possible further increase in the exchange ratio and contractual changes to the merger agreement. Later that evening, Atlas America informed the Atlas Energy special committee’s advisors that it would not agree to a higher exchange ratio.

On April 25, 2009, on behalf of the Atlas Energy special committee, Jones Day and K&L Gates sent a draft merger agreement to Wachtell Lipton. Throughout April 25, 2009 and April 26, 2009, Atlas America and its advisors and the advisors to the Atlas Energy special committee negotiated the terms of the merger agreement, including, among other things, prohibition of the payment of cash distributions and possible adjustment of the exchange ratio if cash distributions were made prior to the closing, covenants with respect to the conduct of the business of Atlas Energy and Atlas America and its other subsidiaries, including the use of cash by Atlas America, and conditions to closing and termination rights.

On April 26, 2009, the Atlas America board of directors and its legal counsel and financial advisor met to consider the terms of the merger agreement that had been negotiated between the parties. Wachtell Lipton reviewed the terms of the proposed merger agreement, and noted that a few issues, including the precise restrictions on Atlas America’s use of cash prior to closing, remained subject to negotiations between the parties. A representative from JPMorgan reviewed the key financial terms of the merger and discussed the proposed merger consideration as well as the public’s percentage ownership of the combined company from an economic and voting perspective. The representative from JPMorgan delivered to the Atlas America board of directors JPMorgan’s oral opinion, subsequently confirmed in writing, that based upon and subject to the factors and assumptions stated in that opinion, as of April 26, 2009, the 1.16 exchange ratio in the merger was fair, from a financial point of view, to Atlas America, as described under “Atlas Energy Proposal / Atlas America Proposal 1: The Merger — Opinion of Atlas America’s Financial Advisor.” After considering the terms of the merger agreement, the opinion of JPMorgan and the other factors described under “Atlas Energy Proposal / Atlas America Proposal 1: The Merger — Atlas America’s Reasons for the Merger; Recommendation of the Atlas America Board of Directors,” the Atlas America board of directors, subject to satisfactory resolution of the small

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number of open issues, (1) determined that the merger agreement and the transactions contemplated thereby, including the stock issuance and the charter amendment, are advisable, fair to and in the best interests of Atlas America and its stockholders, (2) approved the merger agreement and the transactions contemplated thereby, and (3) recommended to Atlas America stockholders that they approve the stock issuance.

During the evening of April 26, 2009, the Atlas Energy special committee held a series of telephonic meetings in which its advisors provided updates regarding the merger agreement negotiations. The advisors reviewed the positions advanced by Atlas America and those by Atlas Energy. The Atlas Energy special committee engaged in a review of the key merger terms that had been negotiated, mindful that Atlas America had stated it would not agree to an exchange ratio higher than 1.16 and evaluated the course of negotiations of the merger terms, including those provisions that Atlas America had not accepted. The special committee also reviewed the qualitative factors that would support a merger, including the available cash at Atlas America and the better access to capital markets that the combined company would likely have, which cash and access would permit Atlas Energy to reduce its debt and lessen Atlas Energy’s concerns about its liquidity and permit the potential acceleration of Atlas Energy’s investment and growth in the Marcellus Shale. The special committee considered the fact that, if the merger were completed, Atlas Energy unitholders (other than Atlas America and Atlas Energy Management, which will not receive Atlas America stock in the merger) would receive common stock in Atlas America and thus participate in any future growth and profitability in the underlying assets of the combined company. Finally, the special committee considered the impact on Atlas Energy and the Atlas Energy unitholders (other than Atlas America and Atlas Energy Management) if a merger with Atlas America did not proceed, in light of the special committee’s belief that the cash distributions to Atlas Energy’s unitholders should be eliminated beginning with the first quarterly distributions in 2009 because of liquidity concerns and other factors. Based upon these factors and considerations, as well as the reasons and considerations described under “Atlas Energy Proposal / Atlas America Proposal 1: The Merger — Atlas Energy’s Reasons for the Merger; Recommendation of the Atlas Energy Board of Directors,” the preliminary consensus of the special committee at the April 26 evening meeting was that, subject to further discussion with the special committee’s advisors, a merger with Atlas America, at the exchange ratio and on the other terms reviewed with the special committee, represented, as a whole, the best terms that could be obtained from Atlas America and was in the best interest of Atlas Energy and its public unitholders.

During the evening of April 26, 2009 and early morning of April 27, 2009, representatives of the parties resolved the remaining open issues to the satisfaction of both parties.

During the morning of April 27, 2009, the Atlas Energy special committee held a telephonic meeting with its various advisors. Representatives from K&L Gates informed the special committee of the final proposed changes to the merger agreement, including that Atlas America agreed to restrictions on its use of cash, and answered the questions of the special committee with respect to such changes. Also at this meeting, UBS reviewed with the special committee UBS’ financial presentation with respect to the exchange ratio and delivered to the special committee an oral opinion, which opinion was confirmed by delivery of a written opinion dated April 27, 2009, to the effect that, as of that date and based on and subject to various assumptions, matters considered and limitations described in its opinion, the exchange ratio provided for in the merger was fair, from a financial point of view, to holders of Atlas Energy common units (other than Atlas America, officers and directors of Atlas Energy and Atlas America and their respective affiliates). Upon completion of its deliberations, the Atlas Energy special committee unanimously determined that the merger agreement and the transactions contemplated thereby were advisable, fair and reasonable to, and in the best interests of, Atlas Energy and the unaffiliated holders of Atlas Energy common units. The special committee unanimously adopted a resolution to recommend that the Atlas Energy board of directors approve the merger agreement and the transactions contemplated thereby and recommend to the common unitholders of Atlas Energy that they vote in favor of the approval and adoption of the merger agreement and the transactions contemplated thereby, including the merger.

Following the action of the Atlas Energy special committee, a telephonic meeting of the Atlas Energy board of directors was held, at which the special committee delivered its recommendation to the Atlas Energy board of directors to approve the merger agreement and the transactions contemplated thereby and to recommend that the

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unitholders of Atlas Energy vote in favor of the approval of the merger transaction. The Atlas Energy board of directors, by the unanimous vote of all the Atlas Energy directors who were members of the special committee with other directors abstaining or recusing themselves, (a) determined that the merger agreement and the transactions contemplated thereby were advisable, fair and reasonable to and in the best interests of Atlas Energy and the unaffiliated unitholders of Atlas Energy and (b) approved and adopted the merger agreement and determined to recommend its adoption and approval by the Atlas Energy unitholders.

On April 27, 2009, Atlas Energy, Atlas America and Atlas Energy Management executed the merger agreement, and Atlas America and Atlas Energy issued a joint press release announcing the execution of the merger agreement.

Atlas America’s Reasons for the Merger; Recommendation of the Atlas America Board of Directors

The Atlas America board of directors, by a unanimous vote, at a meeting held on April 26, 2009, determined that the merger agreement and the transactions contemplated thereby, including the stock issuance and the charter amendment, are advisable, fair to and in the best interests of Atlas America and its stockholders and approved the merger agreement and the transactions contemplated by the merger agreement. The Atlas America board of directors unanimously recommends that Atlas America stockholders vote “FOR” the proposal to issue shares of Atlas America common stock in the merger. It is a condition to the merger that the proposal for the stock issuance be duly approved by the Atlas America stockholders.

In the course of reaching its recommendation, the Atlas America board of directors consulted with Atlas America’s senior management and its financial advisors and outside legal counsel and considered a number of substantive factors, both positive and negative, and potential benefits and detriments of the merger to Atlas America and its stockholders.

Expected Benefits of the Merger

In determining that the merger agreement and the transactions contemplated thereby, including the stock issuance, are advisable, fair to and in the best interests of Atlas America and its stockholders, and in reaching its decision to approve the merger agreement and the transactions contemplated thereby, including the stock issuance, the Atlas America board of directors considered a variety of factors that it believed weighed favorably toward the merger, including the following material factors (which are not listed in any relative order of importance):

• Acceleration of Marcellus Development. The Atlas America board of directors believes that the merger will improve the combined company’s ability to accelerate its investment and growth in the Marcellus Shale because Atlas America’s cash on hand can be used to invest in the development of the Marcellus Shale and because, by ceasing distributions (which, from a capital markets perspective, is more feasible for a publicly traded corporation than a publicly traded limited liability company), the cash flow of the combined company can be reinvested in the Marcellus Shale;

• Reduction in Debt. The Atlas America board of directors believes that the merger will improve the combined company’s ability to reduce its debt because Atlas America’s cash on hand can be used to repay such debt and because, by ceasing distributions (which, from a capital markets perspective, is more feasible for a publicly traded corporation than a publicly traded limited liability company), the cash flow of the combined company can be used to repay debt, which the Atlas America board of directors believes is important in light of Atlas Energy’s uncertainties regarding credit availability (including the possibility of a decrease in the borrowing base under Atlas Energy’s revolving credit facility) and the amount of cash being generated by Atlas Energy and its subsidiaries;

• Stronger Balance Sheet. The Atlas America board of directors believes that the combined company resulting from the merger will have a stronger balance sheet, along with a lower cost of capital. In addition, the retention and investment of future cash flows will also reduce the need to raise capital from outside sources under unfavorable market conditions similar to those that currently exist;

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• Greater Cash Flow for Reinvestment. The Atlas America board of directors believes that the combined company’s cash position will allow the combined company and its equityholders to enjoy an enhanced ability to effectively exploit its properties, including by continuing and expanding its horizontal drilling program in the Marcellus Shale for its own account (instead of solely in the form of joint ventures or partnerships with third parties), which the Atlas America board of directors believes could be more favorable to the company than drilling programs in the form of joint ventures or partnerships with third parties;

• Simplified Organizational Structure. The Atlas America board of directors believes that the merger will simplify the organizational structure of Atlas America and Atlas Energy, resulting in a single, publicly traded company with a more transparent organizational structure, a single board of directors and a single class of equity, as compared to the current organizational structure with two publicly traded companies deriving most of their value from the same set of assets, with two boards of directors and three classes of equity (with Atlas Energy requiring a vote of both the Atlas Energy common units and the Atlas Energy Class A units on certain matters). In addition, the simplified organization structure will spread the ongoing costs of being a public company over a larger body of equityholders in the combined company;

• Synergies.The Atlas America board of directors believes that the merger will allow Atlas America and Atlas Energy to achieve synergies in the form of cost savings and other efficiencies, including reduced SEC filing requirements and a reduction in the number of public company boards and other costs associated with multiple public companies;

• Greater Liquidity.The Atlas America board of directors believes that the merger would improve the liquidity of each company’s equity because the combined company and its equity float will be significantly larger than each company on a stand-alone basis;

• Improved Access to Capital Markets. The Atlas America board of directors believes that the combined company will have a larger public float. In addition, the Atlas America board of directors believes that the merger will enhance investor interest in the combined company and its equity securities because, among other things, the combined company will be a corporation instead of a publicly traded limited liability company. The Atlas America board of directors believes that a publicly traded corporation, rather than a publicly traded limited liability company, is the appropriate vehicle for a growth-oriented, resource exploration and production company with the growth opportunities to which the combined company has access because many institutional investors have limitations or restrictions on investing in limited liability companies because of tax and other reasons; and

• Feasibility.The Atlas America board of directors believes that the merger has the greatest likelihood of success of achieving in the short term the goals outlined above, as compared to other possible alternatives, including raising additional cash in either the public equity or debt capital markets or raising additional cash from joint venture partners, which alternatives are dependent on conditions in the capital markets and third parties and which the Atlas America board of directors would not be as favorable to the company as the merger.

Other Material Factors Considered

During the course of its deliberations relating to the merger agreement and the merger, the Atlas America board of directors considered the following factors in addition to the benefits described above:

• the opinion of JPMorgan, dated April 26, 2009, to the Atlas America board of directors to the effect that, as of that date, and based upon the factors and subject to the assumptions set forth in such opinion, the 1.16 exchange ratio was fair, from a financial point of view, to Atlas America, which opinion, together with the material financial analyses performed by JPMorgan and reviewed with the Atlas America board of directors in connection with JPMorgan’s opinion and certain other information regarding JPMorgan’s engagement, are further described under “Atlas Energy Proposal / Atlas America Proposal 1: The Merger — Opinion of Atlas America’s Financial Advisor”;

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• the fact that the exchange ratio is fixed and will not fluctuate based upon changes in the market price of Atlas America common stock between the date of the merger agreement and the date of the consummation of the merger;

• the terms and conditions of the merger agreement, including the strong commitments by both Atlas America and Atlas Energy to complete the merger, and the likelihood of completing the merger on the anticipated schedule;

• the fact that the merger would not trigger a “change of control put” under the indentures governing Atlas Energy’s publicly traded notes;

• the fact that the merger agreement provides that the Atlas America board of directors may withdraw, modify or qualify in any manner its recommendation to the Atlas America stockholders if the Atlas America board of directors concludes in good faith that such a change in recommendation is required to be consistent with its applicable fiduciary duties; and

• the results of the due diligence investigations of Atlas Energy by Atlas America’s legal counsel and financial advisor, which were consistent with the expectations of the Atlas America board of directors with respect to the strategic and financial benefits of the merger.

The Atlas America board of directors weighed these advantages and opportunities against a number of other factors identified in its deliberations weighing negatively against the merger, including:

• the dilution associated with the shares of Atlas America stock that Atlas America will issue to Atlas Energy unitholders in the merger;

• the elimination of potentially valuable payments from the management incentive interests controlled by Atlas America by way of its ownership of Atlas Energy Management, Inc.;

• the fact that because the merger consideration is a fixed exchange ratio of shares of Atlas America common stock to Atlas Energy common units, Atlas America stockholders could be adversely affected by a decrease in the trading price of Atlas Energy common units during the pendency of the merger, and the fact that the merger agreement does not provide Atlas America with a price-based termination right or other similar protection;

• the amount of outstanding Atlas Energy debt and the potential effects of the merger on Atlas Energy’s existing credit agreement and other outstanding debt;

• certain terms of the merger agreement, including restrictions on the conduct of Atlas America’s business prior to the completion of the merger (which require Atlas America to conduct its business in the ordinary course consistent with past practice, subject to specific limitations, which may delay or prevent Atlas America from undertaking business opportunities that may arise pending completion of the merger), particularly restrictions on Atlas America’s use of cash;

• the fact that, according to the merger agreement, in the event that an alternative acquisition proposal is made to Atlas America, notwithstanding the ability of the Atlas America board of directors to withdraw, modify or qualify in any manner its recommendation to the Atlas America stockholders, Atlas America has an obligation to call, hold, and convene the meeting of its stockholders to vote on the stock issuance;

• the fact that the merger would have the effect of eliminating the value to Atlas America derived from its ownership of the management incentive interests and 100% of the Class A units in Atlas Energy, as well as eliminate the value from the concentration of ownership represented by its approximate 47% common unit ownership in Atlas Energy;

• the possible disruption to Atlas America’s business that may result from the merger and the resulting distraction of the attention of Atlas America’s management, as well as the costs and expenses associated with completing the merger;

• the likelihood of litigation challenging the merger and the possibility that an adverse judgment for monetary damages could have a material adverse effect on the operations of the combined company

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after the merger or an adverse judgment granting permanent injunctive relief could indefinitely enjoin completion of the merger;

• the possibility that the merger might not be consummated despite the parties’ efforts or that the closing of the merger may be unduly delayed; and

• the risks of the type and nature described under “Risk Factors,” and the matters described under “Cautionary Statement Regarding Forward-Looking Statements.”

After consideration of these material factors, the Atlas America board of directors determined that these risks could be mitigated or managed by Atlas America or Atlas Energy or, following the merger, by the combined company, were reasonably acceptable under the circumstances, or, in light of the anticipated benefits, overall, were significantly outweighed by the potential benefits of the merger.

The foregoing discussion of the information and factors considered by the Atlas America board of directors includes all of the material factors considered by the Atlas America board of directors, but it is not intended to be exhaustive and may not include all of the factors considered by Atlas America board of directors. In view of the wide variety of factors considered in connection with its evaluation of the merger and the complexity of these matters, the Atlas America board of directors did not find it useful and did not attempt to quantify or assign any relative or specific weights to the various factors that it considered in reaching its determination to approve the merger and the merger agreement and to make its recommendations to Atlas America stockholders. In addition, individual members of the Atlas America board of directors may have given differing weights to different factors. The Atlas America board of directors conducted an overall review of the factors described above, including thorough discussions with Atlas America’s management and outside legal and financial advisors.

The Atlas America board of directors unanimously determined that the merger agreement and the transactions contemplated thereby, including the stock issuance, are advisable, fair to and in the best interests of Atlas America and its stockholders and unanimously approved the merger agreement and the transactions contemplated by the merger agreement. The Atlas America board of directors unanimously recommends that Atlas America stockholders vote “FOR” the proposal to issue shares of Atlas America common stock in the merger.

Atlas Energy’s Reasons for the Merger; Recommendation of the Atlas Energy Special Committee and the Atlas Energy Board of Directors

In the course of evaluating a number of strategic alternatives for Atlas Energy, the Atlas Energy special committee, the members of which constituted a majority of the members of the Atlas Energy conflicts committee, ultimately determined that the merger with Atlas America was the best strategic alternative for Atlas Energy and the Atlas Energy unitholders that are unaffiliated with Atlas America. At meetings of the Atlas Energy special committee, the special committee considered, with the assistance of its advisors, potential strategic alternatives available to Atlas Energy, including a merger with Atlas America. In connection with the proposed merger with Atlas America, the special committee reviewed with its legal counsel and financial advisor the terms of the merger (including the consideration to be received by the unitholders of Atlas Energy), the merger agreement and other related transaction documents and matters. At the meeting on April 27, 2009, the Atlas Energy special committee determined by unanimous vote of all of its members that the merger agreement and the transactions contemplated thereby, including the merger, are advisable, fair and reasonable to, and in the best interests of, Atlas Energy and the Atlas Energy unitholders that are not affiliated with Atlas America, and resolved to recommend that the full Atlas Energy board of directors adopt the merger agreement, approve the transactions contemplated thereby, and recommend the adoption of the merger agreement and approval of the transactions contemplated thereby by the Atlas Energy unitholders.

Expected Benefits of the Merger.

In evaluating the merger, the Atlas Energy special committee consulted with its legal counsel and financial advisor, as well as certain members of Atlas Energy’s management, and, in reaching its determination to approve

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the merger agreement and recommend that the Atlas Energy board of directors approve the merger agreement and the transactions contemplated thereby carefully considered a number of factors involved in and potential benefits of a merger with Atlas America, including the following material factors (which are not listed in any relative order of importance):

• Merger Superior to Alternatives.The special committee’s belief that the merger was superior to other alternatives available to Atlas Energy because, among other things:

• the special committee’s belief that general industry, economic and market conditions posed increased risks to the financial condition, results of operations and prospects of Atlas Energy as a standalone business, including potential liquidity and credit agreement issues and lack of capital to accelerate development of the Marcellus Shale;

• the special committee’s belief that a potential reduction in or elimination of Atlas Energy’s distributions of available cash would likely be necessary, which reduction or elimination, in the absence of a strategic transaction, could result in a material negative impact on the price of Atlas Energy’s units; and

• the special committee’s belief that other standalone alternatives, such as maintaining the status quo, eliminating cash distributions while remaining a limited liability company, or converting to a C-corporation, and such transactional alternatives, such as an outright sale to a third party or a joint venture, were not achievable or in the best interests of Atlas Energy and would not enhance the value of the common units held by unaffiliated unitholders as much as the merger on the terms set forth in the merger agreement;

• Stronger Balance Sheet; Lower Cost of Capital; Improved Liquidity.The special committee’s belief that a merger with Atlas America would create a stronger balance sheet and capital structure, along with a lower cost of capital and improved liquidity;

• Reduction in Debt; Acceleration of Marcellus Shale; Improved Access to Capital Markets.The special committee’s belief that, as a result of the merger with Atlas America, outstanding debt at Atlas Energy could be reduced and accelerated drilling of the Marcellus Shale pursued through a combination of cash available at Atlas America, the retention and investment of future cash otherwise applied to funding cash distributions to unitholders (historically approximately $160 million per year), and better access to the equity capital markets than could be achieved as a limited liability company;

• Continued Participation in Assets.The special committee’s belief that the Atlas Energy public unitholders would be able to continue to participate in the future profitability of the merged entity, which would be enhanced as a result of the improved liquidity situation and the other factors described in this section;

• Elimination of Voting Block and Value of Management Incentive Interests.The special committee’s belief that the merger will enhance value to unaffiliated Atlas Energy unitholders by eliminating the concentration of ownership represented by Atlas America’s approximate 47% common unit ownership and by eliminating the voting and economic effect on the public Atlas Energy unitholders resulting from Atlas America’s ownership of Atlas Energy’s Class A units and management incentive interests, all of which provided Atlas America with significant control over Atlas Energy and provided value to Atlas America not shared by Atlas Energy’s public unitholders;

• Simplified Organizational Structure; Larger Public Float.The special committee’s belief that the merger will simplify the organizational structure of the Atlas companies and create a more attractive investment opportunity with a larger public float;

• Synergies.The special committee’s belief that the merger would allow Atlas America and Atlas Energy to achieve synergies in the form of cost savings and other efficiencies, including reduced SEC filing requirements and a reduction in the number of public company boards and other costs associated with multiple public companies; and

• Feasibility.The special committee’s belief that the merger has the greatest likelihood of success of achieving in the short term the goals outlined above, as compared to other possible alternatives.

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Other Material Factors Considered

The Atlas Energy special committee also considered the following factors in addition to the benefits described above:

• the fact that the terms of the merger agreement were determined through extensive negotiations between the special committee, with the assistance of its own legal and financial advisors and outside counsel to Atlas Energy, on the one hand, and representatives of Atlas America, with the assistance of its advisors, on the other;

• that Atlas America has sufficient unit ownership to effectively block the sale or conversion of Atlas Energy and, based upon discussions between representatives of Atlas America and representatives of the special committee, Atlas America would not support a third party sale of Atlas Energy, a conversion of Atlas Energy from a limited liability company to a corporation, or a joint venture involving the transfer of substantially all the assets of Atlas Energy;

• the history of the negotiations with respect to the exchange ratio that, among other things, ultimately led to an increase in the exchange ratio from 0.96 of a share of Atlas America common stock for each common unit of Atlas Energy that Atlas America did not already own to the final exchange ratio of 1.16 shares of Atlas America common stock for each common unit of Atlas Energy that Atlas America did not already own, or an increase of approximately 21%;

• the special committee’s conclusion that the terms reflected by the exchange ratio and contained in the merger agreement represent the best economic terms that could be obtained from Atlas America and would result in an approximately 49.7% pro forma ownership interest in Atlas America’s assets by current holders of Atlas Energy common units (other than Atlas America) and which represented a small premium to the market price of Atlas Energy common units on April 24, 2009;

• the fact that the exchange ratio was fixed and therefore the value of the consideration payable to Atlas Energy unitholders would increase in the event that the share price of Atlas America increased prior to closing;

• the fact that the merger would not trigger a “change of control put” under the indentures governing Atlas Energy’s publicly traded notes;

• the fact that the merger agreement provides that the Atlas Energy board of directors or the Atlas Energy special committee may withdraw, modify or qualify in any manner its recommendation to the Atlas Energy unitholders if they conclude in good faith that such a change in recommendation is required to be consistent with its applicable fiduciary duties;

• the fact that the merger agreement placed restrictions on Atlas America’s use of cash between the signing of the merger agreement and closing, as well as restrictions on its ability to guarantee obligations of its subsidiaries; and

• the opinion of UBS and related financial presentation dated April 27, 2009 to the special committee as to the fairness, from a financial point of view and as of the date of the opinion, of the exchange ratio provided for in the merger to holders of Atlas Energy common units (other than Atlas America, officers and directors of Atlas Energy and Atlas America and their respective affiliates), which opinion, together with the material financial analyses performed by UBS and reviewed with the special committee in connection with UBS’ opinion and certain other information regarding UBS’ engagement, are further described under “Atlas Energy Proposal / Atlas America Proposal 1: The Merger — Opinion of Financial Advisor to the Atlas Energy Special Committee.”

The Atlas Energy special committee also considered and, as appropriate, balanced against the potential benefits of the merger a number of neutral and potentially negative factors, including the following:

• the potentially adverse tax consequences to certain holders of Atlas Energy common units resulting from the merger, which for U.S. federal income tax purposes, generally will be a taxable transaction to Atlas Energy unitholders;

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• the fact that the exchange ratio does not provide Atlas Energy unitholders with a substantial premium to the market price of Atlas Energy common units, as the exchange ratio represents only a 0.3% premium to the closing market price immediately prior to signing of the merger agreement;

• the fact that the exchange ratio was fixed and therefore the value of the consideration payable to Atlas Energy unitholders would decrease in the event that the share price of Atlas America decreased prior to closing;

• the likelihood of litigation challenging the merger and the possibility that an adverse judgment for monetary damages could have a material adverse effect on the operations of the combined company after the merger or an adverse judgment granting permanent injunctive relief could indefinitely enjoin completion of the merger;

• the fact that public unitholders of Atlas Energy will not be entitled to appraisal rights;

• the fact that Atlas Energy did not solicit alternative proposals prior to executing the merger agreement (because no alternative proposals were likely to be obtained (or, if obtained, successfully concluded) in light of Atlas America’s stated unwillingness to sell its equity interests in Atlas Energy, approve a merger with a third party or approve a conversion of Atlas Energy to a C-corporation;

• the fact that the merger requires approval of the majority of the lenders under the Atlas Energy credit agreement and the receipt of certain regulatory approvals;

• the fact that Atlas America currently owns 47.3% of the outstanding Atlas Energy common units, and Atlas Energy Management, which is a wholly owned subsidiary of Atlas America, owns 100% of the outstanding Atlas Energy Class A units, thus representing a potential conflict of interest;

• the fact that the merger agreement requires only the approval of the merger by holders of a simple majority of both the outstanding Atlas Energy common units and Atlas Energy Class A units, each voting separately as a class (of which Atlas America owns approximately 47% of the Atlas Energy common units and, through Atlas Energy Management, 100% of the Atlas Energy Class A units) and does not include a “majority of the minority” or similar voting requirement;

• the fact that, according to the merger agreement, in the event that an alternative acquisition proposal is made to Atlas Energy, notwithstanding the ability of the Atlas Energy board of directors and Atlas Energy special committee to withdraw, modify or qualify in any manner its recommendation to the Atlas Energy unitholders, Atlas Energy has an obligation to call, hold, and convene a meeting of its unitholders to vote on the adoption of the merger agreement and approval of the transactions contemplated thereby, including the merger;

• the potentially dilutive effect of the merger on the public unitholders of Atlas Energy given that, following the merger, the common unitholders of Atlas Energy (other than Atlas America and Atlas Energy Management, which will not receive Atlas America common stock in the merger) would own approximately 49.7% of Atlas America, as compared to their approximate 51.7% economic ownership of Atlas Energy prior to the merger, without taking into account available cash at Atlas America and the value of other assets of Atlas America;

• the fact that, if the merger is completed, Atlas Energy common unitholders will receive common stock in Atlas America and, therefore, will be exposed to the risks attendant in the other businesses of Atlas America and, therefore, the possibility that Atlas America will not perform as well in the future as Atlas Energy may have performed as a public subsidiary of Atlas America and thus the possibility that the public unitholders of Atlas Energy will not receive the full benefit of any future growth in the value of their equity that Atlas Energy may have otherwise achieved;

• the restrictions on the conduct of Atlas Energy’s business prior to the completion of the merger, which may delay or prevent Atlas Energy from taking certain actions during the time that the merger agreement remains in effect, including making any distributions to the Atlas Energy unitholders;

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• the risk that, while the merger is expected to be completed, there can be no assurance that all conditions to the parties’ obligations to complete the merger will be satisfied and, as a result, it is possible that the merger may not be completed even if approved by Atlas Energy’s unitholders;

• the interests of certain executive officers and directors of Atlas Energy with respect to the merger in addition to their interests as unitholders of Atlas Energy generally (see “Atlas Energy Proposal / Atlas America Proposal 1: The Merger — Interests of Atlas Energy Directors and Executive Officers in the Merger”); and

• other risks associated with an investment in Atlas America common stock described in periodic reports previously filed with the SEC by Atlas America, including those factors discussed in this joint proxy statement/prospectus under “Risk Factors — Risks Relating to Atlas America” and “Risk Factors — Risks Relating to the Business of Atlas Pipeline Holdings and Atlas Pipeline.”

After consideration of these factors, the special committee concluded that the potential benefits of the merger outweighed these considerations and determined that the merger agreement and the transaction contemplated thereby, including the merger were advisable, fair and reasonable and in the best interests of Atlas Energy unitholders not affiliated with Atlas America.

The above discussion of the information and factors considered by the Atlas Energy special committee is not exhaustive and does not include all factors considered by the special committee. In evaluating the merger, the members of the Atlas Energy special committee considered their knowledge of the business, financial condition and prospects of Atlas Energy. In light of the number and variety of factors that the special committee considered in connection with their evaluation of the merger, the special committee did not find it practicable to quantify or assign relative weights to the foregoing factors. Rather, the special committee made its determination based upon the aggregate information available to it. In addition, individual members of the special committee may have given different weights to different factors. Based on the factors outlined above, and the totality of the information presented to and considered by it, the special committee determined that the merger was advisable, fair and reasonable to, and in the best interests of, Atlas Energy unitholders other than Atlas America and its affiliates.

At its meeting on April 27, 2009 following the meeting of the special committee, the Atlas Energy board of directors, with all of the directors other than members of the special committee abstaining or recusing themselves, and based upon the unanimous recommendation of the Atlas Energy special committee, (1) determined that the merger agreement and the transactions contemplated thereby, including the merger, are advisable, fair and reasonable to, and in the best interests of, Atlas Energy and the Atlas Energy unitholders that are not affiliated with Atlas America and (2) approved and adopted the merger agreement and determined to recommend its adoption and approval by the Atlas Energy unitholders.

Based upon the unanimous recommendation of the Atlas Energy special committee, the Atlas Energy board of directors recommends that Atlas Energy unitholders vote “FOR” the proposal to adopt the merger agreement and approve the transactions contemplated thereby, including the merger.

Opinion of Atlas America’s Financial Advisor

Pursuant to an engagement letter dated February 3, 2009, Atlas America retained JPMorgan as its financial advisor in connection with the proposed merger.

At the meeting of the Atlas America board of directors on April 26, 2009, JPMorgan rendered its oral opinion, subsequently confirmed in writing, to the Atlas America board of directors that, as of such date and based upon and subject to the factors and assumptions set forth in its opinion, the exchange ratio in the proposed merger was fair, from a financial point of view, to Atlas America. No limitations were imposed by the Atlas America board of directors upon JPMorgan with respect to the investigations made or procedures followed by it in rendering its opinion. The issuance of JPMorgan’s opinion was approved by a fairness opinion committee of JPMorgan on April 26, 2009.

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The full text of the written opinion of JPMorgan which sets forth the assumptions made, matters considered and limits on the review undertaken, is attached as Annex B to this joint proxy statement/prospectus and is incorporated herein by reference. Atlas America’s stockholders are urged to read the opinion in its entirety. JPMorgan’s written opinion is addressed to the Atlas America board of directors, is directed only to the exchange ratio in the merger and does not constitute a recommendation to any Atlas America stockholder as to how such stockholder should vote at the Atlas America special meeting. The summary of the opinion of JPMorgan set forth in this joint proxy statement/prospectus is qualified in its entirety by reference to the full text of such opinion.

In arriving at its opinions, JPMorgan, among other things:

• reviewed a draft dated April 26, 2009 of the merger agreement;

• reviewed certain publicly available business and financial information concerning Atlas America and Atlas Energy and the industries in which they operate;

• compared the financial and operating performance of Atlas America and Atlas Energy with publicly available information concerning certain other companies JPMorgan deemed relevant and reviewed the current and historical market prices of Atlas America common stock and Atlas Energy common units and certain publicly traded securities of such other companies;

• reviewed certain internal financial analyses and forecasts prepared by the managements of Atlas America and Atlas Energy relating to their respective businesses; and

• performed such other financial studies and analyses and considered such other information as JPMorgan deemed appropriate for the purposes of its opinion.

JPMorgan also held discussions with certain members of the management of Atlas America and Atlas Energy with respect to certain aspects of the merger, and the past and current business operations of Atlas America and Atlas Energy, the financial condition and future prospects and operations of Atlas America and Atlas Energy, the effects of the merger on the financial condition and future prospects of Atlas America and certain other matters JPMorgan believed necessary or appropriate to its inquiry.

JPMorgan relied upon and assumed, without assuming responsibility or liability for independent verification, the accuracy and completeness of all information that was publicly available or was furnished to or discussed with JPMorgan by Atlas America and Atlas Energy or otherwise reviewed by or for JPMorgan. JPMorgan did not conduct or was not provided with any valuation or appraisal of any assets or liabilities, nor did JPMorgan evaluate the solvency of Atlas America and Atlas Energy under any state or federal laws relating to bankruptcy, insolvency or similar matters. In relying on financial analyses and forecasts provided to it or derived therefrom, JPMorgan assumed that they were reasonably prepared based on assumptions reflecting the best currently available estimates and judgments by management as to the expected future results of operations and financial condition of Atlas America and Atlas Energy to which such analyses or forecasts relate. JPMorgan expressed no view as to such analyses or forecasts or the assumptions on which they were based. JPMorgan also assumed that the merger will have the tax consequences described in this joint proxy statement/prospectus, and in discussions with, and materials furnished to JPMorgan by, representatives of Atlas America, and that the transactions contemplated by the merger agreement will be consummated as described in the merger agreement and this joint proxy statement/prospectus, and that the definitive merger agreement would not differ in any material respect from the draft thereof provided to JPMorgan. JPMorgan also assumed that the representations and warranties made by Atlas America and Atlas Energy in the merger agreement and the related agreements are and will be true and correct in all ways material to its analysis. JPMorgan further assumed that all material governmental, regulatory or other consents and approvals (including amendments to any credit facilities) necessary for the consummation of the merger will be obtained without any adverse effect on Atlas America or on the contemplated benefits of the merger.

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The projections furnished to JPMorgan for Atlas America and Atlas Energy were prepared by the respective managements of each company. JPMorgan is not a legal, regulatory or tax expert and has relied on the assessments made by advisors to Atlas America with respect to such issues. Neither Atlas America nor Atlas Energy publicly discloses internal management projections of the type provided to JPMorgan in connection with JPMorgan’s analysis of the merger, and such projections were not prepared with a view toward public disclosure. These projections were based on numerous variables and assumptions that are inherently uncertain and may be beyond the control of management, including, without limitation, factors related to general economic and competitive conditions and prevailing interest rates. Accordingly, actual results could vary significantly from those set forth in such projections.

JPMorgan’s opinion is based on economic, market and other conditions as in effect on, and the information made available to JPMorgan as of, the date of such opinion. Subsequent developments may affect JPMorgan’s opinion, and JPMorgan does not have any obligation to update, revise, or reaffirm such opinion. JPMorgan’s opinion is limited to the fairness, from a financial point of view, of the exchange ratio in the proposed merger, and JPMorgan has expressed no opinion as to the fairness of the merger to, or any consideration of, the holders of any class of securities, creditors or other constituencies of Atlas America or the underlying decision by Atlas America to engage in the merger. Furthermore, JPMorgan expressed no opinion with respect to the amount or nature of any compensation to any officers, directors, or employees of any party to the merger, or any class of such persons relative to the exchange ratio in the merger or with respect to the fairness of any such compensation. JPMorgan expressed no opinion as to the price at which Atlas America common stock or Atlas Energy common units will trade at any future time, whether before or after the closing of the merger.

The terms of the merger agreement, including the exchange ratio, were determined through negotiations between Atlas America and Atlas Energy and were approved by both boards of directors. Atlas America’s decision to enter into the merger agreement was solely that of the Atlas America board of directors. The JPMorgan opinion and financial analyses were only one of the many factors considered by Atlas America in its evaluation of the merger and should not be viewed as determinative of the views of the Atlas America board of directors or Atlas America’s management with respect to the merger or the exchange ratio.

In accordance with customary investment banking practice, JPMorgan employed generally accepted valuation methods in reaching its opinion. The following is a summary of the material financial analyses utilized by JPMorgan in connection with providing its opinion and does not purport to be a complete description of the analysis underlying JPMorgan’s opinion.

JPMorgan performed its analyses of Atlas Energy based on two primary set of assumptions for a net asset valuation: (1) a set of assumptions developed assuming that Atlas Energy remained as a master limited partnership, or the MLP case; and (2) a set of assumptions developed assuming that Atlas Energy was converted to a “C-corporation,” or the C-corp case. JPMorgan compared each of these scenarios to a Discounted Cash Flow analysis of Atlas America.

Net asset valuation of Atlas Energy

JPMorgan conducted a net asset valuation analysis of Atlas Energy. JPMorgan performed its analysis based on a variety of data sources provided by Atlas Energy’s management, including financial projections and economic models, which were discussed with and approved by Atlas America’s management, and certain other publicly available information. JPMorgan assumed forecasted commodity prices based on publicly available trading prices on the New York Mercantile Exchange through 2013 and normalized commodity prices thereafter. The production and realized prices were netted against estimated future operating expenses and capital expenditures to derive the cash flows for the MLP case and the after-tax cash flows for the C-corp case. These cash flows were discounted using discount rates ranging from 11.25% to 13.25% for the MLP case and 9.25% to 11.25% for the C-corp case. The range of discount rates used by JPMorgan in its analysis was estimated using traditional investment banking methodology, including the analysis of selected publicly traded companies engaged in businesses that JPMorgan deemed relevant to Atlas Energy’s businesses.

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Based on the assumptions set forth above, this analysis implied for Atlas Energy common equity ranges of $1,025mm to $2,060mm and $1,156mm to $2,835mm, or an implied share price range of $15.86 to $31.62 and $17.87 to $43.27, for the MLP case and the C-corp case, respectively. Based on these values, the stake of unitholders in Atlas Energy (excluding Atlas America’s and Atlas Energy Management’s units in Atlas Energy) was valued at a range of $530mm to $1,065mm and $597mm to $1,465mm for the MLP case and the C-corp case, respectively.

Discounted Cash Flow Analysis of Atlas America

In determining an estimated range of equity values of Atlas America, JPMorgan performed a discounted cash flow analysis of the future dividends to be received by Atlas America from each of its non-Atlas Energy subsidiaries for the purpose of determining an estimated range of equity values of Atlas America. The discounted cash flow analysis was based upon Atlas America’s business plan for the fiscal years 2009 through 2013 and additional assumptions provided by Atlas America’s management for the fiscal year 2013 and in perpetuity. JPMorgan calculated the free cash flows that Atlas America is expected to generate during fiscal years 2009 through 2013, based on Atlas America’s business plan. JPMorgan calculated an implied range of terminal values for Atlas America using a range of perpetuity growth rates from 1.0% to 3.0% and discount rates ranging from 15.75% to 17.75% for the dividends derived from each of its non-Atlas Energy subsidiaries. The range of discount rates used by JPMorgan in its analysis was estimated using traditional investment banking methodology, including the analysis of selected publicly traded companies engaged in businesses that JPMorgan deemed relevant to Atlas America’s other businesses. Atlas America’s stake in Atlas Energy was valued using the net asset valuation explained above.

Based on the assumptions set forth above, this discounted cash flow analysis implied equity ranges for Atlas America of $569mm to $1,027mm and $633mm to $1,402mm for the MLP case and the C-corp case, respectively, which includes its stake in Atlas Energy.

JPMorgan observed that the net asset valuation ranges of Atlas Energy and the discounted cash flow valuation ranges of Atlas America described above imply a range of exchange ratios of 1.094x to 1.218x and 1.110x and 1.229x for the MLP case and the C-corp case, respectively. JPMorgan noted these ranges relative to the transaction exchange ratio of 1.160x.

The foregoing summary of certain material financial analyses does not purport to be a complete description of the analyses or data presented by JPMorgan. The preparation of a fairness opinion is a complex process and is not necessarily susceptible to partial analysis or summary description. JPMorgan believes that the foregoing summary and its analyses must be considered as a whole and that selecting portions of the foregoing summary and these analyses, without considering all of its analyses as a whole, could create an incomplete view of the processes underlying the analyses and its opinion. In arriving at its opinion, JPMorgan did not attribute any particular weight to any analyses or factors considered by it and did not form an opinion as to whether any individual analysis or factor (positive or negative), considered in isolation, supported or failed to support its opinion. Rather, JPMorgan considered the totality of the factors and analyses performed in determining its opinion. Analyses based upon forecasts of future results are inherently uncertain, as they are subject to numerous factors or events beyond the control of the parties and their advisors. Accordingly, forecasts and analyses used or made by JPMorgan are not necessarily indicative of actual future results, which may be significantly more or less favorable than suggested by those analyses. Moreover, JPMorgan’s analyses are not and do not purport to be appraisals or otherwise reflective of the prices at which businesses actually could be bought or sold. None of the selected companies reviewed as described in the above summary is identical to Atlas America, and none of the selected transactions reviewed was identical to the merger. However, the companies selected were chosen because they are publicly traded companies with operations and businesses that, for purposes of JPMorgan’s analysis, may be considered similar to those of Atlas America. The analyses necessarily involve complex considerations and judgments concerning differences in financial and operational characteristics of the companies involved and other factors that could affect the companies compared to Atlas America and the transactions compared to the merger.

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As a part of its investment banking business, JPMorgan and its affiliates are continually engaged in the valuation of businesses and their securities in connection with mergers and acquisitions, investments for passive and control purposes, negotiated underwritings, secondary distributions of listed and unlisted securities, private placements, and valuations for estate, corporate and other purposes. JPMorgan was selected to advise Atlas America with respect to the merger on the basis of such experience and its familiarity with Atlas America.

For services rendered in connection with the merger, Atlas America has agreed to pay JPMorgan $7.7 million, $1.0 million of which became payable after public announcement of the proposed transaction, and the remainder of which will become payable only if the merger is consummated. In addition, Atlas America has agreed to reimburse JPMorgan for its expenses incurred in connection with its services, including the fees and disbursements of counsel, and will indemnify JPMorgan against certain liabilities, including liabilities arising under the Federal securities laws.

During the two years preceding the date of its opinion, JPMorgan and its affiliates have had commercial or investment banking relationships with Atlas America, Atlas Energy and certain of their respective affiliates for which it and such of its affiliates have received customary compensation. Such services during such period have included acting as joint bookrunner for Atlas Pipeline Holdings in a $250 million bond offering in June 2008, co-manager and bookrunner for Atlas Pipeline Holdings in a $187.6 million follow-on equity offering in June 2008, lead bookrunner for Atlas Energy on bond offerings of $250 million and $150 million in January and May 2008, respectively, and agent bank and lender on Atlas America’s $850 million credit facility in June 2007. In addition, JPMorgan’s banking affiliate is an agent bank and a lender under Atlas Energy’s $650 million senior secured revolving credit facility (which we refer to as the “Atlas Energy Credit Facility”), for which it receives customary compensation or other financial benefits. It is anticipated that the Atlas Energy Credit Facility will be amended in connection with the merger and that such amendment will result in the payment of customary compensation to our affiliate and in certain of the terms under the Atlas Energy Credit Facility being amended to be more favorable to the lenders thereunder. In addition, JPMorgan and its affiliates maintain banking and other business relationships with Atlas America and its affiliates, for which it receives customary fees. In the ordinary course of their businesses, JPMorgan and its affiliates may actively trade the debt and equity securities of Atlas America or Atlas Energy for their own accounts or for the accounts of customers and, accordingly, they may at any time hold long or short positions in such securities.

Opinion of Financial Advisor to the Atlas Energy Special Committee

On April 27, 2009, at a meeting of the Atlas Energy special committee held to evaluate the proposed merger, UBS delivered to the Atlas Energy special committee an oral opinion, which opinion was confirmed by delivery of a written opinion to the Atlas Energy special committee, dated April 27, 2009, to the effect that, as of that date and based on and subject to various assumptions, matters considered and limitations described in its opinion, the exchange ratio provided for in the merger was fair, from a financial point of view, to holders of Atlas Energy common units (other than Atlas America, officers and directors of Atlas Energy and Atlas America, and their respective affiliates).

The full text of UBS’ opinion describes the assumptions made, procedures followed, matters considered and limitations on the review undertaken by UBS. This opinion is attached as Annex C and is incorporated into this joint proxy statement/prospectus by reference.Holders of Atlas Energy common units are encouraged to read UBS’ opinion carefully in its entirety. UBS’ opinion was provided for the benefit of the Atlas Energy special committee in connection with, and for the purpose of, its evaluation of the exchange ratio from a financial point of view and does not address any other aspect of the merger. The opinion does not address the relative merits of the merger as compared to other business strategies or transactions that might be available with respect to Atlas Energy or Atlas Energy’s underlying business decision to effect the merger. The opinion does not constitute a recommendation to any security holder as to how to vote or act with respect to the merger. The following summary of UBS’ opinion is qualified in its entirety by reference to the full text of UBS’ opinion.

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In arriving at its opinion, UBS, among other things:

• reviewed certain publicly available business and financial information relating to Atlas Energy and Atlas America, including publicly available gas reserve estimates of Atlas Energy;

• reviewed certain internal financial information and other data relating to Atlas Energy’s business and financial prospects that were not publicly available, including financial forecasts and estimates prepared by Atlas Energy’s management that the Atlas Energy special committee directed UBS to utilize for purposes of its analysis;

• reviewed certain internal financial information and other data relating to Atlas America’s business and financial prospects that were not publicly available, including financial forecasts and estimates prepared by Atlas America’s management that the Atlas Energy special committee directed UBS to utilize for purposes of its analysis;

• reviewed certain estimates of synergies prepared by Atlas America’s management that were not publicly available and that the Atlas Energy special committee directed UBS to utilize for purposes of its analysis;

• conducted discussions with members of the senior managements of Atlas Energy and Atlas America concerning the businesses and financial prospects of Atlas Energy and Atlas America;

• reviewed publicly available financial and stock market data with respect to certain other companies UBS believed to be generally relevant;

• reviewed current and historical market prices of Atlas Energy common units, Atlas America common stock, and publicly traded securities of certain affiliated entities in which Atlas America holds equity interests and/or for which it has guaranteed certain indebtedness;

• reviewed a draft, dated April 27, 2009, of the merger agreement; and

• conducted such other financial studies, analyses and investigations, and considered such other information, as UBS deemed necessary or appropriate.

In connection with its review, with the Atlas Energy special committee’s consent, UBS assumed and relied upon, without independent verification, the accuracy and completeness in all material respects of the information provided to or reviewed by UBS for the purpose of its opinion. In addition, with the Atlas Energy special committee’s consent, UBS did not make any independent evaluation or appraisal of any of the assets or liabilities (contingent or otherwise) of Atlas Energy, Atlas America or any affiliated entity, and was not furnished with any such evaluation or appraisal. With respect to the financial forecasts and estimates, gas reserve estimates and synergies referred to above, UBS assumed, at the Atlas Energy special committee’s direction, that such financial forecasts and estimates, gas reserve estimates and synergies had been reasonably prepared on a basis reflecting the best currently available estimates and judgments of the managements of Atlas Energy and Atlas America as to the future financial performance of Atlas Energy and Atlas America, the gas reserves of Atlas Energy and such synergies. In addition, UBS assumed, with the Atlas Energy special committee’s approval, that such financial forecasts and estimates, including synergies, would be achieved at the times and in the amounts projected. UBS is not an expert in the evaluation of gas reserves, and UBS expressed no view as to the reserve quantities, or the development or production (including, without limitation, as to their feasibility or timing), of any gas properties of Atlas Energy. UBS relied, without independent verification, upon the assessments of the managements of Atlas Energy and Atlas America as to market trends and prospects relating to the natural gas industry and the potential impact of such trends and prospects on Atlas Energy and Atlas America, including such managements’ assumptions as to future commodity prices reflected in the financial forecasts and estimates utilized in UBS’ analyses, which prices are subject to significant volatility and which, if different than as assumed, could have a material impact on UBS’ opinion. UBS’ opinion was necessarily based on economic, monetary, market and other conditions as in effect on, and the information available to UBS as of, the date of its opinion.

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In addition, at the Atlas Energy special committee’s direction, UBS was not asked to, and it did not, offer any opinion as to the terms, other than the exchange ratio to the extent expressly specified in UBS’ opinion, of the merger agreement or the form of the merger. In addition, UBS expressed no opinion as to the fairness of the amount or nature of any compensation to be received by any officers, directors or employees of any parties to the merger, or any class of such persons, relative to the exchange ratio. UBS expressed no opinion as to what the value of Atlas America common stock would be when issued pursuant to the merger or the prices at which Atlas America common stock or Atlas Energy common units would trade at any time. In rendering its opinion, UBS assumed, with the Atlas Energy special committee’s consent, that (i) the final executed form of the merger agreement would not differ in any material respect from the draft that UBS reviewed, (ii) the parties to the merger agreement would comply with all material terms of the merger agreement and (iii) the merger would be consummated in accordance with the terms of the merger agreement without any adverse waiver or amendment of any material term or condition of the merger agreement. UBS also assumed that all governmental, regulatory or other consents and approvals necessary for the consummation of the merger would be obtained without any material adverse effect on Atlas Energy, Atlas America or the merger. UBS was not authorized to solicit and did not solicit indications of interest in a transaction with Atlas Energy from any party. Except as described above, Atlas Energy imposed no other instructions or limitations on UBS with respect to the investigations made or the procedures followed by UBS in rendering its opinion. The issuance of UBS’ opinion was approved by an authorized committee of UBS.

In connection with rendering its opinion to the Atlas Energy special committee, UBS performed a variety of financial analyses which are summarized below. The following summary is not a complete description of all analyses performed and factors considered by UBS in connection with its opinion. The preparation of a financial opinion is a complex process involving subjective judgments and is not necessarily susceptible to partial analysis or summary description. UBS’ analyses necessarily involve complex considerations and judgments concerning financial and operating characteristics and other factors that could affect such analyses.

UBS believes that its analyses and the summary below must be considered as a whole and that selecting portions of its analyses and factors without considering all analyses and factors could create a misleading or incomplete view of the processes underlying UBS’ analyses and opinion. UBS did not draw, in isolation, conclusions from or with regard to any one factor or method of analysis for purposes of its opinion, but rather arrived at its ultimate opinion based on the results of all factors and analyses assessed as a whole.

The estimates of the future performance of Atlas Energy and Atlas America provided by Atlas Energy or Atlas America in or underlying UBS’ analyses are not necessarily indicative of future results or values, which may be significantly more or less favorable than those estimates. In performing its analyses, UBS considered industry performance, general business and economic conditions and other matters, many of which were beyond the control of Atlas Energy and Atlas America. Estimates of the financial value of companies do not purport to be appraisals or necessarily reflect the prices at which businesses or securities actually may be sold or acquired.

The exchange ratio was determined through negotiation between the Atlas Energy special committee and Atlas America and the decision by Atlas Energy to enter into the merger was solely that of the Atlas Energy special committee and the Atlas Energy board of directors. UBS’ opinion and financial analyses were only one of many factors considered by the Atlas Energy special committee in its evaluation of the merger and should not be viewed as determinative of the views of the Atlas Energy special committee or the Atlas Energy board of directors or management with respect to the merger or the exchange ratio.

The following is a brief summary of the material financial analyses performed by UBS and reviewed with the special committee on April 27, 2009 in connection with its opinion relating to the proposed merger.Considering the data below without considering the full narrative description of the financial analyses, including the methodologies and assumptions underlying the analyses, could create a misleading or incomplete view of UBS’ financial analyses.

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Summary of Financial Analysis

Given that the conversion of Atlas Energy common units into shares of Atlas America common stock in the merger will result, in the aggregate, in an approximately 2% decrease in the equity ownership in Atlas Energy represented by Atlas Energy common units not currently held by Atlas America (which we refer to as “non-Atlas America common units”) in exchange for a pro forma equity ownership interest in Atlas America’s assets (exclusive of the ownership interest in Atlas Energy that holders of non-Atlas America common units will continue to hold immediately after giving effect to the merger in the form of shares of Atlas America common stock), UBS performed separate discounted cash flow analyses of Atlas Energy and Atlas America (excluding, in the case of Atlas America, its ownership interest in Atlas Energy but including synergies anticipated to result from the merger) in order to evaluate the potential financial impact of the merger on non-Atlas America common units. For purposes of such analyses, UBS utilized, at the Atlas Energy special committee’s direction, financial forecasts and estimates relating to Atlas Energy and Atlas America and estimates of synergies anticipated to result from the merger, in each case prepared by the managements of Atlas Energy or Atlas America.

Atlas Energy

In its discounted cash flow analysis of Atlas Energy, UBS calculated a range of implied present values (as of September 30, 2009) of the standalone unlevered, after-tax free cash flows that Atlas Energy was forecasted to generate from September 30, 2009 until December 31, 2013 and of terminal values for Atlas Energy based on Atlas Energy’s calendar year 2013 estimated EBITDA. Implied terminal values were derived by applying to Atlas Energy’s calendar year 2013 estimated EBITDA a range of estimated EBITDA terminal value multiples of 6.5x to 8.5x. Present values of cash flows and terminal values were calculated using discount rates ranging from 12% to 14%. Assuming, based on the exchange ratio provided for in the merger, an implied 2% decrease in the equity ownership in Atlas Energy represented by non-Atlas America common units, this discounted cash flow analysis resulted in a decrease in the implied present value of the equity ownership in Atlas Energy represented by non-Atlas America common units in the aggregate of approximately $18 million to $31 million.

Atlas America

In its discounted cash flow analysis of Atlas America (excluding Atlas America’s ownership interest in Atlas Energy), UBS calculated a range of implied present values (as of September 30, 2009) of the standalone unlevered, after-tax free cash flows that Atlas America was forecasted to generate from distributions attributable to its equity interests in Atlas Pipeline Holdings and Atlas Pipeline (which we collectively refer to as the “Atlas Pipeline distributions”) from September 30, 2009 until December 31, 2013 and of terminal values for Atlas America based on Atlas America’s calendar year 2013 estimated EBITDA attributable to Atlas Pipeline distributions. UBS also calculated a range of implied present values (as of September 30, 2009) of cash flows and terminal values based on the same periods attributable to Atlas America’s overhead costs and to potential synergies anticipated to result from the merger. Implied terminal values were derived by applying estimated terminal value multiples of 6.5x to 8.5x to calendar year 2013 estimated Atlas Pipeline distributions, Atlas America overhead costs and synergies. Present values of cash flows and terminal values were calculated using discount rates ranging from 11.5% to 13.5%. Assuming, based on the exchange ratio provided for in the merger and internal estimates of the managements of Atlas Energy and Atlas America, an estimated implied pro forma equity ownership percentage in Atlas America of approximately 49.7%, this discounted cash flow analysis resulted in an implied present value for the implied pro forma equity ownership in Atlas America (excluding its ownership interest in Atlas Energy) represented by non-Atlas America common units in the aggregate of approximately $38 million to $47 million.

Based on a comparison of the above ranges of implied present values, the discounted cash flow analyses of Atlas Energy and Atlas America (excluding, in the case of Atlas America, its ownership interest in Atlas Energy) indicated that the exchange ratio provided for in the merger implied a potential net increase in the implied present value of non-Atlas America common units in the aggregate of approximately $16 million to $20 million.

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Miscellaneous

Under the terms of UBS’ engagement, Atlas Energy agreed to pay UBS for its financial advisory services in connection with the merger an aggregate fee of $5.0 million, $250,000 of which was payable in July 2009, $1.75 million of which was payable in connection with UBS’ opinion and $3.0 million of which is contingent upon consummation of the merger. In addition, Atlas Energy agreed to indemnify UBS and related parties against liabilities, including liabilities under federal securities laws, relating to, or arising out of, its engagement. UBS and its affiliates in the past have provided services to Atlas Energy and affiliates of Atlas Energy and Atlas America, and, as of the date of UBS’ opinion, were providing services to an affiliate of Atlas Energy and Atlas America, unrelated to the proposed merger, for which UBS and its affiliates received and expected to receive compensation, including acting as financial advisor to an affiliate of Atlas Energy and Atlas America in connection with a disposition transaction that was pending as of the date of UBS’ opinion and having acted as (i) financial advisor to Atlas Energy in connection with an acquisition transaction in 2007, (ii) placement agent for block trades and private placements of equity securities of Atlas Energy and affiliates of Atlas Energy and Atlas America in 2007 and 2008 and (iii) joint bookrunner for a public offering of equity securities of an affiliate of Atlas Energy and Atlas America in 2008. In addition, an affiliate of UBS in the past has been and, as of the date of UBS’ opinion, was a participant in the Atlas Energy Credit Facility, for which such affiliate of UBS received and continued to receive fees and interest payments. In the ordinary course of business, UBS and its affiliates may hold or trade, for their own accounts and the accounts of their customers, securities of Atlas Energy, Atlas America and certain affiliates of Atlas Energy and Atlas America, and, accordingly, may at any time hold a long or short position in such securities. The special committee selected UBS as its financial advisor in connection with the merger because UBS is an internationally recognized investment banking firm with substantial experience in similar transactions and because of UBS’ familiarity with Atlas Energy, certain affiliates of Atlas Energy and Atlas America and their respective businesses. UBS is regularly engaged in the valuation of businesses and their securities in connection with mergers and acquisitions, leveraged buyouts, negotiated underwritings, competitive bids, secondary distributions of listed and unlisted securities and private placements.

Certain Projections

Neither Atlas America nor Atlas Energy makes, as a matter of course, public long-term projections as to future revenues, earnings, cash flows or other results. However, in connection with the discussions concerning the merger, Atlas Energy management and Atlas America management furnished to the Atlas Energy special committee and its advisors and the Atlas America board of directors and its advisors certain information that was not publicly available, including certain projected financial data.

The following table is based on certain projections for Atlas Energy that were provided by Atlas Energy management to the Atlas Energy special committee and its advisors and the Atlas America board of directors and its advisors for the second half of 2009 and for the full years of 2010, 2011, 2012 and 2013:

Atlas Energy Resources, LLC Projections

	Q3		Q4		Fiscal Year		Fiscal Year		Fiscal Year		Fiscal Year
(in millions)	2009		2009		2010		2011		2012		2013
Earnings before interest, taxes, depreciation, depletion and amortization (or EBITDA)	$	74.0	$	76.5	$	289.7	$	320.4	$	359.7	$	403.2
Assumed Distributions from Atlas Energy to Atlas Energy Unitholders	$	—	$	—	$	19.4	$	45.3	$	51.7	$	51.7
Net Cash Flow	$	27.0	$	18.7	$	81.9	$	36.7	$	21.4	$	12.8
Total Debt Outstanding	$	851.0	$	697.9	$	594.2	$	556.4	$	540.7	$	529.9

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In preparing the projections above, Atlas Energy management made the following material assumptions:

• Atlas Energy remains a standalone entity and does not merge with Atlas America;

• Atlas Energy continues to distribute cash to Atlas Energy unitholders (including Atlas America) at a the reduced rates set forth above under “Assumed Distributions From Atlas Energy to Atlas Energy Unitholders as compared to the rate of $157.8 million per year in prior years”;

• natural gas prices would be $4.36, $5.86, $6.67, $6.97 and $7.09 for the years 2009, 2010, 2011, 2012 and 2013, respectively;

• oil prices would be $51.69, $64.23, $69.32, $72.05 and $74.01 for the years 2009, 2010, 2011, 2012 and 2013, respectively;

• cash raised through partnership funds and joint ventures would be $500 million, $525 million, $550 million, $575 million and $600 million for the years 2009, 2010, 2011, 2012 and 2013, respectively;

• the number of wells drilled would be 340, 318, 359, 371 and 389 for the years 2009, 2010, 2011, 2012 and 2013, respectively;

• there would be no legislative changes affecting the U.S. natural gas industry;

• there would be no significant economic or regulatory changes to Atlas Energy’s key product markets;

• there would be no significant impact from any litigation;

• merger-related transaction costs and productivity initiatives charges are excluded; and

• there is a significant decrease in interest on investments.

The following table is based on certain projections for Atlas America (excluding Atlas Energy and its subsidiaries) that were provided by Atlas America management to the Atlas Energy special committee and its advisors and the Atlas America board of directors and its advisors:

Atlas America, Inc. Projections

	Fiscal Year		Fiscal Year		Fiscal Year		Fiscal Year		Fiscal Year
(in millions)	2009		2010		2011		2012		2013
Cash to Atlas America from Atlas Pipeline Distributions	$	0.2	$	0.0	$	0.0	$	2.7	$	2.8
Cash to Atlas America from Atlas Pipeline Holdings Distributions	$	0.5	$	0.2	$	0.0	$	15.6	$	17.4

In preparing the projections above, Atlas America management made the following material assumptions:

• Atlas America maintained its current percentage ownership interest in each of Atlas Pipeline (1.1 million units) and Atlas Pipeline Holdings (64.4%);

• there would be no legislative changes affecting the U.S. natural gas industry;

• there would be no significant economic or regulatory changes to Atlas Energy’s key product markets;

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• there would be no significant impact from pending litigations;

• merger-related transaction costs and productivity initiatives charges are excluded; and

• a significant decrease in interest on investments.

While these projections were prepared in good faith by members of Atlas Energy management and Atlas America management, no assurance can be made regarding future events. The estimates and assumptions underlying the projections involve judgments as of the date that the projections were prepared with respect to, among other things, future economic, competitive, regulatory and financial market conditions and future business decisions that may not be realized and are inherently subject to significant business, economic, competitive and regulatory uncertainties, all of which are difficult to predict and many of which are beyond the control of Atlas Energy and Atlas America and will be beyond the control of the combined company. Accordingly, there can be no assurance that the projected results would be realized or that actual results do not or would not differ materially from those presented in the financial data. Such projections cannot, therefore, be considered a guarantee of operating results, and this information should not be relied on as such. The information in this section was not prepared with a view toward public disclosure or compliance with published guidelines of the SEC or the American Institute of Certified Public Accountants for preparation and presentation of prospective financial information or GAAP and do not reflect the effect of any proposed or other changes in GAAP that may be made in the future. Readers of this joint proxy statement/prospectus are cautioned not to place undue reliance on this information. Inclusion of financial forecasts in this joint proxy statement/prospectus should not be regarded as a representation to Atlas America stockholders or Atlas Energy unitholders that the financial forecasts will be achieved.

Neither Atlas Energy, Atlas America, nor, if the merger is completed, the combined company, has updated, will update, or intends to update or otherwise revise the prospective financial data to reflect circumstances existing since its preparation or to reflect the occurrence of unanticipated events, even in the event that any or all of the underlying assumptions do not prove to be accurate after the date of preparation. Furthermore, neither Atlas Energy, Atlas America, nor, if the merger is completed, the combined company intends to update or revise the prospective financial data to reflect changes in general economic or industry conditions.

The projections above are included in this joint proxy statement/prospectus only because such information was made available to Atlas America and the Atlas Energy special committee. These projections are not included in this joint proxy statement/prospectus in order to induce any Atlas Energy unitholder to vote in favor of the proposal to adopt the merger agreement and approve the transactions contemplated thereby, including the merger, or to induce any Atlas America stockholder to vote in favor of the stock issuance.

Interests of Atlas America Directors and Executive Officers in the Merger

In considering the recommendation of the Atlas America board of directors with respect to the stock issuance, Atlas America stockholders should be aware that Atlas America’s directors and executive officers have interests in the merger that may be different from, or in addition to, Atlas America’s stockholders generally. The Atlas America board of directors was aware of these interests, and considered these interests, among other matters, in evaluating and negotiating the merger agreement and the merger, and in recommending to their stockholders that the proposal in favor of the stock issuance be approved. These interests and arrangements include:

• the continued service on the board of directors of the combined company by Edward E. Cohen and Jonathan Z. Cohen, Chief Executive Officer and Vice Chairman, respectively, of both Atlas America and Atlas Energy, and the six independent directors serving on the Atlas America board of directors at the time the merger is consummated;

• certain officers are officers of both Atlas America and Atlas Energy, including Matthew A. Jones as Chief Financial Officer and Sean P. McGrath as Chief Accounting Officer of both Atlas America and Atlas Energy;

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• Executive Vice President Freddie M. Kotek is an investor in an investment partnership to which Atlas Energy commits 15% to 25% of the total capital. In 2008, of the $550 million that was raised by the partnership, Atlas Energy committed $113 million of the capital; and

• ownership by Atlas America directors and executive officers of 330,128, or approximately 0.5% of the outstanding, Atlas Energy common units, which units will be converted into the merger consideration if the merger is completed.

The following table sets forth the number and percentage of Atlas Energy common units owned as of August 18, 2009 by Atlas America directors and executive officers who beneficially own Atlas Energy common units.

Beneficial Owner	Atlas Energy Common Units Amount and Nature of Beneficial Ownership		Percent of Common Units
Directors
Edward E. Cohen	—	(1)	—
Jonathan Z. Cohen	—	(2)	—
Dennis Holtz	700		*
Harmon S. Spolan	500		*
Non-Director Executive Officers
Freddie M. Kotek	10,700	(3)	*
Matthew A. Jones	1,100	(4)	*
Sean P. McGrath	—	(5)	—
Richard D. Weber	317,128	(6)	*

 * Less than 1%

(1) Mr. E. Cohen owns 200,000 phantom units and 500,000 unit options granted pursuant to the Atlas Energy Long-Term Incentive Plan on January 24, 2007. Each phantom unit represents the right to receive, upon vesting, one common unit. Each unit option represents the right to purchase, upon vesting, one common unit. The phantom units and unit options vest 25% on the third anniversary of the grant and 75% on the fourth anniversary of the grant.

(2) Mr. J. Cohen owns 100,000 phantom units and 200,000 unit options granted pursuant to the Atlas Energy Long-Term Incentive Plan on January 24, 2007. Each phantom unit represents the right to receive, upon vesting, one common unit. Each unit option represents the right to purchase, upon vesting, one common unit. The phantom units and unit options vest 25% on the third anniversary of the grant and 75% on the fourth anniversary of the grant.

(3) Represents 10,700 Atlas Energy units over which Mr. Kotek has shared voting power. Mr. Kotek also owns 20,000 phantom units and 50,000 unit options granted pursuant to the Atlas Energy Long-Term Incentive Plan on January 24, 2007. Each phantom unit represents the right to receive, upon vesting, one common unit. Each unit option represents the right to purchase, upon vesting, one common unit. The phantom units and unit options vest 25% on the third anniversary of the grant and 75% on the fourth anniversary of the grant.

(4) Mr. Jones also owns 20,000 phantom units and 50,000 unit options granted pursuant to the Atlas Energy Long-Term Incentive Plan on January 24, 2007. Each phantom unit represents the right to receive, upon vesting, one common unit. Each unit option represents the right to purchase, upon vesting, one common unit. The phantom units and unit options vest 25% on the third anniversary of the grant and 75% on the fourth anniversary of the grant.

(5) Mr. McGrath owns 10,000 phantom units and 15,000 unit options granted pursuant to the Atlas Energy Long-Term Incentive Plan on January 24, 2007. Each phantom unit represents the right to receive, upon vesting, one common unit. Each unit option represents the right to purchase, upon vesting, one common

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unit. The phantom units and unit options vest 25% on the third anniversary of the grant and 75% on the fourth anniversary of the grant.

(6) Mr. Weber also owns 11,905 restricted units and 93,438 unit options granted pursuant to the terms of Mr. Weber’s employment agreement with Atlas Energy dated April 17, 2006. Each unit option represents the right to purchase, upon vesting, one common unit. The restricted units and the unit options will vest on April 17, 2010.

Interests of Atlas Energy Directors and Executive Officers in the Merger

In considering the recommendation of the Atlas Energy board of directors with respect to the merger agreement, Atlas Energy unitholders should be aware that Atlas Energy’s directors and executive officers have interests in the merger that may be different from, or in addition to, Atlas Energy unitholders generally. The Atlas Energy board of directors was aware of these interests, and considered these interests, among other matters, in evaluating and negotiating the merger agreement and the merger, and in recommending to their unitholders that the proposals in favor of the merger agreement be approved. These interests and arrangements include:

• the continued service on the board of directors of the combined company by Edward E. Cohen and Jonathan Z. Cohen, Chief Executive Officer and Vice Chairman, respectively, of both Atlas America and Atlas Energy, and the four independent directors serving on the Atlas Energy board of directors at the time the merger is consummated;

• certain officers are officers of both Atlas America and Atlas Energy, including Matthew A. Jones as Chief Financial Officer and Sean P. McGrath as Chief Accounting Officer of both Atlas America and Atlas Energy; and

• the conversion of each outstanding restricted unit, phantom unit and unit option of Atlas Energy units held by such executive officers and directors into an equivalent restricted share, phantom share and stock option of Atlas America, respectively, with adjustments in the number of shares and exercise price to reflect the exchange ratio, but otherwise on the same terms and conditions as were applicable prior to the merger; and

• ownership by certain Atlas Energy directors and executive officers of 5,734,819, or approximately 13.8% of the outstanding, shares of Atlas America common stock.

The following table sets forth the number and percentage of shares of Atlas America common stock owned as of August 18, 2009 by Atlas Energy directors and executive officers.

Beneficial Owner	Atlas America Common Stock Amount and Nature of Beneficial Ownership		Percent of Common Stock
Directors
Edward E. Cohen	3,910,978	(1)(3)	9.7
Jonathan Z. Cohen	2,293,647	(2)(3)	5.7
Richard D. Weber	106,895	(3)	*
Bruce M. Wolf	182,939		*
Non-Director Executive Officers
Matthew A. Jones	300,231	(3)	*
Freddie M. Kotek	376,880	(3)	*
Sean P. McGrath	8,552	(3)	*
Lisa Washington	4,195	(3)	*

 * Less than 1%

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(1) Includes (i) 50,454 shares held in an individual retirement account of Betsy Z. Cohen, Mr. E. Cohen’s spouse; (ii) 1,320,202 shares held by a charitable foundation of which Mr. E. Cohen, his spouse and their children serve as co-trustees; and (iii) 141,378 shares held in trust for the benefit of Mr. E. Cohen’s spouse and/or children. Mr. E. Cohen disclaims beneficial ownership of the above referenced shares. 129,296 and 1,320,202 shares are also included in the shares referred to in note 2 below.

(2) Includes (i) 129,296 shares held in a trust of which Mr. J. Cohen is a co-trustee and co-beneficiary and (ii) 1,320,202 shares held by a charitable foundation of which Mr. J. Cohen, his parents and his sibling serve as co-trustees. These shares are also included in the shares referred to in note 1 above. Mr. J. Cohen disclaims beneficial ownership of the above referenced shares.

(3) Includes shares issuable on the exercise of options granted under Atlas America’s Stock Incentive Plan in the following amounts: Mr. E. Cohen — 1,087,500; Mr. J. Cohen — 735,000; Mr. R. Weber — 106,875; Mr. M. Jones — 300,000; Mr. F. Kotek — 116,250; Mr. S. McGrath — 8,438; Ms. L. Washington — 3,750.

Board of Directors Following the Merger

Pursuant to the terms of the merger agreement, at the effective time of the merger, the Atlas America board of directors will consist of 12 persons, including 10 independent directors from the Atlas America board of directors and the Atlas Energy board of directors and Edward Cohen and Jonathan Cohen.

Material U.S. Federal Income Tax Consequences

The following is a summary of the material U.S. federal income tax consequences to Atlas Energy unitholders who exchange Atlas Energy common units in the merger. This summary is based on the Internal Revenue Code, Treasury Regulations issued under the Internal Revenue Code, and judicial and administrative interpretations thereof, each as in effect as of the date of this joint proxy statement/prospectus, all of which are subject to change at any time, possibly with retroactive effect. This discussion assumes that Atlas Energy common units are held as capital assets within the meaning of Section 1221 of the Internal Revenue Code. This summary does not discuss all of the tax consequences that may be relevant to particular Atlas Energy unitholders in light of their individual circumstances, including potential application of the alternative minimum tax, or any aspect of U.S. federal, state or local tax laws, to Atlas Energy unitholders subject to special treatment under the U.S. federal income tax laws (such as insurance companies, financial institutions, tax-exempt organizations, corporations, Atlas Energy unitholders that are not (a) U.S. persons as defined in Section 7701(a)(30) of the Internal Revenue Code nor (b) trusts with valid elections in place under applicable U.S. Treasury Regulations to be treated as U.S. persons, partnerships or other pass-through entities (and persons holding Atlas Energy common units through a partnership or other pass-through entity), retirement plans, regulated investment companies, securities dealers, traders in securities who elect to apply a mark-to-market method of accounting, persons holding Atlas Energy common units as part of a “straddle,” “constructive sale,” or a “conversion transaction” for U.S. federal income tax purposes, or as part of some other integrated investment, expatriates or persons whose functional currency for tax purposes is not the U.S. dollar). If a partnership holds Atlas Energy common units, the tax treatment of a partner generally will depend on the status of the partner and upon the activities of the partnership. Persons who are partners in a partnership holding Atlas Energy common units should consult their tax advisors. This summary also does not discuss any tax consequences arising under the laws of any state, local, foreign or other tax jurisdiction or, except to the extent provided below, any tax consequences arising under U.S. federal tax laws other than U.S. federal income tax laws. We have not requested, and do not plan to request, any rulings from the IRS with respect to any matters discussed in this section, and the statements in this joint proxy statement/prospectus are not binding on the IRS or any court. As a result, neither Atlas Energy nor Atlas America can give any assurance that the IRS will not assert, or that a court will not sustain, a position contrary to any of the tax consequences described below.

ATLAS ENERGY UNITHOLDERS SHOULD CONSULT THEIR OWN TAX ADVISORS AS TO THE SPECIFIC TAX CONSEQUENCES TO THEM OF THE MERGER IN LIGHT OF THEIR

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PARTICULAR CIRCUMSTANCES, INCLUDING THE APPLICABILITY AND EFFECT OF U.S. FEDERAL, STATE, LOCAL AND FOREIGN INCOME AND OTHER TAX LAWS.

General

The receipt of shares of Atlas America common stock in the merger (as well as the receipt of cash in lieu of fractional shares) will be a taxable transaction for U.S. federal income tax purposes. In general, an Atlas Energy unitholder who receives shares of Atlas America common stock in exchange for Atlas Energy common units pursuant to the merger will recognize gain or loss for U.S. federal income tax purposes in an amount equal to the difference, if any, between:

• the amount realized, which is the sum of:

• the fair market value of the shares of Atlas America common stock;

• the unitholder’s share of any Atlas Energy pre-merger liabilities; and

• any cash received in lieu of fractional shares of Atlas America common stock; and

• the unitholder’s adjusted tax basis in such Atlas Energy common units (including basis attributable to his or her share of Atlas Energy’s pre-merger liabilities).

Subject to the discussion immediately below, such gain or loss generally will be long-term capital gain or loss if the unitholder’s holding period for the Atlas Energy common units exceeds one year at the effective time of the merger. Long-term capital gains of noncorporate unitholders generally are eligible for reduced rates of U.S. federal income taxation. The deductibility of capital losses is subject to limitations.

Recapture

Upon the exchange of Atlas Energy common units for Atlas America common stock, an Atlas Energy unitholder may be treated as recognizing ordinary income (or loss) to the extent the merger consideration received is attributable to Atlas Energy’s “unrealized receivables” (including potential recapture items such as depreciation, depletion and intangible drilling and development costs) or “inventory items.” Under Section 751 of the Internal Revenue Code, the merger consideration generally is divided between such items and all other items, resulting in two taxable transactions in which gain or loss is separately computed. Ordinary income attributable to unrealized receivables and inventory items may exceed net taxable gain realized upon the exchange of Units in the merger and may be recognized even if there is a net taxable loss realized. Thus, an Atlas Energy unitholder may recognize both ordinary income and a capital loss.

At-Risk and Passive Activity Loss Rules

Section 465(e) of the Internal Revenue Code requires individuals and closely held corporations to recapture losses previously allowed with respect to their interests in a partnership in the event their amount “at risk” with respect to that partnership becomes less than zero. The consequence of recapture is that a taxpayer must recognize income equal to the negative at-risk amount. A unitholder’s at-risk amount, or “at-risk basis,” generally is equal to such holder’s basis in the Atlas Energy common units, adjusted to exclude certain non-qualified partnership liabilities that otherwise would be included in such holder’s basis. In addition, although guidance is sparse, a unitholder’s at-risk basis likely will be increased by the amount of any gain recognized with respect to such Atlas Energy common units, including gain recognized in the merger. Assuming such gain increases a unitholder’s at-risk basis, such holders should not recognize recapture income under Section 465(e) of the Internal Revenue Code solely as a result of exchanging Atlas Energy common units in the merger. The at risk limitation applies on an activity-by-activity basis, and in the case of natural gas and oil properties, each property is treated as a separate activity. Thus, a taxpayer’s interest in each oil or gas property is generally required to be treated separately so that a loss from any one property is limited to the at-risk amount for that property and not

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the at-risk amount for all the taxpayer’s natural gas and oil properties. It is uncertain how this rule is implemented in the case of multiple natural gas and oil properties owned by a single entity treated as a partnership for federal income tax purposes. However, for taxable years ending on or before the date on which further guidance is published, the IRS will permit aggregation of oil or gas properties Atlas Energy owns in computing a unitholder’s at-risk limitation with respect to Atlas Energy. If a unitholder must compute his at-risk amount separately with respect to each oil or gas property Atlas Energy owns, such holder may not be allowed to utilize his share of losses or deductions attributable to a particular property even though he has a positive at-risk amount with respect to his Atlas Energy common units as a whole. Unitholders that may be subject to these “at-risk” rules should consult their tax advisors concerning their shares of Atlas Energy’s qualifying indebtedness and the application of these rules to their particular circumstances.

The passive loss limitation rules under the Internal Revenue Code generally provide that certain U.S. taxpayers, such as individuals, estates, trusts and certain corporations, are permitted to deduct losses from passive activities, which are generally defined as trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. Any gain or ordinary income recognized by a unitholder with respect to Atlas Energy common units exchanged in the merger generally will be treated as passive activity income (except to the extent attributable to any operating activity that is not a passive activity with respect to such unitholder), and thus may be offset, as applicable, by any passive activity losses attributable to the ownership of the Atlas Energy common units that the unitholder incurs in the taxable year of the merger and by suspended passive activity losses from prior years. Because Atlas Energy is a “publicly traded partnership,” unitholders cannot utilize passive activity losses attributable to any investment or activity other than their ownership of the Atlas Energy common units. Because the merger will be a fully taxable transaction to unitholders and will terminate a unitholder’s entire interest in Atlas Energy, any remaining passive losses attributable to the ownership of such units (including suspended passive activity losses from prior years) generally will no longer be treated as passive losses and thus should be available to offset unitholders’ other gain or income (though the use of such losses may be subject to other limitations).

Allocations

Atlas Energy unitholders will be allocated their proportionate share of Atlas Energy’s items of income, gain, loss and deduction, for the period ending at the effective time of the merger. These allocations will be made in accordance with the terms of the Atlas Energy operating agreement and taking into account any required special allocations. When computing their taxable income or loss, unitholders will be required to take into account their share of such income or loss (subject to the passive activity loss rules described above and other limitations) even though they will not receive any additional cash distributions from Atlas Energy.

Information Reporting and Backup Withholding

Payments of cash made to a unitholder may, under certain circumstances, be subject to information reporting and backup withholding at the applicable rate (currently 28%), unless such holder properly establishes an exemption or provides a correct taxpayer identification number, and otherwise complies with the backup withholding rules. Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules may be refunded or credited against a unitholder’s U.S. federal income tax liability, provided the required information is timely furnished to the IRS.

Accounting Treatment

In December 2007, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 160, “Non-controlling Interests in Consolidated Financial Statements – an amendment of ARB No. 51,” which Atlas America adopted on January 1, 2009. Prior to January 1, 2009, Atlas America was required to follow the provisions of Statement of Financial Accounting Standards No. 141, “Business Combinations” (“SFAS No. 141”), which required the acquisition method of accounting for business combinations, which

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stipulates that the total purchase price be allocated to the identifiable assets acquired and liabilities assumed based on their fair values as of the date of the completion of the transaction, with any excess being allocated to goodwill. SFAS No. 160 applies, among other things, to a parent’s acquisition of non-controlling ownership interests in a subsidiary and provides for changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary to be accounted for as equity transactions. Consequently, in accordance with SFAS No. 160, no gain or loss shall be recognized in net income or comprehensive income, the carrying amount of the controlling interest and the carrying amount of the non-controlling interest is adjusted to reflect the change in ownership in the subsidiary, and any difference between the fair value of consideration received or paid and amount by which the non-controlling interest is adjusted shall be recognized in equity attributable to the parent. Following the completion of the merger, Atlas America will continue to recognize the assets and liabilities of Atlas Energy at their historical values. Reported financial condition and results of operations of Atlas America issued after the completion of the merger will reflect Atlas Energy’s balances and results after completion of the merger, but will not be restated retroactively to reflect the historical financial position or results of operations of Atlas Energy as if the merger had taken place at the respective accounting period.

Regulatory Approvals Required for the Merger

The merger was subject to review by the DOJ and the FTC under the HSR Act. Under the HSR Act, Atlas America and Atlas Energy were required to make pre-merger notification filings and to await the expiration or early termination of the statutory waiting period prior to completing the merger. On May 8, 2009, Atlas America and Atlas Energy filed the requisite notification and report forms under the HSR Act with the DOJ and the FTC, and early termination of the waiting period was granted on May 15, 2009. No further regulatory approvals are required for the completion of the merger.

At any time before or after completion of the merger, either the DOJ, the FTC or any state attorneys general could challenge or seek to block the merger under the antitrust laws, as it deems necessary or desirable in the public interest. In addition, in some jurisdictions, a private party could initiate legal action under the antitrust laws challenging or seeking to enjoin the merger, before or after it is completed. Atlas America and Atlas Energy cannot be sure that a challenge to the merger will not be made or that, if a challenge is made, Atlas America and Atlas Energy will prevail.

Litigation Relating to the Merger

Following the announcement of the merger agreement on April 27, 2009, the following actions were filed in Delaware Chancery Court purporting to challenge the merger:

• Alonzo v. Atlas Energy Resources, LLC, et al., C.A. No. 4553-VCN (Del. Ch. filed 4/30/09);

• Operating Engineers Constructions Industry and Miscellaneous Pension Fund v. Atlas America, Inc., et al., C.A. No. 4589-VCN (Del. Ch. filed 5/13/09);

• Vanderpool v. Atlas Energy Resources, LLC, et al., C.A. No. 4604-VCN (Del. Ch. filed 5/15/09);

• Farrell v. Cohen, et al., C.A. No. 4607-VCN (Del. Ch. filed 5/19/09); and

• Montgomery County Employees’ Retirement Fund v. Atlas Energy Resources, L.L.C., et al., C.A. No. 4613-VCN (Del. Ch. filed 5/21/09).

On June 15, 2009, Vice Chancellor Noble issued an order consolidating all five lawsuits, renaming the actionIn re Atlas Energy Resources, LLC Unitholder Litigation, C.A. No. 4589-VCN, and appointing as co-lead plaintiffs Operating Engineers Construction Industry and Miscellaneous Pension Fund and Montgomery County Employees Retirement Fund. Plaintiffs filed a Verified Consolidated Class Action Complaint on July 1, 2009, which has superseded all prior complaints. The complaint alleges that the defendants breached purported fiduciary duties owed to the public unitholders by negotiating and executing a merger agreement that allegedly

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provides unfair consideration to the public unitholders and that was reached pursuant to an allegedly unfair negotiating process between the Atlas Energy special committee and Atlas America. The complaint also alleges that the defendants have failed to disclose material information regarding the merger. On July 27, 2009, the Chancery Court granted the parties’ scheduling stipulation, setting a preliminary injunction hearing for September 4, 2009. However, on August 7, 2009, Plaintiffs advised the Chancery Court by letter that they were not pursuing their motion for a preliminary injunction, and requested that the September 4, 2009 hearing date be removed from the Court’s calendar. Plaintiffs have advised counsel for the defendants that plaintiffs intend to continue to pursue the action for monetary damages after the merger. Predicting the outcome of this lawsuit is difficult. An adverse judgment for monetary damages could have a material adverse effect on the operations of the combined company after the merger. A preliminary injunction could have delayed or jeopardized the completion of the merger, and an adverse judgment granting permanent injunctive relief could have indefinitely enjoined completion of the merger. Based on the facts known to date, the defendants believe that the claims asserted against them in this lawsuit are without merit, and intend to defend themselves vigorously against the claims.

Restrictions on Sales of Shares of Atlas America Common Stock by Certain Affiliates

The shares of Atlas America common stock to be issued in the merger will be registered under the Securities Act, and will be freely transferable, except for shares of Atlas America common stock issued to any person who is deemed to be an “affiliate” of Atlas America for purposes of Rule 144 under the Securities Act. Persons who may be deemed to be “affiliates” of Atlas America include individuals or entities that control, are controlled by, or are under common control with, Atlas America, and may include officers and directors, as well as significant stockholders of Atlas America.

Listing of Atlas America Common Stock

Atlas America will use its reasonable best efforts to have the shares of Atlas America common stock to be issued in the merger approved for listing on NASDAQ, where Atlas America common stock is currently traded under the symbol “ATLS,” as of the completion of the merger. It is a condition to Atlas Energy’s obligations to complete the merger that the shares of Atlas America common stock to be issued in the merger shall have been approved for listing on NASDAQ, subject to official notice of issuance.

Delisting and Deregistration of Atlas Energy Common Units

If the merger is completed, Atlas Energy common units will no longer be listed on the NYSE and will be deregistered under the Exchange Act.

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Comparative Stock Prices, Dividends and Distributions

The following table sets forth, for the periods indicated, the high and low sales prices of shares of Atlas America common stock and Atlas Energy common units as reported on NASDAQ and the NYSE, respectively, and the quarterly cash dividends and distributions declared per share. For current price information, you should consult publicly available sources.

	Atlas America Common Stock(1)						Atlas Energy Common Units
	High		Low		Dividend		High		Low		Distribution
2007
First Quarter	$	25.63	$	21.55	$	0.02	$	27.46	$	22.10	$	0.43
Second Quarter		38.77		25.12		0.02		37.47		26.26		0.43
Third Quarter		38.29		29.37		0.03		38.85		28.75		0.55
Fourth Quarter		41.89		34.01		0.03		36.00		28.50		0.57
2008
First Quarter		42.41		30.63		0.03		34.87		23.65		0.59
Second Quarter		50.06		40.06		0.03		45.40		31.76		0.61
Third Quarter		46.25		29.01		0.05		40.25		22.41		0.61
Fourth Quarter		34.58		11.00		0.05		26.50		10.23		0.61
2009
First Quarter		18.79		6.98		—		16.84		7.97		—
Second Quarter		20.12		8.48		—		23.08		10.15		—
Third Quarter (through August 20)		23.75		15.05		—		27.37		17.02		—

(1) Atlas America’s quarterly share prices have been adjusted to reflect the 3-for-2 stock splits on May 30, 2008 and May 25, 2007.

No Appraisal Rights

Neither holders of Atlas America common stock nor holders of Atlas Energy common units are entitled to appraisal rights in connection with the merger, stock issuance or other transactions contemplated by the merger agreement.

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THE MERGER AGREEMENT

The following summary describes material provisions of the merger agreement. This summary is subject to, and qualified in its entirety by reference to, the merger agreement, which is attached to this joint proxy statement/prospectus as Annex A and is incorporated by reference into this joint proxy statement/prospectus. You are urged to read the merger agreement carefully and in its entirety, as it is the legal document governing the merger.

The merger agreement and the following summary have been included to provide you with information regarding the terms of the merger agreement and the transaction described in this joint proxy statement/prospectus. The representations and warranties contained in the merger agreement are not intended to be a source of business or operational information about Atlas America or Atlas Energy as such representations and warranties are made as of a specified date, are tools used to allocate risk between the parties, are subject to contractual standards of knowledge and materiality and are modified or qualified by information contained in the parties’ public filings and in the disclosure schedules exchanged by the parties. Business and operational information regarding Atlas America and Atlas Energy can be found elsewhere in this joint proxy statement/prospectus and in the other public documents that Atlas America and Atlas Energy file with the SEC. See “Where You Can Find More Information.”

Structure and Completion of the Merger

Subject to the terms and conditions of the merger agreement, at the effective time of the merger, Merger Sub, a wholly owned subsidiary of Atlas America, will merge with and into Atlas Energy, with Atlas Energy surviving the merger and continuing as a wholly owned subsidiary of Atlas America. At the effective time of the merger, Atlas America will be renamed “Atlas Energy, Inc.”

The filing of the certificate of merger and the consummation of the merger will occur on the third business day after the date on which the conditions to completion of the merger contained in the merger agreement (other than those conditions that are waived or by their nature are to be satisfied by actions taken at the closing of the merger) are satisfied (see “The Merger Agreement — Conditions to the Completion of the Merger” below) or such other date as Atlas America and Atlas Energy may agree in writing. The merger will become effective at the time that the certificate of merger is filed with the Secretary of State of the State of Delaware or at a later time as agreed to by the parties and as set forth in the certificate of merger.

Atlas America and Atlas Energy are working to complete the merger in the third quarter of 2009. However, the merger is subject to various conditions set forth in the merger agreement, and it is possible that factors outside the control of both companies could result in the merger being completed at a later time, or not at all. Atlas America and Atlas Energy hope to complete the merger as soon as reasonably practicable following the special meetings.

Merger Consideration

At the effective time of the merger, each Atlas Energy common unit issued and outstanding, other than treasury units and Atlas Energy common units owned by Atlas America and its subsidiaries, will be cancelled and converted into the right to receive 1.16 shares of Atlas America common stock. The exchange ratio is fixed and will not change between now and the date of the merger, including as a result of a change in the trading price of Atlas America common stock or Atlas Energy common units.

Atlas America will not issue fractional shares of Atlas America common stock in the merger. Instead, Atlas Energy unitholders who otherwise would have received a fraction of a share of Atlas America common stock will receive an amount in cash (without interest and rounded up to the nearest whole cent) equal to such fractional amount multiplied by the closing sale price of Atlas America common stock on NASDAQ as reported byThe Wall Street Journal on the trading day immediately preceding the date on which the effective time of the merger occurs.

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Atlas Energy common units held by Atlas Energy in its treasury immediately prior to the effective time will be cancelled, and will not be converted into the right to receive the merger consideration. Each Class A unit and management incentive interest of Atlas Energy held by Atlas Energy Management, and each Atlas Energy common unit held by Atlas America or its subsidiaries, will continue to be held by Atlas Energy Management and Atlas America or its subsidiaries, as applicable, after the effective time.

Treatment of Equity-Based Awards

Options

Each outstanding option to purchase Atlas Energy common units granted under the Amended and Restated Atlas Energy Resources Long-Term Incentive Plan (which we refer to as the “Atlas Energy Long-Term Incentive Plan”) will be converted pursuant to the merger agreement into a stock option to acquire shares of Atlas America common stock. The number of shares of Atlas America common stock underlying the new Atlas America stock option will be determined by multiplying the number of Atlas Energy common units subject to such option immediately prior to the effectiveness of the merger by 1.16, rounded down to the nearest whole share. The new Atlas America stock option will have a per share exercise price determined by dividing the per unit exercise price of the Atlas Energy option by 1.16, rounded up to the nearest whole penny.

Phantom Units

Each outstanding grant of phantom Atlas Energy common units granted under the Atlas Energy Long-Term Incentive Plan will be converted pursuant to the merger agreement into a grant of phantom shares denominated in the number of shares of Atlas America common stock determined by multiplying the number of Atlas Energy common units subject to such grant immediately prior to the effectiveness of the merger by 1.16 (rounded up to the nearest whole share in respect of any fractional shares subject to the converted phantom share award). The converted phantom share awards will have the same terms and conditions as were applicable to the Atlas Energy phantom unit prior to the effectiveness of the merger.

Restricted Units

Each award of Atlas Energy restricted units granted under the Atlas Energy Long-Term Incentive Plan will be converted into the right to receive, on the same terms and conditions as were applicable to the Atlas Energy restricted unit prior to the effectiveness of the merger, a number of restricted shares of Atlas America common stock determined by multiplying each Atlas Energy restricted unit by 1.16 (rounded up to the nearest whole share in respect of any fractional shares subject to the converted restricted share award).

Exchange of Atlas Energy Common Units in the Merger

At or prior to the effective time of the merger, Atlas America will appoint an exchange agent reasonably acceptable to Atlas Energy to handle the exchange of Atlas Energy common units for the merger consideration, including the payment of cash for fractional shares.

Only those holders of Atlas Energy common units who properly surrender their certificates representing Atlas Energy common units in accordance with the exchange agent’s instructions will receive:

• either certificates representing shares of Atlas America common stock or evidence of shares of Atlas America common stock in book-entry form, at Atlas America’s election;

• cash in lieu of any fractional shares of Atlas America common stock; and

• dividends or other distributions, if any, on Atlas Energy common units with a record date occurring prior to the effective time that have been declared by Atlas Energy in accordance with the terms of the merger agreement.

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After the effective time of the merger, each certificate representing Atlas Energy common units that has not been surrendered will represent only the right to receive upon surrender of that certificate each of the items listed in the preceding sentence. After the effective time of the merger, Atlas Energy will not register any transfers of Atlas Energy common units.

Promptly after the effective time, Atlas America will instruct the exchange agent to mail to each record holder of Atlas Energy common units a letter of transmittal (which will specify that delivery will be effected, and risk of loss and title will pass, only upon proper delivery of such holder’s certificates representing Atlas Energy common units to the exchange agent) and instructions for surrendering the certificates representing Atlas Energy common units (or effective affidavits of loss and posting of bonds, if required by Atlas Energy or Atlas America, in lieu thereof) in exchange for the merger consideration. Upon surrender of certificates representing Atlas Energy common units (or effective affidavits of loss in lieu thereof), together with an executed letter of transmittal, to the exchange agent, the holder of those certificates will be entitled to receive the merger consideration. The surrendered certificates representing Atlas Energy common units will be cancelled.

Conditions to the Completion of the Merger

Each party’s obligation to consummate the merger is subject to the satisfaction or waiver of the following conditions:

• the stock issuance shall have been approved by the affirmative vote of the holders of a majority of the shares of Atlas America common stock voted at the Atlas America special meeting, and the amendment to the Atlas America charter to increase the number of authorized shares of Atlas America common stock shall have been approved by the affirmative vote of the holders of a majority of the outstanding shares of Atlas America common stock (which amendment to the Atlas America charter was approved on July 13, 2009);

• the merger, the merger agreement and the other transactions contemplated by the merger agreement shall have been approved and adopted by the affirmative vote of at least a majority of the outstanding Atlas Energy Class A units and at least a majority of the outstanding Atlas Energy common units, each voting as a separate class;

• the parties to the merger agreement shall have obtained the consent for the merger under the Atlas Energy credit agreement (which consent was obtained on July 10, 2009);

• any waiting period under the HSR Act shall have expired or been terminated and all other filings required to be made prior to the effective time of the merger with, and all other consents, approvals, permits and authorizations required to be obtained prior to the effective time of the merger from, any governmental authority in connection with the execution and delivery of the merger agreement and the consummation of the transactions contemplated by the merger agreement by the parties to the merger agreement and their affiliates shall have made or obtained, except where the failure to obtain such consents, approvals, permits and authorizations would not be reasonably likely to result in a material adverse effect on Atlas America or Atlas Energy (which early termination of the waiting period under the HSR Act was granted on May 15, 2009 and no further regulatory approvals are required);

• no order, decree or injunction of any court or agency of competent jurisdiction shall be in effect, and no law or regulation shall have been enacted or adopted, that enjoins, prohibits or makes illegal consummation of any of the transactions contemplated by the merger agreement;

• no action, proceeding or investigation by any governmental authority with respect to the merger or the other transactions contemplated by the merger agreement shall be pending that seeks to restrain, enjoin, prohibit or delay consummation of the merger or to impose any material restrictions or requirements thereon; and

• the registration statement of which this joint proxy statement/prospectus is a part shall have become effective under the Securities Act, and no stop order shall have been issued and no proceeding for that purpose shall have been initiated or threatened by the SEC or any other governmental authority.

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Atlas Energy’s obligation to consummate the merger is subject to the satisfaction or waiver of the following conditions:

• (i) the representations and warranties of Atlas America in the merger agreement regarding Atlas America’s cash and commitments shall be true and correct as of the date specified therein in all material respects, (ii) the representations and warranties of Atlas America in the merger agreement regarding Atlas America’s capitalization will be true and correct in all material respects, and (iii) each of the other representations and warranties of Atlas America and Merger Sub in the merger agreement will be true and correct, in each of the cases of clauses (ii) and (iii) as of the date of the merger agreement and as of the date of closing of the merger, except for any such representations and warranties made as of a specified date, which shall be true and correct as of such date, except, in the case of clause (iii), where the failure of any such representations and warranties to be so true and correct (without giving effect to any qualification as to materiality or a material adverse effect qualification) would not, individually or in the aggregate, have a material adverse effect on Atlas America;

• Atlas America and Merger Sub shall have duly performed and complied with, in all material respects, all of their agreements and covenants under the merger agreement at or prior to the consummation of the merger;

• Atlas Energy shall have received a certificate signed by an executive officer of Atlas America, dated as of the date of the closing of the merger, as to the satisfaction of the conditions described in the preceding two bullets;

• Atlas America shall have amended the Atlas America charter to authorize the issuance of additional shares of Atlas America common stock as necessary for the stock issuance; and

• the shares of Atlas America common stock to be issued in the merger shall have been approved for listing on NASDAQ, subject to official notice of issuance.

Atlas America’s and Merger Sub’s obligations to consummate the merger are subject to the satisfaction or waiver of the following conditions:

• (i) the representations and warranties of Atlas Energy in the merger agreement regarding Atlas Energy’s capitalization shall be true and correct in all material respects, and (ii) each of the other representations and warranties of Atlas Energy in the merger agreement shall be true and correct, in each of the cases of clauses (i) and (ii) as of the date of the merger agreement and as of the date of closing of the merger, except for any such representations and warranties made as of a specified date, which shall be true and correct as of such date, except, in the case of clause (ii), where the failure of any such representations and warranties to be so true and correct (without giving effect to any qualification as to materiality or a material adverse effect qualification) would not, individually or in the aggregate, have a material adverse effect on Atlas Energy;

• Atlas Energy will have duly performed and complied with, in all material respects, all of its agreements and covenants under the merger agreement at or prior to the consummation of the merger;

• Atlas America shall have received a certificate signed by an executive officer of Atlas Energy, dated as of the date of the closing of the merger, as to the satisfaction of the conditions described in the preceding two bullets; and

• Atlas Energy shall have received resignations for all of the directors on the Atlas Energy board of directors.

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The term “material adverse effect,” as used in the merger agreement, means any state of facts, circumstance, change or effect that is materially adverse to the business, financial condition or results of operations of either party and its subsidiaries, taken as a whole (including, in the case of Atlas America, Atlas Energy and its subsidiaries). However, none of the following (or the effects thereof) will be deemed to constitute, and none of the following will be taken into account in determining whether there has been, or if there is reasonably likely to be, a material adverse effect:

• general economic conditions, changes in securities markets (including any disruption thereof), regulatory or political conditions, including any engagement in hostilities, whether or not pursuant to the declaration of a national emergency or war, the occurrence of any military or terrorist attack or a general economic recession, natural disaster or other force majeure event, in each case in the United States or elsewhere, except to the extent that such condition, change or event affects a party in a materially disproportionate and adverse manner when compared to companies of similar size operating in the same industry or market as such party;

• changes in, or events or conditions generally affecting, the oil and gas exploration and development industry (including changes in commodity prices and general market prices), except to the extent that such changes, events or conditions affect a party in a materially disproportionate and adverse manner when compared to companies of similar size operating in the same industry or market as such party; provided, however, that in the case of Atlas America, the bankruptcy of Atlas America will be considered a material adverse effect;

• changes in laws or U.S. generally accepted accounting principles or interpretations thereof, except to the extent that such changes affect a party in a materially disproportionate and adverse manner when compared to companies of similar size operating in the same industry or market as such party;

• the announcement or pendency of the merger agreement, any actions taken in compliance with the merger agreement or the consummation of the merger;

• any failure by a party to meet estimates of revenues or earnings for any period ending after the date of the merger agreement (provided that the underlying causes of any such failure may be considered in determining whether a material adverse effect has occurred);

• the downgrade in rating of any debt securities of a party by Standard & Poor’s Rating Group, Moody’s Investor Services, Inc. or Fitch Ratings (provided that the underlying causes of any such downgrade may be considered in determining whether a material adverse effect has occurred);

• the taking of any action (or omitting to take any action) required or contemplated by the merger agreement or the taking of any action (or omitting to take any action) that the other party has requested or to which the other party has consented; or

• changes in the price or trading volume of Atlas America common stock or Atlas Energy common units, respectively (provided that the underlying causes of any such changes may be considered in determining whether a material adverse effect has occurred).

Reasonable Best Efforts

Each of Atlas America and Atlas Energy agreed in the merger agreement to use its reasonable best efforts in good faith to take, or cause to be taken, all actions, and to do, or cause to be done, all things necessary, proper, desirable or advisable under applicable laws, so as to permit consummation of the merger as soon as reasonably practicable and otherwise to enable consummation of the transactions contemplated hereby, including obtaining consent under Atlas Energy’s credit agreement, obtaining third party approvals, rescinding or lifting any injunction or restraining order or other order adversely affecting the ability of the parties to consummate the transactions and defending any litigation seeking to enjoin, prevent or delay the merger or seeking material damages. With regards to the Atlas Energy credit agreement, “consent” is defined in the merger agreement as approval by lenders representing greater than 50% of the outstanding Loans (as defined in the Atlas Energy credit agreement) of the

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merger agreement and the transactions contemplated thereby, including the merger, under the Atlas Energy credit agreement, with continued availability of credit thereunder to Atlas Energy on substantially the same terms as existed at the date of the merger agreement, and no redetermination of the borrowing base except in accordance with existing terms of the Atlas Energy credit agreement and subject only to customary fees.

Equityholder Approvals

Atlas Energy agreed in the merger agreement to take in accordance with applicable law and its amended and restated operating agreement, all action necessary to call, convene and hold, as soon as reasonably practicable, an appropriate meeting of Atlas Energy unitholders to consider and vote upon the adoption of the merger agreement, the approval of the merger and the approval of any other matters required to be approved by holders of Atlas Energy Class A units and holders of Atlas Energy common units for consummation of the merger, promptly after the date that the registration statement that forms a part of this joint proxy statement/prospectus is declared effective by the SEC. Each of (1) the Atlas Energy special committee and (2) the Atlas Energy board of directors, with all of the interested and potentially interested directors abstaining or recusing themselves, and based upon the unanimous recommendation of the Atlas Energy special committee, determined that the merger agreement and the transactions contemplated thereby, including the merger, are advisable, fair and reasonable to, and in the best interests of, Atlas Energy and the Atlas Energy unitholders that are not affiliated with Atlas America. Therefore, based upon the unanimous recommendation of the Atlas Energy special committee, the Atlas Energy board of directors recommends that Atlas Energy unitholders vote “FOR” the proposal to adopt the merger agreement and approve the transactions contemplated thereby, including the merger.

At any time prior to obtaining adoption of the merger agreement and approval of the merger by Atlas Energy unitholders, the Atlas Energy board of directors and the Atlas Energy special committee may withdraw, modify or qualify in any manner adverse to Atlas America its recommendation if the Atlas Energy board of directors or the Atlas Energy special committee has concluded in good faith, after consultation with and taking into account the advice of, their outside legal advisors, that the failure to make a change in recommendation would be inconsistent with its applicable fiduciary duties. However, the obligation of Atlas Energy to call, hold and convene the Atlas Energy special meeting will not be affected by any change in recommendation by the Atlas Energy board of directors or the Atlas Energy special committee.

Atlas America has agreed to take in accordance with applicable law and its charter and bylaws, all action necessary to call, convene and hold, as soon as reasonably practicable, an appropriate meeting of Atlas America stockholders to consider and vote upon the approval of the stock issuance and the charter amendment, promptly after the date that the registration statement that forms a part of this joint proxy statement/prospectus is declared effective by the SEC. The Atlas America board of directors has determined that the merger agreement and the transactions contemplated thereby, including the stock issuance and the charter amendment, are advisable, fair to and in the best interests of Atlas America and its stockholders. The Atlas America board of directors has also approved the merger agreement and the transactions contemplated thereby and recommended to Atlas America stockholders that they approve the stock issuance and the charter amendment. Atlas America stockholders approved the charter amendment, increasing the number of authorized shares of Atlas America common stock from 49,000,000 to 114,000,000, at the Atlas America annual meeting held on July 13, 2009.

At any time prior to obtaining approval of the stock issuance and the charter amendment by Atlas America stockholders, the Atlas America board of directors may withdraw, modify or qualify in any manner adverse to Atlas Energy its recommendation if the Atlas America board of directors has concluded in good faith, after consultation with and taking into account the advice of, its outside legal advisors and financial consultants, that the failure to make a change in recommendation would be inconsistent with its fiduciary duties under applicable law. However, the obligation of Atlas America to call, hold and convene the Atlas America special meeting will not be affected by any change in recommendation by the Atlas America board of directors.

So long as the Atlas Energy board of directors and Atlas Energy special committee recommendation in favor of adoption of the merger agreement by Atlas Energy unitholders remains unchanged at the time of the

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Atlas America special meeting, Atlas America and Atlas Energy Management have agreed to vote all of their Atlas Energy common units and Atlas Energy Class A units to adopt the merger agreement, approve the merger and approve any other matters required to be approved by holders of Atlas Energy Class A units and the holders of Atlas Energy common units for consummation of the merger; provided, however, that Atlas America and Atlas Energy Management may, but shall not be required to, vote their Atlas Energy common units and Atlas Energy Class A units in such manner if the Atlas Energy board of directors and Atlas Energy special committee changes its recommendation.

Conduct of Business Pending Completion of the Merger

Each of Atlas America and Atlas Energy has undertaken certain covenants in the merger agreement restricting the conduct of their respective businesses between the date of the merger agreement and the effective time of the merger. In general, each of Atlas America and Atlas Energy has agreed to conduct its business in the ordinary course and in a manner consistent with past practice, in each case in all material respects.

In addition, between the date of the merger agreement and the effective time of the merger, Atlas Energy has agreed, except (i) with Atlas America’s prior written consent, which is not to be unreasonably withheld, delayed or conditioned, (ii) as contemplated by the merger agreement, (iii) for transactions between Atlas Energy and its wholly owned subsidiaries or (iv) as required by applicable law, that Atlas Energy will not and will not permit any of its subsidiaries to, among other things, undertake the following:

• except in the ordinary course of business and consistent with past practice and not in excess of $50,000,000 in the aggregate per quarter, acquire, by merging or consolidating with, or by purchasing an equity interest in or the assets of, or by any other manner, any business or corporation, partnership or other business organization or division thereof, or otherwise acquire any assets of any other entity (other than the purchase of assets from suppliers, clients or vendors in the ordinary course of business and consistent with past practice), or make any capital contribution, or incur any indebtedness for borrowed money, or issue any debt securities, or assume, guarantee or endorse, or otherwise as an accommodation become voluntarily responsible for, the obligations of any person, or make any loans or advances;

• amend or otherwise change its certificate of formation or its amended and restated operating agreement, dated as of December 18, 2006, as amended;

• issue, sell, pledge, dispose of, grant, encumber, or authorize the issuance, sale, pledge, disposition, grant or encumbrance of, any equity interests of any class of Atlas Energy or any of its subsidiaries, or any options, warrants, convertible securities or other rights of any kind to acquire any such equity interests, of Atlas Energy or any of its subsidiaries (except in accordance with the terms of securities or equity compensation awards outstanding on the date of the merger agreement);

• declare, set aside, make or pay any dividend or other distribution, payable in cash, units, property or otherwise, with respect to any of its equity interests or reclassify, combine, split or subdivide, or redeem, purchase or otherwise acquire, directly or indirectly, any of its equity interests;

• adopt a plan of complete or partial liquidation, dissolution, merger, consolidation, restructuring, recapitalization or other reorganization of such entity;

• change its methods of accounting (other than tax accounting, which shall be governed by the subsequent bullet), except in accordance with changes in U.S. generally accepted accounting principles (which we refer to as “GAAP”) as concurred to by Atlas Energy’s independent auditors;

• enter into any closing agreement with respect to material taxes, settle or compromise any material liability for taxes, revoke, change or make any new material tax election, agree to any adjustment of any material tax attribute, file or surrender any claim for a material refund of taxes, execute or consent

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to any waivers extending the statutory period of limitations with respect to the collection or assessment of material taxes, file any material amended tax return or obtain any material tax ruling;

• except in the ordinary course of business and consistent with past practice, (A) grant to any current or former director or officer of Atlas Energy any increase in compensation, bonus or fringe or other benefits or grant any type of compensation or benefit to any such person not previously receiving or entitled to receive such compensation, except to the extent required under any Atlas Energy employee benefit plan as in effect as of the date of the merger agreement, (B) grant to any person any severance, retention, change in control or termination compensation or benefits or any increase therein, except to the extent required under any Atlas Energy employee benefit plan as in effect as of the date of the merger agreement, or (C) enter into or adopt any material employee benefit plan or amend in any material respect any employee benefit plan, except for any amendments in the ordinary course of business consistent with past practice or in order to comply with applicable laws (including Section 409A of the Internal Revenue Code); or

• agree or formally commit to do any of the foregoing.

In addition, between the date of the merger agreement and the effective time of the merger, Atlas America has agreed, except (i) with the Atlas Energy special committee’s prior written consent, which is not to be unreasonably withheld, delayed or conditioned, (ii) as contemplated by the merger agreement, (iii) for transactions between Atlas America and its wholly owned subsidiaries other than Atlas Pipeline Holdings GP, LLC, Atlas Pipeline Holdings, Atlas Pipeline GP, Atlas Pipeline and any of their respective subsidiaries or (iv) as required by applicable law, that Atlas America will not, among other things, undertake the following:

• make any expenditures, except for (i) certain scheduled allowable expenditures, (ii) normal operating expenses incurred in the ordinary course of business consistent with past practice of not more than $1 million per month or $9 million in the aggregate or (iii) for the costs and expenses associated with entering into the merger agreement;

• make any capital contribution, acquire any securities of any of its subsidiaries for cash or incur any indebtedness for borrowed money or issue any debt securities or assume, guarantee or endorse, or otherwise as an accommodation become voluntarily responsible for, the obligations of any person, or make any loans or advances, other than intercompany payables owed to Atlas America relating to services rendered or benefits provided by Atlas America for a subsidiary in the ordinary course consistent with past practice; or

• issue (except in accordance with the terms of securities outstanding on the date of the merger agreement or any existing employee ownership or benefit plan or other contractual obligation), split, combine or reclassify any shares of its capital stock; declare, set aside or pay any dividend or other distribution in respect of its capital stock or otherwise make any payments to stockholders in their capacity as such.

In addition, between the date of the merger agreement and the effective time of the merger, Atlas America has agreed, except (i) with the Atlas Energy special committee’s prior written consent, which is not to be unreasonably withheld, delayed or conditioned, (ii) as contemplated by the merger agreement, (iii) for transactions between Atlas America and its wholly owned subsidiaries other than Atlas Pipeline Holdings GP, LLC, Atlas Pipeline Holdings, Atlas Pipeline GP, Atlas Pipeline and any of their respective subsidiaries or (iv) as required by applicable law, that Atlas America will not and will not permit any of its subsidiaries other than Atlas Pipeline Holdings GP, LLC, Atlas Pipeline Holdings, Atlas Pipeline GP, Atlas Pipeline and any of their respective subsidiaries to, among other things, undertake the following:

• acquire, by merging or consolidating with, or by purchasing an equity interest in or in the assets of, or by any other manner, any business or corporation, partnership or other business organization or division thereof, or otherwise acquire any assets of any other entity (other than the purchase of assets from suppliers, clients or vendors in the ordinary course of business and consistent with past practice);

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• adopt or propose to adopt any amendments to its charter documents;

• adopt a plan of complete or partial liquidation, dissolution, merger, consolidation, restructuring, recapitalization or other reorganization;

• change its methods of accounting (other than tax accounting, which shall be governed by the subsequent bullet), except in accordance with changes in GAAP as concurred to by Atlas America’s independent auditors;

• enter into any closing agreement with respect to material taxes, settle or compromise any material liability for taxes, revoke, change or make any new material tax election, agree to any adjustment of any material tax attribute, file or surrender any claim for a material refund of taxes, execute or consent to any waivers extending the statutory period of limitations with respect to the collection or assessment of material taxes, file any material amended tax return or obtain any material tax ruling; or

• agree or formally commit to do any of the foregoing.

Other Covenants and Agreements

The merger agreement contains certain other covenants and agreements, including covenants relating to the following:

• cooperation between Atlas America and Atlas Energy in the preparation of this joint proxy statement/prospectus;

• cooperation between Atlas America and Atlas Energy in connection with public announcements;

• confidentiality and access by each party to certain information about the other party during the period prior to the effective time of the merger;

• the use of reasonable best efforts by Atlas America to cause the shares of Atlas America common stock to be issued in the merger to be approved for listing on NASDAQ, subject to official notice of issuance;

• cooperation between Atlas America and Atlas Energy to obtain all governmental approvals, consents and waiting period expirations or terminations required to complete the merger;

• the disposition by Atlas Energy, as reasonably requested by the parties to the merger agreement, of Atlas Energy equity securities (including derivative securities) pursuant to the transactions contemplated by the merger agreement by each individual who is a director or officer of Atlas Energy to be exempt from Rule 16b-3 promulgated under the Exchange Act, including taking actions in accordance with the No-Action letter dated January 12, 1999 issued by the SEC regarding such matters;

• the use of commercially reasonable efforts by each party to deliver comfort letters to the other party in form and substance reasonably satisfactory to the board of directors of such other party; and

• Atlas America and Atlas Energy causing, by any necessary action, the appointment to the Atlas America board of directors as of the effective time of the merger four members, as designated by Atlas Energy, from the current Atlas Energy board of directors, all of whom must be independent within the meaning ascribed thereto by NASDAQ.

Atlas America has also agreed to assume all rights to indemnification, advancement of expenses and exculpation from liabilities and acts or omissions occurring at or prior to the effective time of the merger now existing in favor of the current or former directors and officers of Atlas Energy. Atlas America has also agreed to purchase a “tail” directors’ and officers’ liability insurance policy for Atlas Energy and its current and former directors and officers who are currently covered by, or continue to maintain, the liability insurance coverage currently maintained by Atlas Energy.

Atlas America has also agreed to change its name to “Atlas Energy, Inc.” at the effective time of the merger.

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Termination of the Merger Agreement

The merger agreement may be terminated at any time before the effective time of the merger, even after receipt of the requisite Atlas America stockholder approval and Atlas Energy unitholder approval, under the following circumstances:

• by mutual written consent of Atlas America and Atlas Energy;

• by either Atlas America or Atlas Energy upon written notice to the other if:

• the merger is not consummated on or before February 28, 2010; provided, however that this right to terminate will not be available to a party whose failure to fulfill any obligation under the merger agreement or other breach of the merger agreement has been a cause of or resulted in the failure of the merger to be consummated on or prior to such date;

• any governmental entity prohibits the merger and that prohibition has become final and nonappealable (provided that the terminating party has complied with its obligations under the merger agreement);

• Atlas Energy fails to obtain the approval and the adoption of the merger, the merger agreement and the other transactions contemplated by the merger agreement by holders of Atlas Energy common units and holders of Atlas Energy Class A units at an appropriate meeting of Atlas Energy unitholders;

• Atlas America fails to obtain the required approval of the stock issuance and the charter amendment by Atlas America stockholders at an appropriate meeting of Atlas America stockholders;

• there has been a material breach of or any inaccuracy in any of the representations or warranties set forth in the merger agreement on the part of any of the other parties, which breach is not cured within 30 days following receipt by the breaching party of written notice of such breach from the terminating party, or which breach, by its nature, cannot be cured prior to February 28, 2010; provided, however, that no party has the right to terminate the merger agreement unless the breach of representation or warranty, together with all other such breaches, would entitle the party receiving such representation not to consummate the transactions contemplated by the merger agreement because a closing condition has not been met, and the terminating party is not in material breach of the merger agreement;

• there has been a material breach of any of the covenants or agreements in the merger agreement on the part of any of the other parties, which breach has not been cured within 30 days following receipt by the breaching party of written notice of such breach from the terminating party, or which, by its nature, cannot be cured prior to February 28, 2010; provided, however, that no party has the right to terminate the merger agreement unless the breach of covenants or agreements, together with all other such breaches, would entitle the party receiving such covenants or agreements not to consummate the transactions contemplated by the merger agreement because a closing condition has not been met, and the terminating party is not in material breach of the merger agreement;

• by Atlas Energy (with the prior approval of the Atlas Energy special committee), in the event that the Atlas America board of directors withdraws, modifies or qualifies in any manner adverse to Atlas Energy its recommendation to Atlas America stockholders to approve the stock issuance and the charter amendment; or

• by Atlas America, in the event that either of the Atlas Energy board of directors or the Atlas Energy special committee withdraws, modifies or qualifies in any manner adverse to Atlas America its recommendation to Atlas Energy unitholders to adopt the merger agreement and approve the transactions contemplated by the merger agreement.

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Effect of Termination

In the event of the termination of the merger agreement, the agreement will become null and void. In the event of such termination, there shall be no liability on the part of Atlas America, Merger Sub or Atlas Energy; provided, however, that no termination will relieve any party from any liability or obligation with respect to any fraud or intentional breach of the merger agreement.

Specific Performance

Each party is entitled to seek an injunction or injunctions to prevent a breach of the merger agreement and to enforce specifically the terms and provisions of the merger agreement in any federal court located in the State of Delaware or in the Delaware Court of Chancery, in addition to any other remedy to which the parties are entitled at law or in equity.

Fees and Expenses

Generally, all fees and expenses incurred in connection with the merger agreement and the transactions contemplated by the merger agreement will be paid by the party incurring those expenses, subject to the specific exceptions discussed in this joint proxy statement/prospectus.

Waiver and Amendment

Subject to compliance with applicable law, prior to the consummation of the merger, any provision of the merger agreement may be:

• waived in writing by the party benefited by the provision and approved by the Atlas Energy special committee and Atlas America; or

• amended or modified at any time by an agreement in writing approved by the Atlas Energy special committee and Atlas America; provided, however, that after the adoption of the merger agreement and approval of the transactions under the merger agreement at the Atlas Energy special meeting, there can be no amendment made that requires further approval by the Atlas Energy unitholders without the further approval of the Atlas Energy unitholders.

Governing Law

The merger agreement is governed by the laws of the State of Delaware.

Representations and Warranties

Each of Atlas America and Atlas Energy has made reciprocal representations and warranties to the other regarding, among other things:

• organization and qualification;

• subsidiaries;

• capitalization, and, in the case of Atlas Energy, benefit plans;

• corporate power and authority and enforceability of the merger agreement;

• recommendation by their respective board of directors, and, in the case of Atlas Energy, the Atlas Energy special committee, and opinions of Atlas America’s and the Atlas Energy special committee’s financial advisors;

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• no violation and consents;

• compliance with organizational documents and other obligations and permits;

• SEC filings and financial statements;

• absence of undisclosed liabilities;

• absence of certain changes or events;

• litigation;

• accuracy of information supplied in connection with this joint proxy statement/prospectus;

• taxes;

• brokers’ fees payable in connection with the merger;

• in the case of Atlas Energy, the Atlas Energy board of directors’ determination not to pay any distributions with respect to the quarter ended March 31, 2009;

• in the case of Atlas America, cash and commitments; and

• in the case of Atlas America, certain representations regarding Merger Sub.

Atlas Energy Management has also made representations and warranties to Atlas Energy regarding:

• organization and qualification;

• corporate power and authority and enforceability of the merger agreement; and

• no violation and consents.

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ATLAS AMERICA PROPOSAL 2: APPROVAL OF THE ATLAS AMERICA

2009 STOCK INCENTIVE PLAN

The compensation committee of the Atlas America board of directors has approved the Atlas America 2009 Stock Incentive Plan (which we refer to as the “2009 Plan”), effective upon the date it is adopted by the Atlas America board of directors, subject to approval by Atlas America stockholders. The purpose of the 2009 Plan is to give Atlas America a competitive advantage in attracting, retaining and motivating officers, employees, directors and consultants and to provide Atlas America with a stock incentive plan providing incentives directly linked to stockholder value.

Set forth below is a summary of certain important features of the 2009 Plan, which summary is qualified in its entirety by reference to the actual plan attached as Appendix D to this joint proxy statement/prospectus.

Administration

The 2009 Plan will be administered by the Atlas America compensation committee or such other committee of the Atlas America board of directors as the Atlas America board of directors may from time to time designate (which we refer to as the “Committee”). Among other things, the Committee will have the authority to select individuals to whom awards may be granted, to determine the type of award as well as the number of shares of Atlas America common stock to be covered by each award, and to determine the terms and conditions of any such awards.

Eligibility

Persons who serve or agree to serve as officers, employees, directors or consultants of Atlas America and its subsidiaries and affiliates are eligible to be granted awards under the 2009 Plan, as well as prospective employees and consultants who have accepted offers of employment or consultancy from Atlas America and its subsidiaries and affiliates.

Shares Subject to the Plan

The 2009 Plan authorizes the issuance of up to 4,800,000 shares of Atlas America common stock pursuant to awards under the 2009 Plan. The maximum number of shares of Atlas America common stock that may be granted pursuant to incentive stock options is 4,800,000.

No individual participant may be granted options and free-standing stock appreciation rights (which we refer to as “SARs”) covering in excess of 500,000 shares of Atlas America common stock in any calendar year or qualified performance-based awards (as described below), other than options and free-standing SARs, covering in excess of 500,000 shares of Atlas America common stock in any calendar year.

The shares of Atlas America common stock subject to grant under the 2009 Plan are to be made available from authorized but unissued shares or from treasury shares. To the extent that any award is cancelled or forfeited, or any option or stock appreciation right terminates, expires or lapses without being exercised, or any award is settled for cash, the shares of Atlas America common stock subject to such awards not delivered as a result thereof will again be available for awards under the 2009 Plan. If the exercise price of any option and/or the tax withholding obligations relating to any award are satisfied by delivering shares of Atlas America common stock (by either actual delivery or by attestation), only the number of shares of Atlas America common stock issued net of the shares of Atlas America common stock delivered or attested to will be deemed delivered for purposes of the limits in the 2009 Plan. To the extent any shares of Atlas America common stock subject to an award are withheld to satisfy the exercise price (in the case of an option) and/or the tax withholding obligations relating to such award, such shares of Atlas America common stock will not generally be deemed to have been delivered for purposes of the limits set forth in the 2009 Plan.

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In the event of certain extraordinary corporate transactions or events affecting Atlas America, the Committee or the Atlas America board of directors is required to make such substitutions or adjustments as it deems appropriate and equitable to (1) the aggregate number and kind of shares or other securities reserved for issuance and delivery under the 2009 Plan, (2) the various maximum limitations set forth in the 2009 Plan, (3) the number and kind of shares or other securities subject to outstanding awards; and (4) the exercise price of outstanding options and stock appreciation rights. In the case of corporate transactions such as a merger or consolidation, such adjustments may include the cancellation of outstanding awards in exchange for cash or other property or a combination thereof or the substitution of other property for the shares subject to outstanding awards.

As indicated above, several types of stock grants can be made under the 2009 Plan. A summary of these grants is set forth below.

Stock Options and Stock Appreciation Rights

Stock options granted under the 2009 Plan may either be incentive stock options, which are intended to qualify for favorable treatment to the recipient under U.S. federal tax law, or nonqualified stock options, which do not qualify for this favorable tax treatment. Stock appreciation rights granted under the 2009 Plan may either be “tandem SARs,” which are granted in conjunction with an option, or “free-standing SARs,” which are not granted in tandem with a stock option. A tandem SAR may be granted on the grant date of the related option, will be exercisable only to the extent that the related option is exercisable and will have the same exercise price as the related option. A tandem SAR will terminate or be forfeited upon the exercise or forfeiture of the related option, and the related option will terminate or be forfeited upon the exercise or forfeiture of the tandem SAR.

Each grant of stock options or stock appreciation rights under the 2009 Plan will be evidenced by an award agreement that specifies the exercise price, the duration of the award, the number of shares to which the award pertains and such additional limitations, terms and conditions as the Committee may determine, including, in the case of stock options, whether the options are intended to be incentive stock options or nonqualified stock options. The 2009 Plan provides that the exercise price of options and stock appreciation rights will be determined by the Committee, but may not be less than 100% of the fair market value of the stock underlying the options or stock appreciation rights on the date of grant. Optionees may pay the exercise price in cash or, if approved by the Committee, in Atlas America common stock (valued at its fair market value on the date of exercise) or a combination thereof, or by “cashless exercise” through a broker or by withholding shares otherwise receivable on exercise. The term of options and stock appreciation rights will be determined by the Committee, but may not exceed ten years from the date of grant. The Committee will determine the vesting and exercise schedule of options and stock appreciation rights, and the extent to which they will be exercisable after the award holder’s employment terminates. Stock options and stock appreciation rights granted under the 2009 Plan are generally transferable only by will or by the laws of descent and distribution, or in the case of non-qualified options and free-standing SARs, pursuant to a qualified domestic relations order or as otherwise expressly permitted by the Committee including, if so permitted, pursuant to a transfer to the participant’s family members or to a charitable organization, whether directly or indirectly or by means of a trust or partnership or otherwise.

Restricted Stock

Restricted stock may be granted under the 2009 Plan with such restrictions as the Committee may designate. The Committee may provide at the time of grant that the vesting of restricted stock will be contingent upon the achievement of applicable performance goals and/or continued service. The terms and conditions of restricted stock awards (including any applicable performance goals) need not be the same with respect to each participant. During the restriction period, the Committee may require that the stock certificates evidencing restricted shares be held by Atlas America. Restricted stock may not be sold, assigned, transferred, pledged or otherwise encumbered, and is forfeited upon termination of employment, unless otherwise provided by the Committee. Except for these restrictions and any others imposed by the Committee, upon the grant of restricted stock under the 2009 Plan, the recipient will have rights of a stockholder with respect to the restricted stock, including the

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right to vote the restricted stock; however, to the extent determined by the Committee, the 2009 Plan provides that cash dividends paid or made with respect to the restricted shares of Atlas America common stock will generally be automatically deferred and/or reinvested in additional restricted stock and held subject to the vesting of the underlying restricted stock, and stock dividends will generally be paid in the form of additional restricted stock subject to the vesting of the underlying restricted stock.

Restricted Stock Units

The Committee may grant restricted stock units payable in cash or shares of Atlas America common stock, conditioned upon continued service and/or the attainment of performance goals determined by the Committee. The terms and conditions of restricted stock unit awards granted under the 2009 Plan (including any applicable performance goals) need not be the same with respect to each participant. Restricted stock units may not be sold, assigned, transferred, pledged or otherwise encumbered prior to their vesting or settlement, except to the extent provided in an award agreement. Unless otherwise provided in an award agreement or by the Committee, restricted stock units are forfeited upon any termination of employment.

Non-Employee Director Awards

Pursuant to the 2009 Plan, each non-employee director of Atlas America will be awarded on the date of first election or appointment, deferred units payable in shares of Atlas America common stock having a fair market value of $15,000 on the date of grant. In addition, on each anniversary of the date on which a non-employee director is first elected or appointed to the Atlas America board of directors, the non-employee director will be awarded additional deferred units payable in shares of Atlas America common stock having a fair market value of $15,000 on the date of grant. The 2009 Plan provides that such deferred units vest in three equal installments on each of the second, third and fourth anniversary of the date of grant, in each case, subject to continuous service through the applicable vesting date, or sooner, upon the non-employee directors’ death or disability prior to the completion of the period of service required to be performed to fully vest in the deferred units. Unless otherwise provided in an award agreement, upon the occurrence of a change in control, all previously unvested deferred units granted to Atlas America’s non-employee directors will become vested and nonforfeitable.

Other Stock-Based Awards

Other awards of Atlas America common stock and other awards that are valued in whole or in part by reference to, or are otherwise based upon, Atlas America common stock, including (without limitation), unrestricted stock, dividend equivalents, and convertible debentures, may be granted under the 2009 Plan.

Performance Awards

The Committee may establish performance goals in connection with the grant of awards under the 2009 Plan. In the case of performance-based awards that are intended to qualify for the performance-based compensation exemption of Section 162(m)(4), such goals will be based on the attainment of one or any combination of the following either in absolute terms or in comparison to publicly available industry standards or indices: stock price, return on equity, assets under management, EBITDA (earnings before interest, taxes, depreciation and amortization), earnings per share, price-earnings multiples, net income, operating income, pre-tax income, sales, net profit after tax, gross profit, operating profit, cash generation, unit volume, return on equity, change in working capital, return on capital revenues, working capital, accounts receivable, productivity, margin, net capital employed, return on assets, stockholder return, return on capital employed, increase in assets, unit volume, sales, internal sales growth, cash flow, market share, relative performance to a comparison group designated by the Committee, or strategic business criteria consisting of one or more objectives based on meeting specified revenue goals, market penetration goals, customer growth, geographic business expansion goals, cost targets, goals relating to acquisitions or divestitures or stockholder return with respect to Atlas America or any subsidiary, division or department of Atlas America. Such qualified performance-based goals will be set by the

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Committee in the manner prescribed by Section 162(m). The Committee may adjust performance goals in the event of unusual or non-recurring events and other extraordinary items, except to the extent that doing so would cause an award intended to be exempt from the compensation limitations under Section 162(m) to fail to be exempt.

Change in Control and Termination of Employment

Except as otherwise specifically provided with respect to non-employee director deferred unit awards, the impact of a change in control (as defined in the 2009 Plan) on an outstanding award granted under the 2009 Plan, if any, will be set forth in the applicable award agreement. In addition, except as otherwise specifically provided with respect to non-employee director deferred unit awards, upon a participant’s termination of employment, the participant’s outstanding awards will generally be forfeited.

Transferability

Awards under the 2009 Plan are generally not transferable except by will or the laws of descent and distribution or, other than with respect to incentive stock options or tandem SARs, pursuant to a domestic relations order or as otherwise expressly permitted by the Committee.

Amendment and Discontinuance

The 2009 Plan may be amended, suspended or terminated by the Atlas America board of directors, but no amendment, suspension or termination may be made if it would materially impair the rights of a participant without the participant’s consent or cause an award intended to qualify under Section 162(m)(4) to cease to qualify. The 2009 Plan may not be amended without stockholder approval to the extent such approval is required by law or agreement.

U.S. Federal Income Tax Consequences

The following discussion is intended only as a brief summary of the U.S. federal income tax rules that are generally relevant to stock options that may be granted under the 2009 Plan, based upon the U.S. federal tax laws currently in effect. The laws governing the tax aspects of awards are highly technical and such laws are subject to change. The discussion is general in nature and does not take into account a number of considerations which may apply in light of the circumstances of a particular participant under the 2009 Plan. The income tax consequences under applicable foreign, state or local tax laws may not be the same as under U.S. federal income tax laws.

Nonqualified Options

Upon the grant of a nonqualified option, the optionee will not recognize any taxable income and Atlas America will not be entitled to a deduction. Upon the exercise of such an option or related SAR, the excess of the fair market value of the shares acquired on the exercise of the option or SAR over the exercise price or the cash paid under an SAR (which we refer to as the “spread”) will constitute compensation taxable to the optionee as ordinary income. Atlas America, in computing its U.S. federal income tax, will generally be entitled to a deduction in an amount equal to the compensation taxable to the optionee, subject to the limitations of Code Section 162(m).

Incentive Stock Options

An optionee will not recognize taxable income on the grant or exercise of an incentive stock option. However, the spread at exercise will constitute an item includible in alternative minimum taxable income, and, thereby, may subject the optionee to the alternative minimum tax. Such alternative minimum tax may be payable even though the optionee receives no cash upon the exercise of the incentive stock option with which to pay such tax.

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Upon the disposition of shares of stock acquired pursuant to the exercise of an incentive stock option, after the later of (i) two years from the date of grant of the incentive stock option or (ii) one year after the transfer of the shares to the optionee (which we refer to as the “ISO Holding Period”), the optionee will recognize long-term capital gain or loss, as the case may be, measured by the difference between the stock’s selling price and the exercise price. Atlas America is not entitled to any tax deduction by reason of the grant or exercise of an incentive stock option, or by reason of a disposition of stock received upon exercise of an incentive stock option if the ISO Holding Period is satisfied. Different rules apply if the optionee disposes of the shares of stock acquired pursuant to the exercise of an incentive stock option before the expiration of the ISO Holding Period.

The foregoing general tax discussion is intended for the information of stockholders considering how to vote with respect to this proposal and not as tax guidance to participants in the 2009 Plan. Participants in the 2009 Plan are strongly urged to consult their own tax advisors regarding the federal, state, local, foreign and other tax consequences to them of participating in the 2009 Plan.

New Plan Benefits

The benefits or amounts to be received by Atlas America’s named executive officers, Atlas America’s executive officers as a group, Atlas America’s non-employee directors as a group and Atlas America’s non-executive officer employees as a group are not determinable. Atlas America currently expects to continue to make grants of deferred units having a grant-date value of $15,000 to each non-employee director under the 2009 Plan, if it is approved by stockholders, as described above, consistent with its past practices; however, the number of shares underlying such deferred units is not currently determinable, since the number will depend on the fair market value of a share of Atlas America common stock on the date of grant. Otherwise, the future benefits or awards that will be received by or allocated to any executive officers, employees or non-employee directors under the 2009 Plan are not currently determinable since no specific grants have been decided upon.

Vote Required; Recommendation of the Atlas America Board of Directors

The proposal for Atlas America stockholders to approve the Atlas America 2009 Stock Incentive Plan requires the affirmative vote of the holders of a majority of the shares of Atlas America common stock present in person or represented by proxy at the special meeting and entitled to vote thereon.

The Atlas America board of directors recommends that Atlas America stockholders vote FOR approval of the Atlas America 2009 Stock Incentive Plan.

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THE COMPANIES

Atlas Energy Resources, LLC

Atlas Energy Resources, LLC

Westpointe Corporate Center One

1550 Coraopolis Heights Road, 2^nd Floor

Moon Township, PA 15108

Atlas Energy is a publicly traded Delaware limited liability company. Atlas Energy is an independent developer and producer of natural gas and oil, with operations in the Appalachian Basin, where it focuses on the Marcellus Shale and other Devonian shales, in the Michigan Basin, where it focuses on northern Michigan’s Antrim Shale, and in the Illinois Basin, where it focuses on Indiana’s New Albany Shale. Atlas Energy’s major operations in the Appalachian Basin are located in eastern Ohio, western Pennsylvania, and north central Tennessee. Atlas Energy has additional operations and interests in New York, West Virginia and Kentucky. Atlas Energy’s focus is to increase its own reserves, production, and cash flows through a mix of generating new opportunities of geologic prospects, natural gas and oil exploitation and development, and sponsorship of investment partnerships. Atlas Energy generates both upfront and ongoing fees from the drilling, production, servicing, and administration of its wells in these partnerships.

Atlas Energy was formed in June 2006 to own and operate substantially all of the natural gas and oil assets and the investment partnership management business of Atlas America. Atlas Energy Management, Inc., a wholly owned subsidiary of Atlas America, owns 100% of the Atlas Energy Class A units and management incentive interests which give Atlas Energy Management certain control rights over Atlas Energy. Atlas Energy common units are traded on the NYSE under the symbol “ATN.”

Atlas Energy Management, Inc.

Atlas Energy Management, Inc.

Westpointe Corporate Center One

1550 Coraopolis Heights Road, 2^nd Floor

Moon Township, PA 15108

Atlas Energy Management, a direct wholly owned subsidiary of Atlas America, manages Atlas Energy, under the supervision of the Atlas Energy board of directors. Pursuant to a management agreement, dated as of December 18, 2006, among Atlas Energy, Atlas Energy Operating Company, LLC and Atlas Energy Management, Atlas Energy Management provides Atlas Energy with all services necessary or appropriate for the conduct of Atlas Energy’s business.

ATLS Merger Sub, LLC

ATLS Merger Sub, LLC

Westpointe Corporate Center One

1550 Coraopolis Heights Road, 2^nd Floor

Moon Township, PA 15108

Merger Sub, a direct wholly owned subsidiary of Atlas America, was formed solely for the purpose of consummating the merger. Merger Sub has not carried on any activities to date, except for activities incidental to its formation and activities undertaken in connection with the transactions contemplated by the merger agreement, including the merger.

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INFORMATION ABOUT ATLAS AMERICA

General

Atlas America is a publicly traded Delaware corporation whose assets currently consist principally of cash on hand and its ownership interests in the following entities:

• Atlas Energy — As of the date of this joint proxy statement/prospectus, Atlas America owns 29,952,996 Atlas Energy common units, representing approximately 47.3% of the outstanding Atlas Energy common units, as well as, indirectly, all of the Atlas Energy Class A units and management incentive interests. Atlas America manages Atlas Energy through Atlas America’s wholly owned subsidiary, Atlas Energy Management, under the supervision of the Atlas Energy board of directors.

• Atlas Pipeline — As of the date of this joint proxy statement/prospectus, Atlas America owns approximately 2.3% of the equity of Atlas Pipeline, a midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachia regions. The limited partnership interests of Atlas Pipeline are traded on the NYSE under the symbol “APL.”

• Atlas Pipeline Holdings — As of the date of this joint proxy statement/prospectus, Atlas America owns approximately 64.4% of the outstanding common units of Atlas Pipeline Holdings, which is a publicly traded Delaware limited partnership and owner of the general partner of Atlas Pipeline. Through Atlas America’s ownership of the general partner of Atlas Pipeline Holdings, Atlas America manages Atlas Pipeline Holdings. As of the date of this joint proxy statement/prospectus, Atlas Pipeline Holdings owns a 2% general partner interest, all of the incentive distribution rights, an approximate 11.8% limited partner interest, and 15,000 $1,000 par value 12.0% cumulative preferred limited partner units.

• Lightfoot Capital Partners LP (which we refer to as “Lightfoot LP”) and Lightfoot Capital Partners GP LLC (which we refer to as “Lightfoot GP”), the general partner of Lightfoot LP (which we collectively refer to as “Lightfoot”), entities which incubate new master limited partnerships (which we refer to as “MLPs”) and invest in existing MLPs. Atlas America 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. Atlas America also has direct and indirect ownership interests in Lightfoot LP.

Atlas America has been involved in the energy industry since 1968, expanding its operations in 1998 when it acquired The Atlas Group, Inc. and in 1999 when it acquired Viking Resources Corporation, both engaged in the development and production of natural gas and oil and the sponsorship of investment partnerships. Atlas America was originally incorporated in Delaware in September 2000 to become a holding company for Resource America, Inc.’s energy assets and subsidiaries. In May 2004, Atlas America completed an initial public offering of 2,645,000 shares of its common stock. After the initial public offering, Resource America, Inc. continued to own approximately 80.2% of Atlas America. In June 2005, Resource America, Inc. spun-off its remaining ownership interest in Atlas America to Resource America, Inc.’s common stockholders in the form of a tax-free dividend. Atlas America common stock is traded on NASDAQ under the symbol “ATLS.”

Atlas America’s ownership of Atlas Energy Class A units entitles it to receive 2% of the cash distributed by Atlas Energy without any obligation to make future capital contributions to Atlas Energy. Atlas America’s ownership of Atlas Energy’s management incentive interests entitles it to receive an increasing percentage of cash distributed by Atlas Energy as it reaches certain target distribution levels after Atlas Energy has met the tests set forth within the Atlas Energy operating agreement. The rights entitle Atlas America to receive 15.0% of all cash distributed in a quarter after each Atlas Energy common unit has received $0.48 for that quarter, and 25.0% of all cash distributed after each Atlas Energy common unit has received $0.59 for that quarter. As set forth in Atlas Energy’s limited liability company agreement, for Atlas America to receive distributions from Atlas Energy under the management incentive interests, Atlas Energy must:

• for 12 full, consecutive, non-overlapping calendar quarters, (a) pay a quarterly cash distribution to the outstanding Atlas Energy Class A and common units in an amount that, on average exceeds $0.48 per

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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 Atlas Energy 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 Atlas Energy 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.

Effective April 27, 2009, Atlas Energy suspended further distributions pursuant to the merger agreement. Atlas Energy’s suspension of the quarterly distribution for the six months ended June 30, 2009 means that it will not comply with the terms of the 12 quarter test and, as such, Atlas Energy Management will not receive the management incentive distributions that were reserved for during previous periods.

Atlas America’s ownership interest in Atlas Pipeline consists of 1,112,000 common units, representing approximately 2.3% of the outstanding common units of Atlas Pipeline at June 30, 2009, or a 2.3% ownership interest.

Atlas America’s ownership interest in Atlas Pipeline Holdings consists of 17,808,109 common units, representing approximately 64.4% of the outstanding common units of Atlas Pipeline Holdings at June 30, 2009. Atlas Pipeline Holdings’ general partner, which is a wholly owned subsidiary of Atlas America, does not have an economic interest in Atlas Pipeline Holdings, and Atlas Pipeline Holdings’ capital structure does not include incentive distribution rights. Atlas Pipeline Holdings’ ownership interest in Atlas Pipeline consists of the following:

• a 2.0% general partner interest, which entitles it to receive 2% of the cash distributed by Atlas Pipeline;

• 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 Atlas Pipeline as it reaches certain target distribution levels in excess of $0.42 per Atlas Pipeline common unit in any quarter. In connection with Atlas Pipeline’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see “Information About Atlas America — Atlas Pipeline Holdings and Atlas Pipeline — General” below), Atlas Pipeline Holdings, the holder of all of the incentive distribution rights in Atlas Pipeline, had agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to Atlas Pipeline through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter;

• 5,754,253 common units, representing approximately 12.1% of the outstanding common units at June 30, 2009, or a 11.8% ownership interest in Atlas Pipeline; and

• 15,000 $1,000 par value 12.0% cumulative preferred limited partner units at June 30, 2009.

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

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

• 23.0% of all cash distributed after each Atlas Pipeline common unit has received $0.52 for that quarter; and

• 48.0% of all cash distributed after each Atlas Pipeline common unit has received $0.60 for that quarter.

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The recent amendment to Atlas Pipeline’s credit agreement restricts Atlas Pipeline from paying distributions for the remainder of 2009 and permits distributions commencing with the quarter ending March 31, 2010 only if, on a pro forma basis after such payment, Atlas Pipeline’s senior secured leverage ratio is less than or equal to 2.75 to 1.00 and its minimum liquidity, defined generally as cash and cash equivalents less restricted cash plus amounts available for borrowing under the revolver portion of the credit facility, is at least $50 million. In addition, Atlas Pipeline Holdings is restricted under its credit agreement from paying distributions until it repays in full the indebtedness under the credit facility.

Atlas Energy

General

In December 2006, Atlas America contributed substantially all of its natural gas and oil assets and its investment partnership management business to Atlas Energy, a then wholly owned subsidiary. Concurrent with this transaction, Atlas Energy issued 7,273,750 common units, representing a 19.4% ownership interest 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 Atlas America.

Atlas Energy is a publicly traded Delaware limited liability company. Atlas Energy is an independent developer and producer of natural gas and oil, with operations in the Appalachian Basin, where it focuses on the Marcellus Shale and other Devonian shales, in the Michigan Basin, where it focuses on northern Michigan’s Antrim Shale, and in the Illinois Basin, where it focuses on Indiana’s New Albany Shale. Atlas Energy’s major operations in the Appalachian Basin are located in eastern Ohio, western Pennsylvania, and north central Tennessee. Atlas Energy has additional operations and interests in New York, West Virginia and Kentucky. Atlas Energy’s focus is to increase its own reserves, production, and cash flows through a mix of generating new opportunities of geologic prospects, natural gas and oil exploitation and development, and sponsorship of investment partnerships. Atlas Energy generates both upfront and ongoing fees from the drilling, production, servicing, and administration of its wells in these partnerships.

As of June 30, 2009, Atlas Energy had the following key assets:

Appalachia gas and oil operations

• direct and indirect working interests in approximately 8,631 gross productive gas and oil wells;

• overriding royalty interests in approximately 629 gross productive gas and oil wells;

• net daily production of 42.9 million cubic feet equivalents per day (which we refer to as “MMcfed”) for the six months ended June 30, 2009; and

• approximately 935,300 gross (889,700 net) acres, of which approximately 623,300 gross (616,400 net) acres are undeveloped. Included in the undeveloped acreage is 531,950 Marcellus Shale acres in Pennsylvania, New York and West Virginia, of which approximately 266,100 acres are located in Atlas Energy’s core Marcellus Shale position in southwestern Pennsylvania.

Michigan gas and oil operations

• direct and indirect working interests in approximately 2,488 gross producing gas and oil wells;

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

• net daily production of 58.0 MMcfed for the six months ended June 30, 2009; and

• approximately 344,400 gross (272,200 net) acres, of which approximately 35,800 gross (28,100 net) acres are undeveloped.

Indiana gas and oil operations

• direct and indirect working interests in approximately 16 gross producing gas and oil wells;

• net daily production of 0.2 MMcfed for the six months ended June 30, 2009; and

• approximately 244,100 gross (118,200 net) acres, of which approximately 239,100 gross (114,400 net) acres, are undeveloped.

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Partnership management business

• Atlas Energy investment partnership business, which includes equity interests in 95 investment partnerships and a registered broker-dealer which acts as the dealer-manager of Atlas Energy’s investment partnership offerings.

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

Geographic and Geologic Overview

Marcellus Shale Overview

In the fourth quarter of 2006, Atlas Energy 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 Atlas Energy’s acreage in western Pennsylvania. As of June 30, 2009, Atlas Energy controlled approximately 531,950 Marcellus Shale acres in Pennsylvania, New York and West Virginia, and it continues to expand its position. As of that date, Atlas Energy had drilled 153 vertical wells and 10 horizontal wells. Atlas Energy is currently focused on approximately 266,100 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 Atlas Energy’s or Laurel Mountain’s gas gathering infrastructure.

Atlas Energy has recently made great strides in optimizing its completion practices for vertical Marcellus Shale wells. Atlas Energy 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 December 31, 2008, Wright & Company, Inc., Atlas Energy’s independent petroleum engineering consultants assigned an average EUR of 1.423 Bcf per well. As of December 31, 2008, Atlas Energy had 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 Atlas Energy’s primary delivery points in the Appalachian Basin was $0.24 per MMBtu. In addition, Atlas Energy’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 Atlas Energy’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 6% over normal pipeline quality gas in 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

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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 Atlas Energy’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 Atlas Energy’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 Atlas Energy 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. Atlas Energy increased its production volumes for the year ended December 31, 2008 by 59% over prior year

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levels to a record 34.9 Mmcfe. The following table shows Atlas Energy’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	29,664		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)	95,233	89,425		26,989

(1) 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 the 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 it has an interest, based on the equity interest in each such partnership and based on each partnership’s proportionate net revenue interest in these wells.

(2) Appalachia includes Atlas Energy’s production located in Pennsylvania, Ohio, New York, West Virginia, and Tennessee.

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

Investment Partnerships

Atlas Energy 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 Atlas Energy undertakes depends in part upon its ability to obtain investor subscriptions to the partnerships. Atlas Energy 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, Atlas Energy’s investment partnerships are a source of fee-based revenues, which are not directly dependent on natural gas and oil prices. Atlas Energy 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. Atlas Energy also receives an additional interest in each partnership, typically 7% to 10%, for which Atlas Energy does not make any additional capital contribution, for a total interest in its partnerships ranging from 27% to 40%.

During the last three years, Atlas Energy 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 Atlas Energy’s drilling contracts with the programs. Atlas Energy recognizes revenues from drilling operations on the percentage-of-completion method as the wells are drilled, rather than when funds

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are received. Atlas Energy’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		Atlas Energy Contributions		Total Capital
2008	$	438.4	$	146.3	$	584.7
2007		363.3		137.6		500.9
2006		218.5		73.6		292.1
Total	$	1,020.2	$	357.5	$	1,377.7

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 Atlas Energy drilled for itself and its investment partnerships during the last three years. Atlas Energy did not drill any exploratory wells during the years ended December 31, 2008, 2007 and 2006.

Years Ended December 31,	Gross	Net(1)	Atlas Energy 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) Atlas Energy’s percentage interest in wells in which it has a direct ownership interest and (ii) Atlas Energy’s percentage interest in the wells based on its percentage interest in its investment partnerships.

Atlas Energy 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 Atlas Energy’s Appalachian and Michigan properties enable it to drill most of its vertical wells in seven to ten days, although Atlas Energy usually defers completion operations until Atlas Pipeline’s gathering lines are in place. Atlas Energy 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, Atlas Energy receives the following fees:

• Well construction and completion. For each well that is drilled by an investment partnership, Atlas Energy receives an 18% mark-up on those costs incurred to drill and complete the well.

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• Administration and oversight. For each well drilled by an investment partnership, Atlas Energy receives a fixed fee of approximately $15,700 for non-Marcellus Shale wells and $62,241 for Marcellus Shale wells. Additionally, the partnership pays Atlas Energy a monthly per well administrative fee of $75 for the life of the well. Because Atlas Energy coinvests in the partnerships, the net fee that it receives is reduced by its proportionate interest in the well.

• Well services. Each partnership pays Atlas Energy a monthly per well operating fee, currently $100 to $1,500, for the life of the well. Because Atlas Energy coinvests in the partnerships, the net fee that Atlas Energy receives is reduced by its proportionate interest in the well.

Atlas Energy 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. Atlas Energy has subordinated $0.9 million and $0.1 million of its share of revenues from its investment partnerships for the six months ended June 30, 2009 and fiscal 2005, respectively. Atlas Energy does not believe any amounts which may be subordinated in the future will be material to Atlas Energy’s operations.

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

In almost all of the areas Atlas Energy operates in the Appalachian Basin, Michigan and Indiana, the surface owner is normally the natural gas and oil owner allowing Atlas Energy 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, Atlas Energy may elect to farm-in leases and/or purchase leases from other natural gas and oil operators. Typically the assignor of such leases will reserve an overriding royalty interest, ranging in the Appalachian Basin from 1/32^nd to 1/16^th (3.125% to 6.25%), which further reduces the net revenue interest available to Atlas Energy 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 Atlas Energy to between 80.0% and 78.0%.

The interests in some of Atlas Energy’s 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 Atlas Energy for a retained working interest of up to 50% of the wells drilled on the covered acreage. In this event, Atlas Energy’s working

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interest ownership will be reduced by the amount retained by the third party. In all other instances, Atlas Energy anticipates owning a 100% working interest in newly drilled wells.

Contractual Revenue Arrangements

Appalachia Natural Gas

Based on the most recent monthly production data available to Atlas Energy as of December 31, 2008, Atlas Energy anticipates that it and its affiliates, including its investment partnerships, will sell approximately 16% of their Appalachian natural gas production during the year ended December 31, 2009 to Hess. Atlas Energy markets the remainder of its natural gas, which is principally located in the Fayette County, PA area, to Colonial Energy, Inc., UGI Energy Services and others. During the year ended December 31, 2008, Atlas Energy 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 Atlas Energy’s Appalachian operations.

Atlas Energy expects that natural gas produced from Atlas Energy’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, Atlas Energy has natural gas sales agreements with DTE Energy, which are valid through December 31, 2012. DTE Energy has the obligation to purchase all of the natural gas produced and delivered by Atlas Energy and its affiliates from specific projects at certain delivery points with the facilities of:

• Merit Plant/Michigan Consolidated Gas Company (which we refer to as “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 Atlas Energy as of December 31, 2008, Atlas Energy anticipates that Atlas Energy and its affiliates will sell approximately 49% of their Michigan natural gas production during the year ending December 31, 2009 under the DTE Energy agreements in most cases at NYMEX pricing. During the year ended December 31, 2008, Atlas Energy’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 Atlas Energy’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. Atlas Energy 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

Atlas Energy 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

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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, Atlas Energy has a management committee to assure that all financial trading is done in compliance with its hedging policies and procedures. Atlas Energy does not intend to contract for positions that it cannot offset with actual production.

Hess and other third-party marketers to which Atlas Energy 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 Atlas Energy 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. Atlas Energy 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. 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 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. Atlas Energy’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 Atlas Energy’s 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 Atlas Energy’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 Atlas Energy does. Moreover, Atlas Energy also competes with a number of other companies that offer interests in investment partnerships. As a result, competition for investment capital to fund investment partnerships is intense.

Atlas Pipeline Holdings and Atlas Pipeline

General

In July 2006, Atlas America contributed its ownership interests in Atlas Pipeline GP, the general partner of Atlas Pipeline, to Atlas Pipeline Holdings. Concurrent with this transaction, Atlas Pipeline Holdings 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 Atlas America. Atlas Pipeline Holdings’ cash generating assets currently consist solely of its interests in Atlas Pipeline.

Atlas Pipeline is a publicly traded midstream energy services provider engaged in the transmission, gathering and processing of natural gas. Atlas Pipeline is a leading provider of natural gas gathering services in the Anadarko 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, Atlas Pipeline is a leading provider of natural gas processing and treatment services in Oklahoma and Texas. Atlas Pipeline conducts its business through two operating segments: its Mid-Continent operations and its Appalachian operations.

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Through its Mid-Continent operations, as of June 30, 2009, Atlas Pipeline owned and operated:

• eight natural gas processing plants with aggregate capacity of approximately 810 million cubic feet per day (which we refer to as “MMcfd”) and one treating facility with a capacity of approximately 200 MMcfd, located in Oklahoma and Texas; and

• 8,750 miles of active natural gas gathering systems located in Oklahoma, Kansas and Texas, which transport gas from wells and central delivery points in the Mid-Continent region to Atlas Pipeline’s natural gas processing and treating plants or third-party pipelines.

As of June 30, 2009, Atlas Pipeline’s Appalachia operations are conducted principally through its 49% ownership interest in Laurel Mountain Midstream, LLC (“Laurel Mountain”), a joint venture which owns and operates a 1,700 mile natural gas gathering system in the Appalachia Basin located in eastern Ohio, western New York, and western Pennsylvania. On June 1, 2009, Atlas Pipeline contributed its Appalachia System to Laurel Mountain in return for net proceeds of $87.8 million in cash, preferred distribution rights entitling Atlas Pipeline to receive payments under a $25.5 million note and a 49% ownership interest in Laurel Mountain. Williams holds a 51% interest in Laurel Mountain and is its operating member, responsible for day-to-day management. In connection with Atlas Pipeline’s disposition of the Appalachia System, Laurel Mountain entered into natural gas gathering agreements with Atlas Energy and certain of its subsidiaries which superseded the master natural gas gathering agreement and omnibus agreement. Under these agreements, Atlas Energy will dedicate its natural gas production in the Appalachian Basin to Laurel Mountain for transportation to interstate pipeline systems, local distribution companies, and/or end users in the area, subject to certain exceptions. In return, Laurel Mountain is required to accept and transport Atlas Energy’s dedicated natural gas in the Appalachian Basin subject to certain conditions. Atlas Pipeline also owns a 65-mile natural gas gathering system in northeastern Tennessee. Laurel Mountain gathers the majority of the natural gas from wells operated by Atlas Energy.

Since Atlas Pipeline’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, Atlas Pipeline 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 (which we refer to as the “Anadarko Assets”). The transaction was effected by the formation of two joint venture companies which own the respective systems, to which Atlas Pipeline contributed $1.9 billion and Anadarko contributed the Anadarko Assets. Atlas Pipeline 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, Atlas Pipeline Holdings purchased $168.8 million of these Atlas Pipeline 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. Atlas Pipeline Holdings, as general partner and holder all of Atlas Pipeline’s incentive distribution rights, also agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to Atlas Pipeline through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. Atlas Pipeline Holdings also agreed that the resulting allocation of incentive distribution rights back to Atlas Pipeline would be after Atlas Pipeline Holdings 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 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, Atlas Pipeline reached an agreement with Pioneer Natural Resources Company (which we refer to as “Pioneer”), 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,

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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. Atlas Pipeline will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercises the purchase options.

Both Atlas Pipeline’s Mid-Continent and Appalachian operations are located in areas of abundant and long-lived natural gas production and significant new drilling activity. Atlas Pipeline provides gathering and processing services to the wells connected to its systems, primarily under long-term contracts. Atlas Pipeline 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 Atlas Pipeline’s Velma service area, is not suitable for long-haul pipeline transmission or commercial use and must be compressed, transported via pipeline to a central processing facility, and then processed to remove the heavier hydrocarbon components such as NGLs and other contaminants that would interfere with pipeline transmission or the end use of the natural gas. Natural gas processing plants generally treat (remove carbon dioxide and hydrogen sulfide) and remove the NGLs, enabling the treated, “dry” gas (stripped of liquids) to meet pipeline specification for long-haul transport to end users. After being separated from natural gas at the processing plant, the mixed NGL stream, commonly referred to as “y-grade” or “raw mix,” is typically transported on pipelines to a centralized facility for fractionation into discrete NGL purity products: ethane, propane, normal butane, isobutane, and natural gasoline.

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

Contracts and Customer Relationships

Atlas Pipeline’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 Atlas Pipeline 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 Atlas Pipeline 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.

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In the Appalachian region, substantially all of the natural gas Laurel Mountain transports is for Atlas Energy under POP contracts, as described below, in which Laurel Mountain 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 Atlas Pipeline’s inception in January 2000, its Appalachia System transportation fee has generally exceeded this minimum. The balance of the Appalachia System natural gas Laurel Mountain transports is for third-party operators generally under fixed-fee contracts.

Atlas Pipeline’s Mid-Continent segment revenue consists of the fees earned from its transmission, gathering and processing operations. Under certain agreements, Atlas Pipeline 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, Atlas Pipeline transports natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas. In connection with Atlas Pipeline’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. Atlas Pipeline’s revenue is a function of the volume of natural gas that it gathers and processes and is not directly dependent on the value of the natural gas.

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

Keep-Whole Contracts. These contracts require Atlas Pipeline, as the processor, to purchase raw natural gas from the producer at current market rates. Therefore, Atlas Pipeline bears the economic risk (which we refer to as 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 Atlas Pipeline’s keep-whole contracts is minimized.

Atlas Pipeline’s Mid-Continent Operations

Atlas Pipeline owns approximately 9,550 miles of intrastate natural gas gathering systems, including approximately 800 miles of inactive pipeline, located in Oklahoma, Kansas, northern and western Texas and the Texas panhandle, and eight processing plants and one stand-alone treating facility in Oklahoma and Texas. Atlas Pipeline’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 Permian Basin and the Golden Trend area of Oklahoma. Atlas Pipeline’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, Atlas Pipeline’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. Atlas Pipeline’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.

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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.

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 Atlas Pipeline 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 Atlas Pipeline 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 Atlas Pipeline acquired control of the Midkiff/Benedum system in July 2007, Atlas Pipeline 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, Atlas Pipeline 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.

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,

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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. Atlas Pipeline’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. Atlas Pipeline sells natural gas to purchasers at the tailgate of the Velma plant and sells NGL production to ONEOK Hydrocarbon. Atlas Pipeline 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 Atlas Pipeline’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. Atlas Pipeline 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. Atlas Pipeline 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, Atlas Pipeline believes that the Sweetwater plant is capable of recovering more NGLs than a lean oil processing plant. During July 2008, Atlas Pipeline completed a 60 MMcfd expansion of the Sweetwater plant to a total processing capacity of 180 MMcfd. Through this expansion, Atlas Pipeline 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, Atlas Pipeline 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 Atlas Pipeline’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.

Atlas Pipeline has enjoyed long-term relationships with the majority of its Mid-Continent producers. For instance, on the Velma system, where Atlas Pipeline 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 Atlas Pipeline’s gathering systems have evergreen term extensions.

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Natural Gas and NGL Marketing

Atlas Pipeline 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.

Atlas Pipeline sells its NGL production to ONEOK Hydrocarbon under four separate agreements. The Velma agreement has an initial term expiring February 1, 2011, the Elk City/Sweetwater agreement has an initial term expiring 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 Atlas Pipeline’s 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

Atlas Pipeline’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. Atlas Pipeline 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.

Atlas Pipeline (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 Atlas Pipeline to a generally neutral price risk (long sales approximate short purchases), while scenario (c) does not expose Atlas Pipeline to any price risk; in both scenarios, risk management is not required. Scenario (a) does involve commodity risk.

Atlas Pipeline 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 Atlas Pipeline’s contractual relationships with natural gas producers, or, alternatively, a function of cost of sales. Atlas Pipeline 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 Atlas Pipeline to pay a percentage of revenue to the producer. This results in Atlas Pipeline being net long physical natural gas and NGLs.

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• Keep-whole: requires Atlas Pipeline 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 Atlas Pipeline. This results in Atlas Pipeline being long physical NGLs and short physical natural gas.

Atlas Pipeline 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.

Atlas Pipeline 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 Atlas Pipeline sell the physical residue natural gas or NGLs. Atlas Pipeline 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, Atlas Pipeline has established a committee to review its derivative instruments for compliance with its policies and procedures.

For additional information on Atlas Pipeline’s derivative activities and a summary of Atlas Pipeline’s outstanding derivative instruments as of June 30, 2009, please see, “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Atlas America — Quantitative and Qualitative Disclosures About Market Risk” below.

Atlas Pipeline’s Appalachian Basin Operations

Atlas Pipeline and its affiliates, including Laurel Mountain, own and operate approximately 1,835 miles of intrastate gas gathering systems located in eastern Ohio, western New York, western Pennsylvania and northern West Virginia. The Appalachian operations of Atlas Pipeline and its affiliates, including Laurel Mountain, serve approximately 7,440 wells with an average throughput of 107.4 MMcfd of natural gas for the six months ended June 30, 2009. Laurel Mountain’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, the Appalachian operations’ gathering systems transport natural gas directly to customers. The Appalachian operations’ 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. The Appalachian operations’ 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 the Appalachian operations transport in the Appalachian Basin is derived from wells operated by Atlas Energy. Atlas Pipeline and its affiliates, including Laurel Mountain, are party to gathering agreements with Atlas Energy and certain of its subsidiaries that are intended to maximize the use and expansion of the Appalachian operations’ gathering systems and the amount of natural gas which they transport in the region.

Appalachian Basin Overview

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

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Natural Gas Supply

From the inception of Atlas Pipeline’s operations in January 2000 through December 31, 2008, Atlas Pipeline 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, Atlas Pipeline connected 741 wells to its gathering system. As discussed above, Atlas Pipeline contributed its Appalachia System to Laurel Mountain in June 2009. Laurel Mountain’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 Atlas Energy and connected to Laurel Mountain’s gathering systems and by Laurel Mountain’s ability to acquire additional gathering assets.

Natural Gas Revenue

The revenue of Atlas Pipeline and its affiliates, including Laurel Mountain, is determined primarily by the amount of natural gas flowing through its gathering systems and the price received for this natural gas. Atlas Pipeline and Laurel Mountain have agreements with Atlas Energy under which Atlas Energy pays both parties gathering fees generally equal to a percentage, typically 16%, of the gross weighted average sales price of the natural gas transported subject, in most cases, to minimum prices of $0.35 or $0.40 per Mcf. For the year ended December 31, 2008, Atlas Pipeline received gathering fees averaging $1.40 per Mcf. Atlas Pipeline and Laurel Mountain charge other operators fees negotiated at the time they connect their wells to the gathering systems or, in a pipeline acquisition, that were established by the entity from which Atlas Pipeline or Laurel Mountain acquired the pipeline.

Because Atlas Pipeline and Laurel Mountain do not buy or sell gas in connection with their Appalachian operations, Atlas Pipeline and Laurel Mountain do not engage in hedging. Atlas Energy maintains a hedging program. Since Atlas Pipeline and Laurel Mountain receive transportation fees from Atlas Energy generally based on the selling price received by Atlas Energy inclusive of the effects of financial and physical hedging, these financial and physical hedges mitigate the risk of Atlas Pipeline’s and Laurel Mountain’s percentage-of-proceeds arrangements.

Competition

Acquisitions

Atlas Pipeline has encountered competition in acquiring midstream assets owned by third parties. In several instances, Atlas Pipeline 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, Atlas Pipeline 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 Atlas Pipeline’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, Copano 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. Atlas Pipeline 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.

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

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Appalachian Basin

Atlas Pipeline’s Appalachia 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 the Appalachia operations principally serve wells drilled by Atlas Energy, Atlas Pipeline’s Appalachia operations are affected by competitive factors affecting Atlas Energy’s ability to obtain properties and drill wells, which affects Atlas Pipeline’s Appalachia operations ability to expand their gathering systems and to maintain or increase the volume of natural gas they transport and, thus, their 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 Atlas Pipeline’s Appalachia operations gathering systems. These delays would reduce the volume of natural gas Atlas Pipeline’s Appalachia operations otherwise would have transported, thus reducing Atlas Pipeline’s Appalachia operations’ potential transportation revenues.

In connection with Atlas Pipeline’s disposition of the Appalachia System, Laurel Mountain entered into natural gas gathering agreements with Atlas Energy and certain of its subsidiaries that superseded the master natural gas gathering agreement and omnibus agreement. Under these agreements, Atlas Energy will dedicate its natural gas production in an agreed area of mutual interest in the Appalachian Basin to Laurel Mountain for transportation to interstate pipeline systems, local distribution companies, and/or end users in the area, subject to certain exceptions. In return, Laurel Mountain is required to accept and transport Atlas Energy’s dedicated natural gas in the agreed Appalachian Basin areas, subject to certain conditions.

Atlas America’s Relationship with Atlas Energy, Atlas Pipeline Holdings and Atlas Pipeline

Atlas Energy Contribution Agreement

The substantial majority of the assets Atlas Energy owns were held, directly or indirectly, by Atlas America and its subsidiaries. In connection with Atlas Energy’s initial public offering, Atlas America entered into a contribution agreement pursuant to which Atlas America contributed to Atlas Energy all of the stock of Atlas America’s natural gas and oil development and production subsidiaries as well as the development and production assets owned by Atlas America. As consideration for this contribution, Atlas Energy distributed to Atlas America the net proceeds Atlas Energy received from that offering, as well as 29,352,996 Atlas Energy common units, the Class A units and the management incentive interests. As part of the contribution agreement, Atlas America has agreed to indemnify Atlas Energy for losses attributable to title defects to Atlas Energy’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, Atlas Energy has agreed to indemnify Atlas America for all losses attributable to the post-closing operations of the assets contributed to Atlas Energy, to the extent not subject to its indemnification obligations.

Management Agreement between Atlas Energy Management and Atlas Energy

Upon completion of the Atlas Energy initial public offering, Atlas America’s subsidiary, Atlas Energy Management, entered into a management agreement with Atlas Energy pursuant to which Atlas Energy Management manages Atlas Energy’s business affairs under the supervision of the Atlas Energy board of directors. Atlas Energy Management provides 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 must reimburse Atlas Energy Management for all expenses that it incurs on Atlas Energy’s behalf pursuant to the management agreement. These expenses include costs for providing corporate staff and support services to Atlas Energy. Atlas Energy Management charges 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

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such persons and their allocated overhead. The allocation of compensation expense for such persons is 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 are not be liable to Atlas Energy, any subsidiary of Atlas Energy, Atlas Energy’s directors or Atlas Energy unitholders for acts or omissions performed in good faith and in accordance with and pursuant to the management agreement, except by reason of acts constituting gross negligence, bad faith, willful misconduct, fraud or a knowing violation of criminal law. Atlas Energy will indemnify Atlas Energy Management, its stockholders, directors, officers, employees and affiliates with respect to all expenses, losses, damages, liabilities, demands, charges and claims arising from acts of Atlas Energy Management, its stockholders, directors, officers, employees and affiliates not constituting gross negligence, bad faith, willful misconduct, fraud or a knowing violation of criminal law performed in good faith in accordance with and pursuant to the management agreement. Atlas Energy Management and its affiliates will indemnify Atlas Energy and Atlas Energy’s directors and officers with respect to all expenses, losses, damages, liabilities, demands, charges and claims arising from acts of Atlas Energy Management or its affiliates constituting gross negligence, bad faith, willful misconduct, fraud or a knowing violation of criminal law or any claims by employees of Atlas Energy Management or its affiliates relating to the terms and conditions of their employment. Atlas Energy Management and/or Atlas America will carry errors and omissions and other customary insurance.

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

The management agreement does not have a specific term; however, Atlas Energy Management may not terminate the agreement before December 18, 2016. Atlas Energy may terminate the management agreement only upon the affirmative vote of holders of at least two-thirds of its outstanding common units, including units held by Atlas America. 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.

Atlas America’s Guaranty of Atlas Pipeline Holdings’ Revolving Credit Facility

On June 1, 2009, Atlas Pipeline Holdings entered into an amendment to its revolving credit facility, dated as of July 26, 2006, with Wachovia Bank, National Association, as administrative agent, and the lenders thereunder. In connection with the execution of the amendment, Atlas Pipeline Holdings agreed to immediately repay $30 million of the approximately $46 million outstanding indebtedness under the credit facility, such that approximately $16 million currently remains outstanding. The amendment also terminated Atlas Pipeline Holdings’ right to make further borrowings under the credit facility. Atlas Pipeline Holdings agreed to repay $4 million of the remaining $16 million on each of July 13, 2009, October 13, 2009 and January 13, 2010, with the balance of indebtedness being due on the original maturity date of April 13, 2010. In connection with the execution of this amendment, Atlas America agreed to guarantee the remaining debt outstanding under the credit facility. Pursuant to this guaranty, Atlas America made a $4 million payment in respect of a payment due on July 13, 2009 under the Atlas Pipeline Holdings credit agreement.

Atlas Pipeline Holdings’ $30 million repayment was funded from the proceeds of (i) a loan from Atlas America in the amount of $15 million, with an interest rate of 12% per annum and a maturity date the day following the day Atlas Pipeline Holdings pays all outstanding indebtedness due under the credit facility, and (ii) the purchase by Atlas Pipeline of $15 million of preferred equity in a newly formed subsidiary of Atlas Pipeline Holdings. Moreover, in consideration of Atlas America’s guaranty, Atlas Pipeline Holdings issued to Atlas America an additional promissory note, in which the amount payable under the note equals the interest that

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would be payable on a loan with a principal amount equal to the outstanding indebtedness under Atlas Pipeline Holdings’ credit facility, where the interest rate equals 3.75% per annum and accrues quarterly. The maturity date on this note is the day following the day Atlas Pipeline Holdings pays all outstanding indebtedness due under the credit facility. Both promissory notes issued by Atlas Pipeline Holdings to Atlas America are payable-in-kind until their maturity date.

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 (formerly First Energy Solutions Corp.) accounted for 10%, 10% and 18%, respectively, of Atlas Energy’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 Energy accounted for 49% and 46% of Atlas Energy’s Michigan oil and gas production revenues, respectively. No other single customer accounted for more than 10% of Atlas Energy’s total revenues during these periods.

Substantially all of Laurel Mountain’s operating system revenues currently consist of the fees it receives under gathering 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 Atlas Pipeline’s Mid-Continent systems with a majority of their natural gas supply. For the year ended December 31, 2008, there were three Atlas Pipeline 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

Atlas Energy’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. Atlas Energy’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;

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• 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 Atlas Energy’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 Atlas Energy’s operating costs. Atlas America believes that Atlas Energy’s operations on the whole substantially comply with all currently applicable environmental laws and regulations and that Atlas Energy’s continued compliance with existing requirements will not have a material adverse impact on Atlas America’s financial condition and results of operations. However, Atlas America cannot predict how environmental laws and regulations that may take effect in the future may impact Atlas Energy’s properties or operations. For the three years ended December 31, 2008, Atlas Energy did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of Atlas Energy’s facilities. Atlas America is 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 its 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, Atlas Pipeline must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact Atlas Pipeline’s business activities in many ways, such as:

• restricting the way Atlas Pipeline 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 Atlas Pipeline’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.

Atlas America believes that Atlas Pipeline’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

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expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts currently anticipated. Moreover, Atlas America 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 Atlas Pipeline to incur significant costs. For the three years ended December 31, 2008, Atlas Pipeline did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of its facilities or systems. Atlas America is 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 its 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 (which we refer to as “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 Atlas Energy’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 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 Environmental Protection Agency (which we refer to as 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.

Atlas America believes that Atlas Energy’s and Atlas Pipeline’s operations are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that Atlas Energy and Atlas Pipeline hold 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 Atlas America does not believe the current costs of managing Atlas Energy’s and Atlas Pipeline’s wastes to be significant, any more stringent regulation of natural gas and oil exploitation and production wastes could increase Atlas Energy’s and Atlas Pipeline’s costs to manage and dispose of such wastes.

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Comprehensive Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act, 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.

Atlas Energy’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 Atlas America believes that Atlas Energy 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 Atlas Energy 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 Atlas Energy’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, Atlas Energy 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.

Atlas Pipeline 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 Atlas Pipeline 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 Atlas Pipeline 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 Atlas Pipeline. 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 Atlas Pipeline’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, Atlas Pipeline 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. Atlas America believes that Atlas Energy’s and Atlas Pipeline’s operations on the whole are in substantial compliance with the requirements of the Clean Water Act.

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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 Atlas Energy’s and Atlas Pipeline’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 Atlas Energy’s or Atlas Pipeline’s customers to the point where demand for natural gas is affected. Atlas Pipeline 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. Atlas America believes, however, that Atlas Pipeline’s operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to Atlas Pipeline than to any other similarly situated companies. Atlas America believes that Atlas Energy’s and Atlas Pipeline’s operations are in substantial compliance with the requirements of the Clean Air Act.

OSHA and Other Regulations

Atlas Energy and Atlas Pipeline 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 Atlas Energy and Atlas Pipeline organize and/or disclose information about hazardous materials used or produced in their operations. Atlas America believes that Atlas Energy and Atlas Pipeline 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 Atlas Energy’s and Atlas Pipeline’s future operations. Atlas Energy’s and Atlas Pipeline’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 Atlas Energy’s and Atlas Pipeline’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 Atlas Energy’s and Atlas Pipeline’s cost of doing business and, consequently, affects Atlas Energy’s and Atlas Pipeline’s profitability, these burdens generally do not affect Atlas Energy and Atlas Pipeline 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.

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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. Atlas Energy’s and Atlas Pipeline’s operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs Atlas Energy and Atlas Pipeline 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 Atlas Pipeline’s Velma gas plant contains high levels of hydrogen sulfide, and Atlas Pipeline 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 Atlas Pipeline is in substantial compliance with all such requirements.

Drilling and Production

Atlas Energy’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 Atlas Energy 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 Atlas Energy’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 Atlas Energy can produce from its wells or limit the number of wells or the locations at which Atlas Energy 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 Atlas Energy’s wells, and to limit the number of wells or locations Atlas Energy can drill.

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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. Atlas America does not believe that compliance with these laws will have a material adverse effect upon its stockholders.

Pipeline Safety

Atlas Pipeline’s pipelines are subject to regulation by the U.S. Department of Transportation under the Natural Gas Pipeline Safety Act of 1968, as amended (which we refer to as 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. Atlas America believes that Atlas Pipeline’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 Atlas Pipeline’s operations but there is no assurance that this will continue in the future.

Gathering Pipeline Regulation

Section 1(b) of the Natural Gas Act exempts natural gas gathering facilities from the jurisdiction of the FERC. Atlas Pipeline owns a number of intrastate natural gas pipelines in Kansas, Oklahoma and Texas and Laurel Mountain owns intrastate natural gas pipelines in New York, Ohio and Pennsylvania that Atlas Pipeline 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 Atlas Pipeline’s or Laurel Mountain’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. Laurel Mountain’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. Laurel Mountain’s gas gathering operations currently are not subject to regulation by the New York Public Service Commission. Laurel Mountain’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. In the event the Ohio, New York or Pennsylvania authorities seek to regulate Atlas Pipeline’s or Laurel Mountain’s operations, Atlas Pipeline

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believes that its operating costs could increase and its transportation fees could be adversely affected, thereby reducing Atlas Pipeline’s net revenues and ability to fund its operations, pay required debt service on its credit facilities and make distributions to Atlas America, as general partner, and its common unitholders.

Nonetheless, Atlas Pipeline 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, Atlas Pipeline’s revenues could decrease. Collectively, any of these laws may restrict Atlas Pipeline’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. Atlas Pipeline’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.

Atlas Pipeline’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. Atlas America cannot predict what effect, if any, such changes might have on Atlas Pipeline’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 Atlas Pipeline’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. Atlas America cannot predict the ultimate impact of these regulatory changes on Atlas Pipeline’s operations.

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 Atlas Pipeline’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

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jurisdiction over the siting of liquefied natural gas (which we refer to as “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, Atlas America employed 978 persons.

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 and leases other field offices in Ohio, Philadelphia and New York on a month-to-month basis. Atlas Pipeline leases 37,100 square feet of office space in Tulsa, Oklahoma through November 2009.

Atlas Energy

Atlas America owned the properties discussed below until they were transferred on December 18, 2006 to Atlas Energy. Accordingly, they are referred to as Atlas Energy’s properties even though Atlas America 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

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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 “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 Atlas Energy’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

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(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.

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Developed and Undeveloped Acreage

The following table sets forth information about Atlas Energy’s developed and undeveloped natural gas and oil acreage as of December 31, 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

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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

Atlas Pipeline Holdings’ assets consist principally of its ownership interests in Atlas Pipeline and Atlas Pipeline Holders maintains no separate properties. As of June 30, 2009, the principal facilities of Atlas Pipeline and its affiliates, including Laurel Mountain, in Appalachia included approximately 1,835 miles of 2 to 12 inch diameter pipeline. As of June 30, 2009, Atlas Pipeline’s principal facilities in the Mid-Continent area consisted of eight natural gas processing plants, one treating facility, and approximately 9,550 miles of active and inactive 2 to 42 inch diameter pipeline. Substantially all of Atlas Pipeline’s and Laurel Mountain’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 Atlas Pipeline’s compressor stations are located on property owned in fee or on property obtained via long-term leases or surface easements.

Atlas Pipeline’s and Laurel Mountain’s property or rights-of-way are subject to encumbrances, restrictions and other imperfections. These imperfections have not interfered, and are not expected to materially interfere, with the conduct of their 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, 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 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.

Legal Proceedings

Atlas Energy, Atlas America, and certain officers and directors of both companies are named defendants in a consolidated purported class action lawsuit brought by Atlas Energy unitholders in Delaware Chancery Court generally alleging claims of breach of fiduciary duty in connection with the merger transaction. The complaint alleges that the defendants breached purported fiduciary duties owed to the public unitholders by negotiating and executing a merger agreement that allegedly provides unfair consideration to the public unitholders and that was reached pursuant to an allegedly unfair negotiating process between the special committee of Atlas Energy and Atlas America. The complaint also alleges that the defendants have failed to disclose material information regarding the merger. The lawsuit originally sought monetary damages or injunctive relief, or both, but the plaintiffs subsequently withdrew their motion for a preliminary injunction to block the merger prior to close and have stated that they will now pursue the action subsequent to the merger. See “Atlas Energy Proposal / Atlas America Proposal 1: The Merger — Litigation Relating to the Merger.”

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

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Dividend Policy

The determination of the amount of future cash dividends on Atlas America common stock, if any, is at the sole discretion of the Atlas America board of directors based upon its analysis of factors it deems relevant. Generally, these factors include Atlas America’s results of operations, financial condition, capital requirements, contractual restrictions, restrictions imposed by applicable law or the SEC and business and investment strategy. There is no assurance that after the merger the Atlas America board of directors will determine to implement a policy to pay periodic dividends.

Officers and Directors

Directors to Serve until the 2012 Annual Meeting:

Mark C. Biderman, 63, was Executive Vice President and Vice Chairman of National Financial Partners Corp., a publicly traded financial services company, from September 2008 to December 2008. Before that, from November 1999 to September 2008, he was National Financial’s Executive Vice President and Chief Financial Officer. From May 1987 to October 1999, Mr. Biderman served as Managing Director and Head of the Financial Institutions Group at CIBC World Markets Group, an investment banking firm, and its predecessor, Oppenheimer & Co., Inc. Mr. Biderman is a Chartered Financial Analyst.

Gayle P.W. Jackson, 63, has been President of Energy Global, Inc., a consulting firm which specializes in corporate development, diversification and government relations strategies for energy companies, since 2004. From 2001 to 2004, Ms. Jackson served as Managing Director of FE Clean Energy Group, a global private equity management firm that invests in energy companies and projects in Asia, Central and Eastern Europe and Latin America. From 1985 to 2001, Ms. Jackson was President of Gayle P.W. Jackson, Inc., a consulting firm that advised energy companies on corporate development and diversification strategies and also advised national and international governmental institutions on energy policy. Ms. Jackson served as Deputy Chairman of the Federal Reserve Bank of St. Louis in 2004-05 and was a member of the Federal Reserve Bank Board from 2000 to 2005. She is a member of the Board of Directors of Ameren Corporation, a publicly traded public utility holding company, and of the Advisory Panel of Cleantech Private Equity, a London-based private equity buyout fund manager that invests in clean technology companies. Ms. Jackson has been a member of the managing board of Atlas Pipeline GP since March 2005, and will resign from the managing board if she is elected to the Atlas America board of directors.

Directors to Serve until the 2010 Annual Meeting:

Carlton M. Arrendell, 47, has been a director since February 2004. Mr. Arrendell has been a Vice President and Chief Investment Officer of Full Spectrum of NY LLC since May 2007. Prior to joining Full Spectrum, Mr. Arrendell served as a special real estate consultant to the AFL-CIO Investment Trust Corporation following six years of service as Investment Trust Corporation’s Chief Investment Officer. Mr. Arrendell is also an attorney admitted to practice law in Maryland and the District of Columbia.

Jonathan Z. Cohen, 39, has been Vice Chairman of the Atlas America board of directors since Atlas America’s formation. Mr. Cohen has been Vice Chairman of the boards of directors of Atlas Energy and its manager, Atlas Energy Management, since their formation in June 2006. Mr. Cohen has been Vice Chairman of the managing board of Atlas Pipeline GP since its formation in 1999 and Vice Chairman of the board of Atlas Pipeline Holdings GP since its formation in January 2006. Mr. Cohen has been a senior officer of Resource America since 1998, serving as the Chief Executive Officer since 2004, President since 2003 and a director since 2002. Mr. Cohen has been Chief Executive Officer, President and a director of Resource Capital Corp. since its formation in 2005, and was the trustee and secretary of RAIT Financial Trust (a publicly traded real estate investment trust) from 1997, and its Vice Chairman from 2003, until December 2006. Mr. Cohen is a son of Edward E. Cohen.

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Donald W. Delson, 58, has been a director since February 2004. Mr. Delson has over 20 years of experience as an investment banker specializing in financial institutions. Mr. Delson has been a Managing Director, Corporate Finance Group, at Keefe, Bruyette & Woods, Inc. since 1997, and before that was a Managing Director in the Corporate Finance Group at Alex. Brown & Sons from 1982 to 1997. Mr. Delson served as an independent member of the managing board of Atlas Pipeline GP from June 2003 until May 2004.

Directors to Serve until the 2011 Annual Meeting:

Edward E. Cohen, 70, has been the Chairman of the Atlas America board of directors and the Chief Executive Officer and President of Atlas America since its organization in September 2000. Mr. Cohen has been the Chairman of the board of directors and Chief Executive Officer of Atlas Energy and Atlas Energy Management since their formation in June 2006. Mr. Cohen has been the Chairman of the managing board of Atlas Pipeline GP since its formation in 1999, and Chief Executive Officer of Atlas Pipeline from 1999 until January 2009. Mr. Cohen has been the Chairman of the board of Atlas Pipeline Holdings GP, LLC, the general partner of Atlas Pipeline Holdings, since its formation in January 2006, and Chief Executive Officer of Atlas Pipeline Holdings from January 2006 until February 2009. In addition, Mr. Cohen has been Chairman of the board of directors of Resource America, Inc. (a publicly traded specialized asset management company) since 1990, and was its Chief Executive Officer from 1988 until 2004, and President from 2000 until 2003; Chairman of the board of directors of Resource Capital Corp. (a publicly traded real estate investment trust) since its formation in September 2005; a director of TRM Corporation (a publicly traded consumer services company) from 1998 to July 2007; and Chairman of the board of directors of Brandywine Construction & Management, Inc. (a property management company) since 1994. Mr. Cohen is the father of Jonathan Z. Cohen.

Dennis A. Holtz, 69, has been a director since February 2004. Mr. Holtz maintained a corporate law practice with D.A. Holtz, Esquire & Associates in Philadelphia and New Jersey from 1988 until his retirement in January 2008.

Harmon S. Spolan, 73, has been a director since August 2006. Since January 2007, Mr. Spolan has served as of counsel to the law firm Cozen O’Connor, where he is chairman of the firm’s charitable foundation. From 1999 until January 2007, Mr. Spolan was a member of the firm and served as chairman of its Financial Services Practice Group and as co-marketing partner. Before joining Cozen O’Connor, Mr. Spolan served as President, Chief Operating Officer, and a director of JeffBanks, Inc., and its subsidiary bank for 22 years. Mr. Spolan has served as a director of Coleman Cable, Inc., since November 2007. Mr. Spolan served as director of TRM Corporation from June 2002 until April 2008.

Non-Director Principal Officers

The Atlas America board of directors appoints principal officers of Atlas America each year at its annual meeting following the annual meeting of stockholders and from time to time as appropriate.

Eugene N. Dubay, 60, has been Atlas America’s Senior Vice President since January 2009. He has also been President and Chief Executive Officer of both Atlas Pipeline and Atlas Pipeline Mid-Continent, LLC since January 2009. Mr. Dubay has served as a member of the managing board of Atlas Pipeline GP since October 2008, where he served as an independent member until his appointment as President and Chief Executive Officer. Mr. Dubay has been the Chief Executive Officer and President of Atlas Pipeline Holdings since February 2009. Mr. Dubay was the Chief Operating Officer of Continental Energy Systems LLC (a successor to SEMCO Energy) since 2003. Mr. Dubay has also held positions with ONEOK, Inc. and Southern Union Company and has over 20 years experience in midstream assets and utilities operations, strategic acquisitions, regulatory affairs and finance. Mr. Dubay is a certified public accountant and a graduate of the U.S. Naval Academy.

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Matthew A. Jones, 47, has been Atlas America’s Chief Financial Officer and the Chief Financial Officer of Atlas Pipeline GP since March 2005. Mr. Jones has been the Chief Financial Officer and a director of Atlas Energy since its formation in June 2006 and has been the Chief Financial Officer of Atlas Pipeline Holdings GP since January 2006 and a director since February 2006. From 1996 to 2005, Mr. Jones worked in the Investment Banking group at Friedman Billings Ramsey, concluding as Managing Director. Mr. Jones worked in Friedman Billings Ramsey’s Energy Investment Banking Group from 1999 to 2005 and in Friedman Billings Ramsey’s Specialty Finance and Real Estate Group from 1996 to 1999. Mr. Jones is a Chartered Financial Analyst.

Freddie M. Kotek, 53, has been an Executive Vice President since February 2004 and served as a director from September 2001 until February 2004. Mr. Kotek has been Chairman of Atlas Resources, LLC since September 2001 and Chief Executive Officer and President of Atlas Resources since January 2002. Mr. Kotek was Atlas America’s Chief Financial Officer from February 2004 until March 2005. Mr. Kotek was a Senior Vice President of Resource America from 1995 until May 2004, President of Resource Leasing, Inc. (a wholly owned subsidiary of Resource America) from 1995 until May 2004.

Sean P. McGrath, 38, has been Atlas America’s Chief Accounting Officer and the Chief Accounting Officer of Atlas Energy since December 2008. Mr. McGrath has been the Chief Accounting Officer of Atlas Pipeline Holdings GP since January 2006. Mr. McGrath has been the Chief Accounting Officer of Atlas Pipeline GP since May 2005. Mr. McGrath was the Controller of Sunoco Logistics Partners L.P., a publicly traded partnership that transports, terminals and stores refined products and crude oil, from 2002 to 2005. From 1998 to 2002, Mr. McGrath was Assistant Controller of Asplundh Tree Expert Co., a utility services and vegetation management company. Mr. McGrath is a Certified Public Accountant.

Richard D. Weber, 44, has been President, Chief Operating Officer and a director of Atlas Energy and President, Chief Operating Officer and a director of Atlas Energy Management since their formation in June 2006. Mr. Weber served from June 1997 until March 2006 as Managing Director and Group Head of the Energy Group of KeyBanc Capital Markets, a division of KeyCorp, and its predecessor, McDonald & Company Securities, Inc., where he oversaw activities with oil and gas producers, pipeline companies and utilities.

Director Independence

The Atlas America board of directors currently consists of eight members, six of whom are independent directors as defined by NASDAQ standards and the Securities Act. The six independent directors are Messrs. Arrendell, Biderman, Delson, Holtz, Jackson and Spolan.

Director and Executive Compensation

Compensation Discussion and Analysis

Atlas America is required to provide information regarding the compensation program in place as of December 31, 2008, for its CEO, CFO and the three other most highly compensated executive officers. We refer to Atlas America’s CEO, CFO and the other three most highly compensated executive officers as Atlas America’s “named executive officers.”

Atlas America’s compensation committee is responsible for formulating and presenting recommendations to the Atlas America board of directors with respect to the compensation of the named executive officers. The compensation committee is also responsible for administering employee benefit plans, including incentive plans. The compensation committee comprises Messrs. Delson, Arrendell and Holtz, with Mr. Delson acting as the chairperson, all of whom are independent directors of Atlas America.

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Compensation Objectives

Atlas America believes that its compensation program must support its business strategy, be competitive, and provide both significant rewards for outstanding performance and clear financial consequences for underperformance. It also believes that a significant portion of the named executive officers’ compensation should be “at risk” in the form of annual and long-term incentive awards that are paid, if at all, based on individual and company accomplishment. Accounting and cost implications of compensation programs are considered in program design; however, the essential consideration is that a program is consistent with Atlas America’s business needs.

Compensation Methodology

The Atlas America compensation committee makes recommendations to the Atlas America board of directors on compensation amounts during the month after the close of the fiscal year. In the case of base salaries, it recommends the amounts to be paid for that year. In the case of annual bonus and long-term incentive compensation, the committee recommends the amount of awards based on the then concluded fiscal year. Atlas America typically pays cash awards and issues equity awards in February. The compensation committee has the discretion to recommend the issuance of equity awards at other times during the fiscal year. In addition, the Atlas America named executive officers and other employees who perform services for its publicly traded subsidiaries, Atlas Energy Resources, Atlas Pipeline and Atlas Pipeline Holdings, may receive stock-based awards from these subsidiaries, each of which has delegated compensation decisions to the Atlas America compensation committee since none of those companies have their own employees.

The compensation committee has retained Mercer (US) Inc. to provide information, analyses, and advice regarding executive compensation. The compensation committee originally retained Mercer in June 2006 to analyze and review the competitiveness and appropriateness of all elements of the compensation Atlas America paid to its named executive officers, individually and as a group, for fiscal 2006. The purpose of the analysis was to determine whether Atlas America’s compensation practices were within the norm for companies of similar size and focus. The peer group analysis was not aimed at establishing benchmarks for the Atlas America compensation program, but rather to provide a “reality check” to obtain a general understanding of then current compensation levels. Because of the importance to Atlas America of its direct-placement energy investment programs and the creation of new initiatives and entities, Mercer looked not only to the energy industry in evaluating compensation levels but also to the financial services and alternative asset industries. Mercer’s analysis established that Atlas America’s fiscal 2006 compensation amounts fell between the median and the 75th percentile of the peer group it used, which the compensation committee found acceptable in the context of its evaluation of the performance of the named executive officers.

At the committee’s direction, Mercer provided the following services for the committee during fiscal 2008:

• provided on-going advice as needed on the design of Atlas America’s annual and long-term incentive plans;

• advised the committee as requested on the performance measures and performance targets for the annual programs by providing an analysis of total stockholder return for a peer group of companies identified by Atlas America and of the metrics of its internal performance review; and

• provided advice on Jonathan Cohen’s employment agreement.

In the course of conducting its activities for fiscal 2008, Mercer attended four meetings of the compensation committee and presented its findings and recommendations for discussion.

The compensation committee has established procedures that it considers adequate to ensure that Mercer’s advice remains objective and is not influenced by Atlas America management. These procedures include: a direct reporting relationship of the Mercer consultant to the chairman of the compensation committee; provisions in the

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engagement letter with Mercer specifying the information, data, and recommendations that can and cannot be shared with management; an annual update to the compensation committee on Mercer’s financial relationship with Atlas America, including a summary of the work performed for us during the preceding 12 months; and written assurances from Mercer that, within the Mercer organization, the Mercer consultant who performs services for the compensation committee has a reporting relationship and compensation determined separately from Mercer’s other lines of business and from its other work for us. With the consent of the compensation committee chair, Mercer may contact Atlas America’s executive officers for information necessary to fulfill its assignment and may make reports and presentations to and on behalf of the compensation committee that the executive officers also receive.

Atlas America’s Chief Executive Officer provides the compensation committee with key elements of both the company’s and the named executive officers’ performance during the year. Atlas America’s CEO makes recommendations to the compensation committee regarding the salary, bonus and incentive compensation component of each named executive officer’s total compensation, including his own. Atlas America’s CEO, at the compensation committee’s request, may attend committee meetings; however, his role during the meetings is to provide insight into Atlas America’s performance as well as the performance of other comparable companies in the same industry. In making its compensation decisions, the compensation committee meets in executive session, without management, both with and without Mercer.

Ultimately, the decisions regarding executive compensation are made by the compensation committee after extensive discussion regarding appropriate compensation and may reflect factors and considerations other than the information and advice provided by Mercer and Atlas America’s CEO. The compensation committee’s decisions are approved by the Atlas America board of directors.

Elements of Atlas America’s Compensation Program

The Atlas America executive officer compensation package generally includes a combination of annual cash and long-term incentive compensation. Annual cash compensation comprises a base salary plus a cash bonus. Long-term incentives consist of a variety of equity awards. Both the annual cash incentives and long-term incentives may be performance-based.

Base Salary

Base salary is intended to provide fixed compensation to the named executive officers for their performance of core duties that contributed to Atlas America’s success as measured by the elements of corporate performance mentioned above. Base salaries are not intended to compensate individuals for extraordinary performance or for above average company performance.

Annual Incentives

Annual incentives are intended to tie a significant portion of each of the named executive officer’s compensation to Atlas America’s annual performance and/or that of its subsidiaries or divisions for which the officer is responsible. Generally, the higher the level of responsibility of the executive within the company, the greater is the incentive component of that executive’s target total cash compensation. The compensation committee may recommend awards of performance-based bonuses and discretionary bonuses.

Performance-Based Bonuses. The Atlas America Annual Incentive Plan for Senior Executives (which we refer to as the “Senior Executive Plan”) was initially approved by Atlas America stockholders at the 2007 annual meeting. The Senior Executive Plan is designed to permit Atlas America to qualify for an exemption from the $1,000,000 deduction limit under Section 162(m) of the Code for compensation paid to Atlas America’s named executive officers. The Senior Executive Plan provides awards for the achievement of predetermined, objective performance measures over a specified 12-month performance period, generally the Atlas America fiscal year.

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Awards under the Senior Executive Plan are paid in cash. In 2008, the Senior Executive Plan was amended to increase the maximum award payable to an individual to $15 million from $5 million and to allow awards to be paid in either cash or shares of common stock under Atlas America’s Stock Incentive Plan. In addition, in 2008 the Senior Executive Plan was clarified to allow the compensation committee to make such adjustments as it deems appropriate to performance goals in the event of a change of control. Notwithstanding the existence of the Senior Executive Plan, the compensation committee believes that stockholder interests are best served by not restricting its discretion and flexibility in crafting compensation, even if the compensation amounts result in non-deductible compensation expense. Therefore, the committee reserves the right to approve compensation that is not fully deductible.

In March 2009, the compensation committee approved 2009 target bonus awards to be paid from a bonus pool. The bonus pool is equal to 18.3% of Atlas America’s adjusted distributable cash flow unless the adjusted distributable cash flow includes any capital transaction gains in excess of $50 million, in which case 10% of that excess will be included in the bonus pool. If the adjusted distributable cash flow does not equal at least 75% of the average adjusted distributable cash flow for the previous 3 years, no bonuses will be paid. Adjusted distributable cash flow means the sum of (i) cash available for distribution to Atlas America by any of its subsidiaries (regardless of whether such cash is actually distributed), plus (ii) interest income during the year, plus (iii) to the extent not otherwise included in adjusted distributable cash flow, any realized gain on the sale of securities, including securities of a subsidiary, less (iv) Atlas America’s stand-alone general and administrative expenses for the year excluding any bonus expense (other than non-cash bonus compensation included in general and administrative expenses), and less (v) to the extent not otherwise included in adjusted distributable cash flow, any loss on the sale of securities, including securities of a subsidiary. A return of Atlas America’s capital investment in a subsidiary is not intended to be included and, accordingly, if adjusted distributable cash flow includes proceeds from the sale of all or substantially all of the assets of a subsidiary, the amount of such proceeds to be included in adjusted distributable cash flow will be reduced by Atlas America’s basis in the subsidiary. The maximum award payable, expressed as a percentage of Atlas America’s estimated 2009 adjusted distributable cash flow, for each participant is as follows: Edward E. Cohen, 6.14%; Jonathan Z. Cohen, 4.37%; Matthew A. Jones, 3.46%; Richard D. Weber, 2.60% and Freddie Kotek, 1.73%. Pursuant to the terms of the Senior Executive Plan, the compensation committee has the discretion to recommend reductions, but not increases, in awards under the plan.

Discretionary Bonuses. Discretionary bonuses may be awarded to recognize individual and group performance.

Long-Term Incentives

Atlas America believes that its long-term success depends upon aligning its executives’ and stockholders’ interests. To support this objective, it provides its executives with various means to become significant stockholders, including the Atlas America long-term incentive programs and those of its public subsidiaries. These awards are usually a combination of stock options, restricted units and phantom units which vest over four years to support long-term retention of executives and reinforce Atlas America’s longer-term goals.

Grants under the Atlas America Stock Incentive Plan

Awards under the Atlas America Stock Incentive Plan (which we refer to as the “Atlas America Plan”), may be in the form of incentive stock options, non-qualified stock options and restricted stock.

Stock Options. The Atlas America compensation committee has recommended for award stock options under the Plan from time to time. Stock option grants have a ten-year term and usually vest 25% per year. These stock options provide value to the recipient only if Atlas America’s share price is higher than on the date of the grant.

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Restricted Stock. On very limited occasions, restricted stock grants have been awarded. These grants vest 25% per year on the anniversary of the date of grant. Restricted stock units reward stockholder value creation slightly differently than stock options: restricted stock units are impacted by all stock price changes, both increases and decreases.

Grants under Subsidiary Plans

As described above, Atlas America’s named executive officers who perform services for one or more of Atlas America’s publicly traded subsidiaries may receive stock-based awards under the long-term incentive plan of the appropriate subsidiary.

Supplemental Benefits, Deferred Compensation and Perquisites

Atlas America does not emphasize supplemental benefits for executives other than Mr. E. Cohen and Mr. J. Cohen, and perquisites are discouraged. None of the named executive officers have deferred any portion of their compensation.

Employment Agreements

Atlas America generally disfavors the use of employment agreements unless they are required to attract or to retain executives to the organization. It has entered into employment agreements with Messrs. E. Cohen and Weber. In January 2009, Atlas America entered into an employment agreement with Mr. J. Cohen. See “Director and Executive Compensation — Employment Agreements and Potential Payments Upon Termination or Change of Control” below. Atlas America’s compensation committee takes termination compensation payable under these agreements into account in determining annual compensation awards, but ultimately its focus is on recognizing each individual’s contribution to the company’s performance during the year.

Determination of 2008 Compensation Amounts

As described above, after the end of the 2008 fiscal year, Atlas America’s compensation committee set the base salaries of its named executive officers for the 2009 fiscal year and recommended incentive awards based on the prior year’s performance. In carrying out its function, the compensation committee acted in consultation with Mercer.

In determining the actual amounts to be paid to the named executive officers, the compensation committee considered both individual and company performance. Atlas America’s CEO makes recommendations of award amounts based upon the named executive officers’ individual performances as well as the performance of Atlas America’s publicly held subsidiaries for which each named executive officer provides service; however, the compensation committee has the discretion to approve, reject or modify the recommendations. The compensation committee noted that the Atlas America management team had accomplished the following strategic objectives, among others, during fiscal 2008: maintained an unencumbered balance sheet, raised approximately $1.2 billion for its subsidiaries through issuances of equity and senior unsecured notes and increases in senior secured credit facilities, raised approximately 23% more for Atlas Energy’s investment partnerships than fiscal 2007, solidified Atlas Energy’s position as one of the leading companies in the Marcellus Shale by adding approximately 69,000 acres at very competitive prices and drilling over 90 wells, increased total proved reserves by approximately 11% over the prior year, increased natural gas processing capacity and achieved record throughput on both the Appalachia and Mid-Continent pipeline systems. In addition, the compensation committee reviewed the calculations of Atlas America’s adjusted distributable cash flow and determined that 2008 adjusted distributable cash flow exceeded the pre-determined minimum threshold of 95% of 2007 adjusted distributable cash flow by more than 50%.

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Base Salary. Consistent with its preference for having a significant portion of Atlas America’s named executive officers’ overall compensation package be incentive compensation, Atlas America’s CEO did not recommend any increases in salaries for 2009. The compensation committee took this recommendation into consideration and ultimately adopted it.

Annual Incentives. The maximum amount payable to each of the named executive officers pursuant to the predetermined percentages established under the Senior Executive Plan was as follows: Edward E. Cohen, $8,644,000; Jonathan Z. Cohen, $6,152,000; Matthew A. Jones, $4,880,000; Freddie M. Kotek, $2,440,000 and Richard D. Weber, $3,660,000. As described above, Atlas America’s named executive officers substantially outperformed the incentive goals set for them and, under normal circumstances, bonuses would have substantially increased for 2008. However, the compensation committee recognized that prevailing economic conditions are not normal and decided, pursuant to its discretionary authority as set forth in the Senior Executive Plan, to recommend that the maximum amount for each named executive officer be reduced and recommended that Atlas America award cash incentive bonuses as follows: Edward E. Cohen, $1,950,000; Jonathan Z. Cohen, $500,000; Matthew A. Jones, $1,500,000; Freddie M. Kotek, $1,000,000 and Richard D. Weber, $1,200,000.

Long-Term Incentives. The compensation committee determined that it would not recommend that Atlas America make equity-based awards to its named executive officers because it felt that previous awards were adequate.

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Summary Compensation Table

The following table sets forth information concerning the compensation for fiscal 2008, 2007 and 2006 for Atlas America’s Chief Executive Officer, Chief Financial Officer and each of Atlas America’s three other most highly compensated executive officers whose aggregate salary and bonus (including amounts of salary and bonus foregone to receive non-cash compensation) exceeded $100,000.

Name and principal position	Year	Salary ($)		Bonus ($)		Stock awards ($)(1)		Option awards ($)(2)		Non-equity incentive plan compensation ($)		Change in pension value and nonqualified deferred compensation earnings ($)			All other compensation ($)			Total ($)
Edward E. Cohen	2008	$	900,000		—	$	2,037,449	$	1,686,919	$	1,950,000	$	734,078	(3)	$	733,938	(4)	$	8,042,384
Chairman of the Board and Chief Executive Officer	2007	$	900,000		—	$	2,407,901	$	810,417	$	5,000,000	$	1,150,222		$	554,777		$	10,823,317
	2006	$	600,000	$	1,400,000	$	674,625	$	84,861			$	121,769		$	41,849		$	2,923,104
Matthew A. Jones	2008	$	300,000		—	$	352,244	$	790,203	$	1,500,000				$	115,313	(5)	$	3,057,759
Chief Financial Officer	2007	$	300,000		—	$	472,212	$	439,128	$	2,000,000		—		$	134,597		$	3,345,937
	2006	$	300,000	$	750,000	$	276,546	$	324,172				—		$	65,602		$	1,716,320
Jonathan Z. Cohen	2008	$	600,000		—	$	1,080,004	$	1,025,369	$	500,000		—		$	386,550	(6)	$	3,591,923
Vice Chairman	2007	$	600,000		—	$	1,384,207	$	324,167	$	4,000,000		—		$	300,906		$	6,609,280
	2006	$	400,000	$	1,000,000	$	439,563	$	33,944				—		$	20,400		$	1,893,907
Freddie M. Kotek	2008	$	300,000		—	$	119,017	$	359,247	$	1,000,000		—		$	48,780	(7)	$	1,827,044
Executive Vice President	2007	$	300,000	$	1,000,000	$	123,410	$	183,710				—		$	47,996		$	1,655,116
	2006	$	300,000	$	350,000		—	$	153,600				—		$	10,867		$	814,467
Richard D. Weber	2008	$	300,000		—	$	250,005	$	726,656	$	1,200,000		—		$	10,473	(8)	$	2,487,134
President and Chief Operating Officer of Atlas Energy Resources, LLC	2007	$	300,000		—	$	250,000	$	463,770	$	1,500,000		—		$	2,857		$	2,516,627
	2006	$	201,923	$	800,000	$	187,504	$	347,779				—		$	26,957		$	1,564,163

(1) Represents the dollar amount of (i) expense recognized by Atlas Pipeline Holdings for financial statement reporting purposes with respect to phantom units granted under the Atlas Pipeline Holdings Long-Term Incentive Plan (which we refer to as the “Atlas Pipeline Holdings Plan”); (ii) expense recognized by Atlas Pipeline for financial statement reporting purposes with respect to phantom units granted under the Atlas Pipeline Long-Term Incentive Plan (which we refer to as the “Atlas Pipeline Plan”) and its incentive compensation arrangements; and/or (iii) expense recognized by Atlas Energy for financial statement reporting purposes with respect to phantom units or restricted units granted under the Atlas Energy Long-Term Incentive Plan (which we refer to as the “Atlas Energy Plan”), all in accordance with FAS 123R. See note 16 to Atlas America’s consolidated financial statements for an explanation of the assumptions made for this valuation.

(2) Represents the dollar amount of (i) expense Atlas America recognized for financial statement reporting purposes with respect to options granted under the Plan, (ii) expense recognized for financial statement reporting purposes by Atlas Pipeline Holdings for options granted under the Atlas Pipeline Holdings Plan; and/or (iii) expense recognized for financial statement reporting purposes by Atlas Energy for options granted under the Atlas Energy Plan, all in accordance with FAS 123R. See note 16 to Atlas America’s consolidated financial statements for an explanation of the assumptions made for this valuation.

(3) Represents the aggregate annual change in the present-value of accumulated pension benefits under the Supplemental Employment Retirement Plan for Mr. E. Cohen.

(4) Includes payments on distribution equivalent rights (which we refer to as “DERs”) of $96,838 with respect to the phantom units awarded under the Atlas Pipeline Plan, $161,100 with respect to phantom units awarded under the Atlas Pipeline Holdings Plan, and $476,000 with respect to the phantom units awarded under the Atlas Energy Plan.

(5) Includes payments on DERs of $31,913 with respect to the phantom units awarded under the Atlas Pipeline Plan, $35,800 with respect to phantom units awarded under the Atlas Pipeline Holdings Plan, and $47,600 with respect to the phantom units awarded under the Atlas Energy Plan.

(6) Represents payments on DERs of $48,238 with respect to the phantom units awarded under the Atlas Pipeline Plan, $65,250 with respect to phantom units awarded under the Atlas Pipeline Holdings Plan, and $181,000 with respect to the phantom units awarded under the Atlas Energy Plan.

(7) Includes payments on DERs of $1,180 with respect to the phantom units awarded under the Atlas Pipeline Plan, $47,600 with respect to the phantom units awarded under the Atlas Energy Plan.

(8) Represents reimbursements for lease payments on Mr. Weber’s vehicle.

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2008 Grants of Plan-Based Awards Table

Name	Grant date	Approval date	Estimated future payouts under non-equity incentive plan awards(1)				All other option awards: number of securities underlying options (#)		Exercise or base price of option awards ($ / Sh)		Grant date fair value of stock and option awards
			Threshold ($)	Target ($)	Maximum ($)
Edward E. Cohen	1/29/08	1/4/08	N/A	N/A	$	8,644,000	300,000	(1)	$	32.53	$	3,507,000	(2)
Matthew A. Jones	1/29/08	1/4/08	N/A	N/A	$	4,880,000	120,000	(1)	$	32.53	$	1,402,800	(2)
Jonathan Z. Cohen	1/29/08	1/4/08	N/A	N/A	$	6,152,000	240,000	(1)	$	32.53	$	2,805,600	(2)
Richard D. Weber	1/29/08	1/4/08	N/A	N/A	$	3,660,000	90,000	(1)	$	32.53	$	1,052,100	(2)
Freddie Kotek	1/29/08	1/4/08	N/A	N/A	$	2,440,000	60,000	(1)	$	32.53	$	701,400	(2)

(1) Represents performance-based bonuses under Atlas America’s Senior Executive Plan. As discussed under “Director and Executive Compensation — Annual Incentives — Performance-Based Bonuses,” the compensation committee set performance goals based on Atlas America’s adjusted distributable cash flow and established maximum awards, but not minimum or target amounts, for each eligible named executive officer. The Atlas America Senior Executive Plan sets an individual limit of $15,000,000 per annum regardless of the maximum amounts that might otherwise be payable.

(2) Represents grants of stock options made under the Plan, which vest 25% on each anniversary of the grant, valued at $11.69 per option using the Black-Scholes option pricing model to estimate the weighted average fair value of each unit option granted with weighted average assumptions for (a) expected dividend yield of 3.7%, (b) risk-free interest rate of 2.6%, (c) expected volatility of 33.0%, and (d) an expected life of 6.3 years. Amounts reflect a 3-for-2 stock split effected on June 2, 2008. These awards were made with respect to Atlas America’s 2007 fiscal year but actually granted during the 2008 fiscal year.

Employment Agreements and Potential Payments Upon Termination or Change of Control

Edward E. Cohen

In May 2004, Atlas America entered into an employment agreement with Edward E. Cohen, who currently serves as the Chairman, Chief Executive Officer and President of Atlas America. The agreement was amended as of December 31, 2008 to comply with requirements under Section 409A of the Internal Revenue Code relating to deferred compensation. The agreement requires Mr. Cohen to devote such time to Atlas America as is reasonably necessary to the fulfillment of his duties, although it permits him to invest and participate in outside business endeavors. The agreement provided for initial base compensation of $350,000 per year, which may be increased by the compensation committee based upon its evaluation of Mr. Cohen’s performance. Mr. Cohen is eligible to receive incentive bonuses and stock option grants and to participate in all employee benefit plans in effect during his period of employment.

The agreement has a term of three years and, until notice to the contrary, the term is automatically extended so that on any day on which the agreement is in effect it has a then-current three-year term. Atlas America entered into Mr. Cohen’s employment agreement around the time of its spin-off from Resource America. At that time, it was important to establish a long-term commitment to and from Mr. Cohen as Atlas America’s Chief Executive Officer and President. Atlas America determined that the rolling three-year term was an appropriate amount of time to reflect that commitment and was a term that was commensurate with Mr. Cohen’s position.

Atlas America may terminate the agreement without cause, including upon or after a change of control, upon 30 days’ prior notice, in the event of Mr. Cohen’s death, if he is disabled for 180 days consecutive days during any 12-month period or at any time for cause. Mr. Cohen also has the right to terminate the agreement for good reason. Mr. Cohen must provide 30 days’ notice of a termination by him for good reason within 60 days of the event constituting good reason. Atlas America then would have 30 days in which to cure and, if it does not do

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so, Mr. Cohen’s employment will terminate 30 days after the end of the cure period. Mr. Cohen may also terminate the agreement without cause upon 60 days’ notice. Termination amounts will not be paid until six months after the termination date, if such delay is required by Section 409A.

Change of control is defined as:

• the acquisition of beneficial ownership, as defined in the Exchange Act, of 25% or more of Atlas America’s voting securities or all or substantially all of its assets by a single person or entity or group of affiliated persons or entities, other than an entity affiliated with Mr. Cohen or any member of his immediate family;

• the consummation of a merger, consolidation, combination, share exchange, division or other reorganization or transaction with an unaffiliated entity in which either (a) Atlas America’s directors immediately before the transaction constitute less than a majority of the board of the surviving entity, unless ¹/2 of the surviving entity’s board were Atlas America directors immediately before the transaction and Atlas America’s chief executive officer immediately before the transaction continues as the chief executive officer of the surviving entity; or (b) Atlas America’s voting securities immediately prior to the transaction represent less than 60% of the combined voting power, immediately after the transaction of Atlas America, the surviving entity or, in the case of a division, each entity resulting from the division;

• during any period of 24 consecutive months, individuals who were Atlas America board members at the beginning of the period cease for any reason to constitute a majority of the board, unless the election or nomination for election by Atlas America stockholders of each new director was approved by a vote of at least ²/3 of the directors then still in office who were directors at the beginning of the period; or

• Atlas America stockholders approve a plan of complete liquidation or winding up of Atlas America, or agreement of sale of all or substantially all of Atlas America’s assets or all or substantially all of the assets of its primary subsidiaries to an unaffiliated entity.

Good reason is defined as a reduction in Mr. Cohen’s base pay, a demotion, a material reduction in his duties, relocation, his failure to be elected to the Atlas America board of directors or Atlas America’s material breach of the agreement. Cause is defined as a felony conviction or conviction of a crime involving fraud, embezzlement or moral turpitude, intentional and continual failure by Mr. Cohen to perform his material duties after notice, or violation of confidentiality obligations.

The agreement provides for a Supplemental Executive Retirement Plan (which we refer to as a “SERP”), pursuant to which Mr. Cohen will receive, upon the later of his retirement or reaching the age of 70, an annual retirement benefit equal to the product of:

• 6.5% multiplied by

• his base salary as of the time Mr. Cohen’s employment with Atlas America ceases, multiplied by

• the number of years (or portions thereof) which Mr. Cohen is employed by Atlas America but, in any case, not less than four. If Mr. Cohen’s employment is terminated due to disability, the 3-year period following the termination will be deemed a portion of his employment term for purposes of accruing SERP benefits.

The maximum benefit under the SERP is limited to 65% of his final base salary. The benefit is guaranteed to his estate for up to 10 years if he should die before receiving 10 years’ of SERP benefits. If there is a change of control, if Mr. Cohen resigns for good reason, or if Atlas America terminates his employment without cause, then the SERP benefit will be the greater of the accrued benefit pursuant to the above formula, or 40% of his final base salary.

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The agreement provides the following termination benefits:

• upon termination of employment due to death, Mr. Cohen’s estate will receive (a) a lump sum payment in an amount equal to three times his final base salary, (b) payment of his SERP benefit and (c) automatic vesting of all stock and option awards.

• upon termination due to disability, Mr. Cohen will receive (a) a lump sum payment in an amount equal to three times his final base salary, (b) a lump sum amount equal to the COBRA premium cost for continued health coverage, less the premium charge that is paid by Atlas America’s employees, during the three years following his termination, (c) a lump sum amount equal to the cost Atlas America would incur for life, disability and accident insurance coverage during the three-year period, less the premium charge that is paid by Atlas America’s employees, (d) payment of his SERP benefit, (e) automatic vesting of all stock and option awards and (f) any amounts payable under the Atlas America long-term disability plan.

• upon termination by Atlas America without cause, by Mr. Cohen for good reason or by either party in connection with a change of control, he will be entitled to either (a) if Mr. Cohen does not sign a release, severance benefits under Atlas America’s then current severance policy, if any, or (b) if Mr. Cohen signs a release, (i) a lump sum payment in an amount equal to three times average compensation (defined as the average of the three highest amounts of annual total compensation), (ii) a lump sum amount equal to the COBRA premium cost for continued health coverage, less the premium charge that is paid by Atlas America employees, during the three years following his termination, (iii) a lump sum amount equal to the cost Atlas America would incur for life, disability and accident insurance coverage during the three-year period, less the premium charge that is paid by Atlas America employees, (iv) payment of his SERP benefit and (v) automatic vesting of all stock and option awards.

• upon termination by Mr. Cohen without cause, if he signs a release he will receive (a) a lump sum payment equal to one-half of one year’s base salary then in effect, (b) automatic vesting of all stock and option awards and (c) if he has reached retirement age, his SERP benefits.

In the event that any amounts payable to Mr. Cohen upon termination become subject to any excise tax imposed under Section 4999 of the Internal Revenue Code, Atlas America must pay Mr. Cohen an additional sum such that the net amounts retained by Mr. Cohen, after payment of excise, income and withholding taxes, equals the termination amounts payable, unless Mr. Cohen’s employment terminates because of his death or disability. Atlas America believes that the multiples of the compensation components payable to Mr. Cohen upon termination were generally aligned with competitive market practice for similar executives at the time that his employment agreement was negotiated.

If a termination event had occurred as of December 31, 2008, Atlas America estimates that the value of the benefits to Mr. Cohen would have been as follows:

Reason for termination	Lump sum severance payment			SERP(1)		Benefits(2)		Accelerated vesting of stock awards and option awards(3)		Tax gross-up(4)
Death	$	2,700,000	(5)	$	2,925,000	$	—	$	2,984,200	$	—
Disability		2,700,000	(5)		2,925,000		38,419		2,984,200		—
Termination by Atlas America without cause(6)		10,750,000	(7)		3,600,000		38,419		2,984,200		—
Termination by Mr. Cohen for good reason(6)		10,750,000	(7)		3,600,000		38,419		2,984,200		—
Change of control(6)		10,750,000	(7)		3,600,000		38,419		2,984,200		4,591,308
Termination by Mr. Cohen without cause		450,000	(5)		2,340,000		—		2,984,200		—

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(1) Represents the value of vested benefits payable calculated by multiplying the per year benefit by the minimum of 10 years.

(2) Represents rates currently in effect for COBRA insurance benefits for 36 months.

(3) Represents the value of unvested and accelerated option awards and stock awards disclosed in the “2008 Outstanding Equity Awards at Fiscal Year-End Table.” The payments relating to option awards are calculated by multiplying the number of accelerated options by the difference between the exercise price and the closing price of the applicable stock on December 31, 2008. The payments relating to stock awards are calculated by multiplying the number of accelerated shares or units by the closing price of the applicable stock on December 31, 2008.

(4) Calculated after deduction of any excise tax imposed under section 4999 of the Internal Revenue Code, and any federal, state and local income tax, FICA and Medicare withholding taxes, taking into account the 20% excess parachute payment rate and a 42.65% combined effective tax rate.

(5) Calculated based on Mr. Cohen’s 2008 base salary.

(6) These amounts are contingent upon Mr. Cohen executing a release. If Mr. Cohen does not execute a release he would receive severance benefits under the current Atlas America severance plan.

(7) Calculated based on Mr. Cohen’s average 2008, 2007 and 2006 base salary and bonus.

Jonathan Z. Cohen

In January 2009, Atlas America entered into an employment agreement with Jonathan Z. Cohen, to continue his service as Vice-Chairman, in which position he has served in since 1998. Atlas America entered into the agreement in order to define Mr. Cohen’s role with the company, particularly in light of the fact that he devotes a substantial amount of his time to it. Thus, the agreement specifies that his duties include capital raising, strategic transactions and activities, building and minding stockholder and lender relationships, developing and implementing short- and long-term plans and approaches, and being available to assist Atlas America’s Chairman and board of directors with respect to other matters. The agreement provides that Mr. Cohen’s position will not be full-time and requires him to devote such time to Atlas America as is reasonably necessary to the fulfillment of his duties, and permits him to invest and participate in outside business endeavors.

The agreement provides for initial base compensation of $600,000 per year, which may be increased at the discretion of the Atlas America board of directors. Mr. Cohen is eligible to receive grants of equity-based compensation from Atlas America, Atlas Energy, Atlas Pipeline, Atlas Pipeline Holdings or other of Atlas America’s affiliates, which we refer to collectively as the “Atlas Entities,” and to participate in all employee benefit plans in effect during his period of employment.

The agreement has a term of three years and will be renewed for an additional three-year period, unless either party elects to terminate the agreement by providing notice at least 180 days before the expiration of the then current term. Atlas America may terminate the agreement:

• without cause upon 90 days’ prior notice;

• in the event of Mr. Cohen’s death;

• if he is physically or mentally disabled for 180 days in the aggregate or 90 consecutive days during any 365-day period and the Atlas America board of directors determines, in good faith based upon medical evidence, that he is unable to perform his duties; or

• at any time for cause.

Mr. Cohen has the right to terminate the agreement for good reason, including a change of control. Mr. Cohen must provide notice of a termination by him for good reason within 30 days of the event constituting good

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reason. Atlas America then would have 30 days in which to cure and, if it does not do so, Mr. Cohen’s employment will terminate 30 days after the end of the cure period. Mr. Cohen may also terminate the agreement without cause upon 30 days’ notice. Termination amounts will not be paid until six months after the termination date, if such delay is required by Section 409A of the Internal Revenue Code.

Cause is defined as a felony conviction or conviction of a crime involving fraud, deceit or misrepresentation, failure by Mr. Cohen to materially perform his duties after notice other than as a result of physical or mental illness, or violation of confidentiality obligations or representations in the agreement. Good reason is defined as any action or inaction that constitutes a material breach by Atlas America of the agreement or a change of control. Change of control is defined as:

• the acquisition of beneficial ownership, as defined in the Exchange Act, of 25% or more of Atlas America’s voting securities or all or substantially all of its assets by a single person or entity or group of affiliated persons or entities, other than an entity affiliated with Mr. Cohen or any member of his immediate family;

• the consummation of a merger, consolidation, combination, share exchange, division or other reorganization or transaction with an unaffiliated entity in which either (a) Atlas America’s directors immediately before the transaction constitute less than a majority of the board of the surviving entity, unless ¹/2 of the surviving entity’s board were Atlas America directors immediately before the transaction and Atlas America’s chief executive officer immediately before the transaction continues as the chief executive officer of the surviving entity; or (b) Atlas America’s voting securities immediately prior to the transaction represent less than 60% of the combined voting power, immediately after the transaction of Atlas America, the surviving entity or, in the case of a division, each entity resulting from the division;

• during any period of 24 consecutive months, individuals who were Atlas America board members at the beginning of the period cease for any reason to constitute a majority of the board, unless the election or nomination for election by Atlas America stockholders of each new director was approved by a vote of at least ²/3 of the directors then still in office who were directors at the beginning of the period; or

• Atlas America stockholders approve a plan of complete liquidation or winding up of Atlas America, or agreement of sale of all or substantially all of Atlas America’s assets or all or substantially all of the assets of its primary subsidiaries to an unaffiliated entity.

The agreement provides for a SERP, which will provide a monthly benefit to Mr. Cohen, upon the later of his reaching the age of 60 or 30 days after his retirement, equal to ¹/12 of the product of:

• the highest annual base salary Mr. Cohen received during his service to the Atlas Entities, multiplied by

• 2%, multiplied by

• the number of years (or fractions thereof) during which Mr. Cohen was an officer or director of any of the Atlas Entities on and after January 1, 2004.

The percentage calculated by multiplying the second and third bullet points above cannot exceed 65%. The aggregate amount of the payments made to Mr. Cohen pursuant to the SERP will be offset by the aggregate amounts paid to Mr. Cohen by the Atlas Entities under their qualified benefit programs.

The agreement provides the following regarding termination and termination benefits:

• upon termination of employment due to death, Mr. Cohen’s estate will receive (a) accrued but unpaid bonus and vacation pay, (b) up to 120 monthly SERP payments if he should die before receiving 120 monthly payments and (c) automatic vesting of all equity-based awards.

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• upon termination by Atlas America other than for cause, including disability, or by Mr. Cohen for good reason, Mr. Cohen will receive either (a) if Mr. Cohen does not sign a release, severance benefits under Atlas America’s then current severance policy, if any, or (b) if Mr. Cohen signs a release, (i) a lump sum payment in an amount equal to three years of his average compensation (which is defined as his base salary in effect immediately before termination plus the average of the cash bonuses earned for the three calendar years preceding the year in which the termination occurred), less, in the case of termination by reason of disability, any amounts paid under disability insurance provided by Atlas America, (ii) monthly reimbursement of any COBRA premium paid by Mr. Cohen, less the amount Mr. Cohen would be required to contribute for health and dental coverage if he were an active employee, (iii) payment of his SERP benefits if he has reached retirement age and (iv) automatic vesting of all equity-based awards.

• upon termination by Atlas America for cause or by Mr. Cohen for other than good reason, Mr. Cohen will receive his SERP benefits if he has reached retirement age, and his vested equity-based awards will not be subject to forfeiture.

Atlas America believes that the multiples of the compensation components payable to Mr. Cohen upon termination were generally aligned with competitive market practice for similar executives at the time that his employment agreement was negotiated.

If a termination event had occurred as of December 31, 2008, Atlas America estimates that the value of the benefits to Mr. Cohen would have been as follows:

Reason for termination	Lump sum severance payment			SERP	Benefits(1)	Accelerated vesting of stock awards and option awards(2)
Death		—		—	—	$	1,510,850
Termination by Atlas America other than for cause (including disability) or by Mr. Cohen for good reason (including a change of control)	$	7,300,000	(3)	—	—	$	1,510,850
Termination by Atlas America for cause or by Mr. Cohen for other than good reason		—		—	—		—

(1) Mr. Cohen does not currently receive benefits from Atlas America.

(2) Represents the value of unexercisable option and unvested stock awards disclosed in the “2008 Outstanding Equity Awards at Fiscal Year-End Table.” The payments relating to option awards are calculated by multiplying the number of accelerated options by the difference between the exercise price and the closing price of the applicable stock on December 31, 2008. The payments relating to stock awards are calculated by multiplying the number of accelerated shares or units by the closing price of the applicable stock on December 31, 2008.

(3) Calculated based on Mr. Cohen’s 2008 base salary and the average of his 2008, 2007 and 2006 bonuses.

Richard D. Weber

Atlas America entered into an employment agreement in April 2006 with Richard Weber, who serves as President and Chief Operating Officer of Atlas Energy and Atlas Energy Management. The agreement has a two-year term and, after the first year, the term automatically renews daily so that on any day that the agreement is in effect, the agreement will have a remaining term of one year. Mr. Weber is required to devote substantially all of his working time to Atlas Energy Management and its affiliates. The agreement provides for an annual base salary of not less than $300,000 and a bonus of not less than $700,000 during the first year. After that, bonuses will be awarded solely at the discretion of Atlas America compensation committee. The agreement provides for equity compensation as follows:

• upon execution of the agreement, Mr. Weber was granted options to purchase 50,000 shares of Atlas America stock at $47.86.

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• in January 2007, Mr. Weber received a grant of 47,619 Atlas Energy restricted units with a value of $1,000,000.

• in January 2007, Mr. Weber received options to purchase 373,752 Atlas Energy common units at $21.00.

All of the securities described above vest 25% per year on each anniversary of the date Mr. Weber commenced his employment, April 17, 2006. All securities will vest immediately upon a change of control or termination by Mr. Weber for good reason or by Atlas Energy Management other than for cause. Change of control is defined as:

• the acquisition of beneficial ownership, as defined in the Exchange Act, of 50% or more of Atlas America’s or Atlas Energy’s voting securities or all or substantially all of Atlas America’s or Atlas Energy’s assets by a single person or entity or group of affiliated persons or entities, other than an entity of which either Mr. E. Cohen or Mr. J. Cohen is an officer, manager, director or participant;

• Atlas America or Atlas Energy consummate a merger, consolidation, combination, share exchange, division or other reorganization or transaction with an unaffiliated entity after which Atlas Energy Management is not the manager of Atlas Energy; or

• Atlas America’s or Atlas Energy unitholders approve a plan of complete liquidation or winding up, or agreement of sale of all or substantially all of Atlas America’s or Atlas Energy’s assets other than an entity of which either Mr. E. Cohen or Mr. J. Cohen is an officer, manager, director or participant.

The change of control triggering events relating to the possible absence of Messrs. Cohen reflects that Mr. Weber’s belief that Messrs. Cohen effectively controlled Atlas America at the time of his employment and their separation would therefore constitute a change of control.

Good reason is defined as a material breach of the agreement, reduction in his base pay, a demotion, a material reduction in his duties or his failure to be elected to the Atlas Energy board of directors. Cause is defined as fraud in connection with his employment, conviction of a crime other than a traffic offense, material failure to perform his duties after written demand by the Atlas America board of directors or breach of the representations made by Mr. Weber in the employment agreement if the breach impacts his ability to fully perform his duties. Disability is defined as becoming disabled by reason of physical or mental disability for more than 180 days in the aggregate or a period of 90 consecutive days during any 365-day period and the good faith determination by the Atlas America board of directors based upon medical evidence that Mr. Weber is unable to perform his duties under his employment agreement.

Atlas Energy Management may terminate Mr. Weber without cause upon 45 days written notice or for cause upon written notice. Mr. Weber may terminate his employment for good reason or for any other reason upon 30 days’ written notice. Key termination benefits are as follows:

• if Mr. Weber’s employment is terminated due to death, (a) Atlas Energy Management will pay to Mr. Weber’s designated beneficiaries a lump sum cash payment in an amount equal to the bonus that Mr. Weber received from the prior fiscal year prorated for the time employed during the current fiscal year, (b) Mr. Weber’s family will receive health insurance coverage for one year, and (c) all Atlas Energy units and option awards will automatically vest.

• if Atlas Energy Management terminates Mr. Weber’s employment other than for cause (including termination by reason of disability), or Mr. Weber terminates his employment for good reason, (a) Atlas Energy Management will pay amounts and benefits otherwise payable to Mr. Weber as if Mr. Weber remained employed for one year, except that the bonus amount shall be prorated and based on the bonus awarded in the prior fiscal year, and (b) all stock, unit and option awards will automatically vest.

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Mr. Weber is entitled to a gross-up payment if any payments made to him would constitute an excess parachute payment under Section 280G of the Internal Revenue Code such that the net amount Mr. Weber receives after the deduction of any excise tax, any federal, state and local income tax, and any FICA and Medicare withholding tax is the same amount he would have received had such taxes not been deducted. The agreement includes standard restrictive covenants for a period of two years following termination, including non-compete and non-solicitation provisions.

If a termination event had occurred as of December 31, 2008, Atlas America estimates that the value of the benefits to Mr. Weber would have been as follows:

Reason for termination	Lump sum severance payment			Benefits(1)		Accelerated vesting of stock awards and option awards(2)		Tax gross-up
Death	$	1,200,000	(3)	$	17,193	$	—	—
Disability		—			19,826		—	—
Termination by Atlas America other than for cause (including disability) or by Mr. Weber for good reason	$	1,500,000	(4)		19,826		304,054	—
Change of control		—			—		304,054	—

(1) Represents rates currently in effect for COBRA insurance benefits for 12 months.

(2) Represents the value of unexercisable option and unvested unit awards disclosed in the “2008 Outstanding Equity Awards at Fiscal Year-End Table.” The payments relating to option awards are calculated by multiplying the number of accelerated options by the difference between the exercise price and the closing price of the applicable units on December 31, 2008. The payments relating to unit awards are calculated by multiplying the number of accelerated shares or units by the closing price of the applicable stock on December 31, 2008.

(3) Represents Mr. Weber’s 2008 bonus.

(4) Calculated as the sum of Mr. Weber’s 2008 base salary and bonus.

Long-Term Incentive Plans

The Atlas America Plan

The Atlas America Plan authorizes the granting of up to 4.5 million shares of Atlas America common stock to its employees, affiliates, consultants and directors in the form of incentive stock options, non-qualified stock options, SARs, restricted stock and deferred units. SARs represent a right to receive cash in the amount of the difference between the fair market value of a share of Atlas America common stock on the exercise date and the exercise price, and may be free-standing or tied to grants of options. A deferred unit represents the right to receive one share of Atlas America common stock upon vesting. Awards under the Atlas America Plan generally become exercisable as to 25% each anniversary after the date of grant, except that deferred units awarded to non-executive board members vest 33 ¹/3% on each of the second, third and fourth anniversaries of the grant, and expire not later than ten years after the date of grant. Units will vest sooner upon a change in control of Atlas America or death or disability of a grantee, provided the grantee has completed at least six months service.

Senior Executive Plan

For a description of Atlas America’s Senior Executive Plan, please see “Director and Executive Compensation — Annual Incentives — Performance-Based Bonuses.”

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Atlas Energy Plan

Eligible participants in the Atlas Energy Plan are the employees, directors and consultants of Atlas Energy Management and its affiliates, including Atlas America, who perform services for Atlas Energy. Awards under the Atlas Energy Plan may be phantom units, unit options and tandem DERs with respect to phantom units for an aggregate of 3,600,000 common units. The Atlas Energy Plan is administered by Atlas Energy’s compensation committee. Awards under the Atlas Energy Plan generally become exercisable as to 25% on the third anniversary of the date of grant and 75% on the fourth anniversary of the date of grant.

Atlas Pipeline Plan

Officers, employees and non-employee managing board members of Atlas Pipeline’s general partner and employees of the general partner’s affiliates and consultants are eligible to receive awards under the Atlas Pipeline Plan of either phantom units or unit options for an aggregate of 435,000 common units. The Atlas Pipeline Plan is administered by Atlas America’s compensation committee under delegation from the general partner’s managing board. Currently, only phantom units have been issued under the Atlas Pipeline Plan.

A phantom unit entitles a grantee to receive a common unit upon vesting of the phantom unit or, at the discretion of the compensation committee, cash equivalent to the fair market value of a common unit. In addition, the compensation committee may grant a participant a DER, which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions Atlas Pipeline makes on a common unit during the period the phantom unit is outstanding. A unit option entitles the grantee to purchase common units at an exercise price determined by the compensation committee at its discretion. Except for phantom units awarded to non-employee managing board members of the general partner, the compensation committee determines the vesting period for phantom units and the exercise period for options. Phantom units granted under the Atlas Pipeline Plan generally vest over 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 compensation committee, although no awards currently outstanding contain any such provision. Phantom units awarded to non-employee managing board members of the general partner vest over a four-year period. Awards will automatically vest upon a change of control, as defined in the Atlas Pipeline Plan.

Executive Group Incentive Program

In connection with Atlas Pipeline’s acquisition of Spectrum Field Services, Inc. in July 2004, and its retention of certain Spectrum executive officers, an executive group incentive program for Atlas Pipeline’s Mid-Continent operations was created. Eligible participants in the executive group incentive program are Robert R. Firth, David D. Hall and such other of Atlas Pipeline officers as agreed upon by Messrs. Firth and Hall and the Atlas America board of directors. The executive group incentive program has three award components: base incentive, additional incentive and acquisition look-back incentive, as follows:

Base Incentive. An award of 29,411 of Atlas Pipeline common units on the day following the earlier to occur of the filing of Atlas Pipeline’s quarterly report on Form 10-Q for the quarter ending September 30, 2007 or a change in control if the following conditions were met:

• distributable cash flow (defined as earnings before interest, depreciation, amortization and any allocation of overhead from Atlas Pipeline, less maintenance capital expenditures on the Spectrum assets) generated by the Spectrum assets, as expanded since Atlas Pipeline’s acquisition of them, has averaged at least 10.7%, on an annualized basis, of average gross long-term assets (defined as total assets less current assets, closing costs associated with any acquisition and plus accumulated depreciation, depletion and amortization) over the 13 quarters ending September 30, 2007; and

• there having been no more than 2 quarters with distributable cash flow of less than 7%, on an annualized basis, of gross long-term assets for that quarter.

Atlas Pipeline issued 29,411 common units under this component.

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Additional Incentive. An award of Atlas Pipeline common units, promptly upon the filing of its September 30, 2007 Form 10-Q, in an amount equal to 7.42% of the base incentive for each 0.1% by which average annual distributable cash flow exceeds 10.7% of average gross long-term assets, as described above, up to a maximum of an additional 29,411 common units. 29,411 common units were issued under this component.

Acquisition Look-back Incentive. If the requirements for the base incentive have been met, an award of Atlas Pipeline common units determined by dividing (x) 1.5% of the imputed value of the Elk City system plus 1.0% of the imputed value of all Mid-Continent acquisitions completed before December 31, 2007 that were identified by members of the Mid-Continent executive group by (y) the average closing price of Atlas Pipeline common units for the five trading days before December 31, 2008. Imputed value of an acquisition is equal to the distributable cash flow generated by the acquired entity during the 12 months ending December 31, 2008 divided by the yield. Yield is determined by dividing (i) the sum of Atlas Pipeline’s quarterly distributions for the quarter ending December 31, 2008 multiplied by four by (ii) the closing price of its common units on December 31, 2008. A total award of 301,854 common units is expected to be issued under this component.

Atlas Pipeline Holdings Plan

The Atlas Pipeline Holdings Plan provides performance incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners who perform services for Atlas Pipeline Holdings. The Atlas Pipeline Holdings Plan is administered by Atlas America’s compensation committee under delegation from the Atlas Pipeline Holdings board of directors. The compensation committee may grant awards of either phantom units or unit options for an aggregate of 2,100,000 common limited partner units.

Partnership Phantom Units. A phantom unit entitles a participant to receive an Atlas Pipeline Holdings common unit upon vesting of the phantom unit or, at the discretion of the compensation committee, cash equivalent to the then fair market value of a common unit. In tandem with phantom unit grants, the Compensation Committee may grant a DER. The compensation committee determines the vesting period for phantom units. Through December 31, 2008, phantom units granted under the Atlas Pipeline Holdings Plan generally vest 25% on the third anniversary of the date of grant and 75% on the fourth anniversary of the date of grant.

Partnership Unit Options. A unit option entitles a participant to receive a common unit upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of a common unit as determined by the compensation committee on the date of grant of the option. The compensation committee determines the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through December 31, 2008, unit options granted generally will vest 25% on the third anniversary of the date of grant and the remaining 75% on the fourth anniversary of the date of grant.

The vesting of both types of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the compensation committee, although no awards currently outstanding contain any such provision. Awards will automatically vest upon a change of control, as defined in the Atlas Pipeline Holdings Plan.

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2008 Outstanding Equity Awards at Fiscal Year End Table

	Option awards							Stock awards
	Number of securities underlying unexercised options (#)		Number of securities underlying unexercised options (#)		Option exercise price ($)		Option expiration date	Number of shares or units of stock that have not vested (#)		Market value of shares or units of stock that have not vested ($)
Name	Exercisable		Unexercisable
Edward E. Cohen	1,012,500	(1)	—		$	11.32	7/1/2015	—		$	—
	75,000	(2)	225,000	(3)	$	32.53	1/29/2018	—		$	—
	—		500,000	(6)	$	23.06	1/24/2017	200,000	(7)	$	2,554,000	(8)
	—		—			—	—	15,000	(4)	$	90,000	(5)
	—		500,000	(9)	$	22.56	11/10/2016	90,000	(10)	$	340,200	(11)
Matthew A. Jones	202,500	(12)	67,500	(13)	$	11.32	7/1/2015	—		$	—
	30,000	(14)	90,000	(15)	$	32.53	1/29/2018	—		$	—
	—		50,000	(17)	$	23.06	1/24/2017	20,000	(18)	$	255,400	(8)
	—		—			—	—	6,250	(16)	$	37,500	(5)
	—		100,000	(19)	$	22.56	11/10/2016	20,000	(20)	$	75,600	(11)
Jonathan Z. Cohen	675,000	(21)	—		$	11.32	7/1/2015	—		$	—
	60,000	(22)	180,000	(23)	$	32.53	1/29/2018	—		$	—
	—		200,000	(25)	$	23.06	1/24/2017	100,000	(26)	$	1,277,000	(8)
	—		—			—	—	10,625	(24)	$	63,750	(5)
	—		200,000	(27)	$	22.56	11/10/2016	45,000	(28)	$	170,100	(11)
Richard D. Weber	56,250	(29)	56,250	(30)	$	21.27	4/17/2016	—		$	—
	30,000	(31)	90,000	(32)	$	32.53	1/29/2018	—		$	—
	186,876	(33)	186,876	(34)	$	21.00	4/17/2016	23,810	(35)	$	304,054	(8)
	—		—			—	—	—		$	—
	—		—			—	—	—		$	—
Freddie Kotek	101,250	(36)	33,750	(37)	$	11.32	7/1/2015	—		$	—
	15,000	(38)	45,000	(39)	$	32.53	1/29/2018	—		$	—
	—		50,000	(41)	$	23.06	1/24/2017	20,000	(42)	$	255,400	(8)
	—		—			—	—	250	(40)	$	1,500	(5)
	—		—			—	—	—		$	—

(1) Represents 1,012,500 options to purchase Atlas America stock, granted on 7/1/05 in connection with its spin-off from Resource America, which vested immediately. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

(2) Represents 75,000 options to purchase Atlas America stock, granted on 1/29/08. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

(3) Represents options to purchase Atlas America stock, which vest as follows: 1/29/09 — 75,000, 1/29/09 — 75,000 and 1/29/10 — 75,000. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

(4) Represents Atlas Pipeline phantom units, which vest as follows: 3/16/09 — 5,000; 11/1/09 — 5,000 and 11/1/10 — 5,000.

(5) Based on closing market price of Atlas Pipeline common units on December 31, 2008 of $ 6.00.

(6) Represents Atlas Energy options, which vest as follows: 1/24/10 — 125,000 and 1/24/11 — 375,000.

(7) Represents Atlas Energy phantom units, which vest as follows: 1/24/10 — 50,000 and 1/24/17 — 150,000.

(8) Based upon closing price of Atlas Energy common units on December 31, 2008 of $12.77.

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(9) Represents Atlas Pipeline Holdings options, which vest as follows: 11/10/09 — 125,000 and 11/10/10 — 375,000.

(10) Represents Atlas Pipeline Holdings phantom units, which vest as follows: 11/10/09 — 22,500 and 11/10/10 — 67,500.

(11) Based on closing market price of Atlas Pipeline Holdings common units on December 31, 2008 of $3.78.

(12) Represents 202,500 options to purchase Atlas America stock, granted on 7/1/05 in connection with its spin-off from Resource America. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

(13) Represents options to purchase Atlas America stock, which vest as follows: 7/1/09 — 67,500. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

(14) Represents 30,000 options to purchase Atlas America stock, granted on 1/29/08. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

(15) Represents options to purchase Atlas America stock, which vest as follows: 1/29/09 — 30,000, 1/29/09 — 30,000 and 1/29/10 — 30,000. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

(16) Represents Atlas Pipeline phantom units, which vest as follows: 3/16/09 — 3,750; 11/1/09 — 1,250 and 11/1/10 — 1,250.

(17) Represents Atlas Energy options, which vest as follows: 1/24/10 — 12,500 and 1/24/11 — 37,500.

(18) Represents Atlas Energy phantom units, which vest as follows: 1/24/10 — 5,000 and 1/24/11 — 15,000.

(19) Represents Atlas Pipeline Holdings options, which vest as follows: 11/10/09 — 25,000 and 11/10/10 — 75,000.

(20) Represents Atlas Pipeline Holdings phantom units, which vest as follows: 11/10/09 — 5,000 and 11/10/10 — 15,000.

(21) Represents 675,000 options to purchase Atlas America stock, granted on 7/1/05 in connection with its spin-off from Resource America, which vested immediately. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

(22) Represents 60,000 options to purchase Atlas America stock, granted on 1/29/08. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

(23) Represents options to purchase Atlas America stock, which vest as follows: 1/29/09 — 60,000, 1/29/09 — 60,000 and 1/29/10 — 60,000. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

(24) Represents Atlas Pipeline phantom units, which vest as follows: 3/16/09 — 3,125; 11/1/09 — 3,750 and 11/1/10 — 3,750.

(25) Represents Atlas Energy options, which vest as follows: 1/24/10 — 50,000 and 1/24/11 — 150,000.

(26) Represents Atlas Energy phantom units, which vest as follows: 1/24/10 — 25,000 and 1/24/11 — 75,000.

(27) Represents Atlas Pipeline Holdings options, which vest as follows: 11/10/09 — 50,000 and 11/10/10 — 150,000.

(28) Represents Atlas Pipeline Holdings phantom units, which vest as follows: 11/10/09 — 11,250 and 11/10/10 — 33,750.

(29) Represents 56,250 options to purchase Atlas America stock. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

(30) Represents options to purchase Atlas America stock, which vest as follows: 4/17/09 — 28,125 and 4/17/10 — 28,125. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

(31) Represents 22,500 options to purchase Atlas America stock, granted on 1/29/08. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

(32) Represents options to purchase Atlas America stock, which vest as follows: 1/29/09 — 22,500, 1/29/09 — 22,500 and 1/29/10 — 22,500. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

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(33) Represents 186,876 options to purchase Atlas Energy common units.

(34) Represents 186,876 Atlas Energy options, which vest as follows: 4/17/09 — 93,438 and 4/17/10 — 93,438.

(35) Represents Atlas Energy restricted units, which vest as follows: 4/17/09 — 11,905 and 4/17/10 — 11,905.

(36) Represents 101,250 options to purchase Atlas America stock, granted on 7/1/05 in connection with its spin-off from Resource America. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

(37) Represents options to purchase Atlas America stock, which vest as follows: 7/1/09 — 33,750. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

(38) Represents 15,000 options to purchase Atlas America stock, granted on 1/29/08. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

(39) Represents options to purchase Atlas America stock, which vest as follows: 1/29/09 — 15,000, 1/29/09 — 15,000 and 1/29/10 — 15,000. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

(40) Represents Atlas Pipeline phantom units, which vest as follows: 3/16/09 — 250.

(41) Represents Atlas Energy options, which vest as follows: 1/24/10 — 12,500 and 1/24/11 — 37,500.

(42) Represents Atlas Energy phantom units, which vest as follows: 1/24/10 — 5,000 and 1/24/11 — 15,000.

2008 Option Exercises and Stock Vested Table

	Stock awards
Name	Number of shares acquired on vesting (#)		Value realized on vesting ($)
Edward E. Cohen	16,250	(1)	$	557,500
Matthew A. Jones	5,000	(1)	$	176,562
Jonathan Z. Cohen	10,625	(1)	$	353,100
Richard D. Weber	11,905	(2)	$	491,200
Freddie Kotek	250	(1)	$	10,275

(1) Represents Atlas Pipeline common units.

(2) Represents Atlas Energy common units.

2008 Pension Benefits Table

Name	Plan name	Number of years credited service (#)	Present value of accumulated benefit ($)		Payments during last fiscal year ($)
Edward E. Cohen	SERP	6	$	3,208,914	—

For a description of Mr. Cohen’s SERP, see “Information About Atlas America — Director and Executive Compensation — Employment Agreements and Potential Payments Upon Termination or Change of Control — Edward E. Cohen,” and for a discussion of the valuation method and material assumptions applied in quantifying the present value of the accumulated benefit, please see note 16 to Atlas America’s consolidated financial statements included elsewhere in this joint proxy statement/prospectus.

Director Compensation

The independent directors receive a flat fee of $60,000 per year. In addition to the cash compensation, independent directors receive an annual grant of deferred stock having a fair market value of $15,000 with a vesting schedule in which 33% of the award vests on the second, third and fourth anniversaries of the grant date.

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2008 Director Compensation Table

Name	Fees earned or paid in cash ($)		Stock awards ($)(1)		Total ($)
Carlton M. Arrendell	$	60,000	$	15,000	$	75,000
William R. Bagnell	$	60,000	$	15,000	$	75,000
Donald W. Delson	$	60,000	$	15,000	$	75,000
Nicholas A. DiNubile	$	60,000	$	15,000	$	75,000
Dennis A. Holtz	$	60,000	$	15,000	$	75,000
Harmon S. Spolan	$	60,000	$	6,664	$	66,664

(1) Represents the dollar amount of expense recognized by Atlas America for financial statement reporting purposes with respect to deferred units granted under the Atlas America Plan (see Note 16 to Atlas America’s 2008 year end consolidated financial statements) in accordance with FAS 123R. For Messrs. Arrendell, Bagnell, Delson, DiNubile and Holtz, represents 203 deferred shares granted under the Atlas America Plan on May 14, 2008 (adjusted to 305 deferred shares as a result of a 3-for-2 stock split which was effected on June 2, 2008), having a grant date fair value, valued in accordance with FAS 123R at the closing price of Atlas America common stock on the grant date of $73.66 (adjusted to $49.11 post-split), of $14,952. The units vest one-third on each of the second, third and fourth anniversaries of the date of grant. The vesting schedule for the shares is as follows: 5/14/10 — 101; 5/14/11 — 101 and 5/14/12 —103. For Mr. Spolan, who was appointed as a member of the Atlas America board of directors in August 2008, represents 397 deferred shares granted under the Atlas America Plan on August 24, 2008, having a grant date fair value, valued in accordance with FAS 123R at the closing price of Atlas America common stock on the grant date of $37.69, of $14,963. The vesting schedule for the award is as follows: 8/24/10 — 132; 8/24/11 — 132 and 8/24/12 — 133.

Certain Relationships and Related Transactions

Atlas America does not have a separate written policy with respect to transactions with related persons. However, consistent with its code of business conduct and ethics, Atlas America’s policy is to have its board of directors or one of its committees consisting solely of independent directors approve all related party transactions. A “related person” is defined under the applicable SEC regulation and includes Atlas America’s directors, executive officers and beneficial owners of 5% or more of Atlas America common stock. In approving any related person transaction, the board or committee must determine that the transaction is fair and reasonable to Atlas America. All persons performing services for Atlas America are required by its code of business conduct and ethics to report a potential conflict of interest, initially to their immediate supervisor. All of the transactions described below were approved by the Atlas America board of directors or one of its committees consisting solely of independent directors.

In the ordinary course of its business operations, Atlas America and its affiliates have ongoing relationships with several related entities:

Relationship with Atlas Energy and its Partnerships

Atlas Energy conducts certain activities through, and a substantial portion of its revenues are attributable to, energy limited partnerships. Atlas Energy serves as general partner of these partnerships and assumes customary rights and obligations for them. As the general partner, Atlas Energy is liable for the partnerships’ liabilities and can be liable to limited partners if it breaches its responsibilities with respect to the operations of the partnerships. Atlas Energy is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the partnerships’ revenue, and costs and expenses according to the respective partnership agreements.

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Atlas America has entered into a merger agreement with Atlas Energy. If completed, Atlas Energy will become Atlas America’s wholly owned subsidiary. For more information, see “Atlas Energy Proposal / Atlas America Proposal 1: The Merger.”

Relationship with Atlas Pipeline Holdings

On June 1, 2009, Atlas Pipeline Holdings entered into an amendment to its revolving credit facility. In connection with the execution of the amendment, Atlas Pipeline Holdings agreed to immediately repay $30 million of the approximately $46 million outstanding indebtedness under the credit facility, such that approximately $16 million currently remains outstanding. The amendment also terminated Atlas Pipeline Holdings’ right to make further borrowings under the credit facility. Atlas Pipeline Holdings agreed to repay $4 million of the remaining $16 million on each of July 13, 2009, October 13, 2009 and January 13, 2010, with the balance of indebtedness being due on the original maturity date of April 13, 2010. In connection with the execution of this amendment, Atlas America agreed to guarantee the remaining debt outstanding under the credit facility. Pursuant to this guaranty, Atlas America made a $4 million payment in respect of a payment due on July 13, 2009 under the Atlas Pipeline Holdings credit agreement.

Atlas Pipeline Holdings’ $30 million repayment was funded from the proceeds of (i) a loan from Atlas America in the amount of $15 million, with an interest rate of 12% per annum and a maturity date the day following the day Atlas Pipeline Holdings pays all outstanding indebtedness due under the credit facility, and (ii) the purchase by Atlas Pipeline of $15 million of preferred equity in a newly formed subsidiary of Atlas Pipeline Holdings. Moreover, in consideration of Atlas America’s guaranty, Atlas Pipeline Holdings issued to Atlas America an additional promissory note, in which the amount payable under the note equals the interest that would be payable on a loan with a principal amount equal to the outstanding indebtedness under Atlas Pipeline Holdings’ credit facility, where the interest rate equals 3.75% per annum and accrues quarterly. The maturity date on this note is the day following the day Atlas Pipeline Holdings pays all outstanding indebtedness due under the credit facility. Both promissory notes issued by Atlas Pipeline Holdings to Atlas America are payable-in-kind until their maturity date.

Relationship with Resource America

Atlas America has the following agreements with Resource America, Atlas America’s former parent, for which Edward E. Cohen, Atlas America’s Chairman, Chief Executive Officer and President, serves as Chairman and is a greater than 10% stockholder, and Jonathan Z. Cohen, Atlas America’s Vice Chairman, serves as Chief Executive Officer and President.

Tax Matters Agreement

As part of Atlas America’s initial public offering in 2004, it entered into a tax matters agreement with Resource America, which governs their respective rights, responsibilities, and obligations after Atlas America’s initial public offering with respect to tax liabilities and benefits, tax attributes, tax contests and other matters regarding income taxes, non-income taxes and related tax returns.

In general, under the tax matters agreement:

• Resource America is responsible for any U.S. federal income taxes of the affiliated group for U.S. federal income tax purposes of which Resource America is the common parent. With respect to any periods beginning after Atlas America’s initial public offering, it is responsible for any U.S. federal income taxes attributable to it or any of its 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 Atlas America or one of its subsidiaries, on the other hand. However, in the event that Atlas America or one of its subsidiaries is included in such a group for U.S. state or local income tax

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purposes for periods (or portions thereof) beginning after the date of Atlas America’s initial public offering, Atlas America is responsible for its portion of such income tax liability as if it and its subsidiaries had filed a separate tax return that included only it and its 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 Atlas America and its subsidiaries), and Atlas America is responsible for any U.S. state or local income taxes filed on returns that include only it and its subsidiaries.

Atlas America has generally agreed to indemnify Resource America and its affiliates against any and all tax-related liabilities that may be incurred by them relating to the distribution to the extent such liabilities are caused by Atlas America’s actions. This indemnification applies even if Resource America has permitted Atlas America to take an action that would otherwise have been prohibited under the tax-related covenants as described above.

During 2008, Atlas America did not have any liability to Resource America pursuant to the tax matters agreement.

Transition Services Agreement

Also in connection with Atlas America’s initial public offering, it entered into a transition services agreement with Resource America which governs the provision support services between them, such as:

• cash management and debt service administration;

• accounting and tax;

• investor relations;

• payroll and human resources administration;

• legal;

• information technology;

• data processing;

• real estate management; and

• other general administrative functions.

Atlas America and Resource America will pay each other a fee for these services equal to their fair market value. The fee is payable monthly in arrears, 15 days after the close of each month. Atlas America and Resource America also agreed to pay or reimburse each other for any out-of-pocket payments, costs and expenses associated with these services. During fiscal 2008, Atlas America reimbursed Resource America $1.0 million pursuant to this agreement. Certain operating expenditures totaling $0.1 million that remain to be settled between the parties are reflected in Atlas America’s consolidated balance sheets as advances from affiliate.

Resource America’s relationship with Anthem Securities (a wholly owned subsidiary of Atlas Energy)

Anthem Securities, until December 2006 Atlas America’s wholly owned subsidiary and now a wholly owned subsidiary of Atlas Energy, is a registered broker-dealer which provides dealer-manager services for investment programs sponsored by Resource America’s real estate and equipment finance segments. Salaries of the personnel performing services for Anthem are paid by Resource America, and Anthem reimburses Resource America for the allocable costs of such personnel. In addition, Resource America agreed to cover some of the operating costs for Anthem’s office of supervisory jurisdiction, principally licensing fees and costs. In fiscal 2008, there was no activity requiring reimbursements.

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Security Ownership of Certain Beneficial Owners and Management

The following table sets forth the number and percentage of shares of common stock owned, as of August 18, 2009, by (a) each person who, to our knowledge, is the beneficial owner of more than 5% of the outstanding shares of its common stock, (b) each of its present directors and nominees, (c) each of its executive officers serving during the 2008 fiscal year, and (d) all of its directors, nominees and executive officers as a group. This information is reported in accordance with the beneficial ownership rules of the Securities and Exchange Commission under which a person is deemed to be the beneficial owner of a security if that person has or shares voting power or investment power with respect to such security or has the right to acquire such ownership within 60 days. Shares of common stock issuable pursuant to options or warrants are deemed to be outstanding for purposes of computing the percentage of the person or group holding such options or warrants but are not deemed to be outstanding for purposes of computing the percentage of any other person. Unless otherwise indicated in footnotes to the table, each person listed has sole voting and dispositive power with respect to the securities owned by such person.

	Common stock
	Amount and nature of beneficial ownership(2)		Percent of class
Beneficial owner
Directors(1)
Carlton M. Arrendell	5,103		*
Edward E. Cohen	3,910,978	(3)(5)	9.7	%
Jonathan Z. Cohen	2,293,647	(4)(5)	5.7	%
Donald W. Delson	5,603		*
Dennis A. Holtz	8,210		*
Gayle P.W. Jackson	0		*
Mark C. Biderman	2,000		*
Harmon S. Spolan	642	(6)	*
Non-director executive officers(1)
Freddie M. Kotek	376,880	(5)	*
Matthew A. Jones	300,231	(5)	*
Sean P. McGrath	8,552	(5)	*
Richard D. Weber	106,895	(5)	*
All executive officers, directors and nominees as a group (12 persons)	5,569,243	(7)	13.4	%
Other owners of more than 5% of outstanding shares
Cobalt Capital Management, Inc.	5,416,697	(8)	13.8	%
Iridian Asset Management LLC	6,129,817	(9)	15.6	%
Leon G. Cooperman	3,543,338	(10)	9.0	%
Mundar Capital Management	2,436,158	(11)	6.2	%

 * Less than 1%

(1) The business address for each director, director nominee and executive officer is 1550 Coraopolis Heights Road, 2^nd Floor, Moon Township, Pennsylvania 15108.

(2) All shares reflect a 3-for-2 stock split which was effected on June 2, 2008.

(3) Includes (i) 50,454 shares held in an individual retirement account of Betsy Z. Cohen, Mr. E. Cohen’s spouse; (ii) 1,320,202 shares held by a charitable foundation of which Mr. E. Cohen, his spouse and their children serve as co-trustees; and (iii) 141,378 shares held in trust for the benefit of Mr. E. Cohen’s spouse and/or children. Mr. E. Cohen disclaims beneficial ownership of the above-referenced shares. 129,296 and 1,320,202 shares are also included in the shares referred to in footnote 4 below.

(4) Includes (i) 129,296 shares held in a trust of which Mr. J. Cohen is a co-trustee and co-beneficiary and (ii) 1,320,202 shares held by a charitable foundation of which Mr. J. Cohen, his parents and his sibling serve

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as co-trustees. These shares are also included in the shares referred to in footnote 3 above. Mr. J. Cohen disclaims beneficial ownership of the above-referenced shares.

(5) Includes shares issuable on exercise of options granted under the Atlas America Stock Incentive Plan in the following amounts: Mr. E. Cohen — 1,087,500 shares; Mr. J. Cohen — 735,000 shares; Mr. Kotek — 116,250 shares; Mr. Jones — 300,000 shares; Mr. McGrath — 8,438 shares; and Mr. Weber — 106,875 shares.

(6) Includes 394 deferred units issued under the Atlas America Stock Incentive Plan and vesting within 60 days. Each deferred unit, upon vesting, converts into one share of Atlas America common stock.

(7) This number has been adjusted to exclude 129,296 shares and 1,320,202 shares which were included in both Mr. E. Cohen’s beneficial ownership amount and Mr. J. Cohen’s beneficial ownership amount.

(8) This information is based on a Schedule 13G/A filed with the SEC on February 17, 2009. The address for Cobalt Capital Management, Inc. is 237 Park Avenue, Suite 900, New York, New York 10017.

(9) This information is based on a Schedule 13G/A filed with the SEC on February 4, 2009. The address for Iridian Asset Management, LLC is 276 Post Road West, Westport, CT 06880-4704.

(10) This information is based on a Schedule 13G/A filed with the SEC on February 5, 2009. The address for Mr. Cooperman is 88 Pine Street, Wall Street Plaza, 31st Floor, New York, New York 10005.

(11) This information is based on a Schedule 13G/A filed with the SEC on February 12, 2009. The address for Mundar Capital Management is 480 Pierce Street, Birmingham, MI 48009.

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Selected Historical Financial Data of Atlas America

In June 2006, Atlas America changed its year end from September 30 to December 31, and, therefore, the selected historical financial data below includes a transition period of the three months ended December 31, 2005, and its new year ended December 31.

The following table should be read together with Atlas America’s audited consolidated financial statements and notes thereto and Atlas America’s unaudited consolidated financial statements and notes thereto included elsewhere in this joint proxy statement/prospectus. Atlas America has 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 its audited consolidated financial statements included elsewhere in this joint proxy statement/prospectus. Such financial statements have been audited by Grant Thornton LLP, independent registered public accounting firm.

The selected financial data set forth in the table include Atlas America’s historical consolidated financial statements, which have been adjusted to reflect the following:

• in May 2009, Atlas Pipeline Partners, L.P. (NYSE: APL – “APL”), an entity in which Atlas America has a direct and indirect ownership interest and which Atlas America consolidates within its consolidated financial statements, completed the sale of its NOARK gas gathering and interstate pipeline system (“NOARK”). In accordance with FASB Statement No. 144, “Accounting for the Impairment or Disposal of Long-lived Assets” (“SFAS No. 144”), Atlas America has retrospectively adjusted its prior period consolidated financial statements to reflect the amounts related to the operations of NOARK as discontinued operations; and

• the adoption of Statement of Financial Accounting Standards No. 160, “Non-controlling Interests in Consolidated Financial Statements-an amendment of ARB No. 51.” SFAS No. 160 amends ARB No. 51 to establish accounting and reporting standards for the non-controlling interest (minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling 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 statements of operations at amounts that include the amounts attributable to both the parent and the non-controlling interest. Atlas America adopted the requirements of SFAS No. 160 on January 1, 2009, and has reflected the retrospective application for all periods presented.

	Six Months Ended June 30,						Years Ended December 31,								Three Months Ended December 31,			Years Ended September 30,
	2009			2008			2008			2007			2006		2005			2005		2004
	(in thousands, except per share data)
Statement of operations data:
Revenues:
Well construction and completion	$	175,735		$	226,479		$	415,036		$	321,471		$	198,567	$	42,145		$	134,338	$	86,880
Gas and oil production		141,922			155,182			311,850			180,125			88,449		24,086			63,499		48,526
Transmission, gathering and processing		349,737			807,417			1,384,212			767,085			367,551		108,708			262,829		34,483
Administration and oversight		6,495			10,154			19,362			18,138			11,762		2,964			9,875		8,396
Well services		9,932			10,064			20,482			17,592			12,953		2,561			9,552		8,430
Gain on asset sales		105,691			—			—			—			—		—			—		—
Equity income in joint venture		710			—			—			—			—		—			—		—
Gain (loss) on mark-to-market derivatives		(18,277	)		(404,849	)		(63,480	)		(153,325	)		2,316		(138	)		1,887		(255	)
Total revenues		771,945			804,447			2,087,462			1,151,086			681,598		180,326			481,980		186,460

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	Six Months Ended June 30,						Years Ended December 31,									Three Months Ended December 31,			Years Ended September 30,
	2009			2008			2008			2007			2006			2005			2005			2004
	(in thousands, except per share data)
Costs and expenses:
Well construction and completion	$	149,098		$	196,939		$	359,609		$	279,540		$	172,666		$	36,648		$	116,816		$	75,548
Gas and oil production		21,089			23,047			48,194			24,184			8,499			1,721			6,044			5,265
Transmission, gathering and processing		302,890			658,516			1,153,555			617,629			315,081			96,406			229,816			27,870
Well services		4,544			5,062			10,654			9,062			7,337			1,487			5,167			4,399
General and administrative		49,553			45,945			57,787			111,180			44,312			9,614			24,563			16,021
Depreciation, depletion and amortization		100,967			85,214			178,269			100,838			39,408			9,346			24,895			14,700
Goodwill impairment loss		—			—			676,860			—			—			—			—			—
Total costs and expenses		628,141			1,014,723			2,484,928			1,142,433			587,303			155,222			407,301			143,803
Operating income (loss)		143,804			(210,276	)		(397,466	)		8,653			94,295			25,104			74,679			42,657
Other income (expense):
Interest expense		(76,568	)		(69,207	)		(144,065	)		(93,677	)		(26,439	)		(5,420	)		(11,467	)		(2,881	)
Gain on early extinguishment of debt		—			—			19,867			—			—			—			—			—
Other, net		6,135			8,024			11,383			10,696			8,176			318			4,519			(2,219	)
Total other income (expense), net		(70,433	)		(61,183	)		(112,815	)		(82,981	)		(18,263	)		(5,102	)		(6,948	)		(5,100	)
Income (loss) from continuing operations before income taxes		73,371			(271,459	)		(510,281	)		(74,328	)		76,032			20,002			67,731			37,557
Provision (benefit) for income taxes		6,263			(1,431	)		(5,021	)		13,283			26,713			6,577			20,018			11,409
Income (loss) from continuing operations		67,108			(270,028	)		(505,260	)		(87,611	)		49,319			13,425			47,713			26,148
Income from discontinued operations, net of income taxes		59,761			13,848			19,671			29,471			10,986			5,044			—			—
Income (loss) before cumulative effect of accounting change		126,869			(256,180	)		(485,589	)		(58,140	)		60,305			18,469			47,713			26,148
Cumulative effect of accounting change		—			—			—			—			3,825			—			—			—
Net income (loss)		126,869			(256,180	)		(485,589	)		(58,140	)		64,130			18,469			47,713			26,148
(Income) loss attributable to non-controlling interests		(112,858	)		254,831			479,431			93,476			(18,283	)		(6,745	)		(14,773	)		(4,961	)
Net income (loss) attributable to common stockholders	$	14,011		$	(1,349	)	$	(6,158	)	$	35,336		$	45,847		$	11,724		$	32,940		$	21,187
Net income (loss) attributable to common stockholders per share(1):
Basic:
Income (loss) from continuing operations attributable to common stockholders	$	0.25		$	(0.06	)	$	(0.19	)	$	0.82		$	1.01		$	0.24		$	0.73		$	0.54
Income (loss) from discontinued operations attributable to common stockholders		0.11			0.03			0.04			0.05			0.02			0.02			—			—
Net income (loss) attributable to common stockholders	$	0.36		$	(0.03	)	$	(0.15	)	$	0.87		$	1.03		$	0.26		$	0.73		$	0.54
Diluted:
Income (loss) from continuing operations attributable to common stockholders	$	0.24		$	(0.06	)	$	(0.19	)	$	0.78		$	0.99		$	0.24		$	0.73		$	0.54
Income (loss) from discontinued operations attributable to common stockholders		0.11			0.03			0.04			0.05			0.02			0.02			—			—
Net income (loss) attributable to common stockholders	$	0.35		$	(0.03	)	$	(0.15	)	$	0.83		$	1.01		$	0.26		$	0.73		$	0.54

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	Six Months Ended June 30,						Years Ended December 31,									Three Months Ended December 31,			Years Ended September 30,
	2009			2008			2008			2007			2006			2005			2005			2004
	(in thousands, except per share data)
Balance sheet data (at period end):
Property, plant and equipment, net	$	3,714,402		$	3,414,243		$	3,744,815		$	3,210,785		$	884,812		$	535,933		$	508,822		$	314,582
Total assets(2)		4,581,366			5,357,106			4,845,881			4,919,052			1,379,838			1,059,751			762,566			425,200
Total debt, including current portion		2,154,589			2,069,567			2,413,082			1,994,456			324,151			298,781			191,727			135,625
Total stockholders’ equity		1,637,019			1,602,926			1,529,568			2,008,944			677,728			456,147			310,473			223,227
Book value per common share(1)		41.66			39.75			38.24			49.19			15.28			10.14			6.90			5.66
Cash flow data:
Net cash provided by (used in) operating activities(3)	$	119,655		$	15,453		$	(47,416	)	$	195,085		$	62,186		$	53,485		$	113,409		$	62,386
Net cash provided by (used in) investing activities(3)		153,800			(261,554	)		(643,893	)		(3,508,157	)		(184,157	)		(195,567	)		(296,255	)		(182,615	)
Net cash provided by (used in) financing activities		(296,620	)		341,680			649,909			3,273,881			268,108			179,046			171,935			124,049

(1) Amounts have been adjusted to reflect Atlas America’s 3-for-2 stock splits on May 30, 2008, May 25, 2007 and March 10, 2006.

(2) Certain pre-development costs and joint venture receivables previously netted with “Liabilities associated with drilling contracts” of $3.6 million, $3.6 million and $1.5 million as of December 31, 2005 and September 30, 2005 and 2004, respectively, have been reclassified from “Liabilities associated with drilling contracts” to oil and gas properties and accounts receivable to conform to the presentation of “Total assets” for all other periods presented.

(3) Net cash flows provided by operating activities and net cash flows used in investing activities have been restated for the three months ended December 31, 2005 and the fiscal years ended September 30, 2005 and 2004 to conform to the current presentation for all other periods presented (see note 2 above). As a result, net cash flows provided by operating activities have been increased by $0.7 million, $1.4 million and $12.3 million for the three months ended December 31, 2005 and the fiscal years ended September 30, 2005 and 2004, respectively, and net cash flows used in investing activities has been decreased by the same amount for the respective periods, except for the fiscal year ended September 30, 2004, which decreased net cash flows in investing activities by $0.8 million and net cash flows provided by financing activities by $11.5 million.

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

The following discussion provides information to assist in understanding Atlas America’s financial condition and results of operations. This discussion should be read in conjunction with Atlas America’s consolidated financial statements and related notes appearing elsewhere in this joint proxy statement/prospectus.

General

Atlas America is a publicly traded Delaware corporation whose assets currently consist principally of cash on hand and its ownership interests in the following entities:

• Atlas Energy — As of the date of this joint proxy statement/prospectus, Atlas America owns 29,952,996 Atlas Energy common units, representing approximately 47.3% of the outstanding Atlas Energy common units, as well as, indirectly, all of the Atlas Energy Class A units and management incentive interests. Atlas America manages Atlas Energy through Atlas America’s wholly owned subsidiary, Atlas Energy Management, under the supervision of the Atlas Energy board of directors.

• Atlas Pipeline — As of the date of this joint proxy statement/prospectus, Atlas America owns approximately 2.3% of the equity of Atlas Pipeline, a midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachia regions. The limited partnership interests of Atlas Pipeline are traded on the NYSE under the symbol “APL.”

• Atlas Pipeline Holdings — As of the date of this joint proxy statement/prospectus, Atlas America owns approximately 64.4% of the outstanding common units of Atlas Pipeline Holdings, which is a publicly traded Delaware limited partnership and owner of the general partner of Atlas Pipeline. Through Atlas America’s ownership of the general partner of Atlas Pipeline Holdings, Atlas America manages Atlas Pipeline Holdings. As of the date of this joint proxy statement/prospectus, Atlas Pipeline Holdings owns a 2% general partner interest, all of the incentive distribution rights, an approximate 11.8% limited partner interest, and 15,000 $1,000 par value 12.0% cumulative preferred limited partner units.

• Lightfoot LP and Lightfoot GP, the general partner of Lightfoot LP, entities which incubate new MLPs and invest in existing MLPs. Atlas America 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. Atlas America also has direct and indirect ownership interests in Lightfoot LP.

Atlas America has been involved in the energy industry since 1968, expanding its operations in 1998 when it acquired The Atlas Group, Inc. and in 1999 when it acquired Viking Resources Corporation, both engaged in the development and production of natural gas and oil and the sponsorship of investment partnerships. Atlas America was originally incorporated in Delaware in September 2000 to become a holding company for Resource America, Inc.’s energy assets and subsidiaries. In May 2004, Atlas America completed an initial public offering of 2,645,000 shares of its common stock. After the initial public offering, Resource America, Inc. continued to own approximately 80.2% of Atlas America. In June 2005, Resource America, Inc. spun-off its remaining ownership interest in Atlas America to Resource America, Inc.’s common stockholders in the form of a tax-free dividend. Atlas America common stock is traded on NASDAQ under the symbol “ATLS.”

Atlas America’s ownership of Atlas Energy Class A units entitles it to receive 2% of the cash distributed by Atlas Energy without any obligation to make future capital contributions to Atlas Energy. Atlas America’s ownership of Atlas Energy’s management incentive interests entitles it to receive an increasing percentage of cash distributed by Atlas Energy as it reaches certain target distribution levels after Atlas Energy has met the tests set forth within the Atlas Energy operating agreement. The rights entitle Atlas America to receive 15.0% of all cash distributed in a quarter after each Atlas Energy common unit has received $0.48 for that quarter, and 25.0% of all cash distributed after each Atlas Energy common unit has received $0.59 for that quarter. As set

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forth in Atlas Energy’s limited liability company agreement, for Atlas America to receive distributions from Atlas Energy under the management incentive interests, Atlas Energy must:

• for 12 full, consecutive, non-overlapping calendar quarters, (a) pay a quarterly cash distribution to the outstanding Atlas Energy 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 Atlas Energy 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 Atlas Energy 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.

Effective April 27, 2009, Atlas Energy suspended further distributions pursuant to the merger agreement. Atlas Energy’s suspension of the quarterly distribution during the six months ended June 30, 2009 means that it will not comply with the terms of the 12-quarter test and, as such, Atlas Energy Management will not receive the management incentive distributions that were reserved for during previous periods.

Atlas America’s ownership interest in Atlas Pipeline consists of 1,112,000 common units, representing approximately 2.3% of the outstanding common units of Atlas Pipeline at June 30, 2009, or a 2.3% ownership interest.

Atlas America’s ownership interest in Atlas Pipeline Holdings consists of 17,808,109 common units, representing approximately 64.4% of the outstanding common units of Atlas Pipeline Holdings at June 30, 2009. Atlas Pipeline Holdings’ general partner, which is a wholly owned subsidiary of Atlas America, does not have an economic interest in Atlas Pipeline Holdings, and Atlas Pipeline Holdings’ capital structure does not include incentive distribution rights. Atlas Pipeline Holdings’ ownership interest in Atlas Pipeline consists of the following:

• a 2.0% general partner interest, which entitles it to receive 2% of the cash distributed by Atlas Pipeline;

• 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 Atlas Pipeline as it reaches certain target distribution levels in excess of $0.42 per Atlas Pipeline common unit in any quarter. In connection with Atlas Pipeline’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems, Atlas Pipeline Holdings, the holder of all of the incentive distribution rights in Atlas Pipeline, had agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to Atlas Pipeline through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter;

• 5,754,253 common units, representing approximately 12.0% of the outstanding common units at June 30, 2009, or a 11.8% ownership interest in Atlas Pipeline; and

• 15,000 $1,000 par value 12.0% cumulative preferred limited partner units at June 30, 2009.

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

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

• 23.0% of all cash distributed after each Atlas Pipeline common unit has received $0.52 for that quarter; and

• 48.0% of all cash distributed after each Atlas Pipeline common unit has received $0.60 for that quarter.

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The recent amendment to Atlas Pipeline’s credit agreement restricts Atlas Pipeline from paying distributions for the remainder of 2009 and permits distributions commencing with the quarter ending March 31, 2010 only if, on a pro forma basis after such payment, Atlas Pipeline’s senior secured leverage ratio is less than or equal to 2.75 to 1.00 and its minimum liquidity, defined generally as cash and cash equivalents less restricted cash plus amounts available for borrowing under the revolver portion of the credit facility, is at least $50 million. In addition, Atlas Pipeline Holdings is restricted under its credit agreement from paying distributions until it repays in full the indebtedness under the credit facility.

Financial Presentation

Atlas America’s principal operating activities are conducted principally through Atlas Energy, Atlas Pipeline Holdings, and Atlas Pipeline, and Atlas America’s cash flows consist primarily of distributions received from Atlas Energy, Atlas Pipeline and Atlas Pipeline Holdings on Atlas America’s ownership interests. Atlas America’s consolidated financial statements contain the consolidated financial statements of Atlas Energy and Atlas Pipeline Holdings, and Atlas Pipeline Holdings’ consolidated financial statements include the consolidated financial statements of Atlas Pipeline. The non-controlling interests in Atlas Energy, Atlas Pipeline Holdings and Atlas Pipeline are reflected as income (loss) attributable to non-controlling interests in Atlas America’s consolidated statements of operations and as a component of stockholders’ equity on Atlas America’s consolidated balance sheets. Throughout this section, when we refer to Atlas America’s consolidated financial statements, we are referring to the consolidated results for Atlas America and its wholly owned subsidiaries and the consolidated results of Atlas Energy and Atlas Pipeline Holdings, including Atlas Pipeline’s financial results, adjusted for non-controlling interests in Atlas Energy’s, Atlas Pipeline Holdings’ and Atlas Pipeline’s net income (loss).

Atlas Energy

Atlas Energy is an independent developer and producer of natural gas and oil, with operations in the Appalachian Basin, the Michigan Basin, and the Illinois Basin. Within these Basins, it focuses its drilling and production in four established shale plays; namely, the Marcellus Shale of western Pennsylvania, the Antrim Shale of northern Michigan, the Chattanooga Shale of northeastern Tennessee, and the New Albany Shale of west central Indiana. Atlas Energy’s Appalachian Basin major operations are located in eastern Ohio, western Pennsylvania, and north central Tennessee. It has additional operations in New York, West Virginia and Kentucky. Atlas Energy specializes in development of these natural gas basins because they provide it with repeatable, low-risk drilling opportunities. Atlas Energy is also a leading sponsor and manager of tax-advantaged direct investment natural gas and oil partnerships in the United States. It funds the drilling of natural gas and oil wells on its acreage by sponsoring and managing tax advantaged investment partnerships. Atlas Energy generally structures its investment partnerships so that, upon formation of a partnership, it co-invests in and contributes leasehold acreage to it, enters into drilling and well operating agreements with it and becomes its managing general partner. Atlas Energy is managed by Atlas Energy Management, Inc., Atlas America’s wholly-owned subsidiary, through which it provides Atlas Energy with the personnel necessary to manage its assets and raise capital.

As of and for the six months ended June 30, 2009, Atlas Energy had the following key assets:

Appalachia gas and oil operations

• direct and indirect working interests in approximately 8,631 gross producing gas and oil wells;

• overriding royalty interests in approximately 629 gross producing gas and oil wells;

• net daily production of 42.9 million cubic feet equivalents per day (“MMcfed”) for the six months ended June 30, 2009; and

• approximately 935,300 gross (889,700 net) acres, of which approximately 623,300 gross (616,400 net) acres, are undeveloped. Included in the undeveloped acreage is 531,950 Marcellus Shale acres in Pennsylvania, New York and West Virginia, of which approximately 266,100 acres are located in Atlas Energy’s core Marcellus Shale position in southwestern Pennsylvania.

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Michigan gas and oil operations

• direct and indirect working interests in approximately 2,488 gross producing gas and oil wells;

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

• net daily production of 58.0 MMcfed for the six months ended June 30, 2009; and

• approximately 344,400 gross (272,200 net) acres, of which approximately 35,800 gross (28,100 net) acres, are undeveloped.

Indiana gas and oil operations

• direct and indirect working interests in approximately 16 gross producing gas and oil wells;

• net daily production of 0.2 Mmcfed for the six months ended June 30, 2009; and

• approximately 244,100 gross (118,200 net) acres, of which approximately 239,100 gross (114,400 net) acres, are undeveloped.

Partnership management business

• Atlas Energy investment partnership business, which includes equity interests in 95 investment partnerships and a registered broker-dealer which acts as the dealer-manager of Atlas Energy’s investment partnership offerings.

• since July 2008, Atlas Energy has raised $560.0 million in investor funds, including $122.8 million raised in the three months ended June 30, 2009 for its most recent investment partnership, Atlas Resources Public #18-2009(B) L.P.

Atlas Pipeline Holdings and Atlas Pipeline

Atlas Pipeline Holdings is the general partner of Atlas Pipeline and its cash generating assets currently consist solely of its interests in Atlas Pipeline.

Atlas Pipeline is a leading provider of natural gas gathering services in the Anadarko 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, Atlas Pipeline is a leading provider of natural gas processing and treatment services in Oklahoma and Texas. Atlas Pipeline’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.

As of June 30, 2009, through its Mid-Continent operations, Atlas Pipeline owns and operates:

• eight active 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

• 8,750 miles of active natural gas gathering systems located in Oklahoma, Kansas and Texas, which transport gas from wells and central delivery points in the Mid-Continent region to Atlas Pipeline’s natural gas processing and treating plants or third party pipelines.

As of June 30, 2009, Atlas Pipeline’s Appalachia operations are conducted principally through its 49% ownership interest in Laurel Mountain Midstream, LLC (“Laurel Mountain”—see “Recent Events”), a joint venture which owns and operates a 1,700 mile natural gas gathering system in the Appalachia Basin located in eastern Ohio, western New York, and western Pennsylvania. Atlas Pipeline also owns a 65-mile natural gas gathering system in northeastern Tennessee. Laurel Mountain gathers the majority all of the natural gas from wells operated by Atlas Energy.

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Subsequent Events

New Atlas Energy Derivative Positions

On July 20, 2009, Atlas Energy entered into certain natural gas derivative contracts for calendar 2013 production volume of 220,000 MMbtu per month with an average fixed price of $6.90 per MMbtu.

Atlas Energy Issuance of Senior Unsecured Notes

On July 16, 2009, Atlas Energy issued $200.0 million of 12.125% senior unsecured notes (“Atlas Energy 12.125% Senior Notes”) due 2017 at 98.116% of par value to yield 12.5% at maturity. Atlas Energy used the net proceeds of $191.7 million, net underwriting fees of $4.5 million, to repay outstanding borrowings under its revolving credit facility (see “Atlas Energy Credit Facility”). Under the terms of its credit facility, the credit facility borrowing base is automatically reduced by 25% of the stated principal amount of any senior unsecured notes offering by Atlas Energy. As such, the borrowing base of the credit facility was reduced by $50.0 million to $600.0 million upon the issuance of the Atlas Energy 12.125% Senior Notes. Interest on the Atlas Energy 12.125% Senior Notes is payable semi-annually in arrears on February 1 and August 1 of each year. The Atlas Energy 12.125% Senior Notes are redeemable at any time at certain redemption prices, together with accrued interest at the date of redemption. In addition, before August 1, 2012, Atlas Energy may redeem up to 35% of the aggregate principal amount of the Atlas Energy 12.125% Senior Notes with the proceeds of certain equity offerings at a stated redemption price of 112.125% of the principal, plus accrued interest. The Atlas Energy 12.125% Senior Notes are junior in right of payment to Atlas Energy’s secured debt, including its obligations under the revolving credit facility. The indenture governing the Atlas Energy 12.125% Senior Notes contains covenants, including limitations of Atlas Energy’s ability to incur certain liens, engage in sale/leaseback transactions, incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase, or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of Atlas Energy’s assets.

Sale of Atlas Pipeline Natural Gas Processing Facility

On July 13, 2009, Atlas Pipeline sold a natural gas processing facility and a one-third undivided interest in other associated assets located in its Mid-Continent operating segment for approximately $22.6 million in cash. The facility was sold to Penn Virginia Resource Partners, L.P. (NYSE: PVR), who will provide natural gas volumes to the facility and reimburse Atlas Pipeline for its proportionate share of the operating expenses. Atlas Pipeline will continue to operate the facility. Atlas Pipeline used the proceeds from this transaction to reduce outstanding borrowings under its senior secured credit facility.

Consent of Atlas Energy Lenders to Permit Merger with Atlas America

On July 10, 2009, Atlas Energy received the requisite consent from its lenders to amend its revolving credit facility to permit the merger with Atlas America. The material terms of the amendment are:

• The merger with Atlas America will be permitted;

• Restrictions on Atlas Energy’s ability to make payments with respect to its equity interest will be revised to permit it to make distributions to Atlas America in an amount equal to the income tax liability at the highest marginal rate attributable to Atlas Energy’s net income. In addition, Atlas Energy will be permitted to make distributions to Atlas America of up to $40.0 million per year and, to the extent that it distributes less than that amount in any year, may carry over up to $20.0 million for use in the next year; and

• The definition of change of control will be revised to include a change of control of Atlas America.

The amendment will become effective upon consummation of the merger.

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Atlas Pipeline Receipt of Additional Cash Proceeds on Sale of NOARK system

On July 7, 2009, Atlas Pipeline received an additional $2.5 million in cash upon the delivery of audited financial statements for the NOARK system assets to Spectra in connection with the completion of the Partnership’s sale of its NOARK gas gathering and interstate pipeline system to Spectra for net proceeds of $292.0 million in cash, net of working capital adjustments (see “Recent Developments”).

Recent Developments

Atlas Energy Completion of Fundraising for Atlas Resources Public #18-2008 Drilling Program

On June 29, 2009, Atlas Energy completed fundraising for Atlas Resources Public #18-2008 Drilling Program, raising $122.8 million, representing the second partnership (Atlas Resources Public #18-2009(B) L.P.) in the program. Atlas Resources, LLC, Atlas Energy’s wholly-owned subsidiary, serves as the managing general partner.

Amendment to Atlas Pipeline Holdings’ Revolving Credit Facility

On June 1, 2009, Atlas Pipeline Holdings entered into an amendment to its credit facility agreement which, among other changes:

• required Atlas Pipeline Holdings to immediately repay $30.0 million of then-outstanding $46.0 million of borrowings under the credit facility, $16.0 million of which was borrowed from Atlas America through a subordinate loan;

• required Atlas Pipeline Holdings to repay $4.0 million of the remaining $16.0 million outstanding under the credit facility on each of July 13, 2009, October 13, 2009 and January 13, 2010, with the balance of the indebtedness being due on the original maturity date of the credit facility of April 13, 2010. Atlas Pipeline Holdings repaid $4.0 million of its outstanding credit facility borrowings on July 13, 2009 in accordance with the amendment through a subordinate loan with Atlas America. Atlas Pipeline Holdings may not borrow additional amounts under the credit facility or issue letters of credit;

• required Atlas Pipeline Holdings to use any of its “excess cash flow”, which the amendment generally defines as cash in excess of $1.5 million as of the last business day of each month, to repay outstanding borrowings under the credit facility. In addition, the amendment requires Atlas Pipeline Holdings to repay borrowings under the credit facility with the net proceeds of any sales of its common units in Atlas Pipeline;

• eliminated all financial covenants in the credit agreement, including the leverage ratio, the combined leverage ratio with Atlas Pipeline, and the interest coverage ratio (all as defined within the credit facility agreement);

• prohibits Atlas Pipeline Holdings from paying any cash distributions on or redeeming any of its equity while the credit facility is in effect and permits Atlas Pipeline Holdings to pay operating expenses only to the extent incurred or paid in the ordinary course of business; and

• reduces the applicable margin above LIBOR, the federal funds rate plus 0.5% or the Wachovia Bank, National Association prime rate to be 0.75% for LIBOR loans and 0.0% for federal funds rate or prime rate loans.

On June 1, 2009, in connection with its amendment of the credit facility, Atlas Pipeline Holdings borrowed $15.0 million from Atlas America under a subordinate loan. The maturity date of the subordinate loan is generally the day following the date that Atlas Pipeline Holdings repays all outstanding borrowings under its credit facility. Interest on the outstanding balance under the loan accrues quarterly at the rate of 12.0% per annum. However, prior to the maturity date of the subordinate loan, interest on the outstanding balance under the subordinate loan will not be payable in cash, but instead the principal amount of the loan will be increased by the interest amount payable.

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On June 1, 2009, in connection with Atlas Pipeline Holdings’ amendment of its credit facility, Atlas America guaranteed the remaining balance outstanding under Atlas Pipeline Holdings’ credit facility under a guarantee agreement with the administrative agent of its credit facility. In consideration for this guarantee, Atlas Pipeline Holdings issued to Atlas America a promissory note which requires Atlas Pipeline Holdings to pay interest to Atlas America in an amount equal to the principal amount outstanding under its credit facility. The maturity date of the promissory note is the day following the date that Atlas Pipeline Holdings repays all outstanding borrowings under its credit facility. Interest on the promissory note, which is calculated on the outstanding balance under the credit facility, accrues quarterly at the rate of 3.75% per annum. However, prior to the maturity date of the promissory note, interest under the promissory note will not be payable in cash, but instead the principal amount upon which interest is calculated will be increased by the interest amount payable.

Atlas Pipeline Holdings’ Issuance of Preferred Units to Atlas Pipeline

On June 1, 2009, a newly created, wholly-owned subsidiary of Atlas Pipeline Holdings, Atlas Pipeline Holdings II, LLC (“AHD Sub”), issued $15.0 million of $1,000 par value 12.0% Class B preferred equity (“AHD Sub Preferred Units”) to Atlas Pipeline for cash pursuant to a certificate of designation. Atlas Pipeline Holdings utilized the net proceeds from the issuance to reduce borrowings under its credit facility. Distributions on the AHD Sub Preferred Units are payable quarterly on the same date as the distribution payment date for Atlas Pipeline Holdings’ common units. Distributions on the AHD Sub Preferred Units shall initially be paid in cash or by increasing the amount of the AHD Sub Preferred Unit equity by the amount of the distribution. However, under the terms of the certificate of designation, prior to the repayment of all outstanding borrowings under Atlas Pipeline Holdings’ credit facility, AHD Sub may only pay a cash distribution on the AHD Sub Preferred Units if Atlas Pipeline Holdings has received distributions on Atlas Pipeline’s 12.0% Class B preferred units. After Atlas Pipeline Holdings has repaid all outstanding borrowings under its credit facility, all subsequent distributions declared by AHD Sub on the AHD Sub Preferred Units shall be paid in cash. AHD Sub has the option of redeeming some or all of the AHD Sub Preferred Units, subject to certain limitations under the terms of the certificate of designation. As Atlas Pipeline owns all of the outstanding AHD Sub Preferred Units in an amount equal to the Class B Preferred Units of Atlas Pipeline that Atlas Pipeline Holdings owns, the amounts eliminate in consolidation of Atlas America’s consolidated balance sheet as of June 30, 2009.

Completion of Sale of Atlas Pipeline’s Appalachia System and Entry by Atlas Energy into Gathering Agreements with Laurel Mountain

On May 31, 2009, Atlas Pipeline and subsidiaries of The Williams Companies, Inc. (NYSE: WMB) (“Williams”) completed the formation of the Laurel Mountain Midstream, LLC joint venture (“Laurel Mountain”), which currently owns and operates Atlas Pipeline’s former Appalachia Basin natural gas gathering system, excluding its Northern Tennessee operations. To Laurel Mountain, Williams contributed cash of $100.0 million, of which Atlas Pipeline received approximately $87.8 million, net of working capital adjustments, and a note receivable of $25.5 million. Atlas Pipeline contributed the Appalachia Basin natural gas gathering system and retained a 49% ownership interest in Laurel Mountain, which includes entitlement to preferred distribution rights relating to all payments on the note receivable. Williams retained the remaining 51% ownership interest in Laurel Mountain. Upon completion of the transaction, Atlas Pipeline recognized its 49% ownership interest in Laurel Mountain as an investment in joint venture on Atlas America’s consolidated balance sheet at fair value and recognized a gain on sale of $105.7 million, including $79.7 million associated with the remeasurement of Atlas Pipeline’s investment in Laurel Mountain to fair value. In addition, Atlas Energy sold to Laurel Mountain two natural gas processing plants and associated pipelines located in Southwestern Pennsylvania for $10.0 million, resulting in a $4.2 million loss which is included in gain on asset sale on Atlas America’s consolidated statement of operations. Upon the completion of the transaction, Laurel Mountain entered into new gas gathering agreements with Atlas Energy which superseded the existing natural gas gathering agreements and omnibus agreement between Atlas Pipeline and Atlas Energy. Under the new gas gathering agreement, Atlas Energy will be obligated to pay Laurel Mountain all of the gathering fees it collects from its investment drilling partnerships plus any excess amount over the amount of the competitive gathering fee (which is currently defined as 13% of

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the gross sales price received for the partnerships’ gas). The new gathering agreement contains additional provisions which define certain obligations and options of each party to build and connect newly drilled wells to any Laurel Mountain gathering system. Atlas Pipeline’s ownership interest in Laurel Mountain has been recognized in accordance with the equity method of accounting within Atlas America’s consolidated financial statements. Atlas Pipeline used the net proceeds from the transaction to reduce borrowings under its senior secured credit facility.

Amendment to Atlas Pipeline’s Revolving Credit Facility

On May 29, 2009, Atlas Pipeline entered into an amendment to its credit facility agreement which, among other changes:

• increased the applicable margin above adjusted LIBOR, the federal funds rate plus 0.5% or the Wachovia Bank prime rate upon which borrowings under the credit facility bear interest;

• for borrowings under the credit facility that bear interest at LIBOR plus the applicable margin, set a floor for the adjusted LIBOR interest rate of 2.0% per annum;

• increased the maximum ratios of funded debt (as defined in the credit agreement) to consolidated EBITDA (as defined in the credit agreement; the “leverage ratio”) and interest coverage (as defined in the credit agreement) that the credit facility requires Atlas Pipeline to maintain;

• instituted a maximum ratio of senior secured debt (as defined in the credit agreement) to consolidated EBITDA (the “senior secured leverage ratio”) that the credit facility requires Atlas Pipeline to maintain;

• requires that Atlas Pipeline pay no cash distributions during the remainder of the year ended December 31, 2009 and allows Atlas Pipeline to pay cash distributions beginning January 1, 2010 if its senior secured leverage ratio is less than 2.75x and Atlas Pipeline have minimum liquidity (as defined in the credit agreement) of at least $50.0 million;

• generally limits Atlas Pipeline’s annual capital expenditures to $95.0 million for the remainder of fiscal 2009 and $70.0 million each year thereafter;

• permitted Atlas Pipeline to retain (i) up to $135.0 million of net cash proceeds from dispositions completed in fiscal 2009 for reinvestment in similar replacement assets within 360 days, and (ii) up to $50 million of net cash proceeds from dispositions completed in any subsequent fiscal year subject to certain limitations as defined within the credit agreement; and

• instituted a mandatory repayment requirement of the outstanding senior secured term loan from excess cash flow (as defined in the credit agreement) based upon Atlas Pipeline’s leverage ratio.

Completion of Sale of NOARK by Atlas Pipeline

On May 4, 2009, Atlas Pipeline completed the sale of its NOARK gas gathering and interstate pipeline system to Spectra Energy Partners OLP, LP (NYSE: SEP) (“Spectra”) for net proceeds of $292.0 million in cash, net of working capital adjustments (see “Subsequent Events”). Atlas Pipeline used the net proceeds from the transaction to reduce borrowings under its senior secured term loan and revolving credit facility (see “—Atlas Pipeline Term Loan and Revolving Credit Facility”). Atlas Pipeline has recognized the sale of the NOARK system assets as discontinued operations within Atlas America’s consolidated financial statements.

Early Termination of Derivative Positions by Atlas Energy

In May 2009, Atlas Energy received approximately $28.5 million in proceeds from the early settlement of natural gas and oil derivative positions for production periods from 2011 through 2013. In conjunction with the early termination of these derivatives, Atlas Energy entered into new derivative positions at prevailing prices at the time of the transaction. The net proceeds from the early termination of these derivatives were used to reduce indebtedness under Atlas Energy’s revolving credit facility.

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Atlas Energy Shelf Registration Statement

On May 1, 2009, Atlas Energy’s shelf registration statement was declared effective by the Securities and Exchange Commission, which permits it to periodically issue up to $500.0 million of equity and debt securities. On July 28, 2009, Atlas Energy filed an additional shelf registration in connection with its July 16, 2009 Senior Notes offering (see “Subsequent Events”). The amount, type and timing of any additional offerings will depend upon, among other things, Atlas Energy’s funding requirements, prevailing market conditions and compliance with its credit facility and unsecured senior note covenants.

Atlas America and Atlas Energy Merger Agreement

On April 27, 2009, Atlas America and Atlas Energy executed a definitive merger agreement, pursuant to which Atlas America’s newly formed subsidiary will merge with and into Atlas Energy, with Atlas Energy surviving as Atlas America’s wholly-owned subsidiary. In the merger, each Class B common unit of Atlas Energy not currently held by Atlas America will be converted into 1.16 shares of Atlas America’s common stock, and Atlas America will be renamed “Atlas Energy, Inc.”. Atlas America’s board of directors has approved the merger agreement and has resolved to recommend that Atlas America’s stockholders vote in favor of the transactions contemplated by the merger agreement. Atlas Energy’s board of directors and a special committee of its directors comprised entirely of independent directors have also approved the merger agreement and have resolved to recommend that Atlas Energy’s stockholders vote in favor of the merger. Pending consummation of the merger, Atlas Energy has suspended distributions to its Class A and Class B members’ interests. Atlas Energy’s suspension of the quarterly distribution during the six months ended June 30, 2009 means that it will not comply with the terms of the 12 quarter test and, as such, Atlas America will not receive the management incentive distributions that were reserved for during previous periods. The transaction will be subject to approval by holders of a majority of Atlas America’s outstanding common stock, a majority of Atlas Energy’s outstanding Class B units and other customary closing conditions.

Amendment to Atlas Energy’s Revolving Credit Facility

Effective April 9, 2009, Atlas Energy entered into a second amendment to its credit agreement with a syndicate of banks. Among other provisions, the amendment adjusts the credit facility borrowing base to $650.0 million (see “Subsequent Events”) and amends the definition of applicable margin to, among other things, adjust the Eurodollar Loans rate to a range of 200 to 300 basis points and the applicable margin for base rate loans from a range of 0 to 75 basis points to a range of 112.5 to 212.5 basis points, subject to amounts drawn against the credit facility.

Atlas Pipeline

Since Atlas Pipeline’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, Atlas Pipeline 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 transaction was effected by the formation of two joint venture companies which own the respective systems, to which Atlas Pipeline contributed $1.9 billion and Anadarko contributed the Anadarko Assets. Atlas Pipeline 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, Atlas Pipeline Holdings purchased $168.8 million of these Atlas Pipeline 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. Atlas Pipeline Holdings, as general partner and holder all of Atlas Pipeline’s incentive distribution rights, also agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to Atlas Pipeline through the quarter ended June 30, 2009, and up to

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$3.75 million per quarter thereafter. Atlas Pipeline Holdings also agreed that the resulting allocation of incentive distribution rights back to Atlas Pipeline would be after Atlas Pipeline Holdings 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 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, Atlas Pipeline reached an agreement with Pioneer, 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. Atlas Pipeline will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercises the purchase options.

Contractual Revenue Arrangements

Atlas Energy

Appalachia Natural Gas.

Atlas Energy markets its natural gas, which is principally located in the Fayette County, PA area, primarily to Hess Corporation, Colonial Energy, Inc., UGI Energy Services and others. Atlas America expect that natural gas produced from Atlas Energy’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, Atlas Energy 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 Atlas Energy and its affiliates from specific projects at certain delivery points. Based on recent production data available to Atlas Energy, Atlas America anticipates that Atlas Energy 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.

Crude Oil.

Crude oil produced from Atlas Energy’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. Atlas Energy 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.

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Investment Partnerships.

Atlas Energy generally funds its drilling activities through sponsorship of tax-advantaged investment partnerships. In addition to providing capital for its drilling activities, Atlas Energy’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, Atlas Energy receives the following fees:

• Well construction and completion.For each well that is drilled by an investment partnership, Atlas Energy receives an 18% mark-up on those costs incurred to drill and complete the well.

• Administration and oversight.For each well drilled by an investment partnership, Atlas Energy receives a fixed fee of approximately $15,000 ($62,000 for Marcellus wells). Additionally, the partnership pays Atlas Energy a monthly per well administrative fee of $75 for the life of the well. Because Atlas Energy coinvests in the partnerships, the net fee that it receives is reduced by its proportionate interest in the well.

• Well services.Each partnership pays Atlas Energy a monthly per well operating fee, currently $100 to $1,500, for the life of the well. Because Atlas Energy coinvests in the partnerships, the net fee that Atlas Energy receives is reduced by its proportionate interest in the well.

Atlas Pipeline Partners

Atlas Pipeline’s revenue primarily consists of the fees earned from its transmission, gathering and processing operations. Under certain agreements, Atlas Pipeline 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, Atlas Pipeline transports natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas. In connection with its gathering and processing operations, Atlas Pipeline enters into the following types of contractual relationships with its producers and shippers:

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

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

Keep-Whole Contracts. These contracts require Atlas Pipeline, as the processor, to purchase raw natural gas from the producer at current market rates. Therefore, Atlas Pipeline 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 Atlas Pipeline’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 Atlas America and its subsidiaries. These risks include the availability and costs

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associated with Atlas America’s and its subsidiaries’ borrowing capabilities and raising additional capital, and an increase in the volatility of Atlas America’s and its subsidiaries’ common equity market price. While Atlas America and its subsidiaries do not currently have any plans to access the capital markets, should Atlas America or its subsidiaries 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 Atlas Energy’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 Atlas America and Atlas Energy 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 Atlas Energy produces will generally approximate market prices in the geographic region of the production. In order to address, in part, volatility in commodity prices, Atlas Energy has implemented a hedging program that is intended to reduce the volatility in its revenues. This program mitigates, but does not eliminate, Atlas Energy’s sensitivity to short-term changes in commodity prices. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Atlas America — Quantitative and Qualitative Disclosures About Market Risk” below.

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. Atlas America and Atlas Energy 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 Atlas Energy 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 Atlas America and Atlas Energy anticipate continued high levels of exploration and production activities over the long-term in the areas in which Atlas Energy 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. Atlas America and Atlas Energy have no control over the level of drilling activity in the areas of Atlas Energy’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.

Atlas Pipeline 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 Atlas Pipeline’s competitors operate as master limited partnerships and enjoy a cost of capital comparable to and, in some cases lower than, Atlas Pipeline. Other competitors, such as major oil and gas and pipeline companies, have capital

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resources and control supplies of natural gas substantially greater than Atlas Pipeline. Smaller local distributors may enjoy a marketing advantage in their immediate service areas. Atlas America and Atlas Pipeline believe the primary difference between Atlas Pipeline and some of its competitors is that Atlas Pipeline provides an integrated and responsive package of midstream services, while some of its competitors provide only certain services. Atlas America and Atlas Pipeline believe that offering an integrated package of services, while remaining flexible in the types of contractual arrangements that Atlas Pipeline offers producers, allows Atlas Pipeline to compete more effectively for new natural gas supplies in its regions of operations.

As a result of Atlas Pipeline’s POP and keep-whole contracts, its results of operations and financial condition substantially depend upon the price of natural gas and NGLs. Atlas America and Atlas Pipeline believe 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, Atlas Pipeline generally expects NGL prices to follow changes in crude oil prices over the long term, which Atlas America and Atlas Pipeline 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. However, energy market uncertainty has negatively impacted North American drilling activity in the recent past. Lower drilling levels and shut-in wells 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:

	Six Months Ended June 30,
	2009		2008
Atlas Energy:
Production revenues (in thousands):
Gas	$	136,771	$	147,091
Oil	$	5,151	$	8,091
Production volume(1)(2):
Gas (mcfd)		98,495		90,683
Oil (bpd)		441		420
Total (mcfed)		101,141		93,203
Average sales prices(2):
Gas (per mcf)(3)(4)	$	7.79	$	9.39
Oil (per bbl)(5)	$	67.66	$	106.02
Production costs (per Mcfe)(2)(6):
Lease operating expenses	$	0.84	$	0.81
Production taxes		0.17		0.38
Total production costs per mcf	$	1.01	$	1.19
Atlas Pipeline:
Appalachia system throughput volume (mcfd)(2)(7)		103,003		80,054
Velma system gathered gas volume (mcfd)(2)		73,050		63,960
Elk City/Sweetwater system gathered gas volume (mcfd)(2)		237,445		298,961
Chaney Dell system gathered gas volume (mcfd)(2)		289,889		268,008
Midkiff/Benedum system gathered gas volume (mcfd)(2)		157,687		146,350
Combined throughput volume (mcfd)(2)		861,074		857,333

(1) 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.

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(2) “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.

(3) Atlas Energy’s average sales price before the effects of financial hedging was $4.35 per Mcf and $9.79 per Mcf for the six months ended June 30, 2009 and 2008, respectively.

(4) Includes $2.1 million and $7.9 million of derivative proceeds which were not included as revenue for the six months ended June 30, 2009 and 2008, respectively.

(5) Atlas Energy’s average sales price for oil before the effects of financial hedging was $46.26 per barrel and $109.12 per barrel for the six months ended June 30, 2009 and 2008, respectively.

(6) 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.

(7) Includes 100% of the throughput volume of Laurel Mountain, a joint venture in which Atlas Pipeline has a 49% ownership interest, for the period from May 31, 2009, its date of inception, through June 30, 2009.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

Natural Gas and Oil Production.

Atlas America’s natural gas and oil production revenues were $141.9 million for the six months ended June 30, 2009, compared to $155.2 million for the comparable prior year period. The $13.3 million decrease was primarily due to an 18% decrease in the average realized sales price offset by a 9% increase in production volumes. The increase in production volumes was attributable to a 9,069 Mcf/day increase in Atlas Energy’s Appalachia natural gas volumes related to increased Marcellus Shale drilling operations.

Natural gas and oil production expenses were $21.1 million for the six months ended June 30, 2009, a decrease of $1.9 million from $23.0 million for the comparable prior year period. The decrease was principally attributable to a decrease of $4.4 million in Michigan/Indiana production costs due in part to a $3.4 reduction in production taxes resulting from a decrease in state production tax rate. The decrease was partially offset by an increase of $1.7 million in Appalachia water hauling and disposal costs associated with an increase in the number of Marcellus Shale wells Atlas Energy drilled.

Well Construction and Completion.

Atlas America’s well construction and completion segment margin was $26.6 million for the six months ended June 30, 2009, a decrease of $2.9 million from $29.5 million for the six months ended June 30, 2008. The decrease of $2.9 million in segment margin was attributable to a $56.4 million decrease related to the number of wells drilled, partially offset by an increase of $53.5 million in the gross profit per well. Since Atlas Energy’s drilling contracts are on a “cost-plus” basis (typically cost-plus 18%), an increase in the average cost per well also results in a proportionate increase in the average revenue per well which directly affects the number of wells Atlas Energy drills. The average cost and revenue per well have increased due to a shift from drilling less expensive shallow wells to more expensive deep or horizontal shale wells in Appalachia and in Michigan/Indiana during the six months ended June 30, 2009 in comparison to the prior year comparable periods.

As of June 30, 2009, “Liabilities associated with drilling contracts” on Atlas America’s consolidated balance sheet includes $88.9 million of funds raised that have not been applied to the completion of wells as of June 30, 2009 due to the timing of Atlas Energy’s drilling operations and thus have not been recognized as well construction and completion revenue. Atlas America and Atlas Energy expect to recognize this amount as revenue in the third quarter of 2009.

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Administration and Oversight and Well Services.

Administration and oversight fee revenues were $6.5 million for the six months ended June 30, 2009 compared with $10.2 million for the six months ended June 30, 2009, a decrease of $3.7 million. Well services revenues were $9.9 million for the six months ended June 30, 2009 compared with $10.1 million for the comparable prior year period, an increase of $0.2 million. Well services expenses were $4.5 million for the six months ended June 30, 2009, compared with $5.1 million for the comparable prior year period. The decrease in administration and oversight fee revenue was due to a decrease in the number of wells drilled during the period, while the decrease in well service revenue was due to the decrease in shallow wells drilled since June 30, 2008.

Transmission, Gathering and Processing.

Atlas America’s transmission, gathering and processing revenues were $349.7 million for the six months ended June 30, 2009, a decrease of $457.7 million from $807.4 million for the comparable prior year period. The decline was primarily attributable to decreases in production revenue from Atlas Pipeline’s Chaney Dell system of $168.1 million, Atlas Pipeline’s Midkiff/Benedum system of $127.9 million, Atlas Pipeline’s Elk City/Sweetwater system of $82.3 million and Atlas Pipeline’s Velma system of $78.1 million, which were all impacted principally by significantly lower average commodity prices in comparison to the prior year comparable period. Processed natural gas volume on the Elk City/Sweetwater system averaged 235.3 MMcfd for the six months ended June 30, 2009, an increase of 1.0% from the comparable prior year period. However, NGL production volume for the Elk City/Sweetwater system was 11,650 bpd, an increase of 10.3% from the comparable prior year period, representing an increase in plant production efficiency. The Midkiff/Benedum system had processed natural gas volume of 148.1 MMcfd for the six months ended June 30, 2009, an increase of 6.6% compared to 138.9 MMcfd for the comparable prior year period. NGL production volume for the Midkiff/Benedum system was 21,555 bpd, an increase of 4.7% from the comparable prior year period. Processed natural gas volume averaged 70.6 MMcfd on the Velma system for the six months ended June 30, 2009, an increase of 15.8% from the comparable prior year period. The Velma system’s NGL production volume increased 13.6% from the comparable prior year period to 7,770 bpd. Processed natural gas volume on the Chaney Dell system was 223.5 MMcfd for the six months ended June 30, 2009, a decrease of 11.4% compared to 252.3 MMcfd for the comparable prior year period. However, the Chaney Dell system’s NGL production volume increased 6.2% from the comparable prior year period to 13,674 bpd for the six months ended June 30, 2009.

Transmission, gathering and processing expenses of $302.9 million for the six months ended June 30, 2009 represented a decrease of $355.6 million from the prior year comparable period due primarily to a significant decrease in Atlas Pipeline’s average commodity prices in comparison to the prior year period. Atlas Pipeline’s plant operating expenses of $28.0 million for the six months ended June 30, 2009 represented a decrease of $1.8 million from the prior year comparable period due primarily to a $1.4 million decrease associated with Atlas Pipeline’s Midkiff/Benedum system resulting from lower operating and maintenance costs. Atlas Pipeline’s transportation and compression expenses increased slightly to $6.1 million for the six months ended June 30, 2009 compared with $5.0 million for the prior year comparable period due to higher Atlas Pipeline’s Appalachia system operating and maintenance expenses as a result of increased capacity in comparison to the prior year period.

Gain on asset sale.

Gain on asset sale of $105.7 million for the six months ended June 30, 2009 represents the gain recognized on Atlas Pipeline’s sale of a 51% ownership interest in its Appalachia natural gas gathering system (see “—Recent Developments”).

Equity income in joint venture.

Equity income of $0.7 million for the six months ended June 30, 2009 represents Atlas Pipeline’s ownership interest in the net income of Laurel Mountain, a joint venture in which Atlas Pipeline owns a 49% interest (see “—Recent Developments”), for the period from formation on May 31, 2009 through June 30, 2009.

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Loss on Mark-to-Market Derivatives.

Loss on mark-to-market derivatives was $18.3 million for the six months ended June 30, 2009 compared with $404.8 for the comparable prior year period. This favorable movement of $386.5 million was due primarily to a $180.0 million favorable movement in non-cash mark-to-market adjustments on Atlas Pipeline’s derivatives, the absence in the current year period of $115.8 million of net cash derivative expense related to Atlas Pipeline’s early termination of a portion of its derivative contracts during June 2008, a favorable movement of $65.6 million for non-cash derivative gains related to Atlas Pipeline’s early termination of a portion of its derivative contracts and a $33.5 million favorable movement related to cash settlements on Atlas Pipeline derivatives that were not designated as hedges. The $180.0 million favorable movement in non-cash mark-to-market adjustments on derivatives was due principally to the recognition of a $211.7 million loss during the six months ended June 30, 2008, which was due to an increase in forward crude oil market prices from December 31, 2007 to June 30, 2008 and their unfavorable mark-to-market impact on certain non-hedge derivative contracts Atlas Pipeline had for production volumes in future periods. For example, average forward crude oil prices, which are the basis for adjusting the fair value of Atlas Pipeline’s crude oil derivative contracts, at June 30, 2008 were $140.26 per barrel, an increase of $50.37 per barrel from average forward crude oil market prices at December 31, 2007 of $89.89 per barrel. Atlas Pipeline enters into derivative instruments solely to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices.

Other Income, Costs and Expenses.

General and administrative expenses, including amounts reimbursed to affiliates, increased $3.7 million to $49.6 million for the six months ended June 30, 2009 compared with $45.9 million for the comparable prior year period. The increase was primarily related to $2.8 million of non-recurring severance and other related costs incurred during the first quarter of 2009 for the termination of certain positions within Atlas Pipeline’s Mid-Continent segment and $0.6 million in professional fees related to the anticipated merger between Atlas America and Atlas Energy (see “Recent Developments”).

Depreciation, depletion and amortization increased to $101.0 million for the six months ended June 30, 2009 compared with $85.2 million for the comparable prior year period due primarily to an increase in Atlas Energy’s depletable basis and production volumes and Atlas Pipeline’s expansion capital expenditures incurred between the periods.

Interest expense increased to $76.6 million for the six months ended June 30, 2009 as compared with $69.2 million for the comparable prior year period. This $7.4 million increase was primarily due to an increase in borrowings from Atlas Energy and Atlas Pipeline, partially offset by lower unhedged interest rates. Atlas Pipeline issued additional senior unsecured notes during June 2008 and made a partial repayment of its senior secured term loan in June 2008, and a partial repayment of it term loan and credit facility during second quarter 2009. Atlas Energy issued additional senior unsecured notes in May 2008 and increased its borrowing under its credit facility.

Income tax expense was $6.3 million for the six months ended June 30, 2009 compared with income tax benefit of $1.4 million for the comparable prior year period. Atlas America’s effective income tax rate attributable to its common shareholders was 39.1% and 36.9% for the six months ended June 30, 2009 and 2008, respectively. The increase in Atlas America’s effective income tax rate between periods is a result of a reduction in tax benefits related to depletion and tax-exempt interest income relative to income (loss) before taxes. Currently, it is Atlas America’s expectation that its effective income tax rate will approximate 39% for the year ended December 31, 2009.

Income from discontinued operations consists of amounts associated with Atlas Pipeline’s NOARK gas gathering and interstate pipeline system, which it sold on May 4, 2009 (see “—Recent Developments”). Income from discontinued operations increased to $59.8 million for the six months ended June 30, 2009 compared with

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$13.8 million for the comparable prior year period. The increase was due to the $48.8 million gain, net of $2.2 million of income tax expense, Atlas Pipeline recognized on the sale of the NOARK system, partially offset by a $2.9 million decrease in the operating results of the NOARK system, net of income taxes, due to the sale of the system on May 4, 2009.

Income (loss) attributable to non-controlling interests, which represents the allocation of Atlas Energy’s, Atlas Pipeline Holdings’ and Atlas Pipeline’s earnings to its non-controlling interests, was a loss of $112.9 million for the six months ended June 30, 2009 compared with income of $254.8 million for the prior year comparable period. This change was primarily due to an increase in Atlas Energy’s and Atlas Pipeline’s net earnings between periods.

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:
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			—
Combined throughput volume (mcfd)(5)		852,151			835,922			399,637

(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 Company 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.

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(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

Atlas America’s 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. Atlas Energy’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. Atlas Energy’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 Atlas Energy’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 Atlas Energy’s Michigan assets and a $4.1 million increase from Appalachia production expenses due to an increase in the number of wells Atlas Energy owns.

Well Construction and Completion

Atlas America’s 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 Atlas Energy’s Marcellus Shale wells drilled in 2008, which are drilled at a higher cost than other Appalachian wells. Atlas Energy 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, Atlas Energy 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

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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 Atlas Energy’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 Atlas Energy’s drilling investment partnerships, for which Atlas Energy earns fees for its partnership management activities.

Transmission, Gathering and Processing

Atlas America’s transmission, gathering and processing revenues were $1,384.2 million for the year ended December 31, 2008, an increase of $617.1 million from $767.1 million for the prior year. Transmission, gathering and processing expenses were $1,153.6 million for the year ended December 31, 2008, an increase of $536.0 million from $617.6 million for the prior year. These increases were due principally to a full year of revenues and expenses associated with Atlas Pipeline’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. Atlas Pipeline’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. Atlas Pipeline’s average gross natural gas gathered volume for the year ended December 31, 2008 was 0.852 billion cubic feet per day (which we refer to as “bcfd”) compared with 0.836 bcfd for the prior year, an increase of 0.016 bcfd or 2% 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 Atlas Pipeline’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 Atlas Pipeline’s derivative contracts, and an unfavorable movement of $1.5 million related to Atlas Pipeline’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 Atlas Pipeline 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 Atlas Pipeline’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. Atlas Pipeline 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.

Other Income, Costs and Expenses

General and administrative expenses, including amounts reimbursed to affiliates, decreased $53.4 million to $57.8 million for the year ended December 31, 2008 compared with $111.2 million for the prior year. The decrease was primarily related to a $66.8 million decrease in non-cash compensation expense, partially offset by $13.4 million of higher costs incurred in managing Atlas America’s 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 Atlas Pipeline common unit awards for which the ultimate amount to be issued was determined after the completion of the 2008 fiscal year and is based upon the financial performance of Atlas Pipeline’s acquired assets. The gain was the result of a significant change in the Atlas Pipeline 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

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common unit awards as a result of the effect Atlas Pipeline’s Chaney Dell and Midkiff/Benedum acquisition had on the calculation of the awards. The $13.4 million increase in other general and administrative costs between periods was principally related to a $12.5 million increase in salary, wages and benefits.

Depreciation, depletion and amortization increased to $178.3 million for the year ended December 31, 2008 compared with $100.8 million for the prior year due primarily to the depreciation and depletion associated with Atlas Energy’s acquired Michigan assets and Atlas Pipeline’s acquired Chaney Dell and Midkiff/Benedum system assets and Atlas Energy’s and Atlas Pipeline’s expansion capital expenditures incurred between the periods.

Goodwill impairment loss of $676.9 million for the year ended December 31, 2008 consisted of an impairment charge to Atlas Pipeline’s goodwill as a result of its annual goodwill impairment test. The goodwill impairment resulted from the reduction of Atlas Pipeline’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. Atlas Pipeline’s estimates were subjective and based upon numerous assumptions about future operations and market conditions, which are subject to change.

Interest expense increased to $144.1 million for the year ended December 31, 2008 as compared with $93.7 million for the prior year. This $50.4 million increase was primarily due to interest associated with a full year’s interest expense on the borrowings of Atlas Energy to partially finance the acquisition of its Michigan assets in June 2007 and of Atlas Pipeline 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 Atlas Pipeline’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 Atlas Pipeline’s 8.125% senior unsecured notes and approximately $27.0 million in face amount of its 8.75% senior unsecured notes. All of Atlas Pipeline’s senior unsecured notes repurchased have been retired and are not available for re-issue.

Income (loss) attributable to non-controlling interests for the year ended December 31, 2008, which represents non-controlling, non-affiliated ownership interests in Atlas Energy, Atlas Pipeline Holdings and Atlas Pipeline, 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 Atlas Pipeline’s net loss, a $25.3 million increase in Atlas Energy’s net income, a decrease in Atlas America’s ownership interest in Atlas Pipeline Holdings to 64% for the year ended December 31, 2008 compared with 83% for the first half of the prior year, and a decrease in Atlas America’s ownership interest in Atlas Energy to 51% for the year ended December 31, 2008 compared with 80% for the first half of the prior year. The decrease in Atlas Pipeline’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 Atlas Pipeline recognized in 2008 for the early extinguishment of debt. Atlas Energy’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 Atlas America’s ownership interest in Atlas Pipeline Holdings was due to its private placement of common units to third parties to partially finance its capital contribution to Atlas Pipeline to maintain its 2% general partner interest in relation to Atlas Pipeline’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 Atlas America’s ownership interest in Atlas Energy 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 $5.0 million for the year ended December 31, 2008 compared with a provision for income taxes of $13.3 million for the prior year. The change in Atlas America’s provision (benefit)

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for income taxes was due primarily to a decrease in net income (loss) before taxes between periods. Atlas America’s effective income tax rates attributable to common shareholders were 40% and 29% for the years ended December 31, 2008 and 2007, respectively. The increase in Atlas America’s 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.

Income from discontinued operations consists of amounts associated with Atlas Pipeline’s NOARK gas gathering and interstate pipeline system, which it sold on May 4, 2009 (see “— Recent Developments”). Income from discontinued operations decreased to $19.7 million for the year ended December 31, 2008 compared with $29.5 million for the prior year. The decrease was due to a $21.6 million write-off of costs related to pipeline expansion project, partially offset by an increase in NOARK transportation revenue due to an increase in throughput. The costs incurred related to the pipeline expansion project consisted of NOARK’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.

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

Natural Gas and Oil Production

Atlas America’s 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. Atlas Energy’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. Atlas Energy’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 Atlas Energy’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 Atlas Energy’s Michigan assets during 2007 and higher Appalachia production expenses associated with an increase in the number of wells Atlas Energy owns.

Well Construction and Completion

Atlas America’s 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 Atlas Energy wells drilled for the year ended December 31, 2007 in comparison to the prior year. Atlas Energy 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, Atlas Energy 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 Atlas Energy wells drilled, for which Atlas Energy 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 Atlas Energy’s drilling investment partnerships, for which Atlas Energy earns fees for its partnership management activities.

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Transmission, Gathering and Processing

Atlas America’s transmission, gathering and processing revenues were $767.1 million for the year ended December 31, 2007, an increase of $399.5 million from $367.6 million for the prior year. Transmission, gathering and processing expenses were $617.6 million for the year ended December 31, 2007, an increase of $302.5 million from $315.1 million for the prior year. These increases were due principally to the revenues and expenses associated with Atlas Pipeline’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. Atlas Pipeline’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. Atlas Pipeline’s average gross natural gas gathered volume for the year ended December 31, 2007 was 0.836 billion cubic feet per day compared with 0.400 bcfd for the prior year, an increase of 0.436 bcfd or 109% 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 Atlas Pipeline 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 Atlas Pipeline’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. Atlas Pipeline 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.

Other Income, Costs and Expenses

General and administrative expenses, including amounts reimbursed to affiliates, increased $66.9 million to $111.2 million for the year ended December 31, 2007 compared with $44.3 million for the prior year. The increase was primarily related to a $36.4 million increase in non-cash compensation expense and $30.5 million of higher costs incurred in managing Atlas America’s operations. The increase in non-cash compensation expense was principally attributable to vesting of Atlas Pipeline phantom and common unit awards in 2007, which were based upon the financial performance of Atlas Pipeline’s acquired assets, including the Chaney Dell and Midkiff/Benedum system acquired in July 2007. The $30.5 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 Atlas Energy’s acquisition of its Michigan assets.

Depreciation, depletion and amortization increased to $100.8 million for the year ended December 31, 2007 compared with $39.4 million for the prior year due primarily to the depreciation and depletion associated with Atlas Energy’s acquired Michigan assets and Atlas Pipeline’s acquired Chaney Dell and Midkiff/Benedum system assets and Atlas Energy’s and Atlas Pipeline’s expansion capital expenditures incurred between the periods.

Interest expense increased to $93.7 million for the year ended December 31, 2007 as compared with $26.4 million for the prior year. This $67.3 million increase was primarily due to interest associated with borrowings by Atlas Energy and Atlas Pipeline to partially finance the acquisition of Atlas Energy’s Michigan assets in June 2007 and Atlas Pipeline’s Chaney Dell and Midkiff/Benedum systems during July 2007.

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Income (loss) attributable to non-controlling interests for the year ended December 31, 2007, which represents non-controlling, non-affiliated ownership interests in Atlas Energy, Atlas Pipeline Holdings and Atlas Pipeline, 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 Atlas America’s ownership interests in Atlas Energy and Atlas Pipeline Holdings and a $59.3 million increase in Atlas Energy’s net income between periods, partially offset by a $178.0 million decrease in Atlas Pipeline’s net income. The decrease in Atlas America’s ownership interests in Atlas Energy was principally due to the completion of its initial public offering in December 2006, whereby Atlas America sold an approximate 19% ownership interest in Atlas Energy. Atlas Energy subsequently completed additional sales of common units to further reduce Atlas America’s ownership interest during June 2007. The decrease in Atlas America’s ownership interests in Atlas Pipeline Holdings was principally due to the completion of its initial public offering in July 2006, whereby Atlas America sold an approximately 17% ownership interest in Atlas Pipeline Holdings. Atlas Pipeline Holdings subsequently completed additional sales of common units to further reduce Atlas America’s ownership interest during July 2007. The increase in Atlas Energy’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 Atlas Pipeline’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 $13.3 million for the year ended December 31, 2007 compared with $26.7 million for the prior year due primarily to a decrease in net income between periods. Atlas America’s effective income tax rates attributable to common shareholders were 29% and 39% for the years ended December 31, 2007 and 2006, respectively. The decrease in Atlas America’s 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.

Income from discontinued operations consists of amounts associated with Atlas Pipeline’s NOARK gas gathering and interstate pipeline system, which it sold on May 4, 2009 (see “—Recent Developments”). Income from discontinued operations increased to $29.5 million for the year ended December 31, 2007 compared with $11.0 million for the prior year. The increase was due to an increase in NOARK transportation revenue due to an increase in throughput and an additional Atlas Pipeline’s acquisition of the remaining 25% ownership interest in NOARK in May 2006.

Liquidity and Capital Resources

General

Atlas America’s primary sources of liquidity are distributions received with respect to its ownership interests in Atlas Energy, Atlas Pipeline, Atlas Pipeline Holdings and cash on hand. Atlas America’s primary cash requirements are for its general and administrative expenses and other expenditures, which Atlas America expect to fund through the retention of cash and distributions received and cash on hand. Atlas America’s operations principally occur through its subsidiaries, whose sources of liquidity are discussed in more detail below.

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

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• 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.

At June 30, 2009, Atlas Energy had $196.0 million available committed capacity under its credit facility, subject to covenant limitations, to fund working capital obligations. On July 16, 2009, Atlas Energy issued $200.0 million of 12.125% senior unsecured notes due 2017 at 98.116% of par value to yield 12.5% at maturity (see “Subsequent Events”). Atlas Energy used the net proceeds of $191.7 million, net underwriting fees of $4.5 million, to repay outstanding borrowings under our revolving credit facility. Under the terms of its credit facility (see “Recent Developments”), the credit facility borrowing base is automatically reduced by 25% of the stated principal amount of any senior unsecured notes offering by Atlas Energy. As such, the borrowing base of its credit facility was reduced by $50.0 million to $600.0 million upon the issuance of the 12.125% Senior Notes.

Atlas Pipeline Holdings. Atlas Pipeline Holdings’ primary sources of liquidity are distributions received with respect to its ownership interests in Atlas Pipeline and cash on hand. Atlas Pipeline Holdings’ primary cash requirements are for its general and administrative expenses, including expenses as a result of being a publicly traded partnership, capital contributions to Atlas Pipeline to maintain or increase its ownership interest and quarterly distributions to its common unitholders. Atlas Pipeline Holdings expects to fund its general and administrative expenses through the retention of cash and its capital contributions to Atlas Pipeline through the retention of cash from distributions received from Atlas Pipeline. On May 29, 2009, Atlas Pipeline entered into an amendment to its senior secured credit facility (see “Recent Developments”) which, among other changes, requires that it pay no cash distributions during the remainder of the year ended December 31, 2009 and allows it to pay cash distributions beginning January 1, 2010 if its senior secured leverage ratio is above certain thresholds and it has minimum liquidity (both as defined in the credit agreement) of at least $50.0 million.

At June 30, 2009, Atlas Pipeline Holdings had $16.0 million outstanding under its credit facility (see “Recent Developments”) and was in compliance with its credit facility covenants. Atlas America and Atlas Pipeline Holdings believes that Atlas Pipeline Holdings will have sufficient liquid assets, including its ownership of 5.8 million limited partner units in Atlas Pipeline, cash on hand and borrowing ability, including borrowings from Atlas America, to meet its financial commitments, debt service obligations and possible contingencies for at least the next twelve-month period. However, Atlas Pipeline Holdings is subject to business and other risks that could adversely affect its cash flow. Atlas Pipeline Holdings may need to supplement its cash generation with proceeds from financing activities, including other borrowings and the issuance of additional limited partner units and the sale of its ownership interests in Atlas Pipeline.

Atlas Pipeline Partners.Atlas Pipeline’s primary sources of liquidity are cash generated from operations and borrowings under its credit facility. Atlas Pipeline’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, Atlas America and Atlas Pipeline expect Atlas Pipeline 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 or Atlas Pipeline asset sales.

At June 30, 2009, Atlas Pipeline had $322.0 million of outstanding borrowings under its $380.0 million credit facility and $3.5 million of outstanding letters of credit, which are not reflected as borrowings on Atlas America’s consolidated balance sheet, with $54.5 million of remaining committed capacity under its credit

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facility, subject to covenant limitations (see “Recent Developments”). Atlas Pipeline was in compliance with its credit facility covenants at June 30, 2009. Atlas America and Atlas Pipeline believe that Atlas Pipeline will have sufficient liquid assets, cash from operations and borrowing capacity to meet its financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve-month period. However, Atlas Pipeline is subject to business, operational and other risks that could adversely affect its cash flow. Atlas Pipeline may need to supplement its cash generation with proceeds from financing activities, including borrowings under its credit facility and other borrowings, the issuance of additional limited partner units and the sale of its assets.

Atlas America believes that it and its subsidiaries will have sufficient liquid assets, cash from operations and borrowing capacity to meet their financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve-month period. However, Atlas America and its subsidiaries are subject to business, operational and other risks that could adversely affect their cash flow. Atlas America and its subsidiaries may supplement their cash generation with proceeds from financing activities, including borrowings under Atlas America’s subsidiaries’ credit facilities and other borrowings, the issuance of additional common shares and units and the sale of assets.

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 Atlas America’s subsidiaries’ ability to raise capital and reduce the amount of cash available to fund its operations. Atlas America’s subsidiaries rely on their cash flow from operations and their credit facilities to execute their growth strategy and to meet their financial commitments and other short-term liquidity needs. Atlas America cannot be certain that additional capital will be available to its subsidiaries to the extent required and on acceptable terms. Atlas America believes that it and its subsidiaries will have sufficient liquid assets, cash from operations and borrowing capacity to meet its and their financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve month period.

Cash Flows — Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

Net cash provided by operating activities of $119.7 million for the six months ended June 30, 2009 represented a favorable movement of $104.2 million from net cash provided by operating activities of $15.5 million for the comparable prior year period. The increase was derived principally from a $103.8 million increase in net income excluding non-cash items and a $69.0 million favorable movement in distributions paid to non-controlling interest holders, partially offset by a $67.4 million unfavorable movement in working capital changes and a $7.4 million unfavorable movement in cash provided by discontinued operations. The non-cash charges which impacted net income include favorable movements in income from continuing operations of $284.7, partially offset by favorable decreases in non-cash loss on derivatives of $145.2 million. The increase in net income excluding non-cash charges was principally due to the absence in the current year period of $115.8 million of net cash derivative expense related to Atlas Pipeline’s early termination of a portion of its derivative contracts during June 2008. The movement in cash distributions to non-controlling interest holders is due mainly to decreases in Atlas Energy’s, Atlas Pipeline Holdings’ and Atlas Pipeline’s cash distributions. The movement in working capital was principally due to a $158.8 million unfavorable movement in accounts payable, partially offset by a $74.8 million favorable movement in accounts receivable and other current assets. The movement in non-cash derivative losses resulted from decreases in commodity prices during the six months ended June 30, 2009 and their favorable impact on the fair value of derivative contracts Atlas Energy and Atlas Pipeline have for future periods.

Net cash provided by investing activities of $153.8 million for the six months ended June 30, 2009 represented a favorable movement of $415.4 million from $261.6 million used in investing activities for the comparable prior year period. This favorable movement was principally due to a $305.7 million favorable movement in cash provided by discontinued operations, a $97.9 million increase in proceeds from sale of assets related to the sale of Atlas Pipeline’s Appalachia segment assets to the Laurel Mountain joint venture, and a

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decrease in capital expenditures for Atlas Energy and Atlas Pipeline of $50.8 million, partially offset by a $31.4 million decrease in cash proceeds from acquisition purchase price adjustment. The $305.7 million favorable movement in cash provided by discontinued operations was principally the result of $292.0 million of net cash proceeds from the sale of Atlas Pipeline’s NOARK system assets. See further discussion of capital expenditures under “— Capital Requirements”.

Net cash used in financing activities of $296.6 million for the six months ended June 30, 2009 represented an unfavorable movement of $638.3 million from $341.7 million of net cash provided by financing activities for the comparable prior year period. This unfavorable movement was principally due to a $651.9 million reduction in net proceeds from Atlas Pipeline and Atlas Energy’s issuance of debt and a $289.6 reduction in net proceeds from Atlas Pipeline’s and Atlas Energy’s issuance of equity. This decrease was partially offset by a $186.0 million favorable movement in subsidiary borrowings under their respective credit facilities and a $122.8 million repayment of Atlas Pipeline’s senior secured term loan.

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

Net cash used in operating activities of $47.4 million for the year ended December 31, 2008 represented a decrease of $242.5 million from $195.1 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 non-controlling interests and a $104.4 million decrease in net income excluding non-cash items. The decrease due to cash distributions to minority interests is due mainly to increases in Atlas Energy, Atlas Pipeline Holdings and Atlas Pipeline common units outstanding and their cash distribution amount per common unit. The non-cash charges which impacted net income include unfavorable increases in 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 $676.9 million for goodwill impairment and $77.5 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 Atlas America’s net income, which was due to the mark-to-market of derivative contracts Atlas Pipeline has for future periods. The increase in depreciation, depletion and amortization resulted from Atlas Energy’s acquisition of its Michigan assets in June 2007 and Atlas Pipeline’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007. The movement in non-controlling interests in net income was due to a decrease in Atlas Pipeline’s net income and Atlas America’s ownership interests in Atlas Pipeline Holdings and Atlas Energy between periods, partially offset by an increase in Atlas Energy’s net income.

Net cash used in investing activities of $643.9 million for the year ended December 31, 2008 represented a decrease of $2,864.3 million from $3,508.2 million used in investing activities for the prior year. This decrease was principally due to a $3,157.0 million reduction in net cash paid for acquisitions related Atlas Energy’s acquisition of AGO in June 2007 and Atlas Pipeline’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 Atlas Pipeline’s acquisition of the Chaney Dell and Midkiff/Benedum systems, and a $9.4 million decrease in Atlas America’s cash paid for investments in Lightfoot. These decreases were partially offset by a $326.4 million increase in capital expenditures for Atlas Energy and Atlas Pipeline. See further discussion of capital expenditures under “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Atlas America — Liquidity and Capital Resources — 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 Atlas Pipeline, Atlas Energy, and Atlas Pipeline Holdings credit facility borrowings, a $1,431.5 million decrease in net proceeds from Atlas Pipeline, Atlas Energy and Atlas Pipeline Holdings equity offerings, and a $1,073.8 million increase in repayments of Atlas Pipeline long-term debt. These amounts were partially offset by a $652.0 million increase in

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net proceeds from the issuance of Atlas Pipeline and Atlas Energy long-term debt and a decrease of $40.4 million in Atlas America purchases of Atlas America common stock.

Cash Flows — Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Net cash provided by operating activities of $195.1 million for the year ended December 31, 2007 represented an increase of $132.9 million from $62.2 million of net cash provided by operating activities for the prior year. The increase was derived principally from a $132.0 million increase in net income excluding non-cash items, a $37.9 million favorable movement in deferred taxes, and a $25.0 million favorable movement in working capital, partially offset by a $66.0 million increase in cash distributions paid to non-controlling interests. The increase in net income excluding non-cash items was principally due to higher operating results of Atlas Energy through the acquisition of its Michigan assets in June 2007 and of Atlas Pipeline 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 million, depreciation, depletion and amortization of $61.4 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 Atlas America’s net income, which was principally due to the mark-to-market of derivative contracts Atlas Pipeline has for future periods. The movement in non-controlling interests in net income was due to an increase in Atlas Pipeline’s and Atlas Energy’s net income and a decrease in Atlas America’s ownership interests in Atlas Pipeline Holdings and Atlas Energy between periods. The increase in depreciation, depletion and amortization resulted from Atlas Energy’s acquisition of its Michigan assets in June 2007 and Atlas Pipeline’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 Atlas Pipeline phantom and common unit awards in 2007, which were based upon the financial performance of Atlas Pipeline’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 Atlas Energy, Atlas Pipeline Holdings and Atlas Pipeline common units outstanding and their cash distribution amount per common unit.

Net cash used in investing activities of $3,508.2 million for the year ended December 31, 2007 represented an increase of $3,324.0 million from $184.2 million used in investing activities for the prior year. This decrease was principally due to a $3,157.0 million increase in net cash paid for acquisitions related to Atlas Energy’s acquisition of Atlas Gas and Oil in June 2007 and Atlas Pipeline’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007, a $163.5 million increase in capital expenditures for Atlas Energy and Atlas Pipeline, a $10.4 million increase in Atlas America’s 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Atlas America — Liquidity and Capital Resources — 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 Atlas Pipeline, Atlas Energy, and Atlas Pipeline Holdings credit facility borrowings, and a $1,437.0 million increase in net proceeds from Atlas Pipeline, Atlas Energy and Atlas Pipeline Holdings equity offerings. These amounts were partially offset by a $50.6 million increase in purchases of Atlas America common stock and a $36.6 million decrease in net proceeds from the issuance of Atlas Pipeline long-term debt.

Capital Requirements

Atlas America’s principal assets are its ownership interests in Atlas Energy, Atlas Pipeline and Atlas Pipeline Holdings, through which Atlas America’s operating activities occur. As such, Atlas America does not have any separate capital requirements apart from those entities, other than its commitment to invest a maximum

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of $20.0 million in Lightfoot, of which Atlas America had already invested $10.7 million at June 30, 2009. Atlas Pipeline Holdings, whose principal assets are its ownership interests in Atlas Pipeline, does not have any separate capital requirements apart from Atlas Pipeline. A more detailed discussion of Atlas Energy’s and Atlas Pipeline’s capital requirements is provided below.

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

• maintenance capital expenditures — capital expenditures Atlas Energy 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 Atlas Energy 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. Atlas Pipeline’s operations require continual investment to upgrade or enhance existing operations and to ensure compliance with safety, operational and environmental regulations. Atlas Pipeline’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 Atlas America’s consolidated maintenance and expansion capital expenditures, excluding amounts paid for acquisitions, for the periods presented (in thousands):

	Six Months Ended June 30,
	2009		2008(1)
Atlas Energy
Maintenance capital expenditures	$	25,950	$	25,950
Expansion capital expenditures		70,463		109,720
Total	$	96,413	$	135,670
Atlas Pipeline
Maintenance capital expenditures	$	2,101	$	3,486
Expansion capital expenditures		128,393		138,568
Total	$	130,494	$	142,054
Consolidated
Maintenance capital expenditures	$	28,051	$	29,436
Expansion capital expenditures		198,856		248,288
Total	$	226,907	$	277,724

(1) Restated to reflect amounts reclassified to discontinued operations due to Atlas Pipeline’s sale of its NOARK gas gathering and interstate pipeline system (see “—Recent Developments”).

Atlas Energy. During the six months ended June 30, 2009, Atlas Energy’s capital expenditures related primarily to $51.6 million of investments in its investment partnerships compared with $66.4 million for the six months ended June 30, 2008. Atlas Energy also invested $12.1 million in wells drilled exclusively for its own account and incurred $16.9 million in leasehold costs for the six months ended June 30, 2009. Atlas Energy funded and expects to continue to fund these capital expenditures through cash on hand, cash flows from operations and from amounts available under its credit facility.

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Atlas Pipeline Partners. Atlas Pipeline’s expansion capital expenditures decreased to $128.4 million for the six months ended June 30, 2009 compared with $138.6 million for the prior year comparable period. The decrease was due principally to Atlas Pipeline’s construction of a 60 MMcfd expansion of its Sweetwater processing plant and Atlas Pipeline’s acquisition of a gathering system located in Tennessee during the six months ended June 30, 2008, partially offset by Atlas Pipeline’s continued expansion of its gathering systems and upgrades to processing facilities and compressors to accommodate new wells drilled in its service areas. The decrease in maintenance capital expenditures for the six months ended June 30, 2009 when compared with the comparable prior year period was due to fluctuations in the timing of Atlas Pipeline’s scheduled maintenance activity.

As of June 30, 2009, Atlas Energy’s subsidiaries are committed to expend approximately $19.2 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

The following table summarizes Atlas America’s 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)		295,756		157,719		—
Total	$	347,656	$	201,169	$	79,721
Atlas Pipeline(2)
Maintenance capital expenditures	$	6,051	$	7,659	$	3,197
Expansion capital expenditures		294,672		113,174		75,611
Total	$	300,723	$	120,833	$	78,808
Consolidated
Maintenance capital expenditures(1)	$	57,951	$	51,109	$	—
Expansion capital expenditures(1)		590,428		270,893		—
Total	$	648,379	$	322,002	$	158,529

(1) Atlas Energy 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.

(2) Restated to reflect amounts reclassified to discontinued operations due to Atlas Pipeline’s sale of its NOARK gas gathering and interstate pipeline system (see “—Recent Developments”).

Atlas Energy

Atlas Energy’s expansion capital expenditures increased to $295.8 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. Atlas Energy 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.

Atlas Energy’s expansion capital expenditures increased to $157.7 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. Atlas Energy 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.

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Atlas Pipeline

Atlas Pipeline’s expansion capital expenditures increased to $294.7 million for the year ended December 31, 2008 due principally to the expansion of Atlas Pipeline’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 Atlas Pipeline’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 Atlas Pipeline’s scheduled maintenance activity.

Atlas Pipeline’s expansion capital expenditures increased to $113.2 million for the year ended December 31, 2007 due principally to the expansion of Atlas Pipeline’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 Atlas Pipeline’s Chaney Dell and Midkiff/Benedum systems, which were acquired in July 2007, and fluctuations in the timing of Atlas Pipeline’s other scheduled maintenance activity.

Issuance of Subsidiary Common Units

Atlas America 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” (which we refer to as “SAB 51”). Atlas America has adopted a policy to recognize gains on such transactions as a credit to equity rather than as income. These gains represent Atlas America’s portion of the excess net offering price per unit of each of its subsidiaries’ units to the book carrying amount per unit.

Atlas America has experienced sales of subsidiary units in years prior to 2006 and had not previously recorded gains of $26.6 million on such sales. Atlas America has 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 Atlas America has recorded cumulative gains in the year ended December 31, 2006 financial statements. It is anticipated that Atlas America’s public subsidiaries will have additional issuances in the future as they continue to grow through acquisitions.

Atlas Energy

In May 2008, Atlas Energy sold 2,070,000 Atlas Energy 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 Atlas Energy’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 Atlas America’s consolidated equity as an increase to paid-in capital as well as a corresponding adjustment of $26.4 million to non-controlling interest in accordance with SAB 51 upon completion of the offering.

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

In June 2007, Atlas Energy issued 24,001,009 Atlas Energy common units (an approximate 31% interest in Atlas Energy 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 non-controlling interest, in the year ended December 31, 2007 in accordance with SAB 51 upon completion of the offering.

In December 2006, Atlas America contributed substantially all of its natural gas and oil assets and its investment partnership management business to Atlas Energy, a then wholly owned subsidiary. Concurrent with this transaction, Atlas Energy issued 7,273,750 common units, representing a 19.4% ownership interest at that

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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 Atlas America. Atlas America 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 non-controlling interest in accordance with SAB 51 upon completion of the offering.

Atlas Pipeline and Atlas Pipeline Holdings

On March 30, 2009, Atlas Pipeline Holdings, pursuant to its right within the Atlas Pipeline Class B Preferred Units certificate of designation, purchased an additional 5,000 Atlas Pipeline Class B Preferred Units at face value. Atlas Pipeline used the proceeds from the sale of the Atlas Pipeline Class B Preferred Units for general partnership purposes. The Atlas Pipeline Class B Preferred Units receive distributions of 12.0% per annum, paid quarterly on the same date as the distribution payment date for Atlas Pipeline common units. The record date of determination for holders entitled to receive distributions of the Atlas Pipeline Class B Preferred Units will be the same as the record date of determination for Atlas Pipeline common unitholders entitled to receive quarterly distributions. Additionally, on March 30, 2009, Atlas Pipeline and Atlas Pipeline Holdings agreed to amend the terms of the Atlas Pipeline Class B Preferred Units Certificate of Designation to remove the conversion feature, thus the Atlas Pipeline Class B Preferred Units are not convertible into Atlas Pipeline common units. The amended Atlas Pipeline Class B Preferred Units certificate of designation also gives Atlas Pipeline the right at any time to redeem some or all of the outstanding Atlas Pipeline Class B Preferred Units for cash at an amount equal to the Atlas Pipeline Class B Preferred Unit liquidation value being redeemed, provided that such redemption must be exercised for no less than the lesser of (a) 2,500 Atlas Pipeline Class B Preferred Units or (b) the number of remaining outstanding Atlas Pipeline Class B Preferred Units.

In June 2008, Atlas Pipeline 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, Atlas America purchased 308,109 Atlas Pipeline Holdings common units and 1,112,000 Atlas Pipeline 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. Atlas Pipeline also received a capital contribution from Atlas Pipeline Holdings of $5.4 million for Atlas Pipeline Holdings to maintain its 2.0% general partner interest in it. Atlas Pipeline utilized the net proceeds from both the sales of common units and the capital contribution from Atlas Pipeline Holdings to fund the early termination of certain derivative agreements.

In July 2007, Atlas Pipeline 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 Atlas Pipeline, 3,835,227 common units were purchased by Atlas Pipeline Holdings for $168.8 million. Atlas Pipeline also received a capital contribution from Atlas Pipeline Holdings of $23.1 million for Atlas Pipeline Holdings to maintain its 2.0% general partner interest in Atlas Pipeline. Atlas Pipeline Holdings funded this capital contribution and other transaction costs through borrowings under its revolving credit facility of $25.0 million. Atlas Pipeline utilized the net proceeds from the sale to partially fund the acquisition of the Chaney Dell and Midkiff/Benedum systems.

In July 2007, Atlas Pipeline Holdings issued 6,249,995 common units for net proceeds of $167.0 million after offering costs in a private placement offering. Atlas Pipeline Holdings utilized the net proceeds from the sale to partially fund its purchase of 3,835,227 common units of Atlas Pipeline. 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 non-controlling interest, in the year ended December 31, 2007 in accordance with SAB 51 upon completion of the offering.

In July 2006, Atlas America contributed its ownership interests in Atlas Pipeline GP, the general partner of Atlas Pipeline, to Atlas Pipeline Holdings. Concurrent with this transaction, Atlas Pipeline Holdings 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

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commissions, were distributed to Atlas America. Atlas America 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 non-controlling interest, in the year ended December 31, 2006 in accordance with SAB 51 upon completion of the offering.

In May 2006, Atlas Pipeline 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. Atlas Pipeline 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. Atlas America 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 non-controlling interest, in the year ended December 31, 2006 in accordance with SAB 51 upon completion of the offering.

The following table provides information about Atlas America’s 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	Atlas Energy	$	26,368	$	8,699	$	17,669
2007	Atlas Energy		235,438		87,521		147,917
2006	Atlas Energy		76,034		31,920		44,114
2006	Atlas Pipeline		1,078		452		626
2007	Atlas Pipeline Holdings		87,295		34,316		52,979
2006	Atlas Pipeline Holdings		65,366		27,442		37,924
Total		$	491,579	$	190,350	$	301,229

Dividends

Atlas America paid cash dividends of $2.0 million for the three months ended March 31, 2009, but did not pay cash dividends for the three months ended June 30, 2009. The determination of the amount of future cash dividends, if any, is at the sole discretion of Atlas America’s board of directors and will depend on the various factors affecting its financial condition and other matters the board of directors deems relevant.

Off-Balance Sheet Arrangements

As of June 30, 2009, Atlas America’s off-balance sheet arrangements are limited to Atlas Energy’s guarantee of Crown Drilling of Pennsylvania, LLC’s $8.7 million credit agreement, Atlas Energy’s and Atlas Pipeline’s letters of credit outstanding of $1.2 million and $3.5 million, respectively, and their commitments to expend approximately $19.2 million on capital projects. In addition, Atlas America is committed to invest a total of $20.0 million in Lightfoot, of which $10.7 million has been invested as of June 30, 2009.

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Contractual Obligations and Commercial Commitments

The following table summarizes Atlas America’s 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 Atlas Energy’s, Atlas Pipeline’s and Atlas Pipeline Holdings’ 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

Environmental Regulation

Atlas Energy’s and Atlas Pipeline’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. Atlas America believes that Atlas Energy’s and Atlas Pipeline’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. Atlas Energy and Atlas Pipeline have ongoing environmental compliance programs. However, risks of accidental leaks or spills are associated with their operations. There can be no assurance that Atlas Energy and Atlas Pipeline 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 Atlas Energy’s and Atlas Pipeline’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 Atlas Energy and Atlas Pipeline.

Environmental laws and regulations have changed substantially and rapidly over the last 25 years, and Atlas America anticipates 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 Atlas Energy and Atlas Pipeline 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. Atlas Energy and Atlas Pipeline will attempt to anticipate future regulatory requirements that might be imposed and to plan accordingly, but there can be no assurance that Atlas Energy and Atlas Pipeline will identify and properly anticipate each such charge, or that their efforts will prevent material costs, if any, from arising.

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Changes in Prices and Inflation

Atlas America’s revenues, the value of its assets, it and its subsidiaries’ ability to obtain bank loans or additional capital on attractive terms, and Atlas Energy’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 Atlas America’s ability to control or predict.

Inflation affects the operating expenses of Atlas America’s 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 Atlas America and its subsidiaries’ operations are able to charge. While Atlas America anticipates that inflation will affect its future operating costs, it 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 Atlas America bases its estimates on historical experience and various other assumptions that it believes to be reasonable under the circumstances, actual results may differ from the estimates on which its financial statements are prepared at any given point of time. Changes in these estimates could materially affect Atlas America’s 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. Atlas America summarizes its significant accounting policies within its consolidated financial statements included elsewhere in this joint proxy statement/prospectus. The critical accounting policies and estimates Atlas America has 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 Atlas America’s services or for Atlas America’s 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 “Cautionary Statement Regarding Forward-Looking Statements.”

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As discussed below, Atlas America recognized an impairment of goodwill at December 31, 2008 related to Atlas Pipeline. Atlas America believes this impairment of goodwill was an event that warranted assessment of Atlas Pipeline’s long-lived assets for possible impairment. Atlas Pipeline 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 Atlas America’s 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 Atlas America’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, Atlas America also considers a control premium to the calculations. This control premium is judgmental and is based, among other items, on observed acquisitions in Atlas America’s industry. The resultant fair values calculated for the reporting units are then compared to observable metrics on large mergers and acquisitions in Atlas America’s industry to determine whether those valuations appear reasonable in management’s judgment.

As a result of Atlas Energy’s and Atlas Pipeline’s impairment evaluation at December 31, 2008, Atlas America 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 Atlas Pipeline’s estimated fair value of reporting units in comparison to their carrying amounts at December 31, 2008. Atlas Pipeline’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. Atlas America recognized no goodwill impairments during the years ended December 31, 2007 and 2006. See “Note 2 — Summary of Significant Accounting Policies — Goodwill” in Atlas America’s consolidated financial statements included elsewhere in this joint proxy statement/prospectus regarding its impairment of goodwill and other assets.

Fair Value of Financial Instruments

Atlas America adopted the provisions of SFAS No. 157, “Fair Value Measurements” (which we refer to as “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 Atlas America’s financial statements, or disclosed at fair value in Atlas America’s notes to the financial statements. As a result, Atlas America 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:

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• 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.

Atlas America uses the fair value methodology outlined in SFAS No. 157 to value the assets and liabilities recorded at fair value, including Atlas Energy’s and Atlas Pipeline’s derivative contracts and Atlas America’s SERP. All of Atlas Energy’s and Atlas Pipeline’s commodity derivative contracts, with the exception of Atlas Pipeline’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. Atlas Energy’s, Atlas Pipeline’s and Atlas Pipeline Holdings’ interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model, and are therefore defined as Level 2. Atlas America’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 Atlas Pipeline’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 Atlas Pipeline’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

Atlas Energy’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 Atlas Energy’s reserves. As a result, Atlas Energy’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 Atlas Energy’s estimates or estimates contained in the reserve reports and may affect Atlas Energy’s ability to pay amounts due under its credit facilities or cause a reduction in Atlas Energy’s credit facilities. In addition, Atlas Energy’s proved reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing natural gas and oil prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond Atlas Energy’s control.

Asset Retirement Obligations

On an annual basis, Atlas Energy and Atlas Pipeline estimate the costs of future dismantlement, restoration, reclamation and abandonment of its operating assets. Atlas Energy and Atlas Pipeline 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 June 30, 2009, December 31, 2008 and 2007, the estimate of salvage values was greater than or equal to Atlas America’s 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 Atlas America subsidiaries’ credit adjusted risk free rate. A decrease in salvage values or an increase in dismantlement, restoration, reclamation and abandonment costs from those Atlas Energy and Atlas Pipeline have estimated, or changes in their estimates or costs, could reduce Atlas America’s gross profit from operations.

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Changes and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about Atlas America’s potential exposure to market risks. As Atlas America’s assets currently consist principally of its ownership interests in its 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 Atlas America views and manages its ongoing market risk exposures. All of the market risk sensitive instruments were entered into for purposes other than trading.

General

All of Atlas America’s and its subsidiaries’ assets and liabilities are denominated in U.S. dollars, and as a result, Atlas America does not have exposure to currency exchange risks.

Atlas America and its subsidiaries are exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact Atlas America’s results of operations, cash flows and financial position. Atlas America and its 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 Atlas America’s results of operations, cash flows and financial position as if the hypothetical changes in market risk factors occurred on June 30, 2009. Only the potential impact of hypothetical assumptions is analyzed. The analysis does not consider other possible effects that could impact Atlas America’s and its subsidiaries’ business.

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

Interest Rate Risk.At June 30, 2009, Atlas Energy had an outstanding balance of $456.0 million on its revolving credit facility. At June 30, 2009, Atlas Energy had interest rate derivative contracts having aggregate notional principal amounts of $150.0 million. Under the terms of this agreement, Atlas Energy will pay weighted average interest rates of 3.11% 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 $150.0 million of Atlas Energy’s floating rate debt under its revolving credit facility to fixed rate debt.

At June 30, 2009, Atlas Pipeline Holdings had a credit facility with $16.0 million outstanding. At June 30, 2009, Atlas Pipeline Holdings had an interest rate derivative contract having an aggregate notional principal amount of $25.0 million. Under the terms of the agreement, Atlas Pipeline Holdings will pay an interest rate of 3.01% 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 amounts. The interest rate swap agreement is in effect at June 30, 2009 and expires on May 28, 2010.

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At June 30, 2009, Atlas Pipeline had $322.0 million outstanding under its senior secured revolving credit facility and $459.9 million outstanding under its senior secured term loan. On May 29, 2009, Atlas Pipeline entered into an amendment to its senior secured credit facility agreement, which, among other changes, set a floor for the LIBOR interest rate of 2.0% per annum. At June 30, 2009, Atlas Pipeline had interest rate derivative contracts having aggregate notional principal amounts of $450.0 million. Under the terms of these agreements, Atlas Pipeline 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 are in effect as of June 30, 2009 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 Atlas America’s consolidated interest expense by $1.5 million.

Commodity Price Risk. Atlas America’s 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 its subsidiaries. To limit its exposure to changing natural gas and oil prices, Atlas Energy uses financial derivative instruments for a portion of its future natural gas and oil production. Atlas Pipeline is exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs and condensate rather than cash. Atlas Pipeline enters into financial swap and option instruments to hedge forecasted sales against the variability in expected future cash flows attributable to changes in market prices. 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, Atlas Pipeline receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Option instruments are contractual agreements that grant the right, but not obligation, to purchase or sell natural gas, NGLs and condensate at a fixed price for the relevant period. Both Atlas Energy and Atlas Pipeline apply the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”).

Holding all other variables constant, including the effect of commodity derivatives, a 10% change in the average price of natural gas, NGLs, condensate and oil would result in a change to Atlas America’s consolidated operating income from continuing operations, excluding income tax effects, for the twelve-month period ending June 30, 2010 of approximately $28.6 million.

Atlas Energy. Realized pricing of Atlas Energy’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, Atlas Energy 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 oil contracts are based on a West Texas Intermediate, or WTI, index.

Atlas Energy 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. Atlas Energy 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 within stockholders’ equity in the consolidated balance sheets and realized gains and losses are recognized within the consolidated statements of operations in the month the

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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, Atlas Energy will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings.

The following table summarizes the fair value of Atlas Energy’s derivative instruments as of June 30, 2009 and December 31, 2008, as well as the gain or loss recognized for the six months ended June 30, 2009 and 2008:

Atlas Energy Fair Value of Derivative Instruments:

	Asset Derivatives					Liability Derivatives
Derivatives in SFAS 133 Cash Flow Hedging Relationships		Fair Value					Fair Value
	Balance Sheet Location	June 30, 2009		December 31, 2008		Balance Sheet Location	June 30, 2009			December 31, 2008
		(in thousands)					(in thousands)
Commodity contracts	Current assets	$	116,977	$	107,766	Current liabilities	$	(383	)	$	(9,348	)
	Long-term assets		54,465		69,451	Long-term liabilities		(29,120	)		(8,410	)
			171,442		177,217			(29,503	)		(17,758	)
Interest rate contracts	Current assets		—		—	Current liabilities		(3,602	)		(3,481	)
	Long-term assets		—		—	Long-term liabilities		(1,213	)		(2,361	)
			—		—			(4,815	)		(5,842	)
Total derivatives under SFAS No. 133		$	171,442	$	177,217		$	(34,318	)	$	(23,600	)

Effects of Atlas Energy Derivative Instruments on Consolidated Statements of Operations:

Derivatives in SFAS 133 Cash Flow Hedging Relationships	Gain/(Loss) Recognized in OCI on Derivative (Effective Portion) For the Three Months Ended						Location of Gain/(Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Gain/(Loss) Reclassified from OCI into Income (Effective Portion) For the Three Months Ended
	June 30, 2009			June 30, 2008				June 30, 2009			June 30, 2008
	(in thousands)							(in thousands)
Commodity contracts	$	(22,528	)	$	(212,364	)	Gas and oil production	$	31,564		$	(4,896	)
Interest rate contracts		(132	)		3,831		Interest expense		(1,030	)		(114	)
	$	(22,660	)	$	(208,533	)		$	30,534		$	(5,010	)

Derivatives in SFAS 133 Cash Flow Hedging Relationships	Gain/(Loss) Recognized in OCI on Derivative (Effective Portion) For the Six Months Ended						Location of Gain/(Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Gain/(Loss) Reclassified from OCI into Income (Effective Portion) For the Six Months Ended
	June 30, 2009			June 30, 2008				June 30, 2009			June 30, 2008
	(in thousands)							(in thousands)
Commodity contracts	$	64,286		$	(310,522	)	Gas and oil production	$	47,082		$	1,645
Interest rate contracts		(1,005	)		1,795		Interest expense		(2,032	)		(23	)
	$	63,281		$	(308,727	)		$	45,050		$	1,622

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As of June 30, 2009, Atlas Energy had the following interest rate and commodity derivatives:

Interest Fixed Rate Swap

Term	Notional Amount		Option Type	Contract Period Ended December 31,	Fair Value (Liability)
					(in thousands)
January 2008-January 2011	$	150,000,000	Pay 3.11% – Receive LIBOR	2009	$	(1,932	)
				2010		(2,757	)
				2011		(126	)
					$	(4,815	)

Natural Gas Fixed Price Swaps

Production Period Ending December 31,	Volumes	Average Fixed Price		Fair Value Asset/(Liability)(1)
	(MMBtu)	(per MMBtu)		(in thousands)
2009	21,790,000	$	8.044	$	79,987
2010	31,880,000	$	7.708		52,270
2011	20,720,000	$	7.040		2,973
2012	19,680,000	$	7.223		1,131
2013	10,620,000	$	7.126		(1,631	)
				$	134,730

Natural Gas Costless Collars

Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset/(Liability)(1)
		(MMBtu)	(per MMBtu)		(in thousands)
2009	Puts purchased	120,000	$	11.000	$	795
2009	Calls sold	120,000	$	15.350		—
2010	Puts purchased	3,360,000	$	7.839		6,584
2010	Calls sold	3,360,000	$	9.007		—
2011	Puts purchased	9,540,000	$	6.523		145
2011	Calls sold	9,540,000	$	7.666		—
2012	Puts purchased	4,020,000	$	6.514		—
2012	Calls sold	4,020,000	$	7.718		(978	)
2013	Puts purchased	5,340,000	$	6.516		—
2013	Calls sold	5,340,000	$	7.811		(1,737	)
					$	4,809

Crude Oil Fixed Price Swaps

Production Period Ending December 31,	Volumes	Average Fixed Price		Fair Value Asset/(Liability)(2)
	(Bbl)	(per Bbl)		(in thousands)
2009	31,700	$	99.497	$	896
2010	48,900	$	97.400		1,079
2011	42,600	$	77.460		(30	)
2012	33,500	$	76.855		(105	)
2013	10,000	$	77.360		(35	)
				$	1,805

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Crude Oil Costless Collars

Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset/(Liability)(2)
		(Bbl)	(per Bbl)		(in thousands)
2009	Puts purchased	19,500	$	85.000	$	289
2009	Calls sold	19,500	$	116.884		—
2010	Puts purchased	31,000	$	85.000		448
2010	Calls sold	31,000	$	112.918		—
2011	Puts purchased	27,000	$	67.223		—
2011	Calls sold	27,000	$	89.436		(45	)
2012	Puts purchased	21,500	$	65.506		—
2012	Calls sold	21,500	$	91.448		(73	)
2013	Puts purchased	6,000	$	65.358		—
2013	Calls sold	6,000	$	93.442		(24	)
					$	595
Total Atlas Energy net asset					$	137,124

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

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

Atlas Pipeline Partners and Atlas Pipeline Holdings.Atlas Pipeline Holdings and Atlas Pipeline formally document all relationships between derivative instruments and the items being hedged, including their risk management objective and strategy for undertaking the derivative transactions. This includes matching the derivative contracts to the forecasted transactions. Under SFAS No. 133, Atlas Pipeline Holdings and Atlas Pipeline 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 derivative instrument and the underlying item being hedged, Atlas Pipeline Holdings and Atlas Pipeline will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by Atlas Pipeline Holdings and Atlas Pipeline through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in Atlas America’s consolidated statements of operations. For Atlas Pipeline Holdings’ and Atlas Pipeline’s derivatives qualifying as hedges, they will recognize the effective portion of changes in fair value in stockholders’ equity as accumulated other comprehensive income on Atlas America’s consolidated balance sheet, 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 Atlas America’s consolidated statements of operations as the underlying transactions are settled. For Atlas Pipeline Holdings’ and Atlas Pipeline’s non-qualifying derivatives and for the ineffective portion of qualifying derivatives, they will recognize changes in fair value within gain (loss) on mark-to-market derivatives in Atlas America’s consolidated statements of operations as they occur.

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The following table summarizes Atlas Pipeline Holdings and Atlas Pipeline’s derivative activity for the periods indicated (amounts in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Loss from cash and non-cash settlement of qualifying hedge instruments(1)	$	(7,327	)	$	(33,152	)	$	(27,502	)	$	(50,795	)
Gain/(loss) from change in market value of non-qualifying derivatives(2)		2,509			(136,736	)		(42,481	)		(207,932	)
Gain/(loss) from change in market value of ineffective portion of qualifying derivatives(2)		—			1,934			10,813			(3,726	)
Loss from cash and non-cash settlement of non-qualifying derivatives(2)		(21,105	)		(184,564	)		13,390			(196,489	)
Loss from cash settlement of interest rate derivatives(3)		(3,125	)		(207	)		(6,179	)		(207	)

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

(2) Included within loss on mark-to-market derivatives on Atlas America’s consolidated statements of operations.

(3) Included within interest expense on Atlas America’s consolidated statements of operations.

The following table summarizes Atlas Pipeline Holdings’ and Atlas Pipeline’s gross fair values of cumulative derivative instruments for the period indicated (amounts in thousands):

	June 30, 2009
	Asset Derivatives			Liability Derivatives
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments under SFAS No. 133:
N/A		$	—		$	—
Derivatives not designated as hedging instruments under SFAS No. 133:
Interest rate contracts		$	—	Current portion of derivative liability	$	(8,715	)
Commodity contracts	Current portion of derivative asset		1,815			—
Commodity contracts	Long-term derivative asset		1,606			—
Commodity contracts	Current portion of derivative liability		6,848	Current portion of derivative liability		(56,337	)
Commodity contracts	Long-term derivative liability		3,151	Long-term derivative liability		(15,899	)
		$	13,420		$	(80,951	)

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The following table summarizes the gross effect of the Atlas Pipeline Holdings’ and Atlas Pipeline’s derivative instruments on Atlas America’s consolidated statement of operations for the period indicated (amounts in thousands):

	Three months ended June 30, 2009
	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			Location of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)			Location of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
Derivatives in SFAS No. 133 cash flow hedging relationships:
N/A
Derivatives not designated as hedging instruments under SFAS No. 133:
Interest rate contracts	$	(3,125	)	Interest expense	$	—		N/A
Commodity contracts(1)		(10,894	)	Natural gas and liquids revenue		(13,381	)	Other loss, net
Commodity contracts(2)		—		N/A		(4,155	)	Other loss, net
	$	(14,019	)		$	(17,536	)

(1) Hedges previously designated as cash flow hedges

(2) Dedesignated cash flow hedges and non-designated hedges

	Six months ended June 30, 2009
	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			Location of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)			Location of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
Derivatives in SFAS No. 133 cash flow hedging relationships:
N/A
Derivatives not designated as hedging instruments under SFAS No. 133:
Interest rate contracts	$	(6,179	)	Interest expense	$	—		N/A
Commodity contracts(1)		(26,864	)	Natural gas and liquids revenue		(22,908	)	Other loss, net
Commodity contracts(2)		—		N/A		35,665		Other loss, net
	$	(33,043	)		$	12,757

(1) Hedges previously designated as cash flow hedges

(2) Dedesignated cash flow hedges and non-designated hedges

229

As of June 30, 2009, Atlas Pipeline Holdings 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	$	(323	)
				2010		(221	)
			Total Atlas Pipeline Holdings net liability		$	(544	)

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

As of June 30, 2009, Atlas Pipeline 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 2010	$	200,000,000	Pay 2.88% — Receive  LIBOR	2009	$	(2,480	)
				2010		(351	)
					$	(2,831	)
April 2008 - April 2010	$	250,000,000	Pay 3.14% — Receive  LIBOR	2009	$	(3,430	)
				2010		(1,910	)
					$	(5,340	)

Natural Gas Liquids Sales — Fixed Price Swaps

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability(2)
	(gallons)	(per gallon)		(in thousands)
2009	11,088,000	$	0.745	$	(573	)

Crude Oil Sales Options (associated with NGL volume)

Production Period Ended December 31,	Crude Volume	Associated NGL Volume	Average Crude Price(4)		Fair Value Asset/(Liability)(3)			Option Type
	(barrels)	(gallons)	(per barrel)		(in thousands)
2009	234,000	13,185,000	$	60.97	$	1,234		Puts purchased
2009	1,055,400	59,081,820	$	84.75		(2,622	)	Calls sold
2010	486,000	27,356,700	$	61.24		3,838		Puts purchased
2010	3,127,500	213,088,050	$	86.20		(22,103	)	Calls sold
2010	714,000	45,415,440	$	132.17		708		Calls purchased(5)
2011	606,000	33,145,560	$	100.70		(4,065	)	Calls sold
2011	252,000	13,547,520	$	133.16		764		Calls purchased(5)
2012	450,000	25,893,000	$	102.71		(3,746	)	Calls sold
2012	180,000	9,676,800	$	134.27		801		Calls purchased(5)
					$	(25,191	)

230

Natural Gas Sales — Fixed Price Swaps

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Asset(3)
	(mmbtu)(6)	(per mmbtu)(6)		(in thousands)
2009	240,000	$	8.000	$	866

Natural Gas Basis Sales

Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset(3)
	(mmbtu)(6)	(per mmbtu)(6)			(in thousands)
2009	2,460,000	$	(0.558	)	$	27
2010	2,220,000	$	(0.607	)		124
					$	151

Natural Gas Purchases — Fixed Price Swaps

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability(3)
	(mmbtu)(6)	(per mmbtu)(6)		(in thousands)
2009	5,160,000	$	8.687	$	(22,156	)
2010	4,380,000	$	8.635		(12,414	)
				$	(34,570	)

Natural Gas Basis Purchases

Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Liability(3)
	(mmbtu)(6)	(per mmbtu)(6)			(in thousands)
2009	7,380,000	$	(0.659	)	$	(83	)
2010	6,600,000	$	(0.590	)		(111	)
					$	(194	)

Ethane Put Options

Production Period Ended December 31,	Associated NGL Volume	Average Price(4)		Fair Value Liability(1)			Option Type
	(gallons)	(per gallon)		(in thousands)
2009	630,000	$	0.340	$	(40	)	Puts purchased

Propane Put Options

Production Period Ended December 31,	Associated NGL Volume	Average Price(4)		Fair Value Asset(1)		Option Type
	(gallons)	(per gallon)		(in thousands)
2009	15,498,000	$	0.767	$	752	Puts purchased

231

Isobutane Put Options

Production Period Ended December 31,	Associated NGL Volume	Average Price(4)		Fair Value Asset(1)		Option Type
	(gallons)	(per gallon)		(in thousands)
2009	1,134,000	$	0.969	$	20	Puts purchased

Normal Butane Put Options

Production Period Ended December 31,	Associated NGL Volume	Average Price(4)		Fair Value Asset(1)		Option Type
	(gallons)	(per gallon)		(in thousands)
2009	9,324,000	$	0.964	$	585	Puts purchased

Natural Gasoline Put Options

Production Period Ended December 31,	Associated NGL Volume	Average Price(4)		Fair Value Asset(1)		Option Type
	(gallons)	(per gallon)		(in thousands)
2009	5,796,000	$	1.267	$	358	Puts purchased

Crude Oil Sales

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability(3)
	(barrels)	(per barrel)		(in thousands)
2009	15,000	$	62.700	$	(131	)

Crude Oil Sales Options

Production Period Ended December 31,	Volumes	Average Crude Price(4)		Fair Value Asset (Liability)(3)			Option Type
	(barrels)	(per barrel)		(in thousands)
2009	231,000	$	63.017	$	1,100		Puts purchased
2009	153,000	$	84.881		(434	)	Calls sold
2010	174,000	$	61.111		1,361		Puts purchased
2010	234,000	$	88.088		(1,557	)	Calls sold
2011	72,000	$	93.109		(699	)	Calls sold
2012	48,000	$	90.314		(620	)	Calls sold
				$	(849	)
Total Atlas Pipeline net liability				$	(66,987	)

(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 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) Average price of options based upon average strike price adjusted by average premium paid or received.

232

(5) Calls purchased for 2010 through 2012 represent offsetting 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.

(6) Mmbtu represents million British Thermal Units.

The fair value of derivatives is included in Atlas America’s consolidated balance sheets as follows (in thousands):

	June 30, 2009			December 31, 2008
Current portion of derivative asset	$	118,792		$	152,727
Long-term derivative asset		56,071			69,451
Current portion of derivative liability		(62,189	)		(73,776	)
Long-term derivative liability		(43,081	)		(59,103	)
Total Atlas America net asset	$	69,593		$	89,299

Atlas America.

At June 30, 2009 and December 31, 2008, Atlas America reflected a net hedging asset on its consolidated balance sheets of $69.6 million and $89.3 million, respectively, as a result of Atlas Energy’s, Atlas Pipeline Holdings’ and Atlas Pipeline’s derivative contracts. Of the $29.5 million gains in accumulated other comprehensive income at June 30, 2009, Atlas America will reclassify $20.6 million of gains to its consolidated statements of operations over the next twelve month period as these contracts expire, and $8.9 million of gains 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.

233

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL INFORMATION

The following unaudited pro forma condensed consolidated financial data reflects Atlas America’s historical results as adjusted on a pro forma basis to give effect to (a) the merger and related transactions, (b) Atlas Pipeline’s May 2009 disposition of the NOARK system assets and (c) Atlas Pipeline’s June 2009 disposition of its Appalachia System to Laurel Mountain. The estimated adjustments to effect the merger and Atlas Pipeline’s disposition of the NOARK system assets and the Appalachia System are described in the notes to the unaudited pro forma financial data.

The unaudited pro forma condensed consolidated balance sheet information reflects the following transactions as if they occurred as of June 30, 2009:

• the merger, consisting of the cancellation and conversion of each outstanding Atlas Energy common unit, other than treasury units and Atlas Energy common units owned by Atlas America and its subsidiaries, into the right to receive 1.16 shares of Atlas America common stock. In addition, each outstanding restricted unit, phantom unit and unit option of Atlas Energy will be converted into an equivalent restricted share, phantom share and stock option of Atlas America with adjustments in the number of shares and exercise price to reflect the exchange ratio; and

• in connection with Atlas Pipeline’s May 4, 2009 disposition of the NOARK system assets, Atlas Pipeline received an additional $2.5 million in cash upon the delivery of audited financial statements for the NOARK system assets on July 7, 2009 to Spectra.

The unaudited pro forma condensed consolidated statements of operations information for the twelve months ended December 31, 2008 and the six months ended June 30, 2009 reflect the transactions noted above and the following transactions as if they occurred as of the beginning of the respective period:

• Atlas Pipeline’s May 4, 2009 disposition of the NOARK Holding Companies for $292.0 million in cash, the net proceeds of which were utilized to reduce Atlas Pipeline’s borrowings under its senior secured term loan and credit facility; and

• Atlas Pipeline’s June 2009 contribution of its Appalachia System to Laurel Mountain, a joint venture between Atlas Pipeline and Williams, in return for net proceeds of $87.8 million in cash, preferred distribution rights entitling Atlas Pipeline to receive payments under a $25.5 million note and a 49% ownership interest in Laurel Mountain.

The unaudited pro forma condensed consolidated balance sheet and the pro forma condensed consolidated statements of operations were derived by adjusting Atlas America’s historical consolidated financial statements. However, Atlas America management believes that the adjustments provide a reasonable basis for presenting the significant effects of the transactions described above. The unaudited pro forma financial data presented is for informational purposes only and is based upon available information and assumptions that the management of Atlas America believes are reasonable under the circumstances. This unaudited pro forma financial information is not necessarily indicative of the financial position or results of operations that Atlas America and its subsidiaries would have been had the transactions been consummated on the dates assumed, nor are they necessarily indicative of any future operating results or financial position. Atlas America and its subsidiaries may have performed differently had they been combined during the periods presented.

The unaudited pro forma condensed consolidated balance sheet and the unaudited pro forma condensed consolidated statements of operations include Atlas America’s historical consolidated financial statements, which have been adjusted to reflect the following:

• in May 2009, Atlas Pipeline completed the sale of its NOARK system assets. As such, Atlas America has retrospectively adjusted its prior period consolidated financial statements to reflect the amounts related to the operations of NOARK as discontinued operations in accordance with SFAS No. 144; and

234

• the adoption of Statement of Financial Accounting Standards No. 160, “Non-controlling Interests in Consolidated Financial Statements-an amendment of ARB No. 51.” SFAS No. 160 amends ARB No. 51 to establish accounting and reporting standards for the non-controlling interest (minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling 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 statements of operations at amounts that include the amounts attributable to both the parent and the non-controlling interest. Atlas America adopted the requirements of SFAS No. 160 on January 1, 2009. The consolidated financial statements reflect the retrospective application of SFAS No. 160 for all periods presented.

235

ATLAS AMERICA, INC. AND SUBSIDIARIES

PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET (UNAUDITED)

JUNE 30, 2009

(in thousands)

	Historical			NOARK Disposition Adjustments			Merger Adjustments			Pro Forma
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	81,331		$	2,500	(a)	$	—		$	81,331
					(2,500	)(b)
Accounts receivable		147,447			—			—			147,447
Current portion of derivative asset		118,792			—			—			118,792
Prepaid expenses and other		26,387			—			—			26,387
Prepaid and deferred income taxes		15,280			—			—			15,280
Total current assets		389,237			—			—			389,237
PROPERTY, PLANT AND EQUIPMENT, NET		3,714,402			—			—			3,714,402
LONG-TERM DERIVATIVE ASSET		56,071			—			—			56,071
GOODWILL, NET		35,166			—			—			35,166
INTANGIBLES, NET		184,113			—			—			184,113
INVESTMENT IN JOINT VENTURE		133,803			—			—			133,803
OTHER ASSETS, NET		68,574			—			—			68,574
	$	4,581,366		$	—		$	—		$	4,581,366
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt	$	16,000		$	—		$	—		$	16,000
Accounts payable		98,291			—			—			98,291
Liabilities associated with drilling contracts		88,909			—			—			88,909
Accrued producer liabilities		47,067			—			—			47,067
Current portion of derivative liability to Partnerships		32,839			—			—			32,839
Current portion of derivative liability		62,189			—			—			62,189
Accrued liabilities		106,119			—			—			106,119
Advances from affiliate		202			—			—			202
Total current liabilities		451,616			—			—			451,616
LONG-TERM DERIVATIVE LIABILITY TO PARTNERSHIPS		19,965			—			—			19,965
LONG-TERM DERIVATIVE LIABILITY		43,081			—			—			43,081
LONG-TERM DEBT		2,138,589			(2,500	)(b)		—			2,136,089
DEFERRED TAX LIABILITY		237,003			—			(107,168	)(c)		129,835
OTHER LONG-TERM LIABILITIES		54,093			—			—			54,093
STOCKHOLDERS’ EQUITY:
Preferred stock		—			—			—			—
Common stock		426			—			—			426
Additional paid-in capital		412,370			—			708,844	(c)		1,121,214
Treasury stock, at cost		(144,110	)		—			—			(144,110	)
Accumulated other comprehensive income		29,487			—			37,364	(c)		66,851
Retained earnings		136,741			285	(a)		(72,511	)(c)		64,515
		434,914			285			673,697			1,108,896
Non-controlling interests		1,202,105			2,215	(a)		(566,529	)(c)		637,791
Total stockholders’ equity		1,637,019			2,500			107,168			1,746,687
	$	4,581,366		$	—		$	—		$	4,581,366

See accompanying notes to unaudited pro forma condensed consolidated financial statements

236

ATLAS AMERICA, INC. AND SUBSIDIARIES

PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (UNAUDITED)

FOR THE TWELVE MONTHS ENDED DECEMBER 31, 2008

(in thousands, except per unit data)

	Historical			NOARK Disposition Adjustments			Appalachia System			Appalachia System Disposition Adjustments			Merger Adjustments			Pro Forma
REVENUE:
Well construction and completion	$	415,036		$	—		$	—		$	—		$	—		$	415,036
Gas and oil production		311,850			—			—			—			—			311,850
Transmission, gathering and processing		1,384,212			—			(47,747	)		—			—			1,336,465
Administration and oversight		19,362			—			—			—			—			19,362
Well services		20,482			—			—			—			—			20,482
Equity income in joint venture		—			—			—			13,210	(i)		—			13,210
Gain on mark-to-market derivatives		(63,480	)		—			—			—			—			(63,480	)
Total revenue		2,087,462			—			(47,747	)		13,210			—			2,052,925
COSTS AND EXPENSES:
Well construction and completion		359,609			—			—			—			—	��		359,609
Gas and oil production		48,194			—			—			—			—			48,194
Transmission, gathering and processing		1,153,555			—			(12,468	)		—			—			1,141,087
Well services		10,654			—			—			—			—			10,654
General and administrative		57,787			—			—			—			—			57,787
Depreciation, depletion and amortization		178,269			—			(6,015	)		—			—			172,254
Goodwill impairment		676,860			—			(2,304	)		—			—			674,556
Total costs and expenses		2,484,928			—			(20,787	)		—			—			2,464,141
OPERATING (LOSS) INCOME		(397,466	)		—			(26,960	)		13,210			—			(411,216	)
OTHER INCOME (EXPENSE):
Interest expense		(144,065	)		16,259	(d)		—			4,314	(j)		—			(125,785	)
					(2,267	)(e)					(26	)(k)
Gain on early extinguishment of debt		19,867			—			—			—			—			19,867
Other, net		11,383			—			—			—			—			11,383
Total other income (expense), net		(112,815	)		13,992			—			4,288			—			(94,535	)
(Loss) income before income taxes		(510,281	)		13,992			(26,960	)		17,498			—			(505,751	)
Benefit (provision) for income taxes		5,021			(606	)(f)		—			413	(l)		(30,583	)(n)		(25,755	)
(Loss) income from continuing operations		(505,260	)		13,386			(26,960	)		17,911			(30,583	)		(531,506	)
Income (loss) from discontinued operations, net of income taxes		19,671			(19,671	)(g)		—			—			—			—
Net (loss) income		(485,589	)		(6,285	)		(26,960	)		17,911			(30,583	)		(531,506	)
Income (loss) attributable to non-controlling interests		479,431			(12,477	)(h)		—			8,429	(m)		76,411	(o)		570,099
					18,305	(h)
Net (loss) income attributable to common shareholders	$	(6,158	)	$	(457	)	$	(26,960	)	$	26,340		$	45,828		$	38,593

237

ATLAS AMERICA, INC. AND SUBSIDIARIES

PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (UNAUDITED)

FOR THE TWELVE MONTHS ENDED DECEMBER 31, 2008

(in thousands, except per unit data)

	Historical			NOARK Disposition Adjustments	Appalachia System	Appalachia System Disposition Adjustments	Merger Adjustments	Pro Forma
Net income attributable to common shareholders per share:
Basic:
Income (loss) from continuing operations attributable to common shareholders	$	(0.19	)					$	0.50
Income (loss) from discontinued operations attributable to common shareholders		0.04							—
Income (loss) attributable to common shareholders	$	(0.15	)					$	0.50
Diluted:
Income (loss) from continuing operations attributable to common shareholders	$	(0.19	)					$	0.48
Income (loss) from discontinued operations attributable to common shareholders	$	0.04							—
Income (loss) attributable to common shareholders	$	(0.15	)					$	0.48
Weighted average common shares outstanding:
Basic		39,999							77,889	(p)
Diluted		39,999							80,684	(p)
Income (loss) attributable to common shareholders:
Income (loss) from continuing operations (net of income taxes (benefit))	$	(7,524	)					$	38,593
Income (loss) from discontinued operations (net of income taxes (benefit))		1,366							—
Net income (loss) attributable to common shareholders	$	(6,158	)					$	38,593

238

ATLAS AMERICA, INC. AND SUBSIDIARIES

PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (UNAUDITED)

FOR THE SIX MONTHS ENDED JUNE 30, 2009

(in thousands, except per unit data)

	Historical			NOARK Disposition Adjustments			Appalachia System			Appalachia System Disposition Adjustments			Merger Adjustments			Pro Forma
REVENUE:
Well construction and completion	$	175,735		$	—		$	—		$	—		$	—		$	175,735
Gas and oil production		141,922			—			—			—			—			141,922
Transmission, gathering and processing		349,737			—			(17,220	)		—			—			332,517
Administration and oversight		6,495			—			—			—			—			6,495
Well services		9,932			—			—			—			—			9,932
Gain on asset sales		105,691			—			(109,941	)		—			—			(4,250	)
Equity income in joint venture		710			—			—			4,053	(i)		—			4,763
Loss on mark-to-market derivatives		(18,277	)		—			—			—			—			(18,277	)
Total revenue		771,945			—			(127,161	)		4,053			—			648,837
COSTS AND EXPENSES:
Well construction and completion		149,098			—			—			—			—			149,098
Gas and oil production		21,089			—			—			—			—			21,089
Transmission, gathering and processing		302,890			—			(5,932	)		—			—			296,958
Well services		4,544			—			—			—			—			4,544
General and administrative		49,553			—			—			—			—			49,553
Depreciation, depletion and amortization		100,967			—			(3,016	)		—			—			97,951
Total costs and expenses		628,141			—			(8,948	)		—			—			619,193
OPERATING INCOME		143,804			—			(118,213	)		4,053			—			29,644
OTHER INCOME (EXPENSE):
Interest expense		(76,568	)		3,531	(d)		—			976	(j)		—			(72,061	)
Other, net		6,135			—			—			—			—			6,135
Total other income (expense), net		(70,433	)		3,531			—			976			—			(65,926	)
Income (loss) from continuing operations before income taxes		73,371			3,531			(118,213	)		5,029			—			(36,282	)
(Provision) benefit for income taxes		(6,263	)		(157	)(f)		—			5,043	(l)		(6,137	)(n)		(7,514	)
Income (loss) from continuing operations		67,108			3,374			(118,213	)		10,072			(6,137	)		(43,796	)
Income (loss) from discontinued operations, net of income taxes		59,761			(59,761	)(g)		—			—			—			—
Net (loss) income		126,869			(56,387	)		(118,213	)		10,072			(6,137	)		(43,796	)
Income (loss) attributable to non-controlling interests		(112,858	)		(3,129	)(h)		—			100,293	(m)		15,686	(o)		55,488
					55,496	(h)
Net income (loss) attributable to common shareholders	$	14,011		$	(4,020	)	$	(118,213	)	$	110,365		$	9,549		$	11,692

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ATLAS AMERICA, INC. AND SUBSIDIARIES

PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (UNAUDITED)

FOR THE SIX MONTHS ENDED JUNE 30, 2009

(in thousands, except per unit data)

	Historical		NOARK Disposition Adjustments	Appalachia System	Appalachia System Disposition Adjustments	Merger Adjustments	Pro Forma
Net income attributable to common shareholders per share:
Basic:
Income (loss) from continuing operations attributable to common shareholders	$	0.25					$	0.15
Income (loss) from discontinued operations attributable to common shareholders		0.11						—
Income (loss) attributable to common shareholders	$	0.36					$	0.15
Diluted:
Income (loss) from continuing operations attributable to common shareholders	$	0.25					$	0.15
Income (loss) from discontinued operations attributable to common shareholders		0.11						—
Income (loss) attributable to common shareholders	$	0.35					$	0.15
Weighted average common shares outstanding:
Basic		39,297						78,073	(p)
Diluted		39,717						78,493	(p)
Income (loss) attributable to common shareholders:
Income (loss) from continuing operations (net of income taxes (benefit))	$	9,746					$	11,692
Income (loss) from discontinued operations (net of income taxes (benefit))		4,265						—
Net income (loss) attributable to common shareholders	$	14,011					$	11,692

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ATLAS AMERICA, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(a) To reflect Atlas Pipeline’s receipt of an additional $2.5 million in proceeds from the May 2009 disposition of the NOARK system assets in accordance with the agreement of sale upon delivery of the audited financial statements for the NOARK system assets to the buyer. The proceeds were recorded as a gain on disposition, which was allocated to retained earnings based upon the Company’s and its subsidiaries’ equity interests in Atlas Pipeline, Atlas Pipeline Holdings, the indirect parent of Atlas Pipeline’s general partner and a subsidiary of Atlas America, and non-controlling interests. The Company had previously adjusted its deferred and current taxes payable within its June 30, 2009 historical consolidated balance sheet and its historical consolidated statements of operations for the six months ended June 30, 2009 associated with the $2.5 million gain as the cash was received by the Company prior to issuing its financial statements for those periods.

(b) To reflect the application of Atlas Pipeline’s receipt of an additional $2.5 million in proceeds from the disposition of the NOARK system assets to reduce borrowings under its senior secured term loan, which it was required to do under its credit agreement.

(c) To reflect the cancellation and conversion of 33,428,253 outstanding Atlas Energy common units at June 30, 2009, other than treasury and Atlas Energy common units owned by Atlas America and its subsidiaries, into 1.16 shares of Atlas America common stock. To reflect this transaction, the net book capital of Atlas Energy’s non-controlling interests on Atlas America’s consolidated balance sheet of $566.5 million was eliminated, with offsetting entries to recognize amounts previously allocated to Atlas Energy’s non-controlling interests, including accumulated other comprehensive income of $37.4 million, net of deferred taxes of $23.9 million, and an increase of $708.8 million to common stock and additional paid in capital to reflect the book value of Atlas America’s common shares issued to Atlas Energy’s non-controlling interests based on the market price of Atlas America’s common stock on August13, 2009. In addition, the entry reflects the reduction in deferred tax liabilities of $131.1 million due to the projected increase in tax basis related to Atlas America’s investment in Atlas Energy as compared to its corresponding book basis and an adjustment to retained earnings for the remaining difference between the value of the Atlas America common shares issued and the book value of the non-controlling interests acquired.

(d) To reflect the adjustment to interest expense to reflect Atlas Pipeline’s repayment of $294.5 million of its senior secured credit facility borrowings from the net proceeds of the sale of the NOARK Holding Companies. The weighted average historical interest rates utilized for the interest expense adjustment were 3.8% for the six months ended June 30, 2009 and 5.5% for the twelve months ended December 31, 2008.

(e) To reflect the write-off of unamortized deferred financing costs in connection with Atlas Pipeline’s repayment of $244.5 million of senior secured term loan borrowings, which may not be reborrowed, with a portion of the net proceeds from the disposition of the NOARK Holding Companies.

(f) To reflect the adjustment to Atlas America’s income tax provision as a result of the adjustments to pretax income consisting of Atlas Pipeline’s disposition of the NOARK Holding Companies, the repayment of borrowings under its senior secured credit facility, the write-off of deferred finance costs, and the adjustment of income allocated to the non-controlling interests of Atlas Pipeline and Atlas Pipeline Holdings as a result of the previously mentioned items. Each of the pretax adjustments were tax affected at Atlas America’s historical effective income tax rate for the respective period.

(g) To eliminate the historical financial results of Atlas Pipeline’s NOARK system assets, net of income taxes, which the Company has recognized within income from discontinued operations on its consolidated statements of operations upon their sale in May 2009.

(h) To reflect the adjustment of income allocated to Atlas Pipeline’s and Atlas Pipeline Holdings’ non-controlling interests resulting from adjustments consisting of Atlas Pipeline’s disposition of the NOARK Holding Companies, the repayment of borrowings under its senior secured term loan and credit facility, and the write-off of deferred finance costs.

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(i) To reflect Atlas Pipeline’s 49% equity interest in the net income of Laurel Mountain, which it received as partial consideration for its disposition of the Appalachia System, based upon the historical statement of operations data for the Appalachia System.

(j) To reflect the adjustment to interest expense to reflect Atlas Pipeline’s repayment of $87.8 million of its senior secured credit facility borrowings from the net proceeds of the sale of the Appalachia System. The weighted average historical interest rates utilized for the interest expense adjustment were 3.8% for the six months ended June 30, 2009 and 5.5% for the twelve months ended December 31, 2008.

(k) To reflect the write-off of unamortized deferred financing costs in connection with Atlas Pipeline’s repayment of $2.8 million of senior secured term loan borrowings, which may not be reborrowed, with a portion of the net proceeds from the disposition of the Appalachia System.

(l) To reflect the adjustment to Atlas America’s income tax provision as a result of the adjustments to pretax income consisting of Atlas Pipeline’s disposition of the Appalachia System, the recognition of its equity interest in the net income of Laurel Mountain, the repayment of borrowings under its senior secured credit facility, the write-off of deferred finance costs, and the adjustment of income allocated to the non-controlling interests of Atlas Pipeline and Atlas Pipeline Holdings as a result of the previously mentioned items. Each of the pretax adjustments were tax affected at Atlas America’s historical effective income tax rate for the respective period.

(m) To reflect the adjustment of income allocated to Atlas Pipeline’s and Atlas Pipeline Holdings’ non-controlling interests resulting from adjustments consisting of Atlas Pipeline’s disposition of the Appalachia System, the recognition of its equity interest in the net income of Laurel Mountain, the repayment of borrowings under its senior secured term loan and credit facility, and the write-off of deferred finance costs.

(n) To reflect the adjustment to Atlas America’s income tax provision as a result of the adjustments to pretax income consisting of the adjustment of income allocated to the non-controlling interests of Atlas Energy resulting from the merger.

(o) To reflect the adjustment of income allocated to Atlas Energy’s non-controlling interests resulting from the merger.

(p) To reflect the adjustment of Atlas America’s weighted average outstanding common shares as a result of the cancellation and conversion of Atlas Energy common units held by non-controlling interests into 1.16 shares of Atlas America common stock as a result of the merger.

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DESCRIPTION OF ATLAS AMERICA CAPITAL STOCK

The following is a description of the material terms of the Atlas America charter and bylaws, as each will be in effect as of the effective time of the merger, and of specific provisions of Delaware law. The following description is intended as a summary only and is qualified in its entirety by reference to the Atlas America charter and bylaws, each of which is included as an exhibit to the registration statement of which this joint proxy statement/prospectus forms a part, and is qualified by reference to the Delaware General Corporation Law (which we refer to as the “DGCL”).

Common Stock

As of the effective time of the merger, Atlas America will be authorized to issue up to 114 million shares of common stock. Immediately following the merger, Atlas America expects there to be approximately 78.1 million shares of Atlas America common stock outstanding.

Holders of Atlas America common stock are entitled to receive dividends when, as and if declared by the Atlas America board of directors out of funds legally available for payment, subject to the rights of holders, if any, of Atlas America preferred stock. For more information about Atlas America’s dividends, see “Information About Atlas America—Dividend Policy.”

Each holder of Atlas America common stock is entitled to one vote per share. Subject to the rights, if any, of the holders of any series of preferred stock if and when issued and subject to applicable law, all voting rights are vested in the holders of shares of Atlas America common stock. There are no cumulative voting rights. Accordingly, the holders of a majority of the shares of common stock voting for the election of directors can elect all of the directors if they choose to do so, subject to any voting rights of holders of preferred stock to elect directors.

In the event of a voluntary or involuntary liquidation, dissolution or winding up of Atlas America, the holders of Atlas America common stock will be entitled to share equally in any of the assets available for distribution after Atlas America has paid in full all of its debts and after the holders of all outstanding series of Atlas America preferred stock, if any, have received their liquidation preferences in full.

The issued and outstanding shares of Atlas America common stock are fully paid and nonassessable. Holders of shares of Atlas America common stock are not entitled to preemptive rights. Shares of Atlas America common stock are not convertible into shares of any other class of capital stock.

Preferred Stock

Under the terms of the Atlas America charter, the Atlas America board of directors is authorized to designate and issue shares of preferred stock in one or more series without stockholder approval. The Atlas America board of directors has discretion to determine the rights, preferences, privileges and restrictions, including voting rights, dividend rights, conversion rights, redemption privileges and liquidation preferences, of each series of preferred stock. It is not possible to state the actual effect of the issuance of any shares of preferred stock upon the rights of holders of the common stock until the board of directors determines the specific rights of the holders of the preferred stock. However, these effects might include:

• restricting dividends on the common stock;

• diluting the voting power of the common stock;

• impairing the liquidation rights of the common stock; and

• delaying or preventing a change in control of Atlas America.

Atlas America has no present plans to issue any shares of preferred stock.

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Delaware Anti-Takeover Law and Charter and Bylaw Provisions

Atlas America is subject to the provisions of DGCL Section 203. In general, the statute prohibits a publicly held Delaware corporation from engaging in a “business combination” with an “interested stockholder” for a period of three years after the date of the transaction in which the person became an interested stockholder, unless the business combination or the transaction by which the person became an interested stockholder is approved by the corporation’s board of directors and/or stockholders in a prescribed manner or the person owns at least 85% of the corporation’s outstanding voting stock after giving effect to the transaction in which the person became an interested stockholder. The term “business combination” includes mergers, asset sales and other transactions resulting in a financial benefit to the interested stockholder. Subject to certain exceptions, an “interested stockholder” is a person who, together with affiliates and associates, owns, or within three years did own, 15% or more of the corporation’s voting stock. A Delaware corporation may “opt out” from the application of Section 203 through a provision in its certificate of incorporation or bylaws. Atlas America has not “opted out” from the application of Section 203.

Atlas America’s bylaws provide that nominations for the election of directors and advance notice of other action to be taken at meetings of stockholders must be given in the manner provided in Atlas America’s bylaws, which contain detailed notice requirements relating to nominations and other action.

The foregoing provisions of the Atlas America charter and bylaws and the provisions of DGCL Section 203 could have the effect of delaying, deferring or preventing a change of control of Atlas America.

Liability and Indemnification of Officers and Directors

The Atlas America charter provides that its directors shall not be personally liable to Atlas America or its stockholders for monetary damages for breach of fiduciary duty as a director, except to the extent an exemption from liability is not permitted under the DGCL. That law currently does not permit limitation of liability:

• for any breach of a director’s duty of loyalty to Atlas America or its stockholders,

• for acts of omissions not in good faith or which involve intentional misconduct or a knowing violation of law,

• under Section 174 of the DGCL with respect to unlawful payment of dividends or unlawful stock purchases and redemptions, or

• for any transaction from which the director derives an improper personal benefit.

Moreover, the provisions do not apply to claims against a director for violations of certain laws, including federal securities laws. If the DGCL is amended to authorize the further elimination or limitation of directors’ liability, then the liability of Atlas America directors shall automatically be limited to the fullest extent provided by law. The Atlas America charter and bylaws also contain provisions to indemnify Atlas America directors and officers to the fullest extent permitted by the DGCL. In addition, Atlas America may enter into indemnification agreements with its directors and officers. These provisions and agreements may have the practical effect in certain cases of eliminating the ability of stockholders to collect monetary damages from directors and officers. Atlas America believes that these contractual agreements and the provisions in the Atlas America charter and bylaws are necessary to attract and retain qualified persons as directors and officers.

Listing

Atlas America common stock is listed on NASDAQ under the symbol “ATLS.”

Transfer Agent and Registrar

The transfer agent and registrar for Atlas America common stock is American Stock Transfer & Trust Company.

244

COMPARISON OF RIGHTS OF ATLAS AMERICA STOCKHOLDERS

AND ATLAS ENERGY UNITHOLDERS

If the merger is consummated, unitholders of Atlas Energy will become stockholders of Atlas America. The rights of Atlas America stockholders are governed by and subject to the provisions of the Delaware General Corporation Law and the Amended and Restated Certificate of Incorporation and Bylaws of Atlas America. In contrast, rights of Atlas Energy unitholders are governed by and subject to the provisions of the Delaware Limited Liability Company Act and the Amended and Restated Operating Agreement of Atlas Energy. The following is a summary of the material differences between the rights of holders of Atlas America common stock and the rights of holders of Atlas Energy common units, but does not purport to be a complete description of those differences and is qualified in its entirety by reference to the relevant provisions of (1) the DGCL, (2) the Delaware Limited Liability Company Act (which we refer to as the “LLC Act”), (3) the Atlas America charter, (4) the Amended and Restated Operating Agreement of Atlas Energy (which we refer to as the “Atlas Energy operating agreement”), and (5) the bylaws of Atlas America.

This section does not include a complete description of all differences among the rights of Atlas America stockholders and Atlas Energy unitholders, nor does it include a complete description of the specific rights of such holders. Furthermore, the identification of some of the differences in the rights of such holders as material is not intended to indicate that other differences that may be equally important do not exist. You are urged to read carefully the relevant provisions of the DGCL and the LLC Act, as well as the governing corporate instruments of each of Atlas America and Atlas Energy, copies of which are available, without charge, to any person, including any beneficial owner to whom this joint proxy statement/prospectus is delivered, by following the instructions listed under “Where You Can Find More Information.”

	Rights of Atlas Energy Unitholders	Rights of Atlas America Stockholders
Authorized Equity Securities	Atlas Energy is authorized under the Atlas Energy operating agreement to issue an unlimited number of equity securities of Atlas Energy and options, rights, warrants and appreciations rights relating to such Atlas Energy equity securities, all without the approval of holders of any class of Atlas Energy equity securities outstanding. Prior to the issuance of a class or series of Atlas Energy equity security, the Atlas Energy board of directors is permitted to fix the designations, preferences, rights, powers and duties (which may be senior or prior, pari passu or junior to the preferences, rights, powers and duties of any outstanding class or series of Atlas Energy equity securities) relating to the class or series. The Atlas Energy operating agreement specifically established the following classes of Atlas Energy equity securities: •     Atlas Energy common units, which collectively represent an	Atlas America as of the effective time of the merger will be authorized under the Atlas America charter to issue an aggregate of 115,000,000 shares of capital stock, consisting of 114,000,000 shares of common stock, $0.01 par value per share, and 1,000,000 shares of preferred stock, $0.01 par value per share, issuable in one or more classes or series. Prior to the issuance of a class or series of preferred stock, the Atlas America board of directors is permitted to fix the voting powers, designations, preferences and relative, participating, optional or other special rights and such qualifications, limitations or restrictions relating to the shares of the class or series. As of August 18, 2009, the Atlas America record date, there were 39,363,023 shares of Atlas America common stock issued and outstanding and no preferred stock issued and outstanding.

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	Rights of Atlas Energy Unitholders	Rights of Atlas America Stockholders
	aggregate 98% membership interest in Atlas Energy, •   Atlas Energy Class A units, which have certain class voting rights and collectively represent an aggregate 2% membership interest in Atlas Energy, and •   management incentive interests, which have no voting rights and entitle the holder to receive increasing percentages, up to a maximum of 25.0% of any cash distributed by Atlas Energy in excess of $0.48 per Atlas Energy common unit in any quarter after Atlas Energy has met certain tests set forth in the Atlas Energy operating agreement. As of August 18, 2009 the Atlas Energy record date, there were 63,381,249 Atlas Energy common units issued and outstanding and 1,293,496 Atlas Energy Class A units issued and outstanding, all of which Atlas Energy Class A units were beneficially owned by Atlas Energy Management.
Dividends and Distributions	The Atlas Energy operating agreement requires that, within 45 days after the end of each quarter, Atlas Energy distribute all of its “available cash” to unitholders. “Available cash” is defined in the Atlas Energy operating agreement as all cash on hand at the end of the quarter plus cash on hand from working capital borrowings made after the end of the quarter less the amount of cash that the Atlas Energy board of directors in its discretion establishes to provide for the proper conduct of business (including reserves for future capital expenditures and credit needs), to comply with applicable law and any of Atlas Energy’s debt instruments and for other contracts, and certain other considerations, including reserving funds for future quarterly distributions.	The Atlas America charter and bylaws are silent with respect to dividends. Therefore, the determination of the amount of future cash dividends on Atlas America common stock, if any, is at the sole discretion of the Atlas America board of directors based upon its analysis of factors it deems relevant. Generally, these factors include Atlas America’s results of operations, financial condition, capital requirements and investment opportunities. Under the DGCL, dividends may be declared by the board of directors and paid out of surplus, and, if no surplus is available, out of any net profits for the then current fiscal year or the preceding fiscal year, or both, provided that such payment would not reduce

246

	Rights of Atlas Energy Unitholders	Rights of Atlas America Stockholders
	Under the LLC Act, a limited liability company may not make distributions to members to the extent that at the time of the distribution, after giving effect to the distribution, all liabilities of the company, other than liabilities to members on account of their interests and liabilities for which the recourse of creditors is limited to specified property of the company, exceed the fair value of the assets of the limited liability company, except that the fair value of property that is subject to a liability for which the recourse of creditors is limited shall be included in the assets of the limited liability company only to the extent that the fair value of that property exceeds that liability.	capital below the amount of capital represented by all classes of outstanding stock having a preference as to the distribution of assets upon liquidation.
Amendments to Governing Documents and Approval of Other Extraordinary Transactions	To authorize a (i) merger or consolidation, (ii) sale, lease or exchange of all or substantially all of the company’s assets, or (iii) voluntary liquidation or dissolution, the Atlas Energy operating agreement requires, subject to certain limited exceptions, the affirmative vote of the holders of a majority of the outstanding Atlas Energy common units and the affirmative vote of the holders of a majority of the outstanding Atlas Energy Class A units, in each case, voting separately as a class. Amendments to the Atlas Energy operating agreement generally require the approval of holders of a majority of the outstanding Atlas Energy common units and Atlas Energy Class A units, voting together as a single class. The Atlas Energy operating agreement provides that certain sections (primarily related to certain amendments to the Atlas Energy operating agreement, special meetings of Atlas Energy	To authorize a (i) merger or consolidation, (ii) sale, lease or exchange of all or substantially all of a corporation’s assets, (iii) voluntary liquidation, or (iv) amendments to the certificate of incorporation of a corporation, the DGCL requires, subject to certain limited exceptions, the affirmative vote of the holders of a majority of the outstanding shares of the voting stock. The Atlas America board of directors has the power to adopt, amend, alter or repeal the Atlas America bylaws without stockholder approval.

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	Rights of Atlas Energy Unitholders	Rights of Atlas America Stockholders
	unitholders, voting rights and notice of business and nominations for an annual or special meeting of Atlas Energy unitholders) requires the affirmative vote of holders of at least 75% of the outstanding Atlas Energy common units and 75% of the outstanding Class A units. The Atlas Energy operating agreement also provides that the Atlas Energy board of directors may amend the Atlas Energy operating agreement without the consent of any unitholders in certain circumstances, including, among other things, in connection with a change in the name, principal officer or registered agent of Atlas Energy, the admission or removal of members, the issuance or authorization of new units, any amendment effected, necessitated or contemplated by a merger agreement or plan of conversion approved in accordance with the Atlas Energy operating agreement, provided that any amendment (other than those related to the issuance or authorization of new units) that has a material adverse effect on the rights of any class of units relative to other classes of units must be approved by a majority of the then outstanding member interests of the class affected.
Size and Classification of the Board of Directors	The Atlas Energy board of directors, which currently consists of seven persons, is not classified. Each director is elected at each annual meeting for a one-year term expiring at the next annual meeting of unitholders.	The Atlas America board of directors is divided into three classes, with each class consisting, as nearly as may be possible, of one-third of the total number of directors constituting the entire board. Each class is elected to staggered three-year terms. Pursuant to the terms of the merger agreement, at the effective time of the merger, the Atlas America board of directors will consist of 12 persons, including 10 independent

248

	Rights of Atlas Energy Unitholders	Rights of Atlas America Stockholders
		directors drawn from Atlas America and Atlas Energy serving at the time the merger is consummated and Edward E. Cohen and Jonathan Z. Cohen, Chief Executive Officer and Vice Chairman, respectively, of both Atlas America and Atlas Energy.
Voting Rights and the Election of Directors	The Atlas Energy operating agreement provides that the holders of Atlas Energy common units and Atlas Energy Class A units are entitled to one vote per unit on all matters submitted to unitholders for approval and in the election of directors, voting together as a single class. Directors are elected by a plurality of votes cast for a particular position.	The Atlas America bylaws provide that each stockholder is entitled to one vote for each share of capital stock of Atlas America entitled to vote. In all matters other than the election of directors, the affirmative vote of the majority of shares present in person or represented by proxy at the meeting and entitled to vote on the subject matter shall be the act of the stockholders. Directors shall be elected by a plurality of the votes of the shares present in person or represented by proxy at the meeting and entitled to vote on the election of directors. Voting rights of preferred shares, if any, will be set forth in any certificate of designation issuing such shares.
Calling Special Meetings of Stockholders/Unitholders	Special meetings of the unitholders, for any purpose or purposes, may be called by the Chairman of the board or the Vice Chairman of the board, if there be either, the Chief Executive Officer, the President or a majority of the entire board of directors. No unitholders or group of unitholders, acting in its or their capacity as unitholders, have the right to call a special meeting of the unitholders.	A special meeting of the stockholders, for any purpose or purposes, may be called by the Chairman of the board or the Vice Chairman of the board, if there be either, the Chief Executive Officer, the President, the Secretary or a majority of the entire board of directors.
Notice of Meetings	Notice of meetings are to be delivered by Atlas Energy not less than 10 calendar days nor more than 60 calendar days before the date of the meeting, in a manner and otherwise in accordance with the Atlas Energy operating agreement to each record holder who is entitled to vote at such meeting.	A written notice of meetings shall be given not less than 10 nor more than 60 days before the date of the meeting to each stockholder entitled to vote at such meeting.

249

	Rights of Atlas Energy Unitholders	Rights of Atlas America Stockholders
Removal of Directors	The Atlas Energy operating agreement provides that any director may be removed at any time, with or without cause, by the affirmative vote or consent of a majority of the outstanding Atlas Energy common units and Atlas Energy Class A units, voting together as a single class.	The Atlas America charter provides that any or all of the directors of Atlas America may be removed from office at any time, but only for cause, by the affirmative vote of the holders of at least 66 2/3% of the voting power of Atlas America’s then outstanding capital stock entitled to vote generally in the election of directors.
Filling Vacancies	Subject to removal and other rights of unitholders under the Atlas Energy operating agreement, vacancies existing on the board of directors created by virtue of an increase in the size of the board of directors or resulting from the death, resignation or removal of a director may be filled only by the affirmative vote of a majority of the directors then serving, even if less than a quorum. Any director chosen to fill a vacancy shall hold office until the next annual meeting of unitholders and until his or her successor has been duly elected and qualified or until such director’s earlier death, resignation or removal.	Subject to removal and other rights of stockholders, any vacancy on the board of directors that results from a increase in the number of directors may be filled only by a majority of the board of directors then in office, provided that a quorum is present, and any other vacancy occurring on the board of directors may be filled only by a majority of the board of directors then in office, even if less than a quorum, or by a sole remaining director. Any director of any class elected to fill a vacancy resulting from an increase in the number of directors of such class shall hold office for a term that shall coincide with the remaining term of that class. Any director elected to fill a vacancy not resulting from an increase in the number of directors shall have the same remaining term as that of his predecessor.
Indemnification and Advancement of Expenses of Directors and Officers	The Atlas Energy operating agreement provides that Atlas Energy will indemnify, hold harmless and defend, to the fullest extent permitted by law as it currently exists and to such greater extent as applicable law may hereafter be amended, any person who was or is a party or is threatened to be made a party to, or otherwise requires representation of counsel in connection with a proceeding by reason of the fact that he or she is or was: (a) a director, officer, employee or agent of Atlas Energy or a Tax Matters Partner (as defined by the Internal Revenue Code) of Atlas Energy, (b) a member, partner, manager, director, officer, fiduciary or	The Atlas America charter provides that Atlas America will indemnify its officers and directors to the fullest extent authorized or permitted by applicable law, including the right to reimbursement of expenses incurred in defending or participating in any proceeding. The Atlas America bylaws further provide that Atlas America will indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (a “proceeding”) by reason of the fact

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	Rights of Atlas Energy Unitholders	Rights of Atlas America Stockholders
	trustee of any subsidiary of Atlas Energy, (c) serving at the request of Atlas Energy as a director, manager, officer, tax matters partner, fiduciary or trustee of another person, and (d) designated by Atlas Energy as an indemnitee under the Atlas Energy operating agreement (clauses (a) — (d) referred to herein as “Indemnitees”); provided that an Indemnitee will not be indemnified and held harmless if there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in a criminal matter, acted with knowledge that the Indemnitee’s conduct was criminal. Atlas Energy will pay the expenses (including reasonable attorneys’ fees) incurred by an Indemnitee in defending any proceeding when and as incurred, in advance of the final disposition of such proceeding, upon receipt of an undertaking by or on behalf of such Indemnitee to repay such amount if it is ultimately determined by final judicial decision from which there is no further right to appeal that such person is not entitled to indemnification.	that he or she is or was a director or officer of Atlas America, or is or was a director or officer of Atlas America serving at the request of Atlas America as a director or officer, employee or agent of another corporation, partnership, joint venture, trust employee benefit plan or other enterprise, against expenses (including attorney’s fees), judgments, fines and amounts paid in settlements actually and reasonably incurred by such person in connection with such proceeding if he or she acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interest of Atlas America, and, with respect to any criminal action, had no reason to believe his or her conduct was unlawful. Atlas America may, to the extent authorized by its board of directors, provide rights to indemnification and advancement of expenses to employees and agents of Atlas America similar to those conferred to directors and officers. Atlas America will pay the expenses incurred by a director or officer in defending any proceeding in advance of its final disposition upon receipt of an undertaking by or on behalf of such officer or director to repay such amount if it is ultimately determined that such person is not entitled to be indemnified. Expenses incurred by former directors and officers or other employees and agents may be paid upon such terms and conditions, if any, as Atlas America deems appropriate.
Limitation of Liability of Directors	No Indemnitee will be liable to Atlas Energy or its unitholder for losses incurred as a result of any act or omission of an Indemnitee unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the Indemnitee acted	The Atlas America charter provides that no director shall be personally liable to Atlas America or any of its stockholders for monetary damages for breach of fiduciary duty as a director, except to the extent such exemption from liability or limitation thereof is not permitted under the

251

	Rights of Atlas Energy Unitholders	Rights of Atlas America Stockholders
	in bad faith or engaged in fraud, willful misconduct or, in a criminal matter, acted with knowledge that the Indemnitee’s conduct was criminal. To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to Atlas Energy or its unitholders, none of the directors and any other Indemnitee acting in connection with Atlas Energy’s business or affairs will be liable to Atlas Energy or its unitholders for its good faith reliance on the provisions of the Atlas Energy operating agreement. The provisions of the Atlas Energy operating agreement, to the extent that they restrict or eliminate or otherwise modify the duties (including fiduciary duties) and liabilities of an Indemnitee otherwise existing in law or in equity, are agreed by the unitholders to replace such other duties and liabilities of such Indemnitee.	DGCL as now exists or hereafter may be amended. DGCL does not permit the elimination or limitation of the liability of a director for the following: (1) any breach of the director’s duty of loyalty to the corporation or its stockholders, (2) acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (3) unlawful payment of dividends or unlawful stock purchases or redemptions, and (4) any transaction from which the director derived an improper personal benefit.
Conflicts of Interest	The Atlas Energy operating agreement provides procedures for resolving conflicts of interest that exist or may arise in the future as a result of the relationships between members of the Atlas Energy board of directors and Atlas America and its affiliates, on the one hand, and Atlas Energy and its unitholders, on the other hand. Under the Atlas Energy operating agreement, the Atlas Energy board of directors or its conflicts committee will resolve, on behalf of the Atlas Energy unitholders, any conflicts between Atlas Energy and Atlas America and its affiliates. The conflicts committee of the Atlas Energy board of directors will, at the optional request of the board of directors, review conflicts of interest. Any resolution or course of action by the Atlas Energy board of directors with respect to a conflict of interest will be permitted and deemed	Neither the Atlas America charter nor the Atlas America bylaws contains provisions for the resolution of conflicts of interest.

252

Rights of Atlas Energy Unitholders	Rights of Atlas America Stockholders
approved by all members, and therefore will not constitute a breach of the Atlas Energy operating agreement, if the resolution is: (i)     approved by a majority of the members of the conflicts committee; (ii)    approved by a majority of the outstanding Atlas Energy common units (excluding Atlas Energy common units held by interested parties); (iii)  on terms no less favorable to Atlas Energy than those generally provided to or available from unrelated third parties; or (iv)   fair and reasonable to Atlas Energy, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous.
The Atlas Energy board of directors may adopt a resolution with respect to a conflict of interest provided that interested directors have recused themselves from participation. The Atlas Energy board of directors may, but is not required to, seek the approval of such resolution from the conflicts committee. If the Atlas Energy board of directors does not seek approval from the conflicts committee and the Atlas Energy board determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in clauses (iii) or (iv) above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any unitholder of Atlas Energy, the person bringing the proceeding will have the burden of overcoming the presumption.

253

	Rights of Atlas Energy Unitholders	Rights of Atlas America Stockholders
	An action is in “good faith” for purposes of the Atlas Energy operating agreement, if the Atlas Energy board of directors believes that such action is in the best interest of Atlas Energy.
Fiduciary Duties of Directors	The Atlas Energy operating agreement restricts, eliminates or otherwise modifies the duties, including fiduciary duties, and liabilities of the Atlas Energy board of directors owed to unitholders. The Atlas Energy operating agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.	Delaware law, which has developed through Delaware court cases, ascribes duties to directors of corporations that require them to act as loyal fiduciaries to the corporation’s stockholders. Generally, directors of Delaware corporations are subject to a duty of loyalty and a duty of care. The duty of loyalty requires directors to refrain from self-dealing. Where directors act consistently with their duty of loyalty and also with their duty of care, their decisions generally are presumed to be valid under the business judgment rule. Where directors are interested in a transaction, Delaware law generally imposes the higher “entire fairness” standard when evaluating transactions.
Limited Call Right	The Atlas Energy operating agreement provides that if at any time any person owns more than 87.5% of the then-issued and outstanding membership interests of any class of Atlas Energy, such person will have the right, which it may assign in whole or in part to Atlas Energy or any of its affiliates, to acquire all, but not less than all, of the remaining membership interests of the class held by unaffiliated persons as of a record date to be selected by Atlas Energy management, on at least 10 but not more than 60 days’ notice. The unitholders are not entitled to dissenters’ rights of appraisal under the Atlas Energy operating agreement or the LLC Act if this limited call right is exercised. The purchase price in the event of this purchase is the greater of: (1) the highest price paid by such person for any membership interests of the class purchased within	The DGCL provides that in any case in which at least 90% of the outstanding voting stock of a corporation is owned by another corporation, the parent corporation can merge with the subsidiary corporation with only a resolution of the board of directors of the parent corporation. Stockholder approval of the merger is not required.

254

	Rights of Atlas Energy Unitholders	Rights of Atlas America Stockholders
	the 90 days preceding the date on which such person first mails notice of its election to purchase those membership interests; or (2) the closing market price as of the date three days before the date such notice is mailed.
Voting Rights; Anti-Takeover	If any person or group (other than Atlas America, Atlas Energy Management and their affiliates or persons who acquired their units of Atlas Energy directly from Atlas America, Atlas Energy Management or their affiliates with the prior approval of the Atlas Energy board of directors) beneficially owns 20% or more of any class of units of Atlas Energy then outstanding, all Atlas Energy units owned by such person or group cannot vote on any matter and are not considered outstanding.	Under the DGCL, a corporation is prohibited from engaging in any business combination with an interested stockholder for a period of three years from the date on which the stockholder first becomes an interested stockholder. There is an exception to the three-year waiting period requirement if: (i)     prior to the stockholder becoming an interested stockholder, the board of directors approves the business combination or the transaction in which the stockholder became an interested stockholder; (ii)    upon the completion of the transaction in which the stockholder became an interested stockholder, the interested stockholder owns at least 85% of the voting stock of the corporation other than shares held by directors who are also officers and certain employee stock plans; or (iii)  the business combination is approved by the board of directors and by the affirmative vote of 66 2/3% of the outstanding voting stock not owned by the interested stockholder at a meeting. The DGCL defines the term “business combination” to include, among other things, mergers or consolidations either with the interested stockholder or with another entity if the transaction is caused by the interested stockholder, transfers of 10% or more

255

Rights of Atlas Energy Unitholders

Rights of Atlas America Stockholders

of the assets of a corporation to the interested stockholder except in certain circumstances, issuances or transfers of any stock of the corporation or any majority-owned subsidiary corporation to the interested stockholder except in certain circumstances, any transaction involving the corporation and any majority owned subsidiary of the corporation which has the effect, directly or indirectly, of increasing the proportionate shares of stock owned by the interested stockholder subject to certain exceptions, and the receipt by the interested stockholder of any benefit, directly or indirectly, except proportionately as a stockholder of the corporation, of any loans, advances, guarantees, pledges or other financial benefits. The DGCL defines the term “interested stockholder” generally as any person who (together with affiliates and associates) owns (or in certain cases, within the past three years did own) 15% or more of the outstanding voting stock of the corporation. A corporation can expressly elect not to be governed by the DGCL’s business combination provisions in its certificate of incorporation or bylaws, but Atlas America has not done so.

256

LEGAL MATTERS

The validity of the shares of Atlas America common stock to be issued in the merger will be passed upon by Ledgewood, Philadelphia, Pennsylvania.

EXPERTS

The consolidated financial statements of Atlas America, Inc. as of December 31, 2008 and 2007, and for each of the three years in the period ended December 31, 2008 have been audited by Grant Thornton LLP, independent registered public accountants, as indicated in their report with respect thereto, and are included in this registration statement and prospectus in reliance upon the authority of said firm as experts in accounting and auditing in giving such report.

The combined and consolidated financial statements of Atlas Energy Resources, LLC as of December 31, 2008 and 2007, and for each of the three years in the period ended December 31, 2008 have been audited by Grant Thornton LLP, independent registered public accountants, as indicated in their report (which report expressed an unqualified opinion and contains an explanatory paragraph relating to the Company’s adoption of Financial Accounting Standards Board Interpretation No. 47 in 2006) with respect thereto, and are incorporated by reference into this registration statement and prospectus in reliance upon the authority of said firm as experts in accounting and auditing in giving such report.

The financial statements of DTE Gas & Oil Company as of December 31, 2006 and 2005, and for each of the three years in the period ended December 31, 2006 have been audited by Grant Thornton LLP, independent registered public accountants, as indicated in their report with respect thereto, and are incorporated by reference into this registration statement and prospectus in reliance upon the authority of said firm as experts in accounting and auditing in giving such report.

FUTURE EQUITYHOLDER PROPOSALS

Atlas America

Atlas America held its 2009 annual meeting on July 13, 2009. Atlas America intends to hold an annual meeting in 2010. Rule 14a-8 under the Exchange Act establishes the eligibility requirements and the procedures that must be followed for a stockholder’s proposal or director nomination to be included in a public company’s proxy materials. Under the rule, proposals or director nominations submitted for inclusion in Atlas America’s 2010 proxy materials must be received at Westpointe Corporate Center One, 1550 Coraopolis Heights Road, 2nd Floor, Moon Township, Pennsylvania 15108, Attention: Secretary, on or before February 16, 2010. Proposals must comply with all the requirements of Rule 14a-8 under the Exchange Act.

A stockholder who wishes to present a matter for action at Atlas America’s 2010 annual meeting, but does not want to include it in Atlas America’s proxy materials, must deliver to Atlas America’s Secretary on or before March 18, 2010, which date is 90 days before the first anniversary of the mailing date of Atlas America’s 2009 proxy statement, a notice containing the information required by the advance notice and other provisions of Atlas America’s bylaws. A stockholder who wishes to present one or more directors for nomination at Atlas America’s 2010 annual meeting, but does not want to include it in Atlas America’s proxy materials, must deliver a notice containing the information required by the advance notice and other provisions of Atlas America’s bylaws, including the name of the person(s) to be nominated, to Atlas America’s Secretary on or before March 18, 2010. A copy of Atlas America’s bylaws may be obtained by directing a written request to Atlas America at Westpointe Corporate Center One, 1550 Coraopolis Heights Road, 2nd Floor, Moon Township, Pennsylvania 15108, Attention: Secretary.

257

Atlas Energy

Atlas Energy held its 2009 annual meeting on June 4, 2009. Atlas Energy will hold an annual meeting in 2010 only if the merger has not already been completed. Rule 14a-8 under the Exchange Act establishes the eligibility requirements and the procedures that must be followed for a stockholder’s proposal or director nomination to be included in a public company’s proxy materials. Under the rule, proposals or director nominations submitted for inclusion in Atlas Energy’s 2010 proxy materials must be received at Westpointe Corporate Center One, 1550 Coraopolis Heights Road, 2nd Floor, Moon Township, Pennsylvania 15108, Attention: Secretary, on or before January 5, 2010. Proposals must comply with all the requirements of Rule 14a-8 under the Exchange Act.

A unitholder who wishes to present a matter for action at Atlas Energy’s 2010 annual meeting, but does not choose to include it in Atlas Energy’s proxy materials, must deliver to Atlas Energy’s Secretary on or before February 4, 2010, which date is 90 days before the first anniversary of the mailing date of Atlas Energy’s 2009 proxy statement, a notice containing the information required by the advance notice and other provisions of Atlas Energy’s operating agreement. A unitholder who wishes to present one or more directors for nomination at Atlas Energy’s 2010 annual meeting, but does not choose to offer the nominees for inclusion in Atlas Energy’s proxy materials, must deliver a notice containing the information required by the advance notice and other provisions of Atlas Energy’s operating agreement, including the name of the person(s) to be nominated, to Atlas Energy’s Secretary on or before February 4, 2010. A copy of the Atlas Energy operating agreement may be obtained by directing a written request to Atlas Energy at Westpointe Corporate Center One, 1550 Coraopolis Heights Road, 2nd Floor, Moon Township, Pennsylvania 15108, Attention: Secretary.

OTHER MATTERS

As of the date of this joint proxy statement/prospectus, neither the Atlas America board of directors nor the Atlas Energy board of directors knows of any matters that will be presented for consideration at either the Atlas America special meeting or the Atlas Energy special meeting other than as described in this joint proxy statement/prospectus.

In accordance with Atlas America’s bylaws and Delaware law, business transacted at the Atlas America special meeting will be limited to those matters set forth in the notice of special meeting. Nonetheless, if any other matter is properly presented at the Atlas America special meeting, or any adjournments or postponements of the meeting, and are voted upon, including matters incident to the conduct of the meeting, the enclosed proxy will confer discretionary authority on the individuals named as proxy to vote the shares represented by proxy as to any other matters. It is intended that the persons named in the enclosed proxy and acting thereunder will vote in accordance with their best judgment on such matter.

In accordance with the Atlas Energy operating agreement and Delaware law, business transacted at the Atlas Energy special meeting will be limited to those matters set forth in the notice of special meeting. Nonetheless, if any other matter is properly presented at the Atlas Energy special meeting, or any adjournments or postponements of the meeting, and are voted upon, including matters incident to the conduct of the meeting, the enclosed proxy will confer discretionary authority on the individuals named as proxy to vote the shares represented by proxy as to any other matters. It is intended that the persons named in the enclosed proxy and acting thereunder will vote in accordance with their best judgment on such matter.

258

WHERE YOU CAN FIND MORE INFORMATION

Atlas America and Atlas Energy file annual, quarterly and special reports, proxy statements and other information with the SEC under the Exchange Act. You may read and copy any of this information at the SEC’s Public Reference Room, 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the Public Reference Room. The SEC also maintains an Internet website that has reports, proxy statements and other information about issuers, including Atlas America and Atlas Energy, that make electronic filings with the SEC. The address of that site iswww.sec.gov.

Atlas America has filed a registration statement on Form S-4 to register with the SEC the Atlas America common stock to be issued to Atlas Energy unitholders in the merger. This joint proxy statement/prospectus is a part of that registration statement and constitutes a prospectus of Atlas America in addition to being a proxy statement of Atlas America and Atlas Energy for their respective special meetings. The registration statement, including the attached annexes, exhibits and schedules, contains additional information about Atlas America, Atlas America common stock and Atlas Energy. As permitted by the SEC rules, this joint proxy statement/prospectus does not contain all the information that you can find in the registration statement or the exhibits to that statement.

In addition, the SEC allows Atlas Energy to “incorporate by reference” information into this joint proxy statement/prospectus. This means that we can disclose important information to you by referring you to another document filed separately with the SEC. The information incorporated by reference is deemed to be part of this joint proxy statement/prospectus, except for any information superseded by information in this document. This joint proxy statement/prospectus incorporates by reference the documents set forth below that Atlas Energy has previously filed with the SEC. These documents contain important information about Atlas Energy and its financial performance.

Atlas Energy SEC Filings (File No. 1-33193)	Period
Annual Report on Form 10-K	For the year ended December 31, 2008
Proxy Statement on Schedule 14A	Filed April 30, 2009
Quarterly Reports on Form 10-Q	For the quarterly periods ended March 31, 2009 and June 30, 2009
Current Reports on Form 8-K	Filed February 9, 2009; February 26, 2009; March 27, 2009; April 17, 2009; April 27, 2009; April 28, 2009; May 6, 2009; May 7, 2009; June 5, 2009; July 13, 2009; July 17, 2009; July 24, 2009; and August 10, 2009 (other than the portions of those documents not deemed to be filed)
The description of Atlas Energy common units contained in Atlas Energy’s Registration Statement on Form S-1/A	Filed December 5, 2006
The DTE Gas & Oil Company financial statements	Current Report on Form 8-K/A filed September 12, 2007 (other than the portions of such document not deemed to be filed)

We are also incorporating by reference additional documents that Atlas Energy files with the SEC pursuant to Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act between the date of this joint proxy statement/prospectus and the date of the special meetings. Such documents are considered to be a part of this document, effective as of the date such documents are filed. In the event of conflicting information in these documents, the information in the latest filed document should be considered correct.

Atlas America and Atlas Energy also incorporate by reference the merger agreement attached to this joint proxy statement/prospectus as Annex A.

259

Atlas America has supplied all information contained in this joint proxy statement/prospectus relating to Atlas America, and Atlas Energy has supplied all information contained or incorporated by reference into this joint proxy statement/prospectus relating to Atlas Energy.

You can obtain any of the documents incorporated by reference into this joint proxy statement/prospectus from the SEC, through the SEC’s website atwww.sec.gov, or Atlas Energy by requesting them in writing or by telephone at the following address:

Atlas Energy Resources, LLC

Westpointe Corporate Center One

1550 Coraopolis Heights Road

Moon Township, PA 15108

Attn: Investor Relations

(412) 262-2830

If you would like to request documents from us, please do so by September 18, 2009 to receive them before the special meetings. We will send the documents by first-class mail, or another equally prompt means, within one business day of receiving your request.

Investors may also consult Atlas America’s or Atlas Energy’s websites for more information. Atlas America’s website iswww.atlasamerica.com. Atlas Energy’s website iswww.atlasenergyresources.com. Information included on these websites is not incorporated by reference into this document.

We have not authorized anyone to provide you with information that is different from, or in addition to, what is contained in this joint proxy statement/prospectus or in any of the materials that we have incorporated by reference into this joint proxy statement/prospectus. Therefore, if anyone does give you information of this kind, you should not rely on it. If you are in a jurisdiction where offers to exchange or sell, or solicitations of offers to exchange or purchase, the securities offered by this joint proxy statement/prospectus or the solicitation of proxies is unlawful, or if you are a person to whom it is unlawful to direct these types of activities, then the offer presented in this joint proxy statement/prospectus does not extend to you. The information contained in this joint proxy statement/prospectus is accurate only as of the date of this joint proxy statement/prospectus, unless the information specifically indicates that another date applies.

260

INDEX TO FINANCIAL STATEMENTS

	Page
Atlas America, Inc. and Subsidiaries Financial Statements
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2008 and 2007	F-3
Consolidated Statements of Operations for the years ending December 31, 2008, 2007 and 2006	F-4
Consolidated Statements of Comprehensive Income for the years ending December 31, 2008, 2007 and 2006	F-5
Consolidated Statements of Stockholders’ Equity for the years ending December 31, 2008, 2007 and 2006	F-6
Consolidated Statements of Cash Flows for the years ending December 31, 2008, 2007 and 2006	F-7
Notes to Consolidated Financial Statements	F-8
Atlas America, Inc. and Subsidiaries Unaudited Interim Financial Statements
Consolidated Balance Sheets (unaudited) as of June 30, 2009 and December 31, 2008	F-66
Consolidated Statements of Operations (unaudited) for the six months ended June 30, 2009 and 2008	F-67
Consolidated Statements of Stockholders’ Equity (unaudited) for the six months ended June 30, 2009	F-69
Consolidated Statements of Cash Flows (unaudited) for the six months June 30, 2009 and 2008	F-70
Notes to Consolidated Financial Statements	F-71

F-1

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 (not separately included herein), expressed an unqualified opinion on the effectiveness of internal control over financial reporting.

As discussed in Note 2 to the consolidated financial statements, the Company changed its method for accounting for non-controlling interests due to the adoption of Statement of Financial Accounting Standard No 160 “Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51” on January 1, 2009.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

March 2, 2009 (except with respect to the effects of the discontinued operations as discussed in Note 4 and changes in accounting for non-controlling interests as discussed in Note 2, as to which the date is August 17, 2009)

F-2

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	$	104,496		$	145,896
Accounts receivable		169,405			198,045
Current portion of derivative receivable from partnerships		3,022			213
Current portion of derivative asset		152,726			37,968
Prepaid expenses and other		25,464			22,691
Prepaid and deferred income taxes		32,215			20,642
Current assets related to discontinued operations		13,441			9,335
Total current assets		500,769			434,790
Property, plant and equipment, net		3,744,815			3,210,785
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		53,311			40,791
Long-term assets related to discontinued operations		242,165			243,549
	$	4,845,881		$	4,919,052
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	—		$	64
Accounts payable		140,725			73,385
Liabilities associated with drilling contracts		96,883			118,017
Accrued producer liabilities		66,846			79,791
Current portion of derivative liability to partnerships		34,933			9,014
Current portion of derivative liability		73,776			111,223
Accrued liabilities		103,383			114,646
Advances from affiliate		108			58
Current liabilities related to discontinued operations		10,572			8,038
Total current liabilities		527,226			514,236
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
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
		411,515			413,163
Non-controlling interests		1,118,053			1,595,781
Total stockholders’ equity		1,529,568			2,008,944
	$	4,845,881		$	4,919,052

See accompanying notes to consolidated financial statements

F-3

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		1,384,212			767,085			367,551
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		2,087,462			1,151,086			681,598
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		1,153,555			617,629			315,081
Well services		10,654			9,062			7,337
General and administrative		56,836			110,250			43,075
Net expense reimbursement — affiliate		951			930			1,237
Depreciation, depletion and amortization		178,269			100,838			39,408
Goodwill impairment		676,860			—			—
Total costs and expenses		2,484,928			1,142,433			587,303
Operating income (loss)		(397,466	)		8,653			94,295
Other income (expense):
Interest expense		(144,065	)		(93,677	)		(26,439	)
Gain on early extinguishment of debt		19,867			—			—
Other, net		11,383			10,696			8,176
Total other income (expense)		(112,815	)		(82,981	)		(18,263	)
Income (loss) continuing operations before income taxes		(510,281	)		(74,328	)		76,032
Provision (benefit) for income taxes		(5,021	)		13,283			26,713
Income (loss) from continuing operations		(505,260	)		(87,611	)		49,319
Discontinued operations (net of income taxes of $875, $1,359 and $595)		19,671			29,471			10,986
Income (loss) before cumulative effect of accounting change		(485,589	)		(58,140	)		60,305
Cumulative effect of accounting change (net of tax of $2,530)		—			—			3,825
Net income (loss)		(485,589	)		(58,140	)		64,130
(Income) loss attributable to non-controlling interests		479,431			93,476			(18,283	)
Net income (loss) attributable to common stockholders	$	(6,158	)	$	35,336		$	45,847
Net income (loss) attributable to common stockholders per share — basic:
Income (loss) from continuing operations attributable to common stockholders	$	(0.19	)	$	0.82		$	0.92
Income from cumulative effect of accounting change attributable to common stockholders		—			—			0.09
Discontinued operations attributable to common stockholders		0.04			0.05			0.02
Net income (loss) attributable to common stockholders	$	(0.15	)	$	0.87		$	1.03
Net income (loss) attributable to common stockholders per share — diluted:
Income (loss) from continuing operations attributable to common stockholders	$	(0.19	)	$	0.78		$	0.91
Income from cumulative effect of accounting change attributable to common stockholders		—			—			0.08
Discontinued operations attributable to common stockholders		0.04			0.05			0.02
Net income (loss) attributable to common stockholders	$	(0.15	)	$	0.83		$	1.01
Weighted average common shares outstanding:
Basic		39,999			40,841			44,363
Diluted		39,999			42,418			45,353
Income (loss) attributable to common stockholders:
Income (loss) from continuing operations (net of income taxes (benefit) of ($5,021), $13,283 and $26,713)	$	(7,524	)	$	33,216		$	44,919
Discontinued operations (net of income taxes of $875, $1,359 and $595)		1,366			2,120			928
Net income (loss) attributable to common stockholders	$	(6,158	)	$	35,336		$	45,847

See accompanying notes to consolidated financial statements

F-4

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

	Years Ended December 31,
	2008			2007			2006
Net income (loss)	$	(485,589	)	$	(58,140	)	$	64,130
(Income) loss attributable to non-controlling interests		479,431			93,476			(18,283	)
Net income (loss) attributable to common shareholders		(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		(24,721	)		(90,511	)		17,247
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		69,553			33,271			6,786
Changes in non-controlling interest related to items in other comprehensive income (loss)		(17,999	)		42,931			(10,075	)
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

F-5

ATLAS AMERICA, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(in thousands, except share data)

				Additional Paid-In Capital								ESOP Loan Receivable			Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Non- Controlling Interests			Total Stockholders’ Equity
	Common Stock						Treasury Stock
	Shares	Amount					Shares		Amount
Balance, January 1, 2006	13,336,031	$	133	$	75,967		(1,335	)	$	(73	)	$	(564	)	$	(5,116	)	$	60,078		$	323,297		$	453,722
Issuance of common stock	7,790		—		100		9,542			580			—			—			—			—			680
Other comprehensive income	—		—		—		—			—			—			13,542			—			10,075			23,617
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
Distributions to non-controlling interests	—		—		—		—			—			—			—			—			(38,276	)		(38,276	)
Non-controlling interests’ capital contributions	—		—		—		—			—			—			—			—			93,008			93,008
Net income	—		—		—		—			—			—			—			45,847			18,283			64,130
Balance, December 31, 2006	20,008,419		200		186,696		(659,135	)		(29,349	)		(490	)		8,426			105,858			406,387			677,728
Issuance of common stock	56,736		—		1,181		19,685			912			—			—			—			—			2,093
Other comprehensive income	—		—		—		—			—			—			(14,361	)		—			(42,931	)		(57,292	)
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
Distributions to non-controlling interests	—		—		—		—			—			—			—			—			(104,344	)		(104,344	)
Non-controlling interests’ capital contributions	—		—		—		—			—			—			—			—			1,430,145			1,430,145
Net income	—		—		—		—			—			—			—			35,336			(93,476	)		(58,140	)
Balance, December 31, 2007	29,003,212		290		390,591		(2,126,055	)		(108,886	)		(417	)		(5,935	)		137,520			1,595,781			2,008,944
Issuance of common units	52,386		1		721		28,879			1,296			—			—			—			—			2,018
Other comprehensive loss	—		—		—		—			—			—			27,078			—			17,999			45,077
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
Distributions to non-controlling interests	—		—		—		—			—			—			—			—			(241,016	)		(241,016	)
Non-controlling interests’ capital contributions	—		—		—		—			—			—			—			—			224,720			224,720
Net income (loss)	—		—		—		—			—			—			—			(6,158	)		(479,431	)		(485,589	)
Balance at December 31, 2008	42,503,119	$	426	$	412,869		(3,252,759	)	$	(147,621	)	$	—		$	21,143		$	124,698		$	1,118,053		$	1,529,568

See accompanying notes to consolidated financial statements

F-6

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 (loss) income	$	(485,589	)	$	(58,140	)	$	64,130
Income from discontinued operations		19,671			29,471			10,986
(Loss) income from continuing operations, net of cumulative effect of accounting change		(505,260	)		(87,611	)		53,144
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		178,269			100,838			39,408
Goodwill impairment loss		676,860			—			—
Amortization of deferred finance costs		8,893			10,529			3,818
Non-cash (gain) loss 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	)
(Gain) loss on asset sales and dispositions		(32	)		916			(5,679	)
Gain on early extinguishment of long-term debt		(19,867	)		—			—
Distributions paid to non-controlling interests		(241,016	)		(104,344	)		(38,276	)
Deferred income taxes		(2,738	)		(1,486	)		(39,362	)
Changes in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable and prepaid expenses and other		35,972			(104,228	)		(16,632	)
Accounts payable and accrued liabilities		(9,874	)		138,948			24,627
Accounts payable and accounts receivable — affiliate		50			(59	)		2,551
Other operating assets/liabilities		2,517			849			—
Net cash provided by (used in) continuing operations operating activities		(92,985	)		156,171			27,419
Net cash provided by discontinued operations operating activities		45,569			38,914			34,767
Net cash provided by (used in) operating activities		(47,416	)		195,085			62,186
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(648,379	)		(322,002	)		(158,529	)
Net cash paid for acquisitions		—			(3,156,976	)		—
Acquisition purchase price adjustment		31,429			—			—
Investment in Lightfoot Capital Partners, L.P.		(1,009	)		(10,447	)		—
Proceeds from asset sales		62			1,645			9,109
Other		(785	)		(1,498	)		236
Net cash used in continuing operations investing activities		(618,682	)		(3,489,278	)		(149,184	)
Net cash used in discontinued operations investing activities		(25,211	)		(18,879	)		(34,973	)
Net cash used in investing activities		(643,893	)		(3,508,157	)		(184,157	)
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	)		—			39,000
Net proceeds from Atlas Energy Resources, LLC equity offering		82,497			597,495			139,944
Net proceeds from Atlas Pipeline Holdings, L.P. equity offerings		—			166,984			74,326
Net proceeds from Atlas Pipeline Partners, L.P. common and preferred unit offerings		196,860			946,399			59,585
Dividends paid		(6,664	)		(3,584	)		—
Purchases of treasury stock		(40,027	)		(80,449	)		(29,856	)
Deferred financing costs and other		(16,768	)		(10,581	)		(1,866	)
Net cash provided by continuing operations financing activities		649,909			3,273,881			307,108
Net cash used in discontinued operations financing activities		—			—			(39,000	)
Net cash provided by financing activities		649,909			3,273,881			268,108
Net change in cash and cash equivalents		(41,400	)		(39,191	)		146,137
Cash and cash equivalents, beginning of period		145,896			185,087			38,950
Cash and cash equivalents, end of period	$	104,496		$	145,896		$	185,087

See accompanying notes to consolidated financial statements

F-7

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 15). On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system (see Note 4). As such, the Company has adjusted its prior period consolidated financial statements and related footnote disclosures presented within this Form 10-K to reflect the amounts related to the operations of the NOARK gas gathering and interstate pipeline system as discontinued operations. 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.

F-8

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Non-controlling 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 ownership interests in the net income (loss) of ATN, AHD and APL are reflected within non-controlling interests on the Company’s consolidated statements of operations, and the non-controlling interests in the assets and liabilities of ATN, AHD and APL are reflected as a component of stockholders’ equity on the Company’s consolidated balance sheets. All material intercompany transactions have been eliminated.

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 (“the Partnerships”). 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.

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 non-controlling interests on its statements of operations. The Company also reflects Anadarko’s investment in the net assets of the joint ventures as non-controlling 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 non-controlling 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.

F-9

Reclassifications

Certain amounts in the prior year’s consolidated financial statements have been reclassified to conform to the current year presentation, including $12.1 million as of December 31, 2007, related to ATN pre-development costs shown as a component of “Property, plant and equipment, net” which was previously combined with “Liabilities associated with drilling contracts” on the Company’s consolidated balance sheets.

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.

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.

F-10

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 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.

F-11

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 $12.7 million, $4.9 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 8, “Debt” and Note 10, “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.

F-12

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
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 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	$	98,725

F-13

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 5). 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.

F-14

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 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 17). 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.

F-15

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.

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:

• 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 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

F-16

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 $87.4 million and $122.1 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.

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.

F-17

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 10 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 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.

F-18

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, “Non-controlling 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 non-controlling interest (minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling 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 non-controlling 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 consolidated financial statements reflect the retrospective application, for all periods presented, for SFAS No. 160, which was adopted by the Company effective January 1, 2009.

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 non-controlling 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 non-controlling 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

F-19

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.

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 8). 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 8). 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 16).

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

F-20

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.

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. On May 4, 2009, APL completed the sale of its NOARK operations (see Note 4).

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 8) and received net proceeds of $597.5 million from the private placement of its Class B common. The acquisition was accounted for using the

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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.

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	$	2,087,462		$	1,488,206	$	1,590,517
Income (loss) from continuing operations attributable to common stockholders	$	(7,524	)	$	13,165	$	90,503
Income from discontinued operations attributable to common stockholders		1,366			2,120		928
Net income (loss) attributable to common stockholders	$	(6,158	)	$	15,285	$	91,431
Net income (loss) per share — Basic:
Income (loss) from continuing operations attributable to common stockholders	$	(0.19	)	$	0.33	$	2.04
Income from discontinued operations attributable to common stockholders		0.04			0.05		0.02
Net income (loss) attributable to common stockholders	$	(0.15	)	$	0.38	$	2.06
Net income (loss) per share — Diluted:
Income (loss) from continuing operations attributable to common stockholders	$	(0.19	)	$	0.31	$	2.00
Income from discontinued operations attributable to common stockholders		0.04			0.05		0.02
Net income (loss) attributable to common stockholders	$	(0.15	)	$	0.36	$	2.02

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NOTE 4 — DISCONTINUED OPERATIONS

On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system to Spectra Energy Partners OLP, LP (NYSE:SEP) (“Spectra”) for net proceeds of $292.0 million in cash, net of working capital adjustments. APL received an additional $2.5 million in cash in July 2009 upon the delivery of audited financial statements for the NOARK system assets to Spectra. APL used the net proceeds from the transaction to reduce borrowings under its senior secured term loan and revolving credit facility. APL recognized a gain of $48.8 million (net of income taxes of $2.2 million) upon completion of the transaction, which was recorded within the Company’s consolidated financial statements in the second quarter of 2009. In accordance with FASB Statement No. 144 “Accounting for the Impairment or Disposal of Long-lived Assets” (“SFAS No. 144”), the Company has retrospectively adjusted its consolidated financial statements to reflect the amounts related to the NOARK system assets as discontinued operations. The following table summarizes the components included within income from discontinued operations on the Company’s consolidated statements of operations (amounts in thousands):

	Year ended December 31,
	2008			2007			2006
Total revenue and other loss, net	$	62,423		$	56,587		$	68,096
Total costs and expenses		(41,877	)		(25,757	)		(56,515	)
Income before income tax provision		20,546			30,830			11,581
Income tax provision		(875	)		(1,359	)		(595	)
Income from discontinued operations	$	19,671		$	29,471		$	10,986

The following table summarizes the components included within total assets and liabilities of discontinued operations within the Company’s consolidated balance sheet for the period indicated (amounts in thousands):

	December 31,
	2008		2007
Cash and cash equivalents	$	75	$	(361	)
Accounts receivable		12,365		9,448
Prepaid expenses and other		1,001		248
Total current assets of discontinued operations		13,441		9,335
Property, plant and equipment, net		241,926		243,342
Other assets, net		239		207
Total assets of discontinued operations	$	255,606	$	252,884
Accounts payable	$	4,120	$	2,008
Accrued liabilities		5,892		4,993
Accrued producer liabilities		560		1,037
Total current liabilities of discontinued operations	$	10,572	$	8,038

The Company’s financial reporting basis of net assets included in the consolidated balance sheet attributable to discontinued operations reported above exceeded the tax basis of net assets attributable to discontinued operations by $45.8 million and $31.5 million for year ended December 31, 2008 and 2007, respectively. The Company has estimated its portion of deferred tax liability associated with these differences to be approximately $1.4 million and $1.1 million for year ended December 31, 2008 and 2007, respectively.

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NOTE 5 — PROPERTY, PLANT AND EQUIPMENT

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

	December 31,						Estimated Useful Lives in Years
	2008(1)			2007(1)
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	1,214,991		$	1,043,687
Predevelopment costs		18,772			12,091
Wells and related equipment		872,128			752,184
Total proved properties		2,105,891			1,807,962
Unproved properties		43,749			16,381
Support equipment		9,527			6,716
Total natural gas and oil properties		2,159,167			1,831,059
Pipelines, processing and compression facilities		1,728,472			1,389,555		15 – 40
Rights of way		168,206			158,662		20 – 40
Land, buildings and improvements		24,385			21,487		10 – 40
Other		22,108			19,612		3 – 10
		4,102,338			3,420,375
Less — accumulated depreciation, depletion and amortization		(357,523	)		(209,590	)
	$	3,744,815		$	3,210,785

(1) Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system (see Note 4)

NOTE 6 — 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.

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.

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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 7 — OTHER ASSETS

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

	December 31,
	2008(1)		2007(1)
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		1,617		2,578
Other		156		34
	$	53,311	$	40,791

(1) Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system (see Note 4)

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreements (see Note 8). 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

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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.

NOTE 8 — 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.

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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 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

F-27

(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.

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 9) 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

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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 is unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement.

APL Senior Notes

At December 31, 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.

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.

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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 9 — 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.

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

F-30

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.

F-31

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

F-32

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.

F-33

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	)		—		—

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 8), 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 8), 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

F-34

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.

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.

F-35

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)
	(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

F-36

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	)

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

F-37

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) 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.

F-38

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 10 — 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.

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.

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 9) and the Company’s Supplemental Employment Retirement Plan (“SERP” — see Note 17). 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

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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 11 — 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.

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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.

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 12 — 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.

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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 $90.3 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 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 13 — INCOME TAXES

The following table details the components of the Company’s provision (benefit) for income taxes from continuing operations on net income (loss) attributable to common stockholders for the periods indicated (in thousands):

	Years Ended December 31,
	2008			2007			2006
Provision (benefit) for income taxes:
Current:
Federal	$	(1,929	)	$	14,312		$	54,359
State		(331	)		585			11,388
Deferred		(2,761	)		(1,614	)		(39,034	)
	$	(5,021	)	$	13,283		$	26,713

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A reconciliation between the statutory federal income tax rate and the Company’s effective income tax rate from continuing operations on net income (loss) attributable to common stockholders 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	)

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 it 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.

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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 14 — 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.

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.

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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 15 — ISSUANCE OF SUBSIDIARY UNITS

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

In 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 9).

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 non-controlling 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).

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

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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 non-controlling 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 non-controlling 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 non-controlling 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 non-controlling 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 non-controlling 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

NOTE 16 — 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

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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 19).

(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 19).

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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 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 19).

NOTE 17 — 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),

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“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 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.

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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.

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

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$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.

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

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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 non-controlling interests on the Company’s consolidated balance sheet.

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

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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.

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.

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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 non-controlling 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.

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

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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.

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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

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

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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.

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NOTE 18 — 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(d)			2007(d)			2006(d)
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)	$	1,300,062		$	573,189		$	360,616
Revenues — affiliates		43,726			33,571			26,272
Costs and expenses		(1,829,882	)		(617,317	)		(314,810	)
Segment income (loss)	$	(486,094	)	$	(10,557	)	$	72,078
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 income (loss) from continuing operations
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		(486,094	)		(10,557	)		72,078
Other		5,601			7,099			86
Total segment income (loss)		(161,410	)		220,671			178,015
General and administrative expenses		(56,836	)		(110,250	)		(43,075	)
Net expense reimbursement — affiliate		(951	)		(930	)		(1,237	)
Depreciation, depletion and amortization		(178,269	)		(100,838	)		(39,408	)
Interest expense		(144,065	)		(93,677	)		(26,439	)
Gain on early extinguishment of debt		19,867			—			—
Other income — net		11,383			10,696			8,176
Income (loss) from continuing operations	$	(510,281	)	$	(74,328	)	$	76,032
Capital expenditures
Gas and oil production	$	343,506		$	191,917		$	78,171
Well construction and completion		—			—			—
Atlas Pipeline		300,723			120,833			78,798
Corporate and other		4,150			9,252			1,560
Total capital expenditures	$	648,379		$	322,002		$	158,529

F-58

	December 31,
	2008(d)		2007(d)
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	$	2,210,563	$	1,836,315
Well construction and completion		16,399		11,138
Atlas Pipeline		2,157,590		2,622,567
Discontinued operations		255,606		252,884
Corporate and other		205,723		196,148
	$	4,845,881	$	4,919,052

(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.

(d) Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system (see Note 4).

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. Amounts related to discontinued operations from sale of NOARK’s assets have been removed from all periods shown (see Note 4).

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 19 — 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.

F-59

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.

NOTE 20 — 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.

F-60

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 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

F-61

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	)
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.

F-62

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.

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

F-63

NOTE 21 — QUARTERLY RESULTS (Unaudited)

	Fourth Quarter(1)			Third Quarter			Second Quarter(1)			First Quarter
	(in thousands, except per unit data)
Year ended December 31, 2008:
Revenues	$	515,831		$	767,184		$	334,093		$	470,354
Income (loss) from continuing operations (net of income tax (benefit) of ($17,309), $13,647, ($4,952), and $3,593)	$	(447,056	)	$	211,896		$	(246,859	)	$	(23,241	)
Income (loss) from discontinued operations (net of income taxes of $27, $277, $323 and $248)		(510	)		6,261			7,922			5,998
Net income (loss)		(447,566	)		218,157			(238,937	)		(17,243	)
Income (loss) attributable to non-controlling interests		418,654			(194,054	)		231,166			23,665
Net income (loss) attributable to common shareholders	$	(28,912	)	$	24,103		$	(7,771	)	$	6,422
Net income (loss) attributable to common shareholders per share — basic:
Income (loss) from continuing operations attributable to common shareholders	$	(0.74	)	$	0.59		$	(0.21	)	$	0.15
Discontinued operations attributable to common shareholders		0.00			0.01			0.02			0.01
Net income (loss) attributable to common shareholders	$	(0.74	)	$	0.60		$	(0.19	)	$	0.16
Net income (loss) attributable to common shareholders per share — diluted:
Income (loss) from continuing operations attributable to common shareholders	$	(0.74	)	$	0.56		$	(0.21	)	$	0.14
Discontinued operations attributable to common shareholders		0.00			0.01			0.02			0.01
Net income (loss) attributable to common shareholders	$	(0.74	)	$	0.57		$	(0.19	)	$	0.15

(1) For the second and fourth quarter of the year ended December 31, 2008, approximately 1,910 and 1,332, respectively, stock awards were excluded from the computation of diluted net income per common share because the inclusion of such units would have been anti-dilutive.

F-64

	Fourth Quarter(2)			Third Quarter(2)			Second Quarter		First Quarter
	(in thousands, except per unit data)
Year ended December 31, 2007:
Revenues	$	351,651		$	369,654		$	214,866	$	214,915
Income (loss) from continuing operations (net of income tax (benefit) of ($2,991), $2,773, $7,802, and $5,699)	$	(89,133	)	$	(20,654	)	$	8,422	$	13,754
Income (loss) from discontinued operations (net of income taxes of $383, $323, $332 and $320)		8,768			7,268			6,845		6,590
Net income (loss)		(80,365	)		(13,386	)		15,267		20,344
Income (loss) attributable to non-controlling interests		78,484			6,402			11,776		(3,186	)
Net income (loss) attributable to common shareholders	$	(1,881	)	$	(6,984	)	$	27,043	$	17,158
Net income (loss) attributable to common shareholders per share — basic:
Income (loss) from continuing operations attributable to common shareholders	$	(0.06	)	$	(0.18	)	$	0.66	$	0.39
Discontinued operations attributable to common shareholders		0.01			0.01			0.01		0.01
Net income (loss) attributable to common shareholders	$	(0.05	)	$	(0.17	)	$	0.67	$	0.40
Net income (loss) attributable to common shareholders per share — diluted:
Income (loss) from continuing operations attributable to common shareholders	$	(0.06	)	$	(0.18	)	$	0.64	$	0.38
Discontinued operations attributable to common shareholders		0.01			0.01			0.01		0.01
Net income (loss) attributable to common shareholders	$	(0.05	)	$	(0.17	)	$	0.65	$	0.39

(2) For the third and fourth quarter of the year ended December 31, 2007, approximately 1,689 and 1,798, respectively, stock awards were excluded from the computation of diluted net income per common share because the inclusion of such units would have been anti-dilutive.

F-65

ATLAS AMERICA, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except share and per share data)

(Unaudited)

	June 30, 2009			December 31, 2008
ASSETS
Current assets:
Cash and cash equivalents	$	81,331		$	104,496
Accounts receivable		147,447			169,405
Current portion of derivative receivable from Partnerships		105			3,022
Current portion of derivative asset		118,792			152,727
Prepaid expenses and other		26,282			25,463
Prepaid and deferred income taxes		15,280			32,215
Current assets related to discontinued operations		—			13,441
Total current assets		389,237			500,769
Property, plant and equipment, net		3,714,402			3,744,815
Intangible assets, net		184,113			197,485
Goodwill, net		35,166			35,166
Long-term derivative receivable from Partnerships		5,028			2,719
Long term derivative asset		56,071			69,451
Investment in joint venture		133,803			—
Other assets, net		63,546			53,311
Long-term assets related to discontinued operations		—			242,165
	$	4,581,366		$	4,845,881
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	16,000		$	—
Accounts payable		98,291			140,725
Liabilities associated with drilling contracts		88,909			96,883
Accrued producer liabilities		47,067			66,846
Current portion of derivative liability to Partnerships		32,839			34,933
Current portion of derivative liability		62,189			73,776
Accrued liabilities		106,119			103,383
Advances from affiliate		202			108
Current liabilities related to discontinued operations		—			10,572
Total current liabilities		451,616			527,226
Long-term debt, less current portion		2,138,589			2,413,082
Deferred tax liability		237,003			242,058
Long-term derivative liability to Partnerships		19,965			22,581
Long-term derivative liability		43,081			59,103
Other long-term liabilities		54,093			52,263
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			426
Additional paid-in capital		412,370			412,869
Treasury stock, at cost		(144,110	)		(147,621	)
Accumulated other comprehensive income		29,487			21,143
Retained earnings		136,741			124,698
		434,914			411,515
Non-controlling interests		1,202,105			1,118,053
Total stockholders’ equity		1,637,019			1,529,568
	$	4,581,366		$	4,845,881

See accompanying notes to consolidated financial statements

F-66

ATLAS AMERICA, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Revenue:
Well construction and completion	$	63,367		$	122,341		$	175,735		$	226,479
Gas and oil production		69,979			78,956			141,922			155,182
Transmission, gathering and processing		186,070			438,461			349,737			807,417
Administration and oversight		2,642			5,137			6,495			10,154
Well services		4,839			5,266			9,932			10,064
Gain on asset sales		105,691			—			105,691			—
Equity income in joint venture		710			—			710			—
Loss on mark-to-market derivatives		(18,593	)		(316,068	)		(18,277	)		(404,849	)
Total revenue		414,705			334,093			771,945			804,447
Costs and expenses:
Well construction and completion		53,701			106,384			149,098			196,939
Gas and oil production		9,803			12,379			21,089			23,047
Transmission, gathering and processing		150,363			367,320			302,890			658,516
Well services		2,120			2,650			4,544			5,062
General and administrative		21,577			24,884			48,991			45,511
Net expense reimbursement — affiliate		80			184			562			434
Depreciation, depletion and amortization		50,272			43,359			100,967			85,214
Total costs and expenses		287,916			557,160			628,141			1,014,723
Operating income (loss)		126,789			(223,067	)		143,804			(210,276	)
Other income (expense):
Interest expense		(41,948	)		(34,739	)		(76,568	)		(69,207	)
Other, net		1,254			5,995			6,135			8,024
Total other income (expense)		(40,694	)		(28,744	)		(70,433	)		(61,183	)
Income (loss) from continuing operations before income taxes (benefit)		86,095			(251,811	)		73,371			(271,459	)
Provision (benefit) for income taxes		3,630			(5,030	)		6,263			(1,431	)
Net income (loss) from continuing operations		82,465			(246,781	)		67,108			(270,028	)
Discontinued operations:
Gain on sale of discontinued operations (net of income taxes of $2,234 and $2,234 for the three and six months ended June 30, 2009, respectively)		48,844			—			48,844			—
Income from discontinued operations (net of income taxes of $140 and $401 for the three months ended June 30, 2009 and 2008, respectively, and $499 and $643 for the six months ended June 30, 2009 and 2008, respectively)		2,401			7,844			10,917			13,848
Net income (loss)		133,710			(238,937	)		126,869			(256,180	)
(Income) loss attributable to non-controlling interests		(124,342	)		231,166			(112,858	)		254,831
Net income (loss) attributable to common shareholders	$	9,368		$	(7,771	)	$	14,011		$	(1,349	)

F-67

ATLAS AMERICA, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS — (Continued)

(in thousands, except per share data)

(Unaudited)

	Three Months Ended June 30,					Six Months Ended June 30,
	2009		2008			2009		2008
Net income (loss) attributable to common shareholders per share — basic:
Income (loss) from continuing operations attributable to common shareholders	$	0.15	$	(0.21	)	$	0.25	$	(0.06	)
Discontinued operations attributable to common shareholders		0.09		0.02			0.11		0.03
Net income (loss) attributable to common shareholders	$	0.24	$	(0.19	)	$	0.36	$	(0.03	)
Net income (loss) attributable to common shareholders per share — diluted:
Income (loss) from continuing operations attributable to common shareholders	$	0.15	$	(0.21	)	$	0.24	$	(0.06	)
Discontinued operations attributable to common shareholders		0.09		0.02			0.11		0.03
Net income (loss) attributable to common shareholders	$	0.24	$	(0.19	)	$	0.35	$	(0.03	)
Weighted average common shares outstanding:
Basic		39,432		40,335			39,297		40,330
Diluted		39,803		40,335			39,717		40,330
Income (loss) attributable to common shareholders:
Income (loss) from continuing operations (net of income taxes (benefit) of $3,630 and ($5,030) for the three months ended June 30, 2009 and 2008, respectively, and $6,263 and ($1,431) for the six months ended June 30, 2009 and 2008, respectively)	$	5,664	$	(8,397	)	$	9,746	$	(2,353	)
Discontinued operations (net of income taxes of $2,374 and $401 for the three months ended June 30, 2009 and 2008, respectively, and $2,734 and $643 for the six months ended June 30, 2009 and 2008, respectively)		3,704		626			4,265		1,004
Net income (loss) attributable to common shareholders	$	9,368	$	(7,771	)	$	14,011	$	(1,349	)

See accompanying notes to consolidated financial statements

F-68

ATLAS AMERICA, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

FOR THE SIX MONTHS ENDED JUNE 30, 2009

(in thousands, except share data)

(Unaudited)

	Common Stock			Additional Paid-In Capital			Treasury Stock					Accumulated Other Comprehensive Income		Retained Earnings			Non- controlling Interests			Total Stockholders’ Equity
	Shares	Amount					Shares		Amount
Balance at January 1, 2009	42,503,119	$	426	$	412,869		(3,252,861	)	$	(147,621	)	$	21,143	$	124,698		$	1,118,053		$	1,529,568
Common stock issuance	16,588		—		(2,444	)	71,579			3,511			—		—			—			1,067
Other comprehensive income	—		—		—		—			—			8,344		—			35,422			43,766
Stock option compensation expense	—		—		1,945		—			—			—		—			—			1,945
Dividends paid	—		—		—		—			—			—		(1,968	)		—			(1,968	)
Distributions to non-controlling interests	—		—		—		—			—			—		—			(42,505	)		(42,505	)
Non-controlling interests’ capital contributions	—		—		—		—			—			—		—			(21,723	)		(21,723	)
Net income	—		—		—		—			—			—		14,011			112,858			126,869
Balance at June 30, 2009	42,519,707	$	426	$	412,370		(3,181,282	)	$	(144,110	)	$	29,487	$	136,741		$	1,202,105		$	1,637,019

See accompanying notes to consolidated financial statements

F-69

ATLAS AMERICA, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Six Months Ended June 30,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	126,869		$	(256,180	)
Income from discontinued operations		59,761			13,848
Income (loss) from continuing operations		67,108			(270,028	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		100,967			85,214
Amortization of deferred finance costs		6,382			4,181
Non-cash loss on derivative value, net		64,634			209,795
Non-cash compensation expense		1,775			5,171
Gain on asset sales and dispositions		(104,780	)		(12	)
Distributions paid to non-controlling interests		(42,505	)		(111,490	)
Equity income in joint venture		(710	)		—
Distributions received from joint venture		164			—
Deferred income taxes		5,927			(304	)
Changes in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable and prepaid expenses and other		25,115			(49,703	)
Accounts payable and accrued liabilities		(21,291	)		120,732
Accounts payable and accounts receivable — affiliate		94			65
Other operating assets/liabilities		2,574			624
Net cash provided by (used in) continuing operations operating activities		105,454			(5,755	)
Net cash provided by discontinued operations operating activities		14,201			21,208
Net cash provided by operating activities		119,655			15,453
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(226,907	)		(277,724	)
Acquisition purchase price adjustment		—			31,429
Investment in Lightfoot Capital Partners, L.P.		(2	)		(440	)
Proceeds from asset sales		97,953			34
Other		(7,838	)		290
Net cash used in continuing operations investing activities		(136,794	)		(246,411	)
Net cash provided by (used in) discontinued operations investing activities		290,594			(15,143	)
Net cash provided by (used in) investing activities		153,800			(261,554	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under Atlas Energy Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P. credit facilities		495,000			309,000
Repayments under Atlas Energy Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P. credit facilities		(763,295	)		(768,000	)
Issuance of Atlas Energy Resources, LLC long-term debt		—			407,021
Issuance of Atlas Pipeline Partners, L.P. long-term debt		—			244,854
Repayments on Atlas Pipeline Partners, L.P. long-term debt		—			(122,837	)
Net proceeds from Atlas Energy Resources, LLC equity offering		—			82,533
Net proceeds from Atlas Pipeline Partners, L.P. equity offering		—			207,106
Dividends paid		(1,968	)		(2,682	)
APL Class A preferred unit redemption		(15,000	)		—
Deferred financing costs and other		(11,357	)		(15,315	)
Net cash provided by (used in) financing activities		(296,620	)		341,680
Net change in cash and cash equivalents		(23,165	)		95,579
Cash and cash equivalents, beginning of period		104,496			145,896
Cash and cash equivalents, end of period	$	81,331		$	241,475

See accompanying notes to consolidated financial statements

F-70

ATLAS AMERICA, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

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 June 30, 2009:

• Atlas Energy Resources, LLC (“Atlas Energy” or “ATN”), a publicly traded Delaware limited liability company (NYSE: ATN) which 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. At June 30, 2009, the Company had a 48.3% ownership interest and owned all of the management incentive interests of ATN;

• Atlas Pipeline Partners, L.P. (“Atlas Pipeline Partners” or “APL”), a publicly traded Delaware limited partnership (NYSE: APL) and midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachia regions (NYSE:APL). At June 30, 2009, the Company had a 2.3% 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. AHD’s cash generating assets currently consist solely of its interests in APL. At June 30, 2009, 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 12.0% common limited partner interest, and 15,000 $1,000 par value 12.0% Class B cumulative preferred limited partner units in APL; 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 June 30, 2009, the Company has invested $10.7 million in Lightfoot LP.

On April 27, 2009, the Company and ATN executed a definitive merger agreement, pursuant to which the Company’s newly formed subsidiary will merge with and into ATN, with ATN surviving as the Company’s wholly-owned subsidiary. In the merger, each Class B common unit of ATN not currently held by the Company will be converted into 1.16 shares of the Company’s common stock, and the Company will be renamed “Atlas Energy, Inc.” The Company’s board of directors has approved the merger agreement and has resolved to recommend that the Company’s shareholders vote in favor of the transactions contemplated by the merger agreement. ATN’s board of directors and a special committee of its directors comprised entirely of independent directors have also approved the merger agreement and have resolved to recommend that ATN’s unitholders vote in favor of the merger. Pending consummation of the merger, ATN has suspended distributions to its Class A and Class B members’ interests. The transaction will be subject to approval by holders of a majority of the Company’s outstanding common stock and a majority of ATN’s outstanding Class B units and other customary closing conditions.

The accompanying consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2008 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the Company’s financial position,

F-71

results of operations and cash flows for the periods disclosed have been made. Management has evaluated subsequent events through August 10, 2009, the date the financial statements were issued. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008. Certain amounts in the prior year’s consolidated financial statements have been reclassified to conform to the current year presentation, including $18.8 million of pre-development costs shown as component of “Property, plant, and equipment, net” which was previously combined with “Liabilities associated with drilling contracts” on the Company’s consolidated balance sheets at December 31, 2008. On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system (see Note 4). As such, the Company has adjusted its prior period consolidated financial statements and related footnote disclosures presented within this Form 10-Q to reflect the amounts related to the operations of the NOARK gas gathering and interstate pipeline system as discontinued operations. The results of operations for the three and six month periods ended June 30, 2009 may not necessarily be indicative of the results of operations for the full year ending December 31, 2009.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

In addition to matters discussed further within this note, a more thorough discussion of the Company’s significant accounting policies is included in its audited consolidated financial statements and notes thereto in its annual report on Form 10-K for the year ended December 31, 2008.

Principles of Consolidation and Non-controlling 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 ownership interests in the net income (loss) of ATN, AHD and APL are reflected within non-controlling interests on the Company’s consolidated statements of operations, and the non-controlling interests in the assets and liabilities of ATN, AHD and APL are reflected as a component of stockholders’ equity on the Company’s consolidated balance sheets. All material intercompany transactions have been eliminated.

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 (“the Partnerships”). 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.

The Company’s consolidated financial statements also include APL’s 95% ownership interest in joint ventures which individually own a 100% ownership interest in the Chaney Dell natural gas gathering system and processing plants and a 72.8% undivided interest in the Midkiff/Benedum natural gas gathering system and processing plants. APL consolidates 100% of these joint ventures. The Company reflects the non-controlling 5% ownership interest in the joint ventures as non-controlling interests on its statements of operations. The Company also reflects the 5% ownership interest in the net assets of the joint ventures as non-controlling interests as a component of stockholders’ equity on its consolidated balance sheets. The joint ventures have a $1.9 billion note receivable from the holder of the 5% ownership interest in the joint ventures, which is reflected within non-controlling 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

F-72

results of the Midkiff/Benedum system. APL has an agreement with Pioneer whereby Pioneer has an option to buy up to an additional 22.0% interest in the Midkiff/Benedum system which began on June 15, 2009 and ends 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 $230.0 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 option.

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 and the allocation of purchase price to the fair value of assets acquired. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions as much as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the three and six months ended June 30, 2009 represent actual results in all material respects (see “— Revenue Recognition” accounting policy for further description).

Impairment of Long-Lived Assets

The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review of 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, 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 partnerships’ reserves. These assumptions include

F-73

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 Partnerships’ 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 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. There were no impairments of oil and gas properties or unproved properties recorded by the Company for the three and six months ended June 30, 2009 and 2008.

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 borrowed funds by ATN and APL in the aggregate was 6.6% and 5.5% for the three months ended June 30, 2009 and 2008, respectively, and 6.3% and 5.9% for the six months ended June 30, 2009 and 2008, respectively. The aggregate amount of interest capitalized by ATN and APL was $2.3 million and $2.4 million for the three months ended June 30, 2009 and 2008, respectively, and $5.6 million and $4.7 million for the six months ended June 30, 2009 and 2008, respectively.

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. 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 and expected renewals 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, adjusted for APL’s management’s estimate of whether the individual relationships will continue in excess or less than the average length.

F-74

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 Atlas Gas and Oil Company. ATN amortizes contracts acquired on a declining balance and straight-line method over their respective estimated useful lives.

The following table reflects the components of intangible assets being amortized at June 30, 2009 and December 31, 2008 (in thousands):

	June 30, 2009			December 31, 2008			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	$	(54,514	)	$	(41,735	)
Partnership management and operating contracts		(11,098	)		(10,728	)
Non-compete agreement		(890	)		(667	)
	$	(66,502	)	$	(53,130	)
Net Carrying Amount:
Customer contracts and relationships	$	180,868		$	193,647
Partnership management and operating contracts		3,245			3,615
Non-compete agreement		—			223
	$	184,113		$	197,485

Amortization expense on intangible assets was $6.7 million for both of the three months ended June 30, 2009 and 2008 and $13.4 million for both of the six months ended June 30, 2009 and 2008. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2009-$26.3 million; 2010-$26.3 million; 2011-$26.2 million; 2012-$25.7 million; and 2013-$24.6 million.

Goodwill

At June 30, 2009 and December 31, 2008, the Company had $35.2 million of goodwill recorded in connection with ATN consummated acquisitions. The changes in the carrying amount of goodwill for the six months ended June 30, 2009 and 2008 were as follows (in thousands):

	Six Months Ended June 30,
	2009		2008
Balance, beginning of period	$	35,166	$	744,449
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	)
Balance, end of period	$	35,166	$	712,026

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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.

ATN tests its 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 management must apply judgment in determining the estimated fair value of these reporting units. ATN’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 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, 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 also considers a control premium to the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in ATN’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 industry to determine whether those valuations appear reasonable in management’s judgment. The Company will continue to evaluate goodwill at least annually or when impairment indicators arise. During the six months ended June 30, 2009, no impairment indicators arose.

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 at March 31, 2008.

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Net Income (Loss) Per Share

Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of 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 17). 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):

	Three Months Ended June 30,		Six Months Ended June 30,
	2009	2008(1)	2009	2008(1)
Weighted average number of shares — basic	39,432	40,335	39,297	40,330
Add: effect of dilutive incentive awards	371	—	420	—
Weighted average number of common shares — diluted	39,803	40,335	39,717	40,330

(1) For both the three and six months ended June 30, 2008, approximately 1.9 million shares were excluded from the computation of diluted earnings attributable to common shareholders because the inclusion of such shares would have been anti-dilutive.

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 Partnerships to drill partnership wells. The contracts require that the 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 between 60 and 180 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.

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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 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:

• 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 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 June 30, 2009 and December 31, 2008 of $70.9 million and $87.4 million, respectively, which are included in accounts receivable within the Company’s consolidated balance sheets.

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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 income taxes). The following table sets forth the calculation of the Company’s comprehensive income (loss) (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Net income (loss)	$	133,710		$	(238,937	)	$	126,869		$	(256,180	)
(Income) loss attributable to non-controlling interests		(124,342	)		231,166			(112,858	)		254,831
Net income (loss) attributable to common shareholders		9,368			(7,771	)		14,011			(1,349	)
Other comprehensive loss:
Changes in fair value of derivative instruments accounted for as cash flow hedges, net of tax of $4,222 and $45,502 for the three months ended June 30, 2009 and 2008, respectively, and ($13,003) and $63,316 for the six months ended June 30, 2009 and 2008, respectively		(13,055	)		(290,136	)		60,395			(354,042	)
Less: reclassification adjustment for realized losses (gains) in net income (loss), net of tax of $5,448 and ($1,742) for the three months ended June 30, 2009 and 2008, respectively, and $7,695 and ($1,177) for the six months ended June 30, 2009 and 2008, respectively		(17,318	)		21,215			(16,672	)		32,896
Changes in non-controlling interest related to items in other comprehensive income (loss)		15,248			202,861			(35,422	)		224,310
Plus: amortization of additional post-retirement liability recorded upon adoption of SFAS No. 158, net of tax of $13 and $51 for the three months ended June 30, 2009 and 2008, respectively, and $26 and $102 for the six months ended June 30, 2009 and 2008, respectively		21			88			43			209
Total other comprehensive (loss) gain		(15,104	)		(65,972	)		8,344			(96,627	)
Comprehensive income (loss) attributable to shareholders	$	(5,736	)	$	(73,743	)	$	22,355		$	(97,976	)

Recently Adopted Accounting Standards

In May 2009, the FASB issued Statement No. 165, “Subsequent Events” (“SFAS No. 165”). SFAS No. 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS No. 165 requires management of a reporting entity to evaluate events or transactions that may occur after the balance sheet date for potential recognition or disclosure in the financial statements and provides guidance for disclosures that an entity should make about those events. SFAS No. 165 is effective for interim or annual financial periods ending after June 15, 2009 and shall be applied prospectively. The Company adopted the requirements of SFAS No. 165 on April 1, 2009 and its adoption did not have a material impact on the Company’s financial position or results of operations or related disclosures. The adoption of SFAS No. 165 does not change the Company’s current practices with respect to evaluating, recording and disclosing subsequent events.

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In April 2009, the FASB issued Staff Position 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“FSP FAS 157-4”). FSP FAS 157-4 applies to all fair value measurements and provides additional clarification on estimating fair value when the market activity for an asset has declined significantly. FSP FAS 157-4 also requires an entity to disclose a change in valuation technique and related inputs to the valuation calculation and to quantify its effects, if practicable. FSP FAS 157-4 is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company adopted the requirements of FSP FAS 157-4 on April 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.

In April 2009, the FASB issued Staff Position 115-2 and 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (“FSP FAS 115-2 and FAS 124-2”). FSP FAS 115-2 and FAS 124-2 change existing guidance for determining whether an impairment is other than temporary for debt securities. FSP FAS 115-2 and FAS 124-2 replaces the existing requirement that an entity’s management assess it has both the intent and ability to hold an impaired security until recovery with a requirement that management assess that it does not have the intent to sell the security and that it is more likely than not that it will not have to sell the security before recovery of its cost basis. FSP FAS 115-2 and FAS 124-2 also requires that an entity recognize noncredit losses on held-to-maturity debt securities in other comprehensive income and amortize that amount over the remaining life of the security and for the entity to present the total other-than-temporary impairment in the statement of operations with an offset for the amount recognized in other comprehensive income. FSP FAS 115-2 and FAS 124-2 are effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company adopted the requirements of FSP FAS 115-2 and FAS 124-2 on April 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.

In April 2009, the FASB issued Staff Position 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP FAS 107-1 and APB 28-1”). FSP FAS 107-1 APB 28-1 requires an entity to provide disclosures about fair value of financial instruments in interim financial information. In addition, an entity shall disclose in the body or in the accompanying notes of its summarized financial information for interim reporting periods and in its financial statements for annual reporting periods the fair value of all financial instruments for which it is practicable to estimate that value, whether recognized or not recognized in the statement of financial position. FSP FAS 107-1 APB 28-1 is effective for interim periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company adopted the requirements of FSP FAS 107-1 APB 28-1 on April 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.

In April 2009, the FASB issued Staff Position 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (“FSP 141(R)-1”). FSP 141(R)-1 requires that assets acquired and liabilities assumed in a business combination that arise from contingencies be recognized at fair value if fair value can be reasonably estimated. If fair value of such an asset or liability cannot be reasonably estimated, the asset or liability would generally be recognized in accordance with FASB Statement No. 5, “Accounting for Contingencies” and FASB Interpretation No. 14, “Reasonable Estimation of the Amount of a Loss”. FSP 141(R)-1 also eliminates the requirement to disclose an estimate of the range of outcomes of recognized contingencies at the acquisition date. FSP FAS 141(R)-1 is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 (January 1, 2009 for the Company). The Company adopted the requirements of FSP 141(R)-1 on January 1, 2009 and its adoption did not have a material impact on the Company’s financial position and results of operations.

In June 2008, the Financial Accounting Standards Board (“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

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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 was prohibited. All prior-period EPS data presented was adjusted retrospectively to conform to the provisions of this FSP. The Company applied the requirements of FSP EITF 03-6-1 upon its adoption on January 1, 2009 and the adoption of FSP EITF 03-6-1 had no 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 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 was 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 applied the requirements of FSP FAS 142-3 upon its adoption on January 1, 2009 and the adoption of FSP FAS 142-3 had no 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 required retrospective application of the guidance to all periods presented. Early adoption is prohibited. The Company adopted the requirements of EITF No. 07-4 on January 1, 2009 and it did not have a material impact on its calculation of net income per common shareholder.

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 adopted the requirements of SFAS No. 161 on January 1, 2009 and it resulted in additional disclosures related to its commodity and interest rate derivatives (see Note 8).

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In December 2007, the FASB issued SFAS No. 160, “Non-controlling 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 non-controlling interest (minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling 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 non-controlling interest. Additionally, SFAS No. 160 establishes a single method of 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 also requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated and adjust its remaining investment, if any, at fair value. The Company adopted the requirements of SFAS No. 160 on January 1, 2009 and adjusted the presentation of its financial position and results of operations. Prior period financial positions and results of operations have been adjusted retrospectively to conform to the provisions of SFAS No. 160.

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 non-controlling 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 non-controlling 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 adopted the requirements of SFAS No. 141(R) on January 1, 2009 and it did not have a material impact on its financial position and results of operations.

Recently Issued Accounting Standards

In June 2009, the FASB issued Statement No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles — A Replacement of FASB Statement No. 162” (“SFAS No. 168”). SFAS No. 168 establishes the FASB Accounting Standards Codification (“Codification”) as the single source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. The Codification supersedes all existing non-Securities and Exchange Commission accounting and reporting standards. Following SFAS No. 168, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead, the FASB will issue Accounting Standards Updates, which will serve only to update the Codification. SFAS No. 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Company will apply the requirements of SFAS No. 168 to its financial statements for the interim period ending September 30, 2009 and does not expect it to have a material impact to its financial position or results of operations or related disclosures.

In June 2009, the FASB issued Statement No. 167, “Amendments to FASB Interpretation No. 46(R)” (“SFAS No. 167”). SFAS No. 167 is a revision to FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities” and changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. SFAS No. 167 requires a reporting entity to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. A reporting entity will be required to disclose how its involvement with a variable interest entity affects the reporting entity’s financial statements. SFAS No. 167 is effective at the start of a reporting entity’s first fiscal year beginning after November 15, 2009 (January 1, 2010

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for the Company). The Company will apply the requirements of SFAS No. 167 upon its adoption on January 1, 2010 and does not expect it to have a material impact to its financial position or results of operations or related disclosures.

Modernization of Oil and Gas Reporting

In December 2008, the Securities and Exchange Commission (“SEC”) announced that it had approved revisions to its oil and gas reporting disclosures by adopting amendments to Rule 4-10 of Regulation S-X and Items 201, 801, and 802 of Regulation S-K. These new disclosure requirements are referred to as “Modernization of Oil and Gas Reporting” and include provisions that:

• Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.

• Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end pricing. This should maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date.

• Permit companies to disclose their probable and possible reserves on a voluntary basis. Current rules limit disclosure to only proved reserves.

• Update and revise reserve definitions to reflect changes in the oil and gas industry and new technologies. New updated definitions include “by geographic area” and “reasonable certainty”.

• Permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.

• Require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures are required related to internal controls over reserve estimation, as well as a report addressing the independence and qualifications of a company’s reserves preparer or auditor based on Society of Petroleum Engineers criteria.

The Company will begin complying with the disclosure requirements in its annual report on Form 10-K for the year ending December 31, 2009. The new rules may not be applied to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required. The Company is currently in the process of evaluating the new requirements.

NOTE 3 — APL INVESTMENT IN JOINT VENTURE

On May 31, 2009, APL and subsidiaries of The Williams Companies, Inc. (NYSE: WMB) (“Williams”) completed the formation of Laurel Mountain Midstream, LLC (“Laurel Mountain”), a joint venture which will own and operate APL’s Appalachia Basin natural gas gathering system, excluding APL’s Northern Tennessee operations. To the joint venture, Williams contributed cash of $100.0 million, of which APL received approximately $87.8 million, net of working capital adjustments, and a note receivable of $25.5 million. In addition, ATN sold certain assets to the joint venture for $12.0 million. APL contributed its Appalachia Basin natural gas gathering system and retained a 49% ownership interest. APL is also entitled to preferred distribution rights relating to all payments on the note receivable. Williams retained the remaining 51% ownership interest in Laurel Mountain. Upon completion of the transaction, APL recognized its 49% ownership interest in Laurel Mountain as an investment in joint venture on the Company’s consolidated balance sheet at fair value and recognized a gain on sale of $105.7 million, including $79.7 million associated with the remeasurement of APL’s investment in Laurel Mountain to fair value. APL used the net proceeds from the transaction to reduce borrowings under its senior secured credit facility (see Note 8). In addition, ATN sold to Laurel Mountain two

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natural gas processing plants and associated pipelines located in Southwestern Pennsylvania for $10.0 million, resulting in a $4.2 million loss which is included in gain on asset sale on the Company’s consolidated statement of operations. Upon the completion of the contribution of APL’s Appalachia gathering systems to Laurel Mountain, Laurel Mountain entered into new gas gathering agreements with ATN which superseded the existing natural gas gathering agreements and omnibus agreement between APL and ATN. Under the new gas gathering agreement, ATN is obligated to pay the joint venture all of the gathering fees it collects from its investment drilling partnerships plus any excess amount over the amount of the competitive gathering fee (which is currently defined as 13% of the gross sales price received for the ATN’s gas). APL has accounted for its ownership interest in Laurel Mountain under the equity method of accounting, with recognition of its ownership interest in the income of Laurel Mountain as equity income on the Company’s consolidated statements of operations.

The following table provides summarized statement of operations and balance sheet data on a 100% basis for Laurel Mountain for the three and six months ended June 30, 2009 and as of June 30, 2009 (in thousands):

	Three Months Ended June 30, 2009(1)		Six Months Ended June 30, 2009(1)
Statement of Operations data:
Total revenue	$	3,068	$	3,068
Net income		1,278		1,278
	June 30, 2009
Balance Sheet data:
Current assets	$	7,565
Long-term assets		245,395
Current liabilities		11,104
Long-term liabilities		15,500
Net equity		226,356

(1) Represents the period from May 31, 2009, the date of initial formation, through June 30, 2009.

NOTE 4 — DISCONTINUED OPERATIONS

On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system to Spectra Energy Partners OLP, LP (NYSE:SEP) (“Spectra”) for net proceeds of $292.0 million in cash, net of working capital adjustments. APL received an additional $2.5 million in cash in July 2009 upon the delivery of audited financial statements for the NOARK system assets to Spectra. APL used the net proceeds from the transaction to reduce borrowings under its senior secured term loan and revolving credit facility (see Note 8). The Company accounted for the sale of the NOARK system assets as discontinued operations within its consolidated financial statements and recorded a gain of $48.8 million (net of income taxes of $2.2 million) on the sale of APL’s NOARK assets within income from discontinued operations on its consolidated financial statement of operations for the three and six months ended June 30, 2009. The following table summarizes the components included within income from discontinued operations on the Company’s consolidated statements of operations (amounts in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Total revenue and other loss, net	$	5,269		$	15,988		$	21,274		$	32,359
Total costs and expenses		(2,728	)		(7,743	)		(9,858	)		(17,868	)
Income before income tax provision		2,541			8,245			11,416			14,491
Income tax provision		(140	)		(401	)		(499	)		(643	)
Income from discontinued operations	$	2,401		$	7,844		$	10,917		$	13,848

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The following table summarizes the components included within total assets and liabilities of discontinued operations within the Company’s consolidated balance sheet for the period indicated (amounts in thousands):

	December 31, 2008
Cash and cash equivalents	$	75
Accounts receivable		12,365
Prepaid expenses and other		1,001
Total current assets of discontinued operations		13,441
Property, plant and equipment, net		241,926
Other assets, net		239
Total assets of discontinued operations	$	255,606
Accounts payable	$	4,120
Accrued liabilities		5,892
Accrued producer liabilities		560
Total current liabilities of discontinued operations	$	10,572

The Company’s financial reporting basis of net assets included in the consolidated balance sheet attributable to discontinued operations reported above exceeded the tax basis of net assets attributable to discontinued operations by $45.8 million for year ended December 31, 2008. The Company has estimated its portion of deferred tax liability associated with these differences to be approximately $1.4 million for year ended December 31,2008.

NOTE 5 — PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment are stated at cost. Depreciation, depletion and amortization are based on cost less estimated salvage value primarily using the unit-of-production or straight-line methods 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.

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

	June 30, 2009			December 31, 2008(1)			Estimated Useful Lives in Years
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	1,232,197		$	1,214,991
Pre-development costs		13,501			18,772
Wells and related equipment		936,377			872,128
Total proved properties		2,182,075			2,105,891
Unproved properties		43,996			43,749
Support equipment		9,081			9,527
Total natural gas and oil properties		2,235,152			2,159,167
Pipelines, processing and compression facilities		1,679,471			1,728,472		15 - 40
Rights of way		166,723			168,206		20 - 40
Land, buildings and improvements		24,501			24,385		10 - 40
Other		21,423			22,108		3 - 10
		4,127,270			4,102,338
Less — accumulated depreciation, depletion and amortization		(412,868	)		(357,523	)
	$	3,714,402		$	3,744,815

(1) Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system (see Note 4)

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The Company follows the successful efforts method of accounting for oil and gas producing activities. Acquisition costs of leases and development activities are capitalized. 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 and delay rentals are expensed. Oil is converted to gas equivalent basis (“Mcfe”) at the rate one barrel equals 6 thousand cubic feet (“Mcf”). Depletion is provided on the units-of-production method.

Depletion, depreciation and amortization expense is determined on a field-by-field basis using the units-of-production method. Depletion, depreciation and amortization rates for leasehold acquisition costs based on estimated proved reserves and depletion, depreciation and amortization rates for well and related equipment costs 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 for its interest, properties purchased and working interests with other outside operators.

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

NOTE 6 — OTHER ASSETS

The following is a summary of other assets at the dates indicated (in thousands):

	June 30, 2009		December 31, 2008(1)
Deferred finance costs, net of accumulated amortization of $29,487 and $23,105 at June 30, 2009 and December 31, 2008, respectively	$	43,876	$	38,836
Investments		14,190		12,702
Long-term pipeline lease prepayment		2,043		—
Security deposits		1,975		1,617
Other		1,462		156
	$	63,546	$	53,311

(1) Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system (see Note 4)

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreements (see Note 8). During May 2009, APL recorded $2.3 million of accelerated amortization of deferred financing costs associated with the retirement of a portion of its term loan with the proceeds from the sale of its NOARK system (see Note 4). 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 notes (see Note 8).

Investments at June 30, 2009 and 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 which 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

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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. For the three months ended June 30, 2009 and 2008, the Company recorded a loss of $1.7 million and $0.1 million, respectively. For the six months ended June 30, 2009 and 2008, the Company recorded a loss of $1.7 million and $0.7 million, respectively.

NOTE 7 — 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.

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

	Three Months Ended June 30,					Six Months Ended June 30,
	2009			2008		2009			2008
Asset retirement obligations, beginning of period	$	49,262		$	43,801	$	48,136		$	42,358
Liabilities incurred		166			858		596			1,640
Liabilities settled		(23	)		—		(85	)		(2	)
Accretion expense		737			675		1,495			1,338
Asset retirement obligations, end of period	$	50,142		$	45,334	$	50,142		$	45,334

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.

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NOTE 8 — DEBT

Total debt consists of the following (in thousands):

	June 30, 2009			December 31, 2008
ATN revolving credit facility	$	456,000		$	467,000
ATN 10.75 % senior notes — due 2018		406,289			406,655
AHD credit facility		16,000			46,000
APL revolving credit facility		322,000			302,000
APL term loan		459,885			707,180
APL 8.125 % senior notes — due 2015		271,365			261,197
APL 8.75 % senior notes — due 2018		223,050			223,050
Total debt		2,154,589			2,413,082
Less current maturities		(16,000	)		—
Total long-term debt	$	2,138,589		$	2,413,082

ATN Revolving Credit Facility

At June 30, 2009, ATN had a credit facility with a syndicate of banks with a borrowing base of $650.0 million that matures in June 2012. The borrowing base is redetermined semiannually on April 1 and October 1 subject to changes in ATN’s oil and gas reserves or is automatically reduced by 25% of the stated principal of any senior unsecured notes issued by ATN. On July 16, 2009, ATN issued $200.0 million of senior unsecured notes, and the borrowing base was reduced by $50.0 million to $600.0 million (see Note 19). Up to $50.0 million of the credit facility may be in the form of standby letters of credit, of which $1.2 million was outstanding at June 30, 2009, 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. On April 9, 2009, the credit agreement was amended to, among other things, increase the applicable margin on Eurodollar Loans from a range of 100 to 175 basis points to a range of 200 to 300 basis points and the applicable margin for base rate loans from a range of 0 to 75 basis points to a range of 112.5 to 212.5 basis points. At June 30, 2009 and December 31, 2008, the weighted average interest rate on outstanding borrowings was 2.9% and 2.8%, 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 or the adjusted LIBOR for a month interest period plus 1.0%. 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 credit agreement was amended on July 10, 2009, in anticipation of the merger between ATN and the Company (see Note 19).

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 June 30, 2009. 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 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 1.3 to 1.0 and its ratio of total debt to EBITDA was 2.7 to 1.0 at June 30, 2009.

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ATN Senior Notes

At June 30, 2009, ATN had $400.0 million principal amount outstanding of 10.75% senior unsecured notes (“ATN Senior Notes”) due on February 1, 2018. The ATN Senior Notes are presented combined with the $6.3 million unamortized premium received at June 30, 2009. Interest on the ATN Senior Notes is payable semi-annually in arrears on February 1 and August 1 of each year. The ATN 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 ATN 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 ATN Senior Notes are junior in right of payment to ATN’s secured debt, including its obligations under its credit facility. The indenture governing the ATN 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 the covenants as of June 30, 2009.

AHD Credit Facility

At June 30, 2009, AHD had $16.0 million outstanding under a revolving credit facility with a syndicate of banks. On June 1, 2009, AHD entered into an amendment to its credit facility agreement which, among other changes:

• required AHD to immediately repay $30.0 million of then-outstanding $46.0 million of borrowings under the credit facility, $16.0 million of which was borrowed from the Company through a subordinate loan;

• required AHD to repay $4.0 million of the remaining $16.0 million outstanding under the credit facility on each of July 13, 2009, October 13, 2009 and January 13, 2010, with the balance of the indebtedness being due on the original maturity date of the credit facility of April 13, 2010. AHD repaid $4.0 million of its outstanding credit facility borrowings on July 13, 2009 in accordance with the amendment through a subordinate loan with the Company. AHD may not borrow additional amounts under the credit facility or issue letters of credit;

• required AHD to use any of its “excess cash flow”, which the amendment generally defines as cash in excess of $1.5 million as of the last business day of each month, to repay outstanding borrowings under the credit facility. In addition, the amendment requires AHD to repay borrowings under the credit facility with the net proceeds of any sales of its common units in APL;

• eliminated all financial covenants in the credit agreement, including the leverage ratio, the combined leverage ratio with APL, and the interest coverage ratio (all as defined within the credit facility agreement);

• prohibits AHD from paying any cash distributions on or redeeming any of its equity while the credit facility is in effect and permits AHD to pay operating expenses only to the extent incurred or paid in the ordinary course of business; and

• reduces the applicable margin above LIBOR, the federal funds rate plus 0.5% or the Wachovia Bank, National Association prime rate to be 0.75% for LIBOR loans and 0.0% for federal funds rate or prime rate loans. The weighted average interest rate on the outstanding credit facility borrowings at June 30, 2009 was 1.1%.

Borrowings under AHD’s credit facility are secured by a first-priority lien on a security interest in all of AHD’s assets, including the 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

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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 interest in its subsidiaries. AHD is in compliance with these covenants as of June 30, 2009. 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 the Company, AHD’s general partner or any other obligor, and termination of a material agreement and occurrence of a material adverse effect.

On June 1, 2009, in connection with AHD’s amendment of the credit facility, the Company guaranteed the remaining balance outstanding under the credit facility under a guarantee agreement with the administrative agent of the credit facility. In consideration for this guarantee, AHD issued to the Company a promissory note which requires it to pay interest to the Company in an amount based upon the principal amount outstanding under the credit facility. The maturity date of the promissory note is the day following the date that AHD repays all outstanding borrowings under its credit facility. Interest on the promissory note, which is calculated on the outstanding balance under the credit facility, accrues quarterly at the rate of 3.75% per annum. However, prior to the maturity date of the promissory note, interest under the promissory note will not be payable in cash, but instead the principal amount upon which interest is calculated will be increased by the interest amount payable.

APL Term Loan and Revolving Credit Facility

At June 30, 2009, 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 June 30, 2009 was 6.8%, and the weighted average interest rate on the outstanding APL term loan borrowings at June 30, 2009 was 6.8%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $3.5 million was outstanding at June 30, 2009. These outstanding letter of credit amounts were not reflected as borrowings on the Company’s consolidated balance sheet.

On May 29, 2009, APL entered into an amendment to its credit facility agreement which, among other changes:

• increased the applicable margin above adjusted LIBOR, the federal funds rate plus 0.5% or the Wachovia Bank prime rate upon which borrowings under the credit facility bear interest;

• for borrowings under the credit facility that bear interest at LIBOR plus the applicable margin, set a floor for the adjusted LIBOR interest rate of 2.0% per annum;

• increased the maximum ratios of funded debt (as defined in the credit agreement) to consolidated EBITDA (as defined in the credit agreement; the “leverage ratio”) and interest coverage (as defined in the credit agreement) that the credit facility requires APL to maintain;

• instituted a maximum ratio of senior secured debt (as defined in the credit agreement) to consolidated EBITDA (the “senior secured leverage ratio”) that the credit facility requires APL to maintain;

• requires that APL pay no cash distributions during the remainder of the year ended December 31, 2009 and allows it to pay cash distributions beginning January 1, 2010 if its senior secured leverage ratio is less than 2.75x and it has minimum liquidity (as defined in the credit agreement) of at least $50.0 million;

• generally limits APL’s annual capital expenditures to $95.0 million for the remainder of fiscal 2009 and $70.0 million each year thereafter;

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• permitted APL to retain (i) up to $135.0 million of net cash proceeds from dispositions completed in fiscal 2009 for reinvestment in similar replacement assets within 360 days, and (ii) up to $50.0 million of net cash proceeds from dispositions completed in any subsequent fiscal year subject to certain limitations as defined within the credit agreement; and

• instituted a mandatory repayment requirement of the outstanding senior secured term loan from excess cash flow (as defined in the credit agreement) based upon APL’s leverage ratio.

In June 2008, APL entered into an amendment to the credit facility agreement to revise the definition of “Consolidated EBITDA” to provide for the add-back of charges relating to its early termination of certain derivative contracts (see Note 9) in calculating 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 revolving credit facility with proceeds from its issuance of $250.0 million of 10-year 8.75% senior unsecured notes. Additionally, pursuant to this amendment, in June 2008 APL’s lenders increased their commitments for the revolving credit facility by $80.0 million to $380.0 million.

Borrowings under the 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 Chaney Dell and Midkiff/Benedum joint ventures and APL’s investment in the Laurel Mountain joint venture, and by the guaranty of each of APL’s 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 also unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement. APL is in compliance with these covenants as of June 30, 2009.

The events which constitute an event of default for the 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 APL in excess of a specified amount, and a change of control of APL’s General Partner. The credit facility requires APL to maintain the following ratios:

Fiscal quarter ending:	Maximum Leverage Ratio	Maximum Senior Secured Leverage Ratio	Minimum Interest Coverage Ratio
June 30, 2009	5.50x	3.00x	2.50x
September 30, 2009	6.50x	3.75x	2.50x
December 31, 2009	8.50x	5.25x	1.70x
March 31, 2010	9.25x	5.75x	1.40x
June 30, 2010	8.00x	5.00x	1.65x
September 30, 2010	7.00x	4.25x	1.90x
December 31, 2010	6.00x	3.75x	2.20x
Thereafter	5.00x	3.00x	2.75x

As of June 30, 2009, APL’s leverage ratio was 3.6 to 1.0, its senior secured leverage ratio was 2.2 to 1.0, and its interest coverage ratio was 4.2 to 1.0.

APL Senior Notes

At June 30, 2009, 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 $275.5 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 a net $4.1 million of unamortized discount

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as of June 30, 2009. 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 8.75% 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 8.75% Senior Notes are junior in right of payment to APL’s secured debt, including APL’s obligations under its credit facility.

In January 2009, APL issued Sunlight Capital $15.0 million of its 8.125% Senior Notes to redeem 10,000 APL Class A Preferred Units. Management of APL estimated that the fair value of the $15.0 million 8.125% Senior Notes issued was approximately $10.0 million at the date of issuance based upon the market price of the publicly-traded Senior Notes. As such, APL recognized a $5.0 million discount on the issuance of the Senior Notes, which is presented as a reduction of long-term debt on the Company’s consolidated balance sheets. The discount recognized upon issuance of the Senior Notes will be amortized to interest expense within the Company’s consolidated statements of operations over the term of the 8.125% Senior Notes based upon the effective interest rate method.

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 June 30, 2009.

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 APL 8.75% Senior Notes registration rights agreement by the specified dates.

NOTE 9 — DERIVATIVE INSTRUMENTS

APL, ATN and AHD 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.

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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 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.

Derivatives are recorded on the Company’s consolidated balance sheet as assets or liabilities at fair value. The Company reflected net derivative assets on its consolidated balance sheets of $69.6 million and $89.3 million at June 30, 2009 and December 31, 2008, respectively. Of the $29.5 million of net gain in accumulated other comprehensive income within stockholders’ equity on the Company’s consolidated balance sheet at June 30, 2009, if the fair values of the instruments remain at current market values, the Company will reclassify $20.6 million of gains to the Company’s consolidated statements of operations over the next twelve month period as these contracts expire, consisting of $24.6 million of gains to gas and oil production revenues, $2.6 million of losses to gathering, transmission and processing revenues and $1.4 million of losses to interest expense. Aggregate gains of $9.1 million will be reclassified to the Company’s consolidated statements of operations in later periods as these remaining contracts expire, consisting of $11.8 million of gains to gas and oil production revenues, $2.0 million of losses to gathering, transmission and processing revenues and $0.7 million of losses to interest expense. Actual amounts that will be reclassified will vary as a result of future price changes.

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Atlas Energy

The following table summarizes the fair value of ATN’s derivative instruments as of June 30, 2009 and December 31, 2008, as well as the gain or loss recognized for the six months ended June 30, 2009 and 2008. There were no gains or losses recognized in income for ineffective derivative instruments for the six months ended June 30, 2009 and 2008.

Fair Value of ATN Derivative Instruments:

	Asset Derivatives					Liability Derivatives
Derivatives in SFAS 133 Cash Flow Hedging Relationships	Balance Sheet Location	Fair Value				Balance Sheet Location	Fair Value
		June 30, 2009		December 31, 2008			June 30, 2009			December 31, 2008
		(in thousands)					(in thousands)
Commodity contracts:	Current assets	$	116,977	$	107,766	Current liabilities	$	(383	)	$	(9,348	)
	Long-term assets		54,465		69,451	Long-term liabilities		(29,120	)		(8,410	)
			171,442		177,217			(29,503	)		(17,758	)
Interest rate contracts:	Current assets		—		—	Current liabilities		(3,602	)		(3,481	)
	Long-term assets		—		—	Long-term liabilities		(1,213	)		(2,361	)
			—		—			(4,815	)		(5,842	)
Total derivatives under SFAS No. 133		$	171,442	$	177,217		$	(34,318	)	$	(23,600	)

Effects of ATN Derivative Instruments on Consolidated Statements of Operations:

Derivatives in SFAS 133 Cash Flow Hedging Relationships		Gain/(Loss) Recognized in OCI on Derivative (Effective Portion) For the Three Months Ended						Location of Gain/(Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Gain/(Loss) Reclassified from OCI into Income (Effective Portion) For the Three Months Ended
		June 30, 2009			June 30, 2008				June 30, 2009			June 30, 2008
		(in thousands)							(in thousands)
Commodity contracts		$	(22,528	)	$	(212,364	)	Gas and oil production	$	31,564		$	(4,896	)
Interest rate contracts	��		(132	)		3,831		Interest expense		(1,030	)		(114	)
		$	(22,660	)	$	(208,533	)		$	30,534		$	(5,010	)

Derivatives in SFAS 133 Cash Flow Hedging Relationships	Gain/(Loss) Recognized in OCI on Derivative (Effective Portion) For the Six Months Ended						Location of Gain/(Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Gain/(Loss) Reclassified from OCI into Income (Effective Portion) For the Six Months Ended
	June 30, 2009			June 30, 2008				June 30, 2009			June 30, 2008
	(in thousands)							(in thousands)
Commodity contracts	$	64,286		$	(310,522	)	Gas and oil production	$	47,082		$	1,645
Interest rate contracts		(1,005	)		1,795		Interest expense		(2,032	)		(23	)
	$	63,281		$	(308,727	)		$	45,050		$	1,622

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ATN’s commodity price risk management includes estimated future natural gas and crude oil production of the Partnerships. Therefore, a portion of any unrealized derivative gain or loss is allocable to the limited partners of the Partnerships based on their share of estimated future gas and oil production related to the hedges not yet settled. At June 30, 2009 and December 31, 2008, unrealized derivative liabilities of $47.7 million and $51.8 million are payable to the limited partners in the Partnerships and are included in the Company’s consolidated balance sheets.

In May 2009, ATN received approximately $28.5 million in proceeds from the early termination of natural gas and oil derivative positions for production periods from 2011 through 2013. In conjunction with the early termination of these derivatives, ATN entered into new derivative positions at prevailing prices at the time of the transaction. The net proceeds from the early termination of these derivatives were used to reduce indebtedness under ATN’s credit facility (see Note 8). The gain recognized upon the early termination of these derivative positions will continue to be reported in accumulated other comprehensive income on the Company’s consolidated balance sheets, and will be reclassified into the Company’s consolidated statements of operations in the same periods in which the hedged production revenues would have been recognized in earnings.

At June 30, 2009, ATN had debt outstanding of $456.0 million under its revolving credit facility. In January 2008, ATN entered into derivative contracts 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 No. 133. Using the change in variable cash flow method, no hedge ineffectiveness was identified. The values of ATN’s cash flow hedges included in accumulated other comprehensive income were net unrecognized losses of approximately $4.8 million and $5.8 million at June 30, 2009 and December 31, 2008, respectively. ATN recognized gains on settled swaps of $1.0 million and $0.1 million for the three months ended June 30, 2009 and 2008, respectively, and gains of $2.0 million and $23,000 for the six months ended June 30, 2009 and 2008, respectively.

As of June 30, 2009, ATN had the following interest rate and commodity derivatives:

Interest Fixed Rate Swap

Term	Notional Amount		Option Type	Contract Period Ended December 31,	Fair Value Liability
					(in thousands)
January 2008 - January 2011	$	150,000,000	Pay 3.11% — Receive LIBOR	2009	$	(1,932	)
				2010		(2,757	)
				2011		(126	)
					$	(4,815	)

F-95

Natural Gas Fixed Price Swaps

Production Period Ending December 31,	Volumes	Average Fixed Price		Fair Value Asset/(Liability)(1)
	(MMBtu)	(per MMBtu)		(in thousands)
2009	21,790,000	$	8.044	$	79,987
2010	31,880,000	$	7.708		52,270
2011	20,720,000	$	7.040		2,973
2012	19,680,000	$	7.223		1,131
2013	10,620,000	$	7.126		(1,631	)
				$	134,730

Natural Gas Costless Collars

Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset/(Liability)(1)
		(MMBtu)	(per MMBtu)		(in thousands)
2009	Puts purchased	120,000	$	11.000	$	795
2009	Calls sold	120,000	$	15.350		—
2010	Puts purchased	3,360,000	$	7.839		6,584
2010	Calls sold	3,360,000	$	9.007		—
2011	Puts purchased	9,540,000	$	6.523		145
2011	Calls sold	9,540,000	$	7.666		—
2012	Puts purchased	4,020,000	$	6.514		—
2012	Calls sold	4,020,000	$	7.718		(978	)
2013	Puts purchased	5,340,000	$	6.516		—
2013	Calls sold	5,340,000	$	7.811		(1,737	)
					$	4,809

Crude Oil Fixed Price Swaps

Production Period Ending December 31,	Volumes	Average Fixed Price		Fair Value Asset/(Liability)(2)
	(Bbl)	(per Bbl)		(in thousands)
2009	31,700	$	99.497	$	896
2010	48,900	$	97.400		1,079
2011	42,600	$	77.460		(30	)
2012	33,500	$	76.855		(105	)
2013	10,000	$	77.360		(35	)
				$	1,805

F-96

Crude Oil Costless Collars

Production Period Ending December 31,	Option Type	Volumes	Average Floor and Cap		Fair Value Asset/(Liability)(2)
		(Bbl)	(per Bbl)		(in thousands)
2009	Puts purchased	19,500	$	85.000	$	289
2009	Calls sold	19,500	$	116.884		—
2010	Puts purchased	31,000	$	85.000		448
2010	Calls sold	31,000	$	112.918		—
2011	Puts purchased	27,000	$	67.223		—
2011	Calls sold	27,000	$	89.436		(45	)
2012	Puts purchased	21,500	$	65.506		—
2012	Calls sold	21,500	$	91.448		(73	)
2013	Puts purchased	6,000	$	65.358		—
2013	Calls sold	6,000	$	93.442		(24	)
					$	595
		Total ATN net asset			$	137,124

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

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

Atlas Pipeline Holdings and Atlas Pipeline Partners

Beginning July 1, 2008, APL discontinued 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 are 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 June 30, 2008, which was recognized in accumulated other comprehensive income 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 transactions affect earnings.

During the six months ended June 30, 2009 and year ended December 31, 2008, APL made net payments of $5.0 million and $274.0 million, respectively, related to the early termination of derivative contracts. 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 three and six months ended June 30, 2009 and 2008, the Company recognized the following derivative activity related to the termination of these derivative instruments within its consolidated statements of operations (amounts in thousands):

	Early Termination of Derivative Contracts
	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Net cash derivative expense included within loss on mark-to-market derivatives	$	—		$	(115,810	)	$	(5,000	)	$	(115,810	)
Net non-cash derivative income included within loss on mark-to-market derivatives		—			(315	)		—			(315	)
Net non-cash derivative expense included within gathering, transmission and processing revenue		7,117			(46,345	)		19,220			(46,345	)
Net cash derivative expense included within loss on mark-to-market derivatives		(12,123	)		—			(34,067	)		—

F-97

At June 30, 2009, 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 8), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. The interest rate swap agreement is effective at June 30, 2009 and expires on May 28, 2010. In June 2009, AHD repaid a portion of its borrowings under the credit facility, with a resulting balance of $16.0 million outstanding under the credit facility at June 30, 2009. In addition, in accordance with the June 2009 amendment to its credit facility (see Note 8), AHD is prohibited from borrowing additional amounts under its credit facility once the amounts have been repaid. In accordance with SFAS No. 133, the portion of any gain or loss in other comprehensive income related to forecasted hedge transactions that are no longer expected to occur are to be removed from other comprehensive income and recognized within the Company’s statements of operations. As a result of this reduction in borrowings under the credit facility below the notional amount of the interest rate derivative contract, the Company recognized an expense of $0.2 million within other loss, net in its consolidated statement of operations for the three and six months ended June 30, 2009.

At June 30, 2009, 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 credit facility (see Note 8), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. The APL interest rate swap agreements were in effect as of June 30, 2009 and expire during periods ranging from January 30, 2010 through April 30, 2010. Beginning May 29, 2009, APL discontinued hedge accounting for its interest rate 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 other loss, net in the Company’s consolidated statements of operations. The fair value of these derivative instruments at May 29, 2009, which was recognized within accumulated other comprehensive income 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 transactions affect earnings.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Loss from cash and non-cash settlement of qualifying hedge instruments(1)	$	(7,327	)	$	(33,152	)	$	(27,502	)	$	(50,795	)
Gain/(loss) from change in market value of non-qualifying derivatives(2)		2,509			(136,736	)		(42,481	)		(207,932	)
Gain/(loss) from change in market value of ineffective portion of qualifying derivatives(2)		—			1,934			10,813			(3,726	)
Loss from cash and non-cash settlement of non-qualifying derivatives(2)		(21,105	)		(184,564	)		13,390			(196,489	)
Loss from cash settlement of interest rate derivatives(3)		(3,125	)		(207	)		(6,179	)		(207	)

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

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

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

F-98

The following table summarizes AHD’s and APL’s gross fair values of cumulative derivative instruments for the period indicated (amounts in thousands):

	June 30, 2009
	Asset Derivatives			Liability Derivatives
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments under SFAS No. 133:
N/A		$	—		$	—
Derivatives not designated as hedging instruments under SFAS No. 133:
Interest rate contracts		$	—	Current portion of derivative liability	$	(8,715	)
Commodity contracts	Current portion of derivative asset		1,815			—
Commodity contracts	Long-term derivative asset		1,606			—
Commodity contracts	Current portion of derivative liability		6,848	Current portion of derivative liability		(56,337	)
Commodity contracts	Long-term derivative liability		3,151	Long-term derivative liability		(15,899	)
		$	13,420		$	(80,951	)

The following table summarizes the gross effect of the AHD’s and APL’s derivative instruments on the Company’s consolidated statement of operations for the period indicated (amounts in thousands):

	Three months ended June 30, 2009
	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			Location of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)			Location of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
Derivatives in SFAS No. 133 cash flow hedging relationships:
N/A
Derivatives not designated as hedging instruments under SFAS No. 133:
Interest rate contracts	$	(3,125	)	Interest expense	$	—		N/A
Commodity contracts(1)		(10,894	)	Natural gas and liquids revenue		(13,381	)	Other loss, net
Commodity contracts(2)		—		N/A		(4,155	)	Other loss, net
	$	(14,019	)		$	(17,536	)

(1) Hedges previously designated as cash flow hedges

(2) Dedesignated cash flow hedges and non-designated hedges

F-99

	Six months ended June 30, 2009
	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			Location of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)			Location of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
Derivatives in SFAS No. 133 cash flow hedging relationships:
N/A
Derivatives not designated as hedging instruments under SFAS No. 133:
Interest rate contracts	$	(6,179	)	Interest expense	$	—		N/A
Commodity contracts(1)		(26,864	)	Natural gas and liquids revenue		(22,908	)	Other loss, net
Commodity contracts(2)		—		N/A		35,665		Other loss, net
	$	(33,043	)		$	12,757

(1) Hedges previously designated as cash flow hedges

(2) Dedesignated cash flow hedges and non-designated hedges

As of June 30, 2009, the AHD had the following interest rate 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)
May 2008 - May 2010	$	25,000,000	Pay 3.01% — Receive LIBOR	2009	$	(323	)
				2010		(221	)
			Total AHD net liability		$	(544	)

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

As of June 30, 2009, 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	$	(2,480	)
				2010		(351	)
					$	(2,831	)
April 2008 - April 2010	$	250,000,000	Pay 3.14% — Receive LIBOR	2009	$	(3,430	)
				2010		(1,910	)
					$	(5,340	)

F-100

Natural Gas Liquids Sales — Fixed Price Swaps

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability(2)
	(gallons)	(per gallon)		(in thousands)
2009	11,088,000	$	0.745	$	(573	)

Crude Oil Sales Options (associated with NGL volume)

Production Period Ended December 31,	Crude Volume	Associated NGL Volume	Average Crude Price(4)		Fair Value Asset/(Liability)(3)			Option Type
	(barrels)	(gallons)	(per barrel)		(in thousands)
2009	234,000	13,185,000	$	60.97	$	1,234		Puts purchased
2009	1,055,400	59,081,820	$	84.75		(2,622	)	Calls sold
2010	486,000	27,356,700	$	61.24		3,838		Puts purchased
2010	3,127,500	213,088,050	$	86.20		(22,103	)	Calls sold
2010	714,000	45,415,440	$	132.17		708		Calls purchased(5)
2011	606,000	33,145,560	$	100.70		(4,065	)	Calls sold
2011	252,000	13,547,520	$	133.16		764		Calls purchased(5)
2012	450,000	25,893,000	$	102.71		(3,746	)	Calls sold
2012	180,000	9,676,800	$	134.27		801		Calls purchased(5)
					$	(25,191	)

Natural Gas Sales — Fixed Price Swaps

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Asset(3)
	(mmbtu)(6)	(per mmbtu)(6)		(in thousands)
2009	240,000	$	8.000	$	866

Natural Gas Basis Sales

Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset(3)
	(mmbtu)(6)	(per mmbtu)(6)			(in thousands)
2009	2,460,000	$	(0.558	)	$	27
2010	2,220,000	$	(0.607	)		124
					$	151

Natural Gas Purchases — Fixed Price Swaps

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability(3)
	(mmbtu)(6)	(per mmbtu)(6)		(in thousands)
2009	5,160,000	$	8.687	$	(22,156	)
2010	4,380,000	$	8.635		(12,414	)
				$	(34,570	)

F-101

Natural Gas Basis Purchases

Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Liability(3)
	(mmbtu)(6)	(per mmbtu)(6)			(in thousands)
2009	7,380,000	$	(0.659	)	$	(83	)
2010	6,600,000	$	(0.590	)		(111	)
					$	(194	)

Ethane Put Options

Production Period Ended December 31,	Associated NGL Volume	Average Price(4)		Fair Value Liability(1)			Option Type
	(gallons)	(per gallon)		(in thousands)
2009	630,000	$	0.340	$	(40	)	Puts purchased

Propane Put Options

Production Period Ended December 31,	Associated NGL Volume	Average Price(4)		Fair Value Asset(1)		Option Type
	(gallons)	(per gallon)		(in thousands)
2009	15,498,000	$	0.767	$	752	Puts purchased

Isobutane Put Options

Production Period Ended December 31,	Associated NGL Volume	Average Price(4)		Fair Value Asset(1)		Option Type
	(gallons)	(per gallon)		(in thousands)
2009	1,134,000	$	0.969	$	20	Puts purchased

Normal Butane Put Options

Production Period Ended December 31,	Associated NGL Volume	Average Price(4)		Fair Value Asset(1)		Option Type
	(gallons)	(per gallon)		(in thousands)
2009	9,324,000	$	0.964	$	585	Puts purchased

Natural Gasoline Put Options

Production Period Ended December 31,	Associated NGL Volume	Average Price(4)		Fair Value Asset(1)		Option Type
	(gallons)	(per gallon)		(in thousands)
2009	5,796,000	$	1.267	$	358	Puts purchased

Crude Oil Sales

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability(3)
	(barrels)	(per barrel)		(in thousands)
2009	15,000	$	62.700	$	(131	)

F-102

Crude Oil Sales Options

Production Period Ended December 31,	Volumes	Average Crude Price(4)		Fair Value Asset (Liability)(3)			Option Type
	(barrels)	(per barrel)		(in thousands)
2009	231,000	$	63.017	$	1,100		Puts purchased
2009	153,000	$	84.881		(434	)	Calls sold
2010	174,000	$	61.111		1,361		Puts purchased
2010	234,000	$	88.088		(1,557	)	Calls sold
2011	72,000	$	93.109		(699	)	Calls sold
2012	48,000	$	90.314		(620	)	Calls sold
				$	(849	)
	Total APL net liability			$	(66,987	)

(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 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) Average price of options based upon average strike price adjusted by average premium paid or received.

(5) Calls purchased for 2010 through 2012 represent offsetting 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.

(6) Mmbtu represents million British Thermal Units

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

	June 30, 2009			December 31, 2008
Current portion of derivative asset	$	118,792		$	152,727
Long-term derivative asset		56,071			69,451
Current portion of derivative liability		(62,189	)		(73,776	)
Long-term derivative liability		(43,081	)		(59,103	)
Total Company net asset	$	69,593		$	89,299

NOTE 10 — FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company applies the provisions of SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”) to its financial instruments. 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.

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.

F-103

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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 9) and the Company’s Supplemental Employment Retirement Plan (“SERP” — see Note 17). ATN’s and APL’s commodity hedges, with the exception of APL’s NGL fixed price swaps and NGL options, 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, while the asset related to the funding of the SERP in a rabbi trust is based on third-party financial statements and is therefore also 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 NGL options are based on forward price curves developed by the related financial institution 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 June 30, 2009 (in thousands):

	Level 1		Level 2			Level 3		Total
SERP liability	$	—	$	(3,461	)	$	—	$	(3,461	)
SERP asset funded in rabbi trust		—		3,382			—		3,382
Interest rate derivatives		—		(13,530	)		—		(13,530	)
APL commodity-based derivatives		—		(59,919	)		1,103		(58,816	)
ATN commodity-based derivatives		—		141,939			—		141,939
Total	$	—	$	68,411		$	1,103	$	69,514

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 June 30, 2009 (in thousands):

	NGL Fixed Price Swaps			NGL Sales Options			Total
Balance — December 31, 2008	$	1,509		$	12,316		$	13,825
New options contracts		—			(1,024	)		(1,024	)
Cash settlements from unrealized gain (loss)(1)		(4,215	)		(11,410	)		(15,625	)
Cash settlements from other comprehensive income(1)		3,700			—			3,700
Net change in unrealized gain (loss)(2)		(1,567	)		(1,061	)		(2,628	)
Deferred option premium recognition		—			2,855			2,855
Net change in other comprehensive loss		—			—			—
Balance — June 30, 2009	$	(573	)	$	1,676		$	1,103

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

(2) Included within 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.

F-104

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 debt at June 30, 2009 and December 31, 2008, which consists principally of APL’s term loan, ATN and APL’s Senior Notes and borrowings under the ATN, AHD and APL’s credit facilities, were $1,971.5 million and $1,911.4 million, respectively, compared with the carrying amounts of $2,154.6 million and $2,413.1 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.

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

The Company estimates the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements; the credit-adjusted risk-free rate of the Company; and estimated inflation rates (see Note 7).

Information for assets that are measured at fair value on a non-recurring basis for the three and six months ended June 30, 2009 and 2008 is as follows (in thousands):

	Three Months Ended June 30, 2009				Six Months Ended June 30, 2009
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	166	$	166	$	596	$	596
Total	$	166	$	166	$	596	$	596

NOTE 11 — 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, the Partnerships. ATN serves as general partner of the Partnerships and assumes customary rights and obligations for the Partnerships. As the general partner, ATN is liable for the Partnerships’ liabilities and can be liable to limited partners if it breaches its responsibilities with respect to the operations of the Partnerships. ATN is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Partnerships’ revenue, and costs and expenses according to the respective Partnership agreements.

Relationship with Resource America, Inc.The Company has two agreements that govern its ongoing relationship with Resource America, Inc. (“RAI”), its former parent, that are still in effect at June 30, 2009. 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 three months ended June 30, 2009 and 2008, the Company’s reimbursements to RAI totaled $0.3 million and $0.2 million, respectively, and $0.6 million and $0.4 million for the six months ended June 30, 2009 and 2008, respectively. At June 30, 2009 and December 31, 2008, reimbursements to RAI totaling $0.2 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.

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Relationship with Laurel Mountain. Upon completion of the transaction with Laurel Mountain, ATN entered into new gas gathering agreements with Laurel Mountain which superseded the existing master natural gas gathering agreement and omnibus agreement between ATN and APL. Under the new gas gathering agreement, ATN is obligated to pay Laurel Mountain all of the gathering fees it collects from the partnerships, which generally ranges from $0.35 per Mcf to the amount of the competitive gathering fee (which is currently defined as 13% of the gross sales price received for the partnerships gas) plus any excess amount of the gathering fees collected up to an amount equal to approximately 16% of the natural gas sales price. The new gathering agreement contains additional provisions which define certain obligations and options of each party to build and connect newly drilled wells to any Laurel Mountain gathering system.

NOTE 12 — COMMITMENTS AND CONTINGENCIES

General Commitments

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 management of ATN 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. For the three and six months ended June 30, 2009, $0.7 million and $0.9 million, respectively, of the Company’s net revenues were subordinated, which reduced its cash distribution received from the investment partnerships for the respective periods. No subordination was required for the three and six months ended June 30, 2008.

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 June 30, 2009, the Company and its subsidiaries are committed to expend approximately $19.2 million on pipeline extensions, compressor station upgrades, and processing facility upgrades.

Legal Proceedings

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.

Following the announcement of the merger agreement on April 27, 2009 between the Company and ATN, the following actions were filed in Delaware Chancery Court purporting to challenge the merger:

• Alonzo v. Atlas Energy Resources, LLC, et al., C.A. No. 4553-VCN (Del. Ch. filed 4/30/09);

• Operating Engineers Constructions Industry and Miscellaneous Pension Fund v. Atlas America, Inc., et al., C.A. No. 4589-VCN (Del. Ch. filed 5/13/09);

• Vanderpool v. Atlas Energy Resources, LLC, et al., C.A. No. 4604-VCN (Del. Ch. filed 5/15/09);

• Farrell v. Cohen, et al., C.A. No. 4607-VCN (Del. Ch. filed 5/19/09); and

• Montgomery County Employees’ Retirement Fund v. Atlas Energy Resources, L.L.C., et al., C.A. No. 4613-VCN (Del. Ch. filed 5/21/09).

On June 15, 2009, Vice Chancellor Noble issued an order consolidating all five lawsuits, renaming the actionIn re Atlas Energy Resources, LLC Unitholder Litigation, C.A. No. 4589-VCN, and appointing as co-lead plaintiffs Operating Engineers Construction Industry and Miscellaneous Pension Fund and Montgomery County

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Employees Retirement Fund. Plaintiffs filed a Verified Consolidated Class Action Complaint on July 1, 2009, which has superseded all prior complaints. On July 27, 2009, the Chancery Court granted the parties’ scheduling stipulation, setting a preliminary injunction hearing for September 4, 2009. The complaint advances claims of breach of fiduciary duty in connection with the merger agreement, including allegations of inadequate disclosures in connection with the unitholder vote on the merger, and seeks monetary damages or injunctive relief, or both. On August 7, 2009, Plaintiffs advised the Court by letter that they are not pursuing their motion for preliminary injunction and requested that the hearing date be removed from the Court’s calendar. Plaintiffs have advised counsel for the defendants that they intend to continue to pursue the case after the merger as a claim for money damages. Predicting the outcome of this lawsuit is difficult. An adverse judgment for monetary damages could have a material adverse effect on the operations of the combined company after the merger. A preliminary injunction , had plaintiffs successfully pursued it, could have delayed or jeopardized the completion of the merger, and an adverse judgment granting permanent injunctive relief could have indefinitely enjoined completion of the merger. Based on the facts known to date, the defendants believe that the claims asserted against them in this lawsuit are without merit, and intend to defend themselves vigorously against the claims.

In January 2009, in the matter captioned “Elk City Oklahoma Pipeline, L.P. v. Northern Natural Gas Company”, (District Court of Tulsa County, Oklahoma), Elk City Oklahoma Pipeline, L.P. (“Elk City”), a subsidiary of APL’s, filed a petition against Northern Natural Gas Company (“NNG”), seeking a declaratory judgment related to the interpretation of a Purchase and Sale Agreement for certain pipeline and assets in Western Oklahoma which was entered into between the two parties on June 12, 2008 (the “PSA”). In March 2009, NNG filed a petition together with a motion for summary judgment alleging breach of the PSA for Elk City’s failure to complete the purchase and seeking specific performance or, alternatively, damages, in the matter captioned “Northern Natural Gas Company vs. Elk City Oklahoma Pipeline, L.P.”, (District Court of Tulsa County, Oklahoma). These matters were previously described in the Company’s quarterly report on Form 10-Q for the quarter ended March 31, 2009. Both matters were settled by agreement dated May 19, 2009. The settlement involved a monetary payment by Elk City, but does not require Elk City to purchase the pipeline assets. The amounts Elk City agreed to pay in connection with the settlement do not have a material impact on the Company’s financial condition or results of operations.

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 ATN 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, LLC could not have tortuously interfered with the contract. The Chancery Court dismissed all claims against ATN; however, CNX has appealed this decision.

NOTE 13 — 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. As of June 30, 2009 and December 31, 2008, the Company determined that no material valuation allowance was necessary.

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The Company applies the provisions of FASB Interpretation 48, Accounting for Uncertainty in Income Taxes (“FIN 48”)to its income tax positions. 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. The Company had applied FIN 48 to all tax positions for which the statute of limitation remains open, and there were no additions, reductions or settlements in unrecognized tax benefits during the three and six months ended June 30, 2009 and 2008. The Company has no material uncertain tax positions at June 30, 2009.

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 14 — COMMON STOCK

Stock Repurchase Plan

In September 2008, the Company’s Board of Directors approved a stock repurchase program 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 program approved in September 2005 to purchase 560,291 shares in August and September 2008. The average price for the shares purchased during 2008 was $34.76 per share.

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 three and six months ended June 30, 2008 in the accompanying consolidated financial statements and notes to the consolidated financial statements to reflect this split.

NOTE 15 — ISSUANCE OF SUBSIDIARY UNITS

The Company accounts for offerings by its subsidiaries in accordance with Staff Accounting Bulletin No. 51, “Accounting by the Parent in Consolidation for Sales of Stock by a Subsidiary” (“SAB 51”) and SFAS No. 160. 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 9).

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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 and SFAS No. 160 was recorded in consolidated equity as an increase to paid-in capital as well as a corresponding adjustment of $26.4 million to non-controlling 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.

NOTE 16 — CASH DISTRIBUTIONS

Atlas Energy Resources Cash Distributions. ATN 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 to its Class A and Class B common unitholders in accordance with their respective percentage interests. If Class A and Class B common unit distributions exceed specified target levels in any quarter during or subsequent to the completion of certain tests set forth in ATN’s limited liability company agreement, the Company will receive management incentive distributions of between 15% and 50% of such distributions in excess of the specified target levels as defined in the Company’s limited liability company agreement. The tests within the Company’s limited liability company agreement include a 12-quarter test which requires, among other things, that ATN pay a quarterly cash distribution per unit that on average exceeds $0.42 per unit for 12 full, consecutive, non-overlapping calendar quarters and does not have a calendar quarter during which the distribution per unit was reduced. Effective April 27, 2009, ATN has suspended further distributions pursuant to its merger agreement with the Company (see Note 1). ATN’s suspension of the quarterly distribution during the three months and six months ended June 30, 2009 means that it has not met the tests within the limited liability company agreement and, as such, the Company will not receive the MIIs that were previously reserved for during previous periods. Distributions declared by ATN from January 1, 2008 through June 30, 2009 were as follows:

Date Cash Distribution Paid or Payable	For Quarter Ended	Cash Distribution Per Common Unit		Total Cash Distribution to the Company
				(in thousands)
February 14, 2008	December 31, 2007	$	0.57	$	17,437
May 15, 2008	March 31, 2008	$	0.59	$	18,410
August 14, 2008	June 30, 2008	$	0.61	$	19,060
November 14, 2008	September 30, 2008	$	0.61	$	19,060
February 13, 2009	December 31, 2008	$	0.61	$	19,060

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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. Common unit and General Partner distributions declared by APL for the period from January 1, 2008 through June 30, 2009 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, 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	December 31, 2008	$	0.38	$	17,463	$	2,545
May 13, 2009	March 31, 2009	$	0.15	$	7,147	$	1,010

In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems, 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 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 did not declare a cash distribution for the quarter ended June 30, 2009. On May 29, 2009, APL entered into an amendment to its senior secured credit facility (see Note 8), which, among other things, requires that it pay no cash distributions during the remainder of the year ended December 31, 2009 and allows it to pay cash distributions beginning January 1, 2010 if its senior secured leverage ratio is above certain thresholds and it has minimum liquidity (both as defined in the credit agreement) of at least $50.0 million.

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 January 1, 2008 through June 30, 2009 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)
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	December 31, 2008	$	0.06	$	1,068

There was no distribution declared by AHD for the quarter ended March 31, 2009 or June 30, 2009. On June 1, 2009, AHD entered into an amendment to its credit facility agreement, which, among other changes, prohibited it from paying any cash distributions on its equity while the credit facility is in effect (see Note 8).

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NOTE 17 — BENEFIT PLANS

Incentive Bonus Plan

The Company’s shareholders approved an Incentive Bonus Plan (“Bonus Plan”) 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 three month periods ended June 30, 2009 and 2008, the Company recognized $1.7 million and $1.3 million, respectively, of estimated expenses under the plan and $3.5 million and $2.8 million for the six month periods ended June 30, 2009 and 2008, respectively.

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 straight-line basis. The Company issues new shares when stock options are exercised or units are converted to shares. There were 12,656 options exercised during the three and six months ended June 30, 2009. No options were exercised during the three and six months ended June 30, 2008, respectively.

The following tables set forth the Plan activity for the three and six months ended June 30, 2009 and 2008:

	Three Months Ended June 30,
	2009					2008
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price
Outstanding, beginning of period		3,558,226		$	16.89		3,540,380	$	16.89
Granted		—			—		—		—
Exercised		(12,656	)	$	11.32		—		—
Cancelled		—			—		—		—
Forfeited		(8,438	)	$	11.32		—		—
Outstanding, end of period(1)(2)		3,537,132		$	16.96		3,540,380	$	16.89
Options exercisable, end of period(3)		2,539,674		$	13.35		2,144,650	$	11.64
Non-cash compensation expense recognized (in thousands)	$	974				$	983

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	Six Months Ended June 30,
	2009					2008
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price
Outstanding, beginning of period		3,495,351		$	16.97		2,715,380	$	12.10
Granted		100,000		$	13.35		825,000	$	32.68
Exercised		(12,656	)	$	11.32		—		—
Cancelled		(15,187	)	$	11.32		—		—
Forfeited		(30,376	)	$	11.32		—		—
Outstanding, end of period(1)(2)		3,537,132		$	16.96		3,540,380	$	16.89
Options exercisable, end of period(3)		2,539,674		$	13.35		2,144,650	$	11.64
Non-cash compensation expense recognized (in thousands)	$	1,894				$	1,945
Available for grant at June 30, 2009		763,725

(1) The weighted average remaining contractual life for outstanding options at June 30, 2009 was 7.0 years.

(2) The aggregate intrinsic value of options outstanding at June 30, 2009 was approximately $3.2 million.

(3) The weighted average outstanding contractual life of exercisable options at June 30, 2009 is 6.2 years.

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

	Three Months Ended June 30,		Six Months Ended June 30,
	2009	2008	2009			2008
Expected dividend yield	—	—		0.6	%		0.4	%
Expected stock price volatility	—	—		36	%		33	%
Risk-free interest rate	—	—		2.2	%		2.6	%
Expected term (in years)	—	—		6.25			6.25
Fair value of stock options granted	—	—	$	4.89		$	11.75

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.

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The following table summarizes the activity of deferred and restricted units for the three and six months ended June 30, 2009 and 2008:

	Three Months Ended June 30,
	2009					2008
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Non-vested shares outstanding, beginning of period		11,670		$	24.29		20,270		$	14.31
Granted		4,805		$	15.60		1,523		$	49.26
Matured(1)		(3,941	)	$	15.26		(9,429	)	$	7.96
Forfeited		—			—		—			—
Non-vested shares outstanding, end of period(2)		12,534		$	23.80		12,364		$	23.46
Non-cash compensation expense recognized (in thousands)	$	26				$	24

	Six Months Ended June 30,
	2009					2008
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Non-vested shares outstanding, beginning of period		12,512		$	24.05		21,395		$	14.65
Granted		4,805		$	15.60		1,523		$	49.26
Matured(1)		(4,783	)	$	16.22		(10,554	)	$	9.33
Forfeited		—			—		—			—
Non-vested shares outstanding, end of period(2)		12,534		$	23.80		12,364		$	23.46
Non-cash compensation expense recognized (in thousands)	$	51				$	49

(1) The intrinsic values for phantom unit awards vested during the three months ended at June 30, 2009 and 2008 were $0.1 million and $0.5 million, respectively, and $0.1 million and $28,000 during the six months ended June 30, 2009 and 2008, respectively.

(2) The aggregate intrinsic value for phantom unit awards outstanding at June 30, 2009 was $0.2 million.

At June 30, 2009, the Company had unamortized compensation expense related to its unvested portion of the options and units of $7.2 million that the Company expects to recognize over the next four years.

Employee Stock Ownership Plan

The Company has an Employee Stock Ownership Plan (“ESOP”), which is a qualified non-contributory retirement plan, that 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. 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 is held by the ESOP trustee in a suspense account. On an annual basis, a portion of the common stock will be released from the suspense account and allocated to participating employees. As of June 30, 2009, there were 767,378 shares allocated to participants and 49,861 shares which are unallocated. All unallocated shares will be allocated to participating employees at the end of the ESOP’s fiscal

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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. The fair value of unearned ESOP shares was $0.9 million at June 30, 2009.

Supplemental Employment Retirement Plan (“SERP”)

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 three months ended June 30, 2009 and 2008, expense recognized with respect to this commitment was $0.2 million and $0.4 million, respectively, and $0.3 million and $0.7 million during the six months ended June 30, 2009 and 2008, respectively.

During the six months ended June 30, 2009, the Company funded $3.2 million of the outstanding liability with a financial institution in a rabbi trust, which is included in other assets on the Company’s consolidated balance sheet. As of June 30, 2009, the actuarial present value of the expected postretirement obligation due under this the SERP was $3.5 million, which is included in other long-term liabilities on the Company’s consolidated balance sheets.

The following table provides information about amounts recognized in the Company’s consolidated balance sheets at the dates indicated (in thousands):

	June 30, 2009			December 31, 2008
Other liabilities	$	(3,461	)	$	(3,209	)
Accumulated other comprehensive income		210			255
Deferred income tax asset		123			150
Net amount recognized	$	(3,128	)	$	(2,804	)

The estimated amount that will be amortized from accumulated other comprehensive income into expense for the year ended December 31, 2009 is $0.1 million.

AHD Long-Term Incentive Plan

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 June 30, 2009, AHD had 1,136,300 phantom units and unit options outstanding under the AHD LTIP, with 962,650 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

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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 June 30, 2009, 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 June 30, 2009, 44,425 units will vest within the following twelve months. All phantom units outstanding under the AHD LTIP at June 30, 2009 include DERs granted to the Participants by the AHD LTIP Committee. The amount paid with respect to AHD’s LTIP DERs was $0.1 million for the three months ended June 30, 2008, and $14,000 and $0.2 million for the six months ended June 30, 2009 and 2008, respectively. No DER payments were made during the three months ended June 30, 2009. These amounts were recorded as an adjustment of non-controlling interests on the Company’s consolidated balance sheet.

The following table sets forth the AHD LTIP phantom unit activity for the periods indicated:

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009			2008
Outstanding, beginning of period		181,300		225,475		226,300			220,825
Granted(1)		—		—		—			4,650
Matured		—		—		—			—
Forfeited		—		—		(45,000	)		—
Outstanding, end of period(2)		181,300		225,475		181,300			225,475
Non-cash compensation expense recognized (in thousands)	$	291	$	372	$	(17	)	$	738

(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 $32.28 for the six months ended June 30, 2008. There were no grants awarded for the three months ended June 30, 2009 and 2008 and the six months ended June 30, 2009.

(2) The aggregate intrinsic value for phantom unit awards outstanding at June 30, 2009 is $0.3 million.

At June 30, 2009, AHD had approximately $1.2 million of unrecognized compensation expense related to unvested phantom units outstanding under AHD’s LTIP based upon the fair value of the awards.

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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 June 30, 2009, 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 213,750 unit options outstanding under the AHD LTIP at June 30, 2009 that will vest within the following twelve months. The following table sets forth the AHD LTIP unit option activity for the periods indicated:

	Three Months Ended June 30,
	2009				2008
	Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price
Outstanding, beginning of period		955,000	$	20.54		1,215,000	$	22.56
Granted		—		—		—		—
Matured		—		—		—		—
Forfeited		—		—		—		—
Outstanding, end of period(1)(2)		955,000	$	20.54		1,215,000	$	22.56
Options exercisable, end of period		—		—		—		—
Non-cash compensation expense recognized (in thousands)	$	222			$	309

	Six Months Ended June 30,
	2009					2008
	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		100,000		$	3.24		—		—
Matured		—			—		—		—
Forfeited		(360,000	)	$	22.56		—		—
Outstanding, end of period(1)(2)		955,000		$	20.54		1,215,000	$	22.56
Options exercisable, end of period		—			—		—		—
Non-cash compensation expense recognized (in thousands)	$	(351	)			$	619

(1) The weighted average remaining contractual lives for outstanding options at June 30, 2009 were 7.6 years.

(2) There was no intrinsic value of options outstanding at June 30, 2009.

At June 30, 2009, AHD had approximately $0.9 million of unrecognized compensation expense related to unvested unit options outstanding under AHD’s LTIP based upon the fair value of the awards.

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AHD used the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. The following weighted average assumptions were used for the period indicated:

	Three and Six Months Ended June 30, 2009
Expected dividend yield	7.0	%
Expected stock price volatility	40	%
Risk-free interest rate	2.3	%
Expected term (in years)	6.9

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.

APL Phantom Units. 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 June 30, 2009, 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 June 30, 2009, 29,376 units will vest within the following twelve months. All phantom units outstanding under the APL LTIP at June 30, 2009 include DERs granted to the participants by the APL LTIP Committee. The amounts paid with respect to APL LTIP DERs were $11,000 and $0.2 million for the three months ended June 30, 2009 and 2008, respectively, and $0.1 million and $0.3 million for the six months ended June 30, 2009 and 2008, respectively. These amounts were recorded as reductions of non-controlling interest on the Company’s consolidated balance sheet.

The following table sets forth the APL LTIP phantom unit activity for the periods indicated:

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Outstanding, beginning of period		101,929			171,087			126,565			129,746
Granted(1)		500			345			2,000			54,296
Matured(2)		(25,208	)		(21,509	)		(35,094	)		(33,369	)
Forfeited		(500	)		—			(16,750	)		(750	)
Outstanding, end of period(3)		76,721			149,923			76,721			149,923
Non-cash compensation expense recognized (in thousands)	$	351		$	697		$	256		$	1,183

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(1) The weighted average prices 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, were $5.20 and $43.42 for awards granted for the three months ended June 30, 2009 and 2008, respectively, and $4.75 and $44.43 for awards granted for the six months ended June 30, 2009 and 2008, respectively.

(2) The intrinsic values for phantom unit awards exercised during the three months ended June 30, 2009 and 2008 were $0.1 million and $0.9 million, respectively, and $0.2 million and $1.4 million during the six months ended June 30, 2009 and 2008, respectively.

(3) The aggregate intrinsic value for phantom unit awards outstanding at June 30, 2009 was $0.6 million.

At June 30, 2009, APL had approximately $1.1 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIP based upon the fair value of the awards.

APL Unit Options.A unit option entitles a participant to receive a common unit of APL 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 APL’s common unit as determined by the APL LTIP Committee on the date of grant of the option. The APL LTIP Committee also shall determine how the exercise price may be paid by the Participant. The APL LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through June 30, 2009, unit options granted under APL’s LTIP generally will vest 25% on each of the next four anniversaries of 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 APL LTIP Committee, although no awards currently outstanding contain any such provision. Awards will automatically vest upon a change of control of APL, as defined in the APL’s LTIP. There were 25,000 unit options outstanding under APL’s LTIP at June 30, 2009 that will vest within the following twelve months. The following table sets forth the APL LTIP unit option activity for the periods indicated:

	Three Months Ended June 30,
	2009				2008
	Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options	Weighted Average Exercise Price
Outstanding, beginning of period		100,000	$	6.24	—	—
Granted		—		—	—	—
Matured		—		—	—	—
Forfeited		—		—	—	—
Outstanding, end of period(1)(2)		100,000	$	6.24	—	—
Options exercisable, end of period		—		—	—	—
Weighted average fair value of unit options per unit granted during the period		100,000	$	0.14	—	—
Non-cash compensation expense recognized (in thousands)	$	2			—

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	Six Months Ended June 30,
	2009				2008
	Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options	Weighted Average Exercise Price
Outstanding, beginning of period		—		—	—	—
Granted		100,000	$	6.24	—	—
Matured		—		—	—	—
Forfeited		—		—	—	—
Outstanding, end of period(1)(2)		100,000	$	6.24	—	—
Options exercisable, end of period		—		—	—	—
Weighted average fair value of unit options per unit granted during the period		100,000	$	0.14	—	—
Non-cash compensation expense recognized (in thousands)	$	4			—

(1) The weighted average remaining contractual life for outstanding options at June 30, 2009 was 9.5 years.

(2) There was $0.2 million aggregate intrinsic value of options outstanding at June 30, 2009.

At June 30, 2009, APL had approximately $10,000 of unrecognized compensation expense related to unvested unit options outstanding under the APL’s LTIP based upon the fair value of the awards.

APL used the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. The following weighted average assumptions were used for the period indicated:

	Three & Six Months Ended June 30, 2009
Expected dividend yield	11.0	%
Expected stock price volatility	20	%
Risk-free interest rate	2.2	%
Expected term (in years)	6.3

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 to be issued under the incentive compensation agreements was determined principally by the financial performance of certain APL assets during the year ended December 31, 2008 and the market value of APL’s common units at December 31, 2008. APL’s 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.

As of December 31, 2008, APL recognized in full within its consolidated statements of operations the compensation expense associated with the vesting of awards issued under its incentive compensation agreements, therefore no compensation expense was recognized during the three and six months ended June 30, 2009. APL recognized compensation expense of $0.5 million and a reduction of compensation expense of $2.8 million for

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the three and six months ended June 30, 2008 related to the vesting of awards under its incentive compensation agreements. The non-cash compensation expense adjustments for the three and six months ended June 30, 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 June 30, 2008 when compared with the common unit market price at earlier periods and adjustments based upon the achievement of actual financial performance targets through June 30, 2008. APL follows SFAS No. 123(R) and recognized compensation expense related to these awards based upon the fair value method. During the six months ended June 30, 2009, APL issued 348,620 common units to the certain key employees covered under APL’s incentive compensation agreements. No additional common units will be issued with regard to these agreements.

APL Executive Incentive Plan

In June 2009, APL adopted an executive incentive plan (the “APL Plan”), which provides cash incentive awards to certain employees of APL, but not “Named Executive Officers” of APL, as defined under Securities and Exchange Commission regulations (the “APL Plan Participants”). The APL Plan is administered by a committee (the “APL Plan Committee”) appointed by APL’s chief executive officer. Under the APL Plan, cash bonus units (“Bonus Unit”) may be awarded to the APL Plan Participants at the discretion of the APL Plan Committee. A Bonus Unit entitles an APL Plan Participant to receive the cash equivalent of the then-fair market value of an APL common limited partner unit, without payment of an exercise price, upon vesting of the Bonus Unit. The APL Plan Committee will determine the vesting period for Bonus Units. Through June 30, 2009, Bonus Units granted under the APL Plan vest ratably over a three year period from the date of grant. Awards under the APL Plan will automatically vest upon a change of control of APL, as defined in the APL Plan, and vesting will terminate upon termination of employment. During the three and six months ended June 30, 2009, the APL Plan Committee granted 325,000 Bonus Units to APL Plan Participants under the APL Plan. Of the Bonus Units outstanding under the APL Plan at June 30, 2009, 107,250 Bonus Units will vest within the following twelve months. APL follows SFAS No. 123(R) and recognized compensation expense related to these awards based upon the fair value. During the three and six months ended June 30, 2009, the Company recognized $0.1 million of compensation expense within general and administrative expense on the Company’s consolidated statements of operations with respect to the vesting of these awards. At June 30, 2009, the Company has recognized $0.1 million within accrued liabilities on its consolidated balance sheet with regard to the awards, which represents their fair value at June 30, 2009.

Atlas Energy Resources, LLC Long-Term Incentive Plan

ATN has 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 LTIP is administered by ATN’s compensation committee, which may grant awards of restricted stock units, phantom units or unit options. Awards for a total of 3,742,000 common units may be granted under the LTIP. Awards granted after 2006 vest 25% after three years and 100% upon the four-year anniversary of grant, except for awards of 1,500 units to board members which vest 25% per year over four years. Awards granted in 2006 vest 25% per year over four years. Upon termination of service by a grantee, all unvested awards are forfeited. A restricted stock or phantom unit entitles a grantee to receive a common unit of ATN upon vesting of the unit or, at the discretion of ATN’s compensation committee, cash equivalent to the then fair market value of a common unit of ATN. In tandem with phantom unit grants, ATN’s compensation committee may grant a distribution equivalent right (“DER”), which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions ATN makes on a common unit during the period such phantom unit is outstanding.

Restricted Stock and Phantom Units. Under the ATN LTIP, 23,523 and 26,375 units of restricted stock and phantom units were awarded during the six months ended June 30, 2009 and 2008, 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.

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The following table summarizes the activity of restricted stock and phantom units for the six months ended June 30, 2009:

	Units		Weighted Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2008	768,829		$	23.86
Granted	23,523			14.50
Vested	(13,073	)		21.70
Forfeited	(8,000	)		20.78
Non-vested shares outstanding at June 30, 2009	771,279		$	23.65

Unit Options. There were no unit options granted during the six months ended June 30, 2009. During the six months ended June 30, 2008, 14,000 unit options 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. The following table sets forth option activity for the six months ended June 30, 2009:

	Units		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding at December 31, 2008	1,902,902		$	24.17
Granted	—			—
Exercised	—			—
Forfeited or expired	(7,500	)		23.06
Outstanding at June 30, 2009	1,895,402		$	24.18	7.4	$	0
Options exercisable at June 30, 2009	280,314		$	21.00	6.8
Available for grant at June 30, 2009	1,038,063

The following tables summarize information about unit options outstanding and exercisable at June 30, 2009:

	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	1,647,302	7.4	$	22.59	280,314	$	21.00
$30.24 - 35.00	240,600	8.0	$	34.53	—		—
$37.79 and above	7,500	8.5	$	39.79	—		—
	1,895,402	7.4	$	24.18	280,314	$	21.00

ATN recognized $1.5 million and $1.3 million in compensation expense related to restricted stock units, phantom units and unit options for the three months ended June 30, 2009 and 2008, respectively. ATN recognized $3.0 million and $2.7 million in related compensation expense for the six months ended June 30, 2009 and 2008, respectively. ATN paid $0.3 million with respect to its ATN LTIP DERs for the three months ended June 30, 2008, and $0.4 million and $0.7 million for the six months ended June 30, 2009 and 2008, respectively. No payment was made with respect to ATN’s LTIP DERs for the three months ending June 30, 2009. These amounts were recorded as a reduction of non-controlling interests’ equity on the Company’s

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consolidated balance sheet. At June 30, 2009, ATN had approximately $10.9 million of unrecognized compensation expense related to the unvested portion of the restricted stock units, phantom units and options.

NOTE 18 — OPERATING SEGMENT INFORMATION

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):

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008(c)			2009(c)			2008(c)
Gas and oil production
Revenues(a)	$	69,979		$	78,956		$	141,922		$	155,182
Costs and expenses		(9,803	)		(12,379	)		(21,089	)		(23,047	)
Segment profit	$	60,176		$	66,577		$	120,833		$	132,135
Well construction and completion
Revenues	$	63,367		$	122,341		$	175,735		$	226,479
Costs and expenses		(53,701	)		(106,384	)		(149,098	)		(196,939	)
Segment profit	$	9,666		$	15,957		$	26,637		$	29,540
Atlas Pipeline(c)
Revenues(b)	$	162,088		$	116,538		$	321,348		$	392,303
Revenues — affiliates		6,617			11,523			16,766			20,747
Equity income in joint venture		710			—			710			—
Costs and expenses		(146,594	)		(367,187	)		(298,494	)		(658,262	)
Segment profit (loss)	$	22,821		$	(239,126	)	$	40,330		$	(245,212	)
Other(d)
Revenues	$	6,253		$	4,735		$	9,773		$	9,736
Costs and expenses		(5,889	)		(2,783	)		(8,940	)		(5,316	)
Segment profit	$	364		$	1,952		$	833		$	4,420
Reconciliation of segment profit (loss) to net income (loss) before income tax provision (benefit)
Segment profit (loss)
Gas and oil production	$	60,176		$	66,577		$	120,833		$	132,135
Well construction and completion		9,666			15,957			26,637			29,540
Atlas Pipeline		22,821			(239,126	)		40,330			(245,212	)
Other(d)		364			1,952			833			4,420
Total segment profit (loss)		93,027			(154,640	)		188,633			(79,117	)
Gain on sale of APL’s Appalachia system assets		105,691			—			105,691			—
General and administrative expenses		(21,577	)		(24,884	)		(48,991	)		(45,511	)
Net expense reimbursement — affiliate		(80	)		(184	)		(562	)		(434	)
Depreciation, depletion and amortization		(50,272	)		(43,359	)		(100,967	)		(85,214	)
Interest expense(e)		(41,948	)		(34,739	)		(76,568	)		(69,207	)
Other income (loss) — net		1,254			5,995			6,135			8,024
Income (loss) from continuing operations before income tax provision (benefit)		86,095			(251,811	)		73,371			(271,459	)

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	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008(c)		2009(c)		2008(c)
Capital expenditures
Gas and oil production	$	30,769	$	79,340	$	80,386	$	133,814
Well construction and completion		—		—		—		—
Atlas Pipeline		58,299		66,181		130,494		142,054
Corporate and other		8,437		713		16,027		1,856
Total capital expenditures	$	97,505	$	146,234	$	226,907	$	277,724

	June 30, 2009		December 31, 2008(c)
Balance sheet
Goodwill
Gas and oil production	$	21,527	$	21,527
Well construction and completion		13,639		13,639
Atlas Pipeline		—		—
	$	35,166	$	35,166
Total assets
Gas and oil production	$	2,229,804	$	2,189,931
Well construction and completion		13,580		16,399
Atlas Pipeline(c)		2,169,644		2,157,590
Discontinued operations		—		255,606
Corporate and other		168,338		226,355
	$	4,581,366	$	4,845,881

(a) Includes losses of $0.5 million and $5.0 million on mark-to-market derivatives for three months ended June 30, 2009 and 2008, respectively, and losses of $2.1 million and $7.9 million on mark-to-market derivatives for six months ended June 30, 2009 and 2008, respectively.

(b) Includes losses of $18.6 million and $316.1 million on mark-to-market derivatives for three months ended June 30, 2009 and 2008, respectively, and losses of $18.3 million and $404.8 million on mark-to-market derivatives for six months ended June 30, 2009 and 2008, respectively.

(c) Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system (see Note 4).

(d) Includes revenues and expenses from well services, transportation and administration and oversight that do not meet the quantitative threshold for reporting segment information.

(e) The Company notes that interest expense has not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented.

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.

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NOTE 19 — SUBSEQUENT EVENTS

On July 20, 2009, ATN entered into certain natural gas derivative contracts for calendar 2013 production volume of 220,000 MMbtu per month with an average fixed price of $6.90 per MMbtu.

On July 16, 2009, ATN issued $200.0 million of 12.125% senior unsecured notes (“12.125% Senior Notes”) due 2017 at 98.116% of par value to yield 12.5% at maturity. ATN used the net proceeds from the issuance of approximately $191.7 million, net of underwriting fees of $4.5 million, to repay outstanding borrowings under its revolving credit facility. Under the terms of ATN’s credit facility (see Note 8), the credit facility borrowing base is automatically reduced by 25% of the stated principal amount of any senior unsecured notes offering. As such, the borrowing base of ATN’s credit facility was reduced by $50.0 million to $600.0 million upon the issuance of the 12.125% Senior Notes. Interest on the 12.125% Senior Notes is payable semi-annually in arrears on February 1 and August 1 of each year. The 12.125% Senior Notes are redeemable at any time at certain redemption prices, together with accrued interest at the date of redemption. In addition, before August 1, 2012, ATN may redeem up to 35% of the aggregate principal amount of the 12.125% Senior Notes with the proceeds of certain equity offerings at a stated redemption price of 112.125% of the principal, plus accrued interest. The 12.125% Senior Notes are junior in right of payment to ATN’s secured debt, including its obligations under its revolving credit facility. The indenture governing the 12.125% 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.

On July 13, 2009, APL sold a natural gas processing facility and a one-third undivided interest in other associated assets located in its Mid-Continent operating segment for approximately $22.6 million in cash. The facility was sold to Penn Virginia Resource Partners, L.P. (NYSE: PVR), who will provide natural gas volumes to the facility and reimburse APL for its proportionate share of the operating expenses. APL will continue to operate the facility. APL used the proceeds from this transaction to reduce outstanding borrowings under its senior secured credit facility.

On July 10, 2009, ATN received the requisite consent from its lenders to amend its revolving credit facility to permit the merger with the Company. The material terms of the amendment are:

• The merger with the Company will be permitted;

• Restrictions on ATN’s ability to make payments with respect to its equity interest will be revised to permit it to make distributions to the Company in an amount equal to the income tax liability at the highest marginal rate attributable to ATN’s net income. In addition, ATN will be permitted to make distributions to the Company of up to $40.0 million per year and, to the extent that it distributes less than that amount in any year, may carry over up to $20.0 million for use in the next year; and

• The definition of change of control will be revised to include a change of control of the Company.

The amendment will become effective upon consummation of the merger.

On July 7, 2009, APL received an additional $2.5 million in cash upon the delivery of audited financial statements for the NOARK system assets to Spectra in connection with the completion of APL’s sale of its NOARK gas gathering and interstate pipeline system to Spectra for net proceeds of $292.0 million in cash, net of working capital adjustments (see Note 4).

F-124

Annex A

AGREEMENT AND PLAN OF MERGER

by and among

Atlas Energy Resources, LLC,

Atlas America, Inc.,

Atlas Energy Management, Inc.

and

Merger Sub, as defined herein

Dated as of April 27, 2009

TABLE OF CONTENTS

		Page
Article I              CERTAIN DEFINITIONS		A-1
Section 1.1	Certain Definitions	A-1
Article II            THE MERGER; EFFECTS OF THE MERGER		A-6
Section 2.1	Formation of Merger Sub; Accession	A-6
Section 2.2	The Merger	A-6
Section 2.3	Closing	A-7
Article III          MERGER CONSIDERATION; EXCHANGE PROCEDURES		A-7
Section 3.1	Merger Consideration	A-7
Section 3.2	Exchange of Certificates	A-8
Section 3.3	Rights As Unitholders; Unit Transfers	A-10
Section 3.4	Anti-Dilution Provisions	A-10
Section 3.5	Options, Phantom Units and Restricted Units	A-10
Article IV          REPRESENTATIONS AND WARRANTIES OF ATN		A-11
Section 4.1	Organization and Qualification	A-11
Section 4.2	Subsidiaries	A-12
Section 4.3	Capitalization	A-12
Section 4.4	Authority; Due Authorization; Binding Agreement; Approval	A-13
Section 4.5	ATN Board Recommendation; Opinion of ATN Financial Advisor	A-13
Section 4.6	No Violation; Consents	A-14
Section 4.7	Compliance	A-14
Section 4.8	SEC Filings; Financial Statements	A-15
Section 4.9	No Undisclosed Liabilities	A-15
Section 4.10	Absence of Certain Changes or Events	A-15
Section 4.11	Litigation	A-15
Section 4.12	Proxy Statement	A-15
Section 4.13	Taxes	A-16
Section 4.14	Brokers; Transaction Fees	A-17
Section 4.15	Quarterly Distribution	A-17
Article V            REPRESENTATIONS AND WARRANTIES OF PARENT		A-17
Section 5.1	Organization and Qualification	A-17
Section 5.2	Subsidiaries	A-18
Section 5.3	Capitalization	A-18
Section 5.4	Authority; Due Authorization; Binding Agreement	A-19
Section 5.5	Parent Board Recommendation; Opinion of Parent Financial Advisor	A-19
Section 5.6	No Violation; Consents	A-19
Section 5.7	Compliance	A-20
Section 5.8	SEC Filings; Financial Statements	A-20
Section 5.9	No Undisclosed Liabilities	A-21
Section 5.10	Absence of Certain Changes or Events	A-21
Section 5.11	Litigation	A-21
Section 5.12	Proxy Statement	A-21
Section 5.13	Taxes	A-21
Section 5.14	Commitments	A-22
Section 5.15	Brokers	A-22
Section 5.16	Representations Regarding Merger Sub	A-22
Section 5.17	Representations of Atlas Energy Management	A-22

A-i

TABLE OF CONTENTS

(continued)

		Page
Article VI         ACTIONS PENDING MERGER		A-23
Section 6.1	Conduct of ATN Business	A-23
Section 6.2	Conduct of Parent Business	A-24
Article VII       COVENANTS		A-25
Section 7.1	Reasonable Best Efforts	A-25
Section 7.2	Equityholder Approvals	A-25
Section 7.3	Registration Statement	A-26
Section 7.4	Press Releases	A-27
Section 7.5	Access; Information	A-27
Section 7.6	Common Stock Listed	A-28
Section 7.7	Third Party Approvals	A-28
Section 7.8	Indemnification; Directors’ and Officers’ Insurance	A-28
Section 7.9	Comfort Letters	A-30
Section 7.10	Rule 16b-3	A-30
Section 7.11	Board Membership	A-31
Section 7.12	Name Change	A-31
Article VIII      CONDITIONS TO CONSUMMATION OF THE MERGER		A-31
Section 8.1	Parent Stockholder Approval	A-31
Section 8.2	ATN Equityholder Approval	A-31
Section 8.3	Amendment of the ATN Credit Agreement	A-31
Section 8.4	Governmental Approvals	A-31
Section 8.5	No Injunction	A-31
Section 8.6	Representations, Warranties and Covenants of Parent and Merger Sub	A-32
Section 8.7	Representations, Warranties and Covenants of ATN	A-32
Section 8.8	Effective Registration Statement	A-32
Section 8.9	Amendment of Parent Certificate of Incorporation; NASDAQ Listing	A-32
Section 8.10	Resignation of the ATN Board	A-33
Article IX         TERMINATION		A-33
Section 9.1	Termination	A-33
Section 9.2	Effect of Termination	A-34
Article X           MISCELLANEOUS		A-34
Section 10.1	Fees and Expenses	A-34
Section 10.2	Waiver; Amendment	A-34
Section 10.3	Counterparts	A-34
Section 10.4	Governing Law	A-34
Section 10.5	Notices	A-35
Section 10.6	Entire Understanding; No Third Party Beneficiaries	A-36
Section 10.7	Severability	A-36
Section 10.8	Headings	A-36
Section 10.9	Jurisdiction	A-36
Section 10.10	Waiver of Jury Trial	A-36
Section 10.11	Specific Performance	A-36
Section 10.12	Scope of Representations and Warranties	A-36
Section 10.13	Survival	A-37
Section 10.14	Confidentiality	A-37
Section 10.15	Interpretation	A-37

A-ii

AGREEMENT AND PLAN OF MERGER

This AGREEMENT AND PLAN OF MERGER, dated as of April 27, 2009 (this “Agreement”), is entered into by and among ATLAS ENERGY RESOURCES, LLC, a Delaware limited liability company (“ATN”), ATLAS AMERICA, INC., a Delaware corporation (“Parent”), ATLAS ENERGY MANAGEMENT, INC., a Delaware corporation (“Atlas Energy Management”), and, from and after its accession to this Agreement in accordance with Section 2.1(b), the Delaware limited liability company to be formed as a wholly owned subsidiary of Parent (“Merger Sub”).

WITNESSETH:

WHEREAS, the Board of Directors of Parent (the “Parent Board”), has determined that this Agreement and the transactions contemplated hereby are advisable and in the best interests of Parent and its stockholders, including consummating the business combination provided for in this Agreement, pursuant to which Merger Sub will, subject to the terms and conditions set forth herein, merge with and into ATN (the “Merger”), with ATN surviving, such that following the Merger, ATN will be a wholly owned subsidiary of Parent; and

WHEREAS, the Parent Board has authorized Parent to consent to the adoption of this Agreement by Merger Sub in accordance with Section 2.1(b); and

WHEREAS, the ATN Special Committee (as defined herein), the members of which constitute a majority of the members of the ATN Conflicts Committee, has considered the transactions contemplated by this Agreement and, at a meeting duly called and held, has, by unanimous vote of all of its members, determined that this Agreement and the transactions contemplated hereby are advisable, fair and reasonable to and in the best interests of the Unaffiliated Unitholders and ATN, and resolved to recommend that the full ATN Board (as defined below) adopt this Agreement, approve the transactions contemplated hereby, and recommend adoption and approval by the ATN Unitholders; and

WHEREAS, the Board of Directors of ATN (the “ATN Board”) has considered this Agreement and the transactions contemplated hereby and, at a meeting duly called and held, has, upon the recommendation of the ATN Special Committee and as more particularly described in Section 4.5(a), (i) determined that this Agreement and the transactions contemplated hereby are advisable, fair and reasonable to and in the best interests of the Unaffiliated Unitholders and ATN and (ii) approved and adopted this Agreement and determined to recommend its adoption and approval by the ATN Unitholders; and

WHEREAS, the parties desire to make certain representations, warranties and agreements in connection with the Merger and also to set forth certain terms and conditions to the Merger.

NOW, THEREFORE, in consideration of the mutual covenants, representations, warranties and agreements contained herein, and intending to be legally bound hereby, the parties hereto agree as follows:

ARTICLE I

CERTAIN DEFINITIONS

Section 1.1Certain Definitions. As used in this Agreement, the following terms shall have the meanings set forth below:

“Affiliate” shall mean, with respect to any Person, those other Persons that, directly or indirectly, control or are controlled by, or are under common control with, such Person; provided, however, that, for purposes of this Agreement, ATN and its Subsidiaries shall not be considered Affiliates of Parent and Parent and its Subsidiaries shall not be considered Affiliates of ATN, unless otherwise expressly stated herein.

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“Agreement” shall have the meaning set forth in the introductory paragraph to this Agreement.

“Amended Operating Agreement” shall have the meaning set forth in Section 2.2(c).

“Atlas Energy Management” shall have the meaning set forth in the introductory paragraph of this Agreement.

“ATN” shall have the meaning set forth in the introductory paragraph of this Agreement.

“ATN Board” shall have the meaning set forth in the recitals to this Agreement.

“ATN Change in Recommendation” shall have the meaning set forth in Section 7.2(a).

“ATN Common Units” shall mean the common units representing membership interests of ATN having the rights and obligations specified with respect to ATN Common Units in the Operating Agreement.

“ATN Conflicts Committee” shall mean the “Conflicts Committee” as defined in the Operating Agreement.

“ATN Credit Agreement” shall mean the Credit Agreement, dated as of June 29, 2007, and the Loan Documents (as defined therein), as may be amended from time to time, among ATN, as Parent Guarantor, Atlas Energy Operating Company, LLC, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, Wachovia Bank, National Association, as Syndication Agent, and Bank of America, N.A., BNP Paribas, Royal Bank of Canada, and UBS AG, Stamford Branch, as Co-Documentation Agents, and the lenders party thereto.

“ATN Director Designees” shall have the meaning set forth in Section 7.11.

“ATN Disclosure Schedule” shall mean the Disclosure Schedule delivered by ATN pursuant to Article IV.

“ATN Financial Advisor” shall have the meaning set forth in Section 4.5(b).

“ATN Long-Term Incentive Plan” shall mean the Amended and Restated Atlas Energy Resources Long-Term Incentive Plan, amended and restated as of January 14, 2009.

“ATN Material Adverse Effect” shall have the meaning set forth in Section 4.1.

“ATN Meeting” shall have the meaning set forth in Section 7.2(a).

“ATN Permits” shall have the meaning set forth in Section 4.7(b).

“ATN Phantom Units” shall mean the phantom (notional) ATN Common Units granted under the ATN Long-Term Incentive Plan.

“ATN Recommendation” shall have the meaning set forth in Section 7.2(a).

“ATN Restricted Units” shall mean ATN Common Units that have been granted to employees, directors and consultants of ATN or its Subsidiaries under the ATN Long-Term Incentive Plan and are subject to a “substantial risk of forfeiture” within the meaning of Section 83 of the Code.

“ATN SEC Reports” shall have the meaning set forth in Section 4.8(a).

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“ATN Special Committee” shall mean the Special Committee of the ATN Board, consisting solely of independent directors, which directors are also independent of Parent, formed to consider, among other things, the transactions contemplated by this Agreement.

“ATN Unit Options” shall mean all employee and director options to purchase ATN Common Units pursuant to awards granted under the ATN Long-Term Incentive Plan.

“ATN Unitholder Approval” shall have the meaning set forth in Section 8.2.

“ATN Unitholders” shall mean the holders of ATN Common Units and the holders of the Class A Units, taken together.

“Business Day” shall mean any day which is not a Saturday, Sunday or other day on which banks are authorized or required to be closed in the City of New York.

“Certificate” shall have the meaning set forth in Section 3.1(e).

“Certificate of Merger” shall have the meaning set forth in Section 2.2(b).

“Charter Amendment” shall have the meaning set forth in Section 5.4(b).

“Claim” shall have the meaning set forth in Section 7.8(a).

“Class A Units” shall mean the Class A units representing membership interests of ATN having the rights and obligations specified with respect to such Class A Units in the Operating Agreement.

“Closing” shall have the meaning set forth in Section 2.3.

“Closing Date” shall have the meaning set forth in Section 2.3.

“Code” shall mean the Internal Revenue Code of 1986, as amended.

“Consent” shall have the meaning set forth in Section 7.7(b).

“Delaware LLC Act” shall mean the Delaware Limited Liability Company Act, as amended.

“DGCL” shall mean the Delaware General Corporation Law, as amended.

“Effective Time” shall have the meaning set forth in Section 2.2(b).

“ERISA” shall mean the Employee Retirement Income Security Act of 1974, as amended.

“Exchange Act” shall mean the Securities Exchange Act of 1934, as amended, and the rules and regulations thereunder.

“Exchange Agent” shall have the meaning set forth in Section 3.2(a). “Exchange Agent Agreement” shall have the meaning set forth in Section 3.2(a).

“Exchange Fund” shall have the meaning set forth in Section 3.2(a).

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“Exchange Ratio” shall have the meaning set forth in Section 3.1(a).

“GAAP” shall have the meaning set forth in Section 4.1.

“Governmental Authority” shall mean any national, state, local, county, parish or municipal government, domestic or foreign, any agency, board, bureau, commission, court, tribunal, subdivision, department or other governmental or regulatory authority or instrumentality (including any self-regulatory organization), or any arbitrator in any case that has jurisdiction over ATN, Parent or Merger Sub, as the case may be, or any of their respective properties or assets.

“HSR Act” shall mean the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and the rules and regulations promulgated thereunder.

“Indemnification Expenses” shall have the meaning set forth in Section 7.8(a).

“Indemnified Party” shall have the meaning set forth in Section 7.8(a).

“IRS” shall have the meaning set forth in Section 4.13(c).

“Joint Proxy Statement” shall have the meaning set forth in Section 7.3(a).

“Laws” shall mean federal, state, local or foreign laws, statutes, ordinances, rules, regulations, judgments, orders, injunctions, decrees, arbitration awards, agency requirements, licenses and permits of all Governmental Authorities.

“Lien” shall mean any charge, mortgage, pledge, security interest, restriction, claim, lien, or encumbrance.

“Meeting” shall have the meaning set forth in Section 7.2(b).

“Merger” shall have the meaning set forth in the recitals to this Agreement.

“Merger Consideration” shall have the meaning set forth in Section 3.1(a).

“Merger Sub” shall have the meaning set forth in the introductory paragraph in this Agreement.

“MIIs” shall mean the Management Incentive Interests representing membership interests of ATN having the rights and obligations specified with respect to the Management Incentive Interests in the Operating Agreement.

“NASDAQ” shall mean NASDAQ Stock Market LLC.

“NYSE” shall mean the New York Stock Exchange.

“Operating Agreement” shall mean the Amended and Restated Operating Agreement of ATN, dated as of December 18, 2006, as amended.

“Parent” shall have the meaning set forth in the introductory paragraph to this Agreement.

“Parent Board” shall have the meaning set forth in the recitals to this Agreement.

“Parent Change in Recommendation” shall have the meaning set forth in Section 7.2(b).

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“Parent Common Stock” shall mean the Common Stock, par value $0.01 per share, of Parent.

“Parent Disclosure Schedule” shall mean the Disclosure Schedule delivered by Parent pursuant to Article V.

“Parent Financial Advisor” shall have the meaning set forth in Section 5.5(b).

“Parent Material Adverse Effect” shall have the meaning set forth in Section 5.1.

“Parent Meeting” shall have the meaning set forth in Section 7.2(b).

“Parent Permits” shall have the meaning set forth in Section 5.7(b).

“Parent Preferred Stock” shall have the meaning set forth in Section 5.3(a).

“Parent Recommendation” shall have the meaning set forth in Section 7.2(b).

“Parent Restricted Stock” shall mean shares of Parent Common Stock that have been granted to employees, directors and consultants of Parent or its Subsidiaries under an employee benefit plan and are subject to a “substantial risk of forfeiture” within the meaning of Section 83 of the Code.

“Parent SEC Reports” shall have the meaning set forth in Section 5.8(a).

“Parent Stockholder Approval” shall have the meaning set forth in Section 8.1.

“Person” or “person” shall mean any individual, bank, corporation, partnership, limited liability company, association, joint-stock company, business trust or unincorporated organization.

“Registration Statement” shall have the meaning set forth in Section 7.3(a).

“Representatives” shall mean with respect to a Person, its directors, officers, employees, agents and representatives, including any investment banker, financial advisor, attorney, accountant or other advisor, agent or representative.

“Rights” shall mean, with respect to any Person, securities or obligations convertible into or exchangeable for, or giving any person any right to subscribe for or acquire, or any options, calls or commitments relating to, equity securities of such Person.

“SEC” shall mean the U.S. Securities and Exchange Commission.

“Section 6.2 Subsidiaries” shall have the meaning set forth in Section 6.2.

“Securities Act” shall mean the Securities Act of 1933, as amended, and the rules and regulations thereunder.

“Stock Issuance” shall mean the issuance of shares of Parent Common Stock in the Merger pursuant to this Agreement.

“Subsidiary” shall have the meaning ascribed to such term in Rule 1-02 of Regulation S-X under the Securities Act; provided, however, that for purposes of this Agreement (other than in the definition of Parent Material Adverse Effect), ATN and its Subsidiaries shall not be deemed to be Subsidiaries of Parent.

“Surviving Entity” shall have the meaning set forth in Section 2.2(a).

A-5

“Takeover Law” shall mean any “fair price,” “moratorium,” “control share acquisition,” “business combination” or any other anti-takeover statute or similar statute enacted under state or federal Law.

“Taxes” shall mean all federal, state, local or foreign taxes, charges, levies or other assessments, including all net income, gross income, gross receipts, sales, use, ad valorem, goods and services, capital, transfer, franchise, profits, license, withholding, payroll, employment, employer health, excise, estimated, severance, stamp, occupation, property, transfer, real property transfer or other taxes, custom duties or other similar assessments of any kind whatsoever, together with any interest and any penalties, additions to tax or additional amounts imposed by any taxing authority.

“Tax Returns” shall have the meaning set forth in Section 4.13(a).

“Termination Date” shall have the meaning set forth in Section 9.1(b)(i).

“Treasury Units” shall mean ATN Common Units owned by ATN or any of its Subsidiaries at the Effective Time.

“Unaffiliated Unitholders” shall mean the holders of ATN Common Units, other than Parent and its Affiliates, and the officers and directors of Parent and the officers and directors of ATN.

ARTICLE II

THE MERGER; EFFECTS OF THE MERGER

Section 2.1Formation of Merger Sub; Accession.

(a) Reasonably promptly after the date hereof, and in any event within six (6) Business Days after the date hereof, Parent shall form Merger Sub. Parent shall own 100 percent of the outstanding equity interests of Merger Sub.

(b) Promptly after forming Merger Sub, (x) Parent, as the sole member of Merger Sub, shall approve and adopt this Agreement and (y) Parent shall cause Merger Sub to accede to this Agreement by executing a signature page to this Agreement, after which time Merger Sub shall be a party hereto for all purposes set forth herein. Notwithstanding any provision herein to the contrary, the obligations of Merger Sub to perform its covenants hereunder shall commence only at the time of its formation. Prior to the Effective Time, Parent shall take such actions as are reasonably necessary to cause the board of directors of Merger Sub to unanimously approve this Agreement and declare it advisable for Merger Sub to enter into this Agreement and consummate the transactions contemplated by this Agreement.

Section 2.2The Merger.

(a)The Surviving Entity. Subject to the terms and conditions of this Agreement, at the Effective Time, Merger Sub shall merge with and into ATN, the separate existence of Merger Sub shall cease and ATN shall survive and continue to exist as a Delaware limited liability company (ATN, as the surviving limited liability company in the Merger, sometimes being referred to herein as the “Surviving Entity”), such that following the Merger, ATN will be a wholly owned subsidiary of Parent.

(b)Effectiveness and Effects of the Merger. Subject to the satisfaction or waiver of the conditions set forth in Article VIII in accordance with this Agreement, the Merger shall become effective upon the later to occur of the filing in the office of the Secretary of State of the State of Delaware of a properly executed certificate of merger (the “Certificate of Merger”) or such later date and time as may be set forth in the Certificate of Merger (the “Effective Time”), in accordance with the Delaware LLC Act. The Merger shall have the effects prescribed in the Delaware LLC Act.

A-6

(c)Operating Agreement. At the Effective Time, the Operating Agreement will be amended to be substantially in such form as determined by Parent (the “Amended Operating Agreement”); provided that the provisions related to exculpation and indemnification shall remain the same as in effect as of the date of this Agreement in accordance with Section 7.8(c).

(d)Directors of the Surviving Entity. The individuals who are the directors of Merger Sub immediately prior to the Effective Time shall be the directors of the Surviving Entity as of the Effective Time, until their respective successors are duly elected or appointed and qualified or their earlier death, resignation or removal in accordance with the Amended Operating Agreement of the Surviving Entity.

(e)Officers of the Surviving Entity. The officers of ATN immediately prior to the Effective Time shall be the officers of the Surviving Entity as of the Effective Time, until their respective successors are duly elected or appointed and qualified or their earlier death, resignation or removal in accordance with the Amended Operating Agreement of the Surviving Entity.

(f)Partnership Status. Immediately following the Effective Time, ATN will continue to be a partnership for U.S. federal income tax purposes, and toward that end Parent will continue to hold the ATN Common Units and Atlas Energy Management will continue to hold the Class A Units and MIIs held by Parent and Atlas Energy Management, as applicable, immediately prior to the Effective Time, in each case subject to the terms and conditions of the Amended Operating Agreement.

Section 2.3Closing. Subject to the satisfaction or waiver of the conditions as set forth in Article VIII in accordance with this Agreement, the filing of the Certificate of Merger with the Delaware Secretary of State and the closing of the Merger and the other transactions contemplated hereby (the “Closing”) shall occur on (a) the third Business Day after the day on which all of the conditions set forth in Article VIII (other than those that by their nature are to be satisfied by actions taken at Closing, but subject to their satisfaction or waiver) shall have been satisfied or waived in accordance with the terms of this Agreement or (b) such other date to which the parties may agree in writing. The date on which the Closing occurs is referred to as the “Closing Date.” The Closing of the transactions contemplated by this Agreement shall take place at the offices of Wachtell, Lipton, Rosen & Katz, 51 West 52^nd Street, New York, New York 10019, at 10:00 a.m. local time on the Closing Date.

ARTICLE III

MERGER CONSIDERATION; EXCHANGE PROCEDURES

Section 3.1Merger Consideration. Subject to the provisions of this Agreement:

(a) By virtue of the Merger and without any action by Parent, at the Effective Time each ATN Common Unit issued and outstanding immediately prior to the Effective Time (other than Treasury Units and ATN Common Units held by Parent or its Subsidiaries (including Atlas Energy Management)), including ATN Restricted Units in accordance with Section 3.6(b), shall be converted into the right to receive 1.16 shares of Parent Common Stock (the “Exchange Ratio”). The number of shares of Parent Common Stock issued pursuant to this Section 3.1(a) shall be referred to herein as the “Merger Consideration.”

(b) By virtue of the Merger, all of the membership interests of Merger Sub outstanding immediately prior to the Effective Time shall be cancelled.

(c) By virtue of the Merger, each Treasury Unit outstanding immediately prior to the Effective Time shall cease to be outstanding and shall be cancelled without payment of any consideration therefor, and no shares of capital stock of Parent or other consideration shall be delivered in exchange therefore.

(d) Each Class A Unit and each MII held by Atlas Energy Management immediately prior to the Effective Time, and each ATN Common Unit held by Parent or its Subsidiaries immediately prior to the Effective Time will continue to be held by Atlas Energy Management and Parent or its Subsidiaries, as applicable, after the Effective Time.

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(e) All ATN Common Units (other than ATN Common Units held by Parent), when converted in the Merger, shall cease to be outstanding and shall automatically be canceled and cease to exist. Each holder of a certificate (a “Certificate”) previously representing any such ATN Common Units shall cease to have any rights with respect thereto, except the right to receive (i) the Merger Consideration and (ii) any cash to be paid in lieu of any fractional shares of Parent Common Stock in accordance with Section 3.2(d), in each case to be issued or paid in consideration therefor upon the surrender of such Certificates in accordance with Section 3.2.

Section 3.2Exchange of Certificates.

(a)Exchange Agent; Deposit of Consideration. Prior to the Effective Time, Parent shall appoint a commercial bank or trust company reasonably acceptable to ATN, pursuant to an agreement (the “Exchange Agent Agreement”) to act as exchange agent (the “Exchange Agent”) hereunder. At or prior to the Effective Time, Parent shall deposit or shall cause to be deposited the shares of Parent Common Stock to be issued as Merger Consideration with the Exchange Agent, for the benefit of the holders of ATN Common Units and which shall be used to make all deliveries of shares of Parent Common Stock as required by and pursuant to this Article III. Parent agrees to make available to the Exchange Agent, from time to time as needed, cash sufficient to make payments in lieu of any fractional shares of Parent Common Stock pursuant to Section 3.2(d). Any cash and shares of Parent Common Stock deposited with the Exchange Agent (including as payment for any fractional shares of Parent Common Stock in accordance with Section 3.2(d)) shall hereinafter be referred to as the “Exchange Fund.” The Exchange Agent shall, pursuant to irrevocable instructions delivered by Parent at or prior to the Effective Time, deliver the Merger Consideration contemplated to be paid for ATN Common Units pursuant to this Agreement, through the Merger, out of the Exchange Fund. Except as contemplated by this Section 3.2, the Exchange Fund shall not be used for any other purpose.

(b)Exchange Procedures. Promptly after the Effective Time, Parent shall instruct the Exchange Agent to mail to each record holder of Certificates (i) a letter of transmittal (which shall specify that delivery shall be effected, and risk of loss and title to the Certificates shall pass, only upon proper delivery of the Certificates to the Exchange Agent, and shall be in customary form and agreed to by Parent and ATN prior to the Effective Time) and (ii) instructions for use in effecting the surrender of the Certificates in exchange for the Merger Consideration payable in respect of the ATN Common Units represented by such Certificates. Promptly after the Effective Time, upon surrender of Certificates for cancellation to the Exchange Agent together with such letters of transmittal, properly completed and duly executed, and such other documents as may be required pursuant to such instructions, the holders of such Certificates shall be entitled to receive in exchange therefor (A) at Parent’s election either (i) certificate(s) evidencing shares of Parent Common Stock or (ii) evidence of shares in book-entry form representing, in the aggregate, the whole number of shares of Parent Common Stock that such holder has the right to receive pursuant to this Article III (after taking into account all ATN Common Units then held by such holder) and (B) a check in the amount equal the cash payable in lieu of any fractional shares of Parent Common Stock pursuant to Section 3.2(d). No interest shall be paid or accrued on any Merger Consideration, cash in lieu of fractional shares or on any unpaid dividends and distributions payable to holders of Certificates. In the event of a transfer of ownership of ATN Common Units that is not registered in the transfer records of ATN, the Merger Consideration payable in respect of such ATN Common Units may be paid to a transferee if the Certificate representing such ATN Common Units is presented to the Exchange Agent, accompanied by all documents required to evidence and effect such transfer and the Person requesting such exchange shall pay to the Exchange Agent in advance any transfer or other Taxes required by reason of the delivery of the Merger Consideration in any name other than that of the registered holder of the Certificate surrendered, or shall establish to the satisfaction of the Exchange Agent that such Taxes have been paid or are not payable. Until surrendered as contemplated by this Section 3.2, each Certificate shall be deemed at any time after the Effective Time to represent only the right to receive upon such surrender the Merger Consideration without interest payable in respect of the ATN Common Units represented by such Certificate and any distributions to which such holder is entitled pursuant to Section 3.3.

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(c)No Further Rights in ATN Common Units. The Merger Consideration delivered or issued, as the case may be, in accordance with the terms hereof (including any cash paid pursuant to Section 3.2(d) or Section 3.3) shall be deemed to have been issued in full satisfaction of all rights pertaining to such ATN Common Units.

(d)Fractional Shares of Parent Common Stock. No certificates or scrip of the shares of Parent Common Stock representing fractional shares of Parent Common Stock or book entry credit of the same (after aggregating all fractional shares of Parent Common Stock to be received by such holder) shall be issued upon the surrender for exchange of Certificates in the Merger, and such fractional interests will not entitle the owner thereof to vote or to have any rights as a holder of any shares of Parent Common Stock. Notwithstanding any other provision of this Agreement, each holder of ATN Common Units (including ATN Restricted Units) exchanged in the Merger who would otherwise have been entitled to receive a fraction of a share of Parent Common Stock (after taking into account all Certificates delivered by such holder) shall receive, in lieu thereof, cash (without interest and rounded up to the nearest whole cent) in an amount equal to the product of (i) the closing sale price of the shares of Parent Common Stock on NASDAQ as reported by The Wall Street Journal on the trading day immediately preceding the date on which the Effective Time shall occur and (ii) the fraction of a share of Parent Common Stock that such holder would otherwise be entitled to receive pursuant to this Article III. As promptly as practicable after the determination of the amount of cash, if any, to be paid to holders of fractional interests, the Exchange Agent shall so notify Parent, and it shall, or shall cause the Surviving Entity to, deposit such amount with the Exchange Agent and shall cause the Exchange Agent to forward payments to such holders of fractional interests subject to and in accordance with the terms hereof. No dividend or distribution with respect to Parent Common Stock shall be payable on or with respect to any fractional share and such fractional share interests shall not entitle the owner thereof to any rights of a shareholder of Parent.

(e)Termination of Exchange Fund with Respect to Merger. Any portion of the Exchange Fund constituting shares of Parent Common Stock that remains undistributed to the holders of ATN Common Units in the Merger after 180 days following the Effective Time shall be delivered to Parent upon demand and, from and after such delivery, any former holders of ATN Common Units who have not theretofore complied with this Article III shall thereafter look only to Parent for the Merger Consideration payable in the Merger in respect of such ATN Common Units, and any cash in lieu of fractional shares of Parent Common Stock to which they are entitled pursuant to Section 3.2(d), without any interest thereon. Any amounts remaining unclaimed by holders of ATN Common Units immediately prior to such time as such amounts would otherwise escheat to or become the property of any Governmental Authority shall, to the extent permitted by applicable Law, become the property of Parent or ATN, as the case may be, free and clear of any Liens, claims or interest of any Person previously entitled thereto.

(f)No Liability. None of Parent, ATN or the Surviving Entity shall be liable to any holder of ATN Common Units for any shares of Parent Common Stock (or distributions with respect thereto) or cash from the Exchange Fund delivered to a public official pursuant to any abandoned property, escheat or similar Law.

(g)Lost Certificates. If any Certificate shall have been lost, stolen or destroyed, upon the making of an affidavit of that fact by the Person claiming such Certificate to be lost, stolen or destroyed and, if required by ATN or Parent, the posting by such Person of a bond, in such reasonable amount as ATN or Parent may direct, as indemnity against any claim that may be made against it with respect to such Certificate, the Exchange Agent shall pay in exchange for such lost, stolen or destroyed Certificate the Merger Consideration payable in respect of the ATN Common Units represented by such lost, stolen or destroyed Certificate and any distributions to which the holders thereof are entitled pursuant to Section 3.3.

(h)Withholding. Each of ATN, Parent, the Surviving Entity and the Exchange Agent shall be entitled to deduct and withhold from the consideration otherwise payable pursuant to this Agreement to any holder of ATN Common Units such amounts as ATN, Parent, the Surviving Entity or the Exchange Agent is required to deduct and withhold under the Code or any provision of state, local, or foreign Tax Law, with

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respect to the making of such payment. To the extent that amounts are so withheld, such withheld amounts shall be treated for all purposes of this Agreement as having been paid to the holder of ATN Common Units in respect of whom such deduction and withholding was made by ATN, Parent, the Surviving Entity or the Exchange Agent, as the case may be.

Section 3.3Rights As Unitholders; Unit Transfers. From and after the Effective Time, holders of ATN Common Units shall cease to be, and shall have no rights as, members of ATN, and shall have no rights in respect of ATN Common Units, other than the right to receive (a) any dividend or other distribution with respect to such ATN Common Units with a record date occurring prior to the Effective Time that may have been declared or made by ATN on such ATN Common Units in accordance with the terms of this Agreement or prior to the date hereof and which remain unpaid at the Effective Time and (b) the consideration provided under this Article III. After the Effective Time, there shall be no transfers on the unit transfer books of the ATN Common Units.

Section 3.4Anti-Dilution Provisions. In the event of any subdivisions, reclassifications, recapitalizations, splits, combinations or dividends in the form of equity interests with respect to the Parent Common Stock or the ATN Common Units, the number of shares of Parent Common Stock to be issued in the Merger, the average closing sales prices of the shares of Parent Common Stock determined in accordance with Section 3.2(d) and the Exchange Ratio will be correspondingly adjusted.

Section 3.5Options, Phantom Units and Restricted Units.

(a) At the Effective Time, automatically and without any action on the part of the holder thereof, Parent will assume each outstanding ATN Unit Option, and such ATN Unit Option will become an option (i) to purchase that number of shares of Parent Common Stock (calculated on an aggregate basis and rounded down to the nearest whole share of Parent Common Stock) obtained by multiplying the number of ATN Common Units issuable upon the exercise of such ATN Unit Option by the Exchange Ratio, (ii) at an exercise price per share (calculated on an aggregate basis and rounded up to the nearest whole penny) equal to the per share exercise price of such ATN Unit Option divided by the Exchange Ratio, and (iii) otherwise upon the same terms and conditions as such outstanding ATN Unit Options; provided, however, that the exercise price and the number of shares purchasable pursuant to such ATN Unit Option and the terms and conditions of exercise of such ATN Unit Option will not be treated by Parent or ATN as the grant of a new stock right or a change in the form of payment within the meaning of Section 409A of the Code and the rules and regulations thereunder.

(b) At the Effective Time, each outstanding grant of ATN Phantom Units shall be assumed by Parent and converted into a grant of phantom units denominated in that number of shares of Parent Common Stock equal to the number of ATN Common Units to which such grant of ATN Phantom Units was subject at the time of such assumption multiplied by the Exchange Ratio. At the Effective Time, all outstanding ATN Restricted Units heretofore granted shall be converted pursuant to Section 3.1(a), at the Exchange Ratio, into Parent Restricted Stock. Any fractional share of Parent Restricted Stock, and any fractional Parent phantom unit, shall be rounded up to the nearest whole share of Parent Common Stock. Each share of Parent Common Stock and each Parent phantom unit in respect of which an ATN Restricted Unit or ATN Phantom Unit, respectively, was so assumed and converted shall be subject to, and shall vest upon, the terms and conditions that are the same as those of the applicable ATN Restricted Unit or ATN Phantom Unit. Promptly after the Effective Time, Parent will provide each holder of ATN Restricted Units and ATN Phantom Units with a notice describing the assumption and conversion of such awards.

(c) With the exception of those Persons who hold ATN Unit Options, ATN Restricted Units and ATN Phantom Units, no Person shall have any right under any plan, program, agreement or arrangement with respect to ATN Common Units, or for the issuance or grant of any right of any kind, contingent or accrued, to receive benefits or compensation measured by the value of a number of ATN Common Units at and after the Effective Time.

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(d) Parent will take all corporate actions necessary to reserve for issuance a sufficient number of shares of Parent Common Stock for delivery upon exercise of Parent Stock Options, and vesting of Parent phantom units, in respect of the ATN Unit Options and ATN Phantom Units that Parent assumes under Sections 3.6(a) and 3.6(b).

(e) On or prior to the 30th day following the Effective Time, Parent will file (or will have filed) a registration statement on Form S-8 (or any successor or other appropriate forms) with respect to the shares of Parent Common Stock subject to ATN Unit Options and will use its reasonable efforts to maintain the effectiveness of such registration statement (and maintain the current status of the prospectus or prospectuses contained therein) for as long as such options remain outstanding.

(f) Parent will either, at its option, (i) provide for the grant of assumed and converted equity compensation awards described above in this Section 3.6 under equity compensation plans of Parent, or (ii) assume, as of the Effective Time, the ATN Long-Term Incentive Plan, and provide for the grant or continuation of such awards thereunder. Upon assumption of such plans, such amendments thereto as may be required to reflect the Merger and the requirements of Section 3.6(a) will be deemed to have been made.

ARTICLE IV

REPRESENTATIONS AND WARRANTIES OF ATN

ATN hereby represents and warrants to Parent and Merger Sub that, except as otherwise set forth (i) in ATN’s Disclosure Schedules to this Agreement (the “ATN Disclosure Schedule”) (it being agreed that disclosure of any item in any section of the ATN Disclosure Schedule shall also be deemed to be disclosed with respect to any other section of this Article IV to which the relevance of such item is reasonably apparent on its face) or (ii) in the ATN SEC Reports (excluding any forward-looking statements included therein or any statements of a cautionary nature that are not historical facts in any risk factor section of such documents) filed with the SEC prior to the date of this Agreement:

Section 4.1Organization and Qualification. ATN is a limited liability company duly organized and validly existing in good standing under the Laws of the State of Delaware. ATN has the requisite limited liability power and authority to own or lease its properties and to carry on its business as it is now being conducted and is duly licensed or qualified to do business in each jurisdiction in which the nature of the business conducted by it or the character of the properties owned or leased by it makes such licensing or qualification necessary, except where the failure to be so licensed or qualified would not, individually or in the aggregate, have an ATN Material Adverse Effect (as defined below). When used in connection with ATN or any of its Subsidiaries, the term “ATN Material Adverse Effect” shall mean any state of facts, circumstance, change or effect that is materially adverse to the business, financial condition or results of operations of ATN and its Subsidiaries, taken as a whole, except that none of the following (or the effects thereof) will be deemed to constitute, and none of the following will be taken into account in determining whether there has been or if there is reasonably likely to be, an ATN Material Adverse Effect: (i) general economic conditions, changes in securities markets (including any disruption thereof), regulatory or political conditions, including any engagement in hostilities, whether or not pursuant to the declaration of a national emergency or war, the occurrence of any military or terrorist attack or a general economic recession, natural disasters or other force majeure events, in each case in the United States or elsewhere, except to the extent that such conditions, changes or events affect ATN in a materially disproportionate and adverse manner when compared to companies of similar size operating in the same industry or market as ATN; (ii) changes in or events or conditions generally affecting the oil and gas exploration and development industry (including changes in commodity prices and general market prices), except to the extent that such conditions, changes or events affect ATN in a materially disproportionate and adverse manner when compared to companies of similar size operating in the same industry or market as ATN; (iii) changes in Laws or U.S. generally accepted accounting principles (“GAAP”) or interpretations thereof, except to the extent that such changes affect ATN in a materially disproportionate and adverse manner when compared to companies of similar size operating in the same industry or market as ATN; (iv) the announcement or pendency of this Agreement, any

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actions taken in compliance with this Agreement or the consummation of the Merger; (v) any failure by ATN to meet estimates of revenues or earnings for any period ending after the date of this Agreement (provided that the underlying causes of any such failure may be considered in determining whether an ATN Material Adverse Effect has occurred); (vi) the downgrade in rating of any debt securities of ATN by Standard & Poor’s Rating Group, Moody’s Investor Services, Inc. or Fitch Ratings (provided that the underlying causes of any such downgrade may be considered in determining whether an ATN Material Adverse Effect has occurred); (vii) the taking of any action (or omitting to take any action) required or contemplated by this Agreement or the taking of any action (or omitting to take any action) that Parent, in its capacity as a party to this Agreement and not in any other capacity with respect to ATN or Atlas Energy Management, has requested or to which Parent has consented; or (viii) changes in the price or trading volume of the ATN Common Units (provided that the underlying causes of any such changes may be considered in determining whether an ATN Material Adverse Effect has occurred).

Section 4.2Subsidiaries. Each Subsidiary of ATN (i) is duly organized and validly existing under the Laws of its jurisdiction of organization, (ii) has the requisite corporate or other business entity power and authority to own or lease its properties and to carry on its business as it is now being conducted and (iii) is duly licensed or qualified to do business in each jurisdiction in which the nature of the business conducted by it or the character of the properties owned or leased by it makes such licensing or qualification necessary, in each case, except as would not, individually or in the aggregate, have an ATN Material Adverse Effect. Other than with respect to ATN’s Subsidiaries, ATN does not directly or indirectly own any equity interest in, or any interest convertible into or exchangeable or exercisable for, any equity interest in, any corporation, partnership, joint venture or other business entity, other than equity interests held for investment that are not, in the aggregate, material to ATN. All of ATN’s equity interests in its Subsidiaries, whether directly or indirectly owned, are held free and clear of any Lien (other than in favor of ATN or any of its Subsidiaries), no equity interests of any of ATN’s Subsidiaries are or may become required to be issued by reason of any Rights, there are no contracts, commitments, understandings or arrangements by which any of ATN’s Subsidiaries is or may be bound to sell or otherwise transfer any equity interests of any such Subsidiaries, there are no contracts, commitments, understandings, or arrangements relating to ATN’s rights to vote or to dispose of such equity interests, and all of the equity interests of each such Subsidiary held by ATN or its Subsidiaries are fully paid and nonassessable and are owned by ATN or its Subsidiaries free and clear of any Liens.

Section 4.3Capitalization.

(a) As of March 31, 2009, there were 63,381,249 ATN Common Units issued and outstanding (46,905 of which were ATN Restricted Units), and all of such ATN Common Units and the member interests represented thereby were duly authorized and validly issued in accordance with the Operating Agreement and are fully paid (to the extent required under the Operating Agreement) and nonassessable (except as such nonassessability may be affected by Sections 18-607 and 18-804 of the Delaware LLC Act). As of March 31, 2009, Atlas Energy Management owned 1,293,496 Class A Units, representing all of the issued and outstanding Class A Units and a 2% equity interest in ATN, and all of the MIIs, and such Class A Units and MIIs were duly authorized and validly issued in accordance with the Operating Agreement.

(b) As of the date hereof, there are no interests of ATN’s equity securities authorized and reserved for issuance, ATN does not have any Rights issued or outstanding with respect to its equity securities, and ATN does not have any commitment to authorize, issue or sell any such equity securities or Rights, except pursuant to this Agreement. Since December 31, 2008, ATN has not issued any interests of ATN’s equity securities or Rights in respect thereof or reserved any interests of ATN’s equity securities for such purposes except pursuant to plans or commitments set forth in Section 4.3(b) of the ATN Disclosure Schedule. There are no outstanding contractual obligations of ATN or any of its Subsidiaries to repurchase, redeem or otherwise acquire any equity interests of ATN or any of its Subsidiaries.

(c) The number of ATN Common Units that are issuable and reserved for issuance upon exercise of ATN Unit Options and the vesting of ATN Phantom Units as of the date hereof are set forth in Section 4.3(c) of the ATN Disclosure Schedule.

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(d) Other than with respect to the ATN Long-Term Incentive Plan, neither ATN nor any of its Subsidiaries, (i) sponsors, maintains, directly contributes or is obligated to directly contribute to, any Benefit Plan for the benefit of any employee, former employee, director or former director of ATN or any of its Subsidiaries or (ii) otherwise provides or is obligated to provide benefits to any current, former or future employee, officer or director of ATN or any of its Subsidiaries or to any beneficiary or dependent thereof under any Benefit Plan. For purposes of the foregoing, a “Benefit Plan” means any material “employee benefit plan” as defined in Section 3(3) of ERISA, whether or not subject to ERISA, material employment, consulting, bonus, incentive or deferred compensation, vacation, stock option or other equity-based, severance, termination, retention, change of control, profit-sharing, fringe benefit or other similar material plan, program, agreement or commitment, whether written or unwritten; provided, however, that “Benefit Plan” shall not include any employee benefit plan that is sponsored by Parent.

Section 4.4Authority; Due Authorization; Binding Agreement; Approval.

(a) ATN has all requisite limited liability power and authority to enter into this Agreement and to perform its obligations under this Agreement subject, with respect to the Merger, to the adoption of this Agreement by the affirmative vote of the ATN Unitholders and the Class A Units, to the extent required by the Operating Agreement and applicable Law.

(b) The execution, delivery and performance of this Agreement by ATN and the consummation by ATN of the transactions contemplated hereby have been duly and validly authorized by all requisite limited liability action on the part of ATN (other than receipt of the ATN Unitholder Approval and the filing of appropriate merger documents as required by the Delaware LLC Act).

(c) This Agreement has been duly executed and delivered by ATN and, assuming the due authorization, execution and delivery hereof by Parent, constitutes a valid and binding obligation of ATN, enforceable against ATN in accordance with its terms, except as limited by bankruptcy, insolvency, moratorium, fraudulent transfer, reorganization and other Laws of general applicability relating to or affecting the rights or remedies of creditors and by general equitable principles (whether considered in a proceeding in equity or at Law).

Section 4.5ATN Board Recommendation; Opinion of ATN Financial Advisor.

(a) At a meeting duly called and held, the ATN Special Committee, the members of which constitute a majority of the members of the ATN Conflicts Committee, determined by unanimous vote of all of its members that this Agreement and the transactions contemplated hereby are advisable, fair and reasonable to and in the best interests of the Unaffiliated Unitholders and ATN, and resolved to recommend that the full ATN Board adopt this Agreement, approve the transactions contemplated hereby, and recommend the adoption of this Agreement and approval of the transactions contemplated hereby by the ATN Unitholders. At a meeting duly called and held, the ATN Board ((x) by unanimous vote of all of its members, other than Edward Cohen, Jonathan Cohen, Bruce Wolf and Richard Weber, who recused themselves, and (y) separately by the unanimous approval of all of the independent members of the ATN Board, with Bruce Wolf and Richard Weber present and abstaining from the vote), upon the recommendation of the ATN Special Committee, (i) determined that this Agreement and the transactions contemplated hereby are advisable, fair and reasonable to and in the best interests of the Unaffiliated Unitholders and ATN and (ii) approved and adopted this Agreement and determined to recommend its adoption and approval by the ATN Unitholders. The approval of the members of the Special Committee, which members constitute a majority of the members of the ATN Conflicts Committee, constitutes approval of a majority of the members of the ATN Conflicts Committee.

(b) UBS Securities LLC (the “ATN Financial Advisor”) has orally delivered to the ATN Special Committee its opinion, the written form of which, dated the same date, to be delivered subsequently, to the effect that, as of the date of such opinion and based upon and subject to the matters set forth therein, the

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Exchange Ratio is fair, from a financial point of view, to the holders of ATN Common Units (other than as set forth in such opinion). A copy of such opinion shall be provided to Parent, solely for informational purposes, promptly following its delivery in written form to the ATN Special Committee.

Section 4.6No Violation; Consents.

(a) The execution and delivery of this Agreement by ATN does not, and the consummation by ATN of the transactions contemplated hereby will not (i) violate the Operating Agreement (assuming that the ATN Unitholder Approval is obtained), (ii) constitute a breach or violation of, or a default (or an event which, with notice or lapse of time or both, would constitute such a default) under any indenture, mortgage, deed of trust, loan agreement, lease or other agreement or instrument to which ATN or any of its Subsidiaries is a party or by which any of them or any of their respective properties are bound, (iii) (assuming that the consents and approvals referred to in Section 4.6(b) are duly and timely made or obtained and that, to the extent required by applicable Law, the adoption of this Agreement by the affirmative vote of ATN Unitholders is obtained) violate any Law applicable to ATN or any of its Subsidiaries or any of their properties, (iv) result in the creation or imposition of any Lien upon any property of ATN or its Subsidiaries pursuant to the agreements and instruments referred to in clause (ii) or (v) cause the transactions contemplated by this Agreement to be subject to Takeover Laws, except, in the case of clause (ii), (iii), (iv) or (v), for such conflicts, breaches, violations, defaults, Liens or subjection, that would not, individually or in the aggregate, have an ATN Material Adverse Effect.

(b) Except for (i) expiration or termination of any waiting period applicable to the transactions contemplated by this Agreement under the HSR Act, (ii) compliance with any applicable requirements of (A) the Securities Act, the Exchange Act and any other applicable U.S. state or federal securities Laws and (B) the NYSE and NASDAQ, (iii) filing or recordation of the Certificate of Merger or other appropriate documents as required by the Delaware LLC Act or applicable Law of other states in which ATN is qualified to do business, (iv) any governmental authorizations, consents, approvals or filings necessary for transfers of permits and licenses or made in connection with the transfer of interests in or the change of control of ownership in oil and gas properties and (v) such other authorizations, consents, approvals or filings the failure of which to obtain or make would not, individually or in the aggregate, have an ATN Material Adverse Effect, no authorization, consent or approval of or filing with any Governmental Authority is required to be obtained or made by ATN for the execution and delivery by ATN of this Agreement or the consummation by ATN of the transactions contemplated hereby.

Section 4.7Compliance.

(a) Neither ATN nor any of its Subsidiaries is in (i) violation of the Operating Agreement, its certificate of formation or other equivalent governing documents, as applicable; (ii) violation of any applicable Law, except that no representation or warranty is made in this Section 4.7 with respect to Laws relating to Tax, which are addressed exclusively in Sections 4.13; or (iii) default in the performance of any obligation, agreement, covenant or condition under any indenture, mortgage, deed of trust, loan agreement, lease or other agreement or instrument to which ATN or any of its Subsidiaries is a party or by which any of them or any of their respective properties are bound; except, in the case of clauses (ii) and (iii), for such violations or defaults that, individually or in the aggregate, would not have an ATN Material Adverse Effect.

(b) Except as would not have, individually or in the aggregate, an ATN Material Adverse Effect or with respect to properties or operations that have been sold or otherwise disposed of or are reflected as having been sold or otherwise disposed of in the ATN SEC Reports filed prior to the date hereof, as of the date hereof, (i) ATN and its Subsidiaries are in possession of all franchises, tariffs, grants, authorizations, licenses, permits, easements, variances, exceptions, consents, certificates, approvals and orders of any Governmental Authority necessary for ATN and its Subsidiaries to own, lease and operate their properties and assets or to carry on their businesses as they are now being conducted (the “ATN Permits”), (ii) all ATN Permits are in full force and effect, (iii) no suspension or cancellation of any of the ATN Permits is pending

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or, to the knowledge of ATN, threatened, (iv) ATN and its Subsidiaries are not, and since January 1, 2009 have not been, in violation or breach of, or default under, any ATN Permit and (v) to the knowledge of ATN, no event or condition has occurred which would reasonably be expected to result in a violation or breach of any ATN Permit (in each case, with or without notice or lapse of time or both).

Section 4.8SEC Filings; Financial Statements.

(a) ATN has filed all reports, schedules, registration statements, definitive proxy statements and exhibits to the foregoing documents required to be filed by it with the SEC since January 1, 2007 (collectively, the “ATN SEC Reports”). As of their respective dates, (i) the ATN SEC Reports complied in all material respects with the applicable requirements of the Securities Act or the Exchange Act, as the case may be, and (ii) none of the ATN SEC Reports, as finally amended prior to the date hereof, contained any untrue statement of a material fact or omitted to state a material fact required to be stated therein or necessary to make the statements therein, in light of the circumstances under which they were made, not misleading. No ATN Subsidiary is currently required to file any form, report or other document with the SEC under Section 13(a) or 15(d) of the Exchange Act.

(b) The historical financial statements of ATN, together with the related schedules and notes thereto, included in ATN SEC Reports present fairly, in all material respects, the consolidated financial position of ATN and its consolidated subsidiaries at the dates indicated, and the consolidated results of operations and consolidated cash flows of ATN and its consolidated subsidiaries for the periods specified; and such historical financial statements have been prepared in conformity with GAAP applied on a consistent basis throughout the periods involved, in all material respects, except as noted therein.

Section 4.9No Undisclosed Liabilities. Except (i) as reflected or reserved against in ATN’s consolidated balance sheet (or notes thereto) as of December 31, 2008 included in its Annual Report on Form 10-K for the year ended December 31, 2008, (ii) for liabilities and obligations arising under this Agreement and transactions contemplated by this Agreement, and (iii) for liabilities and obligations incurred since December 31, 2008 in the ordinary course of business consistent with past practice, neither ATN nor any Subsidiary of ATN has any liabilities or obligations of a nature required by GAAP to be reflected in a consolidated balance sheet (or notes thereto) that would have, individually or in the aggregate, an ATN Material Adverse Effect.

Section 4.10Absence of Certain Changes or Events. Since December 31, 2008, except as contemplated by this Agreement or disclosed in the ATN SEC Reports filed prior to the date hereof, ATN has conducted its businesses only in the ordinary course and there has not been (i) any event having, individually or in the aggregate, an ATN Material Adverse Effect, (ii) through the date of this Agreement, any change by ATN in its accounting methods, principles or practices materially affecting the consolidated assets, liabilities or results of operations of ATN and its consolidated Subsidiaries, except insofar as may have been required by a change in GAAP (iii) through the date of this Agreement, any change or revocation or filing of any material Tax election or any settlement or compromise of any material Tax liability; or (iv) through the date of this Agreement, any declaration, setting aside or payment of any dividend or distribution in respect of any equity interests of ATN or any redemption, purchase or other acquisition for value of any of its equity interests, other than regular quarterly cash distributions of Available Cash (as defined in the Operating Agreement) on the ATN Common Units, the Class A Units and the MIIs of ATN in the ordinary course of business.

Section 4.11Litigation. Except with respect to Tax matters, which are addressed exclusively in Section 4.13, there is no action, suit or proceeding before or by any Governmental Authority now pending, or, to the knowledge of ATN, threatened, against ATN or any of its Subsidiaries that would have an ATN Material Adverse Effect.

Section 4.12Proxy Statement. None of the information to be supplied by ATN for inclusion in (a) the Joint Proxy Statement to be filed by ATN and Parent with the SEC, and any amendments or supplements thereto, or (b) the Registration Statement to be filed by Parent with the SEC in connection with the Merger, and any

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amendments or supplements thereto, will, at the respective times such documents are filed, and, in the case of the Joint Proxy Statement, at the time the Joint Proxy Statement or any amendment or supplement thereto is first mailed to ATN Unitholders and Parent stockholders, at the time of the ATN Meeting and the Parent Meeting and at the Effective Time, and, in the case of the Registration Statement, when it becomes effective under the Securities Act, contain any untrue statement of a material fact or omit to state any material fact required to be made therein or necessary in order to make the statements made therein, in light of the circumstances under which they were made, not misleading.

Section 4.13Taxes. Except as would not have, individually or in the aggregate, an ATN Material Adverse Effect:

(a) Each of ATN, its Subsidiaries and any affiliated, combined or unitary group of which any such entity is or was a member has timely (taking into account any extensions) filed all federal, state, local and foreign returns, declarations, reports, estimates, information returns and statements (“Tax Returns”) required to be filed in respect of any Taxes, and has timely paid all Taxes whether or not shown by such Tax Returns to be due and payable.

(b) Each of ATN and its subsidiaries has established reserves that are adequate in the aggregate for the payment of all Taxes that have accrued but that are not yet due and payable through the date hereof, and complied in all respects with all applicable Laws relating to the payment and withholding of Taxes.

(c) Section 4.13 of the ATN Disclosure Schedule sets forth the last taxable period through which the federal income Tax Returns of ATN and its Subsidiaries have been examined by the Internal Revenue Service (the “IRS”) or otherwise closed. All deficiencies asserted as a result of such examinations and any examination by any applicable state or local taxing authority have been paid, fully settled or are being contested in good faith and are adequately provided for in ATN’s most recent audited financial statements. Except as provided for in the ATN SEC Reports filed prior to the date hereof, no audits or other administrative proceedings or court proceedings are presently pending with regard to any Taxes for which ATN or any of its Subsidiaries would be liable, and no deficiency which has not yet been paid for any such Taxes has been proposed, asserted or assessed against ATN or any of its Subsidiaries with respect to any period.

(d) Neither ATN nor any of its Subsidiaries has executed or entered into with the IRS or any taxing authority (i) any agreement or other document extending or having the effect of extending the period for assessment or collection of any Tax for which ATN or any of its Subsidiaries would be liable or (ii) a closing agreement pursuant to Section 7121 of the Code or any similar provision of state or local income tax Law that relates to ATN or any of its Subsidiaries.

(e) Neither ATN nor any of its Subsidiaries is a party to, is bound by or has any obligation under any Tax sharing agreement or similar agreement or arrangement.

(f) Neither ATN nor any of its Subsidiaries has been a “controlled corporation” or a “distributing corporation” in any distribution that was purported or intended to be governed by Section 355 of the Code (or any similar provision of state, local or foreign Law) (i) occurring during the two-year period ending on the date hereof, or (ii) that otherwise constitutes part of a “plan” or “series of related transactions” (within the meaning of Section 355(e) of the Code) that includes the Merger.

(g) ATN qualifies, and has since the date of its formation qualified, to be treated as a partnership for federal, state and local income tax purposes, and ATN has not taken a position inconsistent with such treatment with regard to any Tax.

(h) Each Subsidiary of ATN qualifies, and has since the date of its formation qualified, to be treated either as an entity disregarded from its owner or as a partnership for federal, state and local income tax purposes, and none of any such Subsidiary or ATN has taken a position inconsistent with such treatment with regard to any Tax.

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(i) Neither ATN nor any of its Subsidiaries has any liability in respect of Taxes arising by reason of contract, assumption, transferee liability, operation of Law, Treasury Regulation Section 1.1502-6 (or any similar provision of Law) or otherwise.

Section 4.14Brokers; Transaction Fees. No broker, finder or investment banker (other than the ATN Financial Advisor) is entitled to any brokerage, finder’s or other fee or commission in connection with the transactions contemplated by this Agreement based upon arrangements made by or on behalf of ATN.

Section 4.15Quarterly Distribution. With respect to the quarter ended March 31, 2009, the ATN Board has, in accordance with the Operating Agreement, made such determinations (including as to Available Cash (as defined in the Operating Agreement) and cash reserves and other deductions to Available Cash) such that ATN shall not, and shall not permit any of its Subsidiaries (except for upstream distributions to ATN made by such Subsidiaries or, with respect to any of ATN’s Subsidiaries that are not wholly owned, distributions to any third party required pursuant to any contractual or fiduciary duty or obligation) to, declare, set aside, make or pay any dividend or other distribution, payable in cash, units, property or otherwise, with respect to any of its equity interests.

ARTICLE V

REPRESENTATIONS AND WARRANTIES OF PARENT

Parent hereby (and with respect to Section 5.17 only, Atlas Energy Management) represents and warrants to ATN that, except as otherwise set forth (i) in Parent’s Disclosure Schedule to this Agreement (the “Parent Disclosure Schedule”) (it being agreed that disclosure of any item in any section of the Parent Disclosure Schedule shall also be deemed to be disclosed with respect to any other section of this Article V to which the relevance of such item is reasonably apparent on its face) or (ii) in the Parent SEC Reports (excluding any forward-looking statements included therein or any statements of a cautionary nature that are not historical facts in any risk factor section of such documents) filed with the SEC prior to the date of this Agreement:

Section 5.1Organization and Qualification. Parent is a corporation duly incorporated and validly existing in good standing under the Laws of the State of Delaware. Parent has the requisite corporate power and authority to own or lease its properties and to carry on its business as it is now being conducted and is duly licensed or qualified to do business in each jurisdiction in which the nature of the business conducted by it or the character of the properties owned or leased by it makes such licensing or qualification necessary, except where the failure to be so licensed or qualified would not, individually or in the aggregate, have a Parent Material Adverse Effect (as defined below). When used in connection with Parent or any of its Subsidiaries, the term “Parent Material Adverse Effect” shall mean any state of facts, circumstance, change or effect that is materially adverse to the business, financial condition or results of operations of Parent and its Subsidiaries (including ATN and its Subsidiaries), taken as a whole, except that none of the following (or the effects thereof) will be deemed to constitute, and none of the following will be taken into account in determining whether there has been or if there is reasonably likely to be, a Parent Material Adverse Effect: (i) general economic conditions, changes in securities markets (including any disruption thereof), regulatory or political conditions, including any engagement in hostilities, whether or not pursuant to the declaration of a national emergency or war, the occurrence of any military or terrorist attack or a general economic recession, natural disasters or other force majeure events, in each case in the United States or elsewhere, except to the extent that such conditions, changes or events affect Parent in a materially disproportionate and adverse manner when compared to companies of similar size operating in the same industry or market as Parent; (ii) changes in or events or conditions generally affecting the oil and gas exploration and development industry (including changes in commodity prices and general market prices), except to the extent that such conditions, changes or events affect Parent in a materially disproportionate and adverse manner when compared to companies of similar size operating in the same industry or market as Parent; provided, however, that the bankruptcy of Parent shall be considered to be a Parent Material Adverse Effect; (iii) changes in Laws or GAAP or interpretations thereof, except to the extent that such changes

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affect Parent in a materially disproportionate and adverse manner when compared to companies of similar size operating in the same industry or market as Parent; (iv) the announcement or pendency of this Agreement, any actions taken in compliance with this Agreement or the consummation of the Merger; (v) any failure by Parent to meet estimates of revenues or earnings for any period ending after the date of this Agreement (provided that the underlying causes of any such failure may be considered in determining whether a Parent Material Adverse Effect has occurred); (vi) the downgrade in rating of any debt securities of Parent by Standard & Poor’s Rating Group, Moody’s Investor Services, Inc. or Fitch Ratings (provided that the underlying causes of any such downgrade may be considered in determining whether a Parent Material Adverse Effect has occurred); (vii) the taking of any action (or omitting to take any action) required or contemplated by this Agreement or the taking of any action (or omitting to take any action) that ATN has requested or to which ATN has consented; or (viii) changes in the price or trading volume of Parent’s stock (provided that the underlying causes of any such changes may be considered in determining whether a Parent Material Adverse Effect has occurred).

Section 5.2Subsidiaries. Each Subsidiary of Parent (i) is duly organized and validly existing under the Laws of its jurisdiction of organization, (ii) has the requisite corporate or other business entity power and authority to own or lease its properties and to carry on its business as it is now being conducted and (iii) is duly licensed or qualified to do business in each jurisdiction in which the nature of the business conducted by it or the character of the properties owned or leased by it makes such licensing or qualification necessary, in each case, except as would not, individually or in the aggregate, have a Parent Material Adverse Effect. Other than with respect to Parent’s Subsidiaries, Parent does not directly or indirectly own any equity interest in, or any interest convertible into or exchangeable or exercisable for, any equity interest in, any corporation, partnership, joint venture or other business entity, other than equity interests held for investment that are not, in the aggregate, material to Parent. Except as set forth in Section 5.2 of the Parent Disclosure Schedule, all of the equity interests Parent owns in each of its Subsidiaries, whether directly or through Parent’s Subsidiaries, are held free and clear of any Lien (other than in favor of Parent or any of its Subsidiaries), no equity interests of any of Parent’s Subsidiaries are or may become required to be issued by reason of any Rights, there are no contracts, commitments, understandings or arrangements by which any of Parent’s Subsidiaries is or may be bound to sell or otherwise transfer any equity interests of any such Subsidiaries, there are no contracts, commitments, understandings, or arrangements relating to Parent’s rights to vote or to dispose of such equity interests, and all of the equity interests of each such Subsidiary held by Parent or its Subsidiaries are fully paid and nonassessable and are owned by Parent or its Subsidiaries free and clear of any Liens.

Section 5.3Capitalization.

(a) The authorized capital stock of Parent consists of 49,000,000 shares of common stock, par value $0.01 per share of Parent (“Parent Common Stock”) and 1,000,000 shares of preferred stock, par value $0.01 per share (“Parent Preferred Stock”). As of April 20, 2009, (i) 39,412,758 shares of Parent Common Stock were issued and outstanding (including, for the avoidance of doubt, shares of Parent Common Stock in the form of restricted stock issued pursuant to employee benefit plans of Parent), all of which were validly issued, fully paid and nonassessable (except for any restricted stock), and none of which were issued in violation of any preemptive or similar rights of any securityholder of Parent, (ii) options to purchase an aggregate of 3,725,313 shares of Parent Common Stock were issued and outstanding and (iii) no shares of Parent Preferred Stock were issued and outstanding.

(b) As of the date hereof, except as set forth in Section 5.3(b) of the Parent Disclosure Schedule, there are no interests of Parent’s equity securities authorized and reserved for issuance, Parent does not have any Rights issued or outstanding with respect to its equity securities, and Parent does not have any commitment to authorize, issue or sell any such equity securities or Rights, except pursuant to this Agreement. Since December 31, 2008, Parent has not issued any interests of Parent’s equity securities or rights in respect thereof or reserved any interests of Parent’s equity securities for such purposes except pursuant to plans or commitments set forth in Section 5.3(b) of the Parent Disclosure Schedule. There are no outstanding contractual obligations of Parent or any of its Subsidiaries to repurchase, redeem or otherwise acquire any equity interests of Parent or any of its Subsidiaries.

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Section 5.4Authority; Due Authorization; Binding Agreement.

(a) Parent has all requisite corporate power and authority to enter into this Agreement and to perform its obligations under this Agreement.

(b) The execution, delivery and performance of this Agreement by Parent and the consummation of the transactions contemplated hereby by Parent has been duly and validly authorized by all requisite corporate action on the part of Parent (other than, with respect to the Stock Issuance, the approval of the Stock Issuance by the affirmative vote of Parent Stockholders, to the extent required by applicable Law, with respect to the adoption of the Amended and Restated Certificate of Incorporation of Parent to increase the number of authorized shares of Parent Common Stock (the “Charter Amendment”), the adoption of the Charter Amendment by the affirmative vote of a majority of the outstanding shares of Parent Common Stock and the subsequent filing of the Charter Amendment with the Secretary of State of the State of Delaware, and the filing of appropriate merger documents as required by the Delaware LLC Act).

(c) This Agreement has been duly executed and delivered Parent and, assuming the due authorization, execution and delivery hereof by ATN, constitutes a valid and binding obligation of Parent, enforceable against it in accordance with its terms, except as limited by bankruptcy, insolvency, moratorium, fraudulent transfer, reorganization and other Laws of general applicability relating to or affecting the rights or remedies of creditors and by general equitable principles (whether considered in a proceeding in equity or at Law).

Section 5.5Parent Board Recommendation; Opinion of Parent Financial Advisor.

(a) At a meeting duly called and held, the Parent Board determined that this Agreement and the transactions contemplated hereby, including the Stock Issuance and the Charter Amendment, are advisable, fair to, and in the best interests of, Parent and its stockholders, and recommended that the Parent Board approve this Agreement and the transactions contemplated hereby and recommend to the stockholders of Parent that they approve the Stock Issuance and adopt the Charter Amendment; and

(b) J.P. Morgan Securities Inc. (“Parent Financial Advisor”) has delivered to the Parent Board its opinion, to be delivered subsequently in writing, to the effect that, as of the date thereof and based upon and subject to the matters set forth therein, the Exchange Ratio is fair to Parent from a financial point of view. A copy of such opinion shall be provided to the ATN Special Committee, solely for informational purposes, promptly following its delivery in written form to the Parent Board.

Section 5.6No Violation; Consents.

(a) The execution and delivery of this Agreement by Parent does not, and consummation by Parent of the transactions contemplated hereby will not, (i) violate the certificate of incorporation or bylaws or other comparable governing documents of Parent, (ii) constitute a breach or violation of, or a default (or an event which, with notice or lapse of time or both, would constitute such a default) under any indenture, mortgage, deed of trust, loan agreement, lease or other agreement or instrument to which Parent or any of its Subsidiaries is a party or by which any of them or any of their respective properties are bound, (iii) (assuming that the consents and approvals referred to in Section 5.6(b) are duly and timely made or obtained and that, to the extent required by applicable Law, the adoption of Stock Issuance by the affirmative vote of the Parent Stockholders is obtained) violate any Law applicable to Parent any of its Subsidiaries or any of their properties, (iv) result in the creation or imposition of any Lien upon any property of Parent or any of its Subsidiaries pursuant to the agreements and instruments referred to in clause (ii) or (v) cause the transactions contemplated by this Agreement to be subject to Takeover Laws, except, in the case of clause (ii), (iii), (iv) or (v), for such conflicts, breaches, violations, defaults, Liens, or subjection, that would not, individually or in the aggregate, have a Parent Material Adverse Effect.

(b) Except for (i) expiration or termination of any waiting period applicable to the transactions contemplated by this Agreement under the HSR Act, (ii) compliance with any applicable requirements of

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(A) the Securities Act, the Exchange Act and any other applicable U.S. state or federal securities Laws and (B) the NYSE and NASDAQ, (iii) filing or recordation of merger or other appropriate documents as required by the Delaware LLC Act or applicable Law of other states in which Parent or Merger Sub is qualified to do business, (iv) any governmental consents necessary for transfers of permits and licenses and (v) such other authorizations, consents, approvals or filings the failure of which to obtain or make would not, individually or in the aggregate, have a Parent Material Adverse Effect, except as otherwise set forth on Section 5.6(b) of the Parent Disclosure Schedule, no authorization, consent or approval of or filing with any Governmental Authority is required to be obtained or made by Parent or any ultimate parent entity or controlling person of Parent for the execution and delivery by either of them of this Agreement or the consummation by either of them of the transactions contemplated hereby.

Section 5.7Compliance.

(a) Neither Parent nor any of its Subsidiaries is in (i) violation of its certificate of incorporation, bylaws or other equivalent governing documents, as applicable, (ii) violation of any applicable Law, except that no representation or warranty is made in this Section 5.7 with respect to Laws relating to Tax, which are addressed exclusively in Sections 5.13, or (iii) default in the performance of any obligation, agreement, covenant or condition under any indenture, mortgage, deed of trust, loan agreement, lease or other agreement or instrument to which Parent or any of its Subsidiaries is a party or by which any of them or any of their respective properties are bound, except, in the case of clauses (ii) and (iii), for such violations or defaults that, individually or in the aggregate, would not have a Parent Material Adverse Effect.

(b) Except as would not have, individually or in the aggregate, a Parent Material Adverse Effect or with respect to properties or operations that have been sold or otherwise disposed of or are reflected as having been sold or otherwise disposed of in the Parent SEC Reports filed prior to the date hereof, as of the date hereof, (i) Parent and its Subsidiaries are in possession of all franchises, tariffs, grants, authorizations, licenses, permits, easements, variances, exceptions, consents, certificates, approvals and orders of any Governmental Entity necessary for Parent and its Subsidiaries to own, lease and operate their properties and assets or to carry on their businesses as they are now being conducted (the “Parent Permits”), (ii) all Parent Permits are in full force and effect, (iii) no suspension or cancellation of any of the Parent Permits is pending or, to the knowledge of Parent, threatened, (iv) Parent and its Subsidiaries are not, and since January 1, 2009 have not been, in violation or breach of, or default under, any Parent Permit and (v) to the knowledge of Parent, no event or condition has occurred which would reasonably be expected to result in a violation or breach of any Parent Permit (in each case, with or without notice or lapse of time or both).

Section 5.8SEC Filings; Financial Statements.

(a) Parent has filed all reports, schedules, registration statements, definitive proxy statements and exhibits to the foregoing documents required to be filed by it with the SEC since January 1, 2007 (collectively, the “Parent SEC Reports”). As of their respective dates, (i) the Parent SEC Reports complied in all material respects with the applicable requirements of the Securities Act or the Exchange Act, as the case may be, and (ii) none of the Parent SEC Reports, as finally amended prior to the date hereof, contained any untrue statement of a material fact or omitted to state a material fact required to be stated therein or necessary to make the statements therein, in light of the circumstances under which they were made, not misleading. No Parent Subsidiary, other than Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P., is currently required to file any form, report or other document with the SEC under Section 13(a) or 15(d) of the Exchange Act.

(b) The historical financial statements of Parent, together with the related schedules and notes thereto, included in the Parent SEC Reports present fairly, in all material respects, the consolidated financial position of Parent and its consolidated subsidiaries at the dates indicated, and the consolidated results of operations and consolidated cash flows of Parent and its consolidated subsidiaries for the periods specified; and such historical financial statements have been prepared in conformity with GAAP applied on a consistent basis throughout the periods involved, in all material respects, except as noted therein.

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Section 5.9No Undisclosed Liabilities. Except (i) as reflected or reserved against in Parent’s consolidated balance sheet (or notes thereto) as of December 31, 2008 included in its Annual Report on Form 10-K for the year ended December 31, 2008, (ii) for liabilities and obligations arising under this Agreement and transactions contemplated by this Agreement, and (iii) for liabilities and obligations incurred since December 31, 2008 in the ordinary course of business consistent with past practice, neither Parent nor any Subsidiary of Parent has any liabilities or obligations of a nature required by GAAP to be reflected in a consolidated balance sheet (or notes thereto) that would have, individually or in the aggregate, a Parent Material Adverse Effect.

Section 5.10Absence of Certain Changes or Events. Since December 31, 2008, except as contemplated by this Agreement or disclosed in the Parent SEC Reports filed prior to the date hereof, Parent has conducted its businesses only in the ordinary course and there has not been (i) any event having, individually or in the aggregate, a Parent Material Adverse Effect, (ii) through the date of this Agreement, any change by Parent in its accounting methods, principles or practices materially affecting the consolidated assets, liabilities or results of operations of Parent and its consolidated subsidiaries, except insofar as may have been required by a change in GAAP or (iii) through the date of this Agreement, any declaration, setting aside or payment of any dividend or distribution in respect of any capital stock of Parent or any redemption, purchase or other acquisition for value of any of its capital stock, other than regular dividends.

Section 5.11Litigation. Except with respect to Tax matters, which are addressed exclusively in Section 5.13, there is no action, suit or proceeding before or by any Governmental Authority now pending, or, to the knowledge of Parent, threatened, against Parent or any of its subsidiaries that would have a Parent Material Adverse Effect.

Section 5.12 Proxy Statement. None of the information to be supplied by Parent for inclusion in (a) the Joint Proxy Statement to be filed by ATN and Parent with the SEC, and any amendments or supplements thereto, or (b) the Registration Statement to be filed by Parent with the SEC in connection with the Merger, and any amendments or supplements thereto, will, at the respective times such documents are filed, and, in the case of the Joint Proxy Statement, at the time the Joint Proxy Statement or any amendment or supplement thereto is first mailed to ATN Unitholders and Parent stockholders, at the time of the ATN Meeting and the Parent Meeting and at the Effective Time, and, in the case of the Registration Statement, when it becomes effective under the Securities Act, contain any untrue statement of a material fact or omit to state any material fact required to be made therein or necessary in order to make the statements made therein, in light of the circumstances under which they were made, not misleading.

Section 5.13Taxes. Except as would not have, individually or in the aggregate, a Parent Material Adverse Effect:

(a) Each of Parent, its Subsidiaries and any affiliated, combined or unitary group of which any such entity is or was a member has timely (taking into account any extensions) filed all Tax Returns required to be filed in respect of any Taxes, and has timely paid all Taxes whether or not shown by such Tax Returns to be due and payable.

(b) Each of Parent and its Subsidiaries has established reserves that are adequate in the aggregate for the payment of all Taxes that have accrued but that are not yet due and payable through the date hereof, and complied in all respects with all applicable Laws relating to the payment and withholding of Taxes.

(c) Section 5.13 of the Parent Disclosure Schedule sets forth the last taxable period through which the federal income Tax Returns of Parent and its Subsidiaries have been examined by the IRS or otherwise closed. All deficiencies asserted as a result of such examinations and any examination by any applicable state or local taxing authority have been paid, fully settled or are being contested in good faith and are adequately provided for in Parent’s most recent audited financial statements. Except as provided for in the Parent SEC Reports filed prior to the date hereof, no audits or other administrative proceedings or court proceedings are presently pending with regard to any Taxes for which Parent or any of its Subsidiaries would be liable, and no deficiency which has not yet been paid for any such Taxes has been proposed, asserted or assessed against Parent or any of its Subsidiaries with respect to any period.

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(d) Neither Parent nor any of its Subsidiaries has executed or entered into with the IRS or any taxing authority (i) any agreement or other document extending or having the effect of extending the period for assessment or collection of any Tax for which Parent or any of its Subsidiaries would be liable or (ii) a closing agreement pursuant to Section 7121 of the Code or any similar provision of state or local income tax Law that relates to Parent or any of its Subsidiaries.

(e) Neither Parent nor any of its Subsidiaries is a party to, is bound by or has any obligation under any Tax sharing agreement or similar agreement or arrangement.

(f) Neither Parent nor any of its Subsidiaries has been a “controlled corporation” or a “distributing corporation” in any distribution that was purported or intended to be governed by Section 355 of the Code (or any similar provision of state, local or foreign Law) (i) occurring during the two-year period ending on the date hereof, or (ii) that otherwise constitutes part of a “plan” or “series of related transactions” (within the meaning of Section 355(e) of the Code) that includes the Merger.

(g) Neither Parent nor any of its Subsidiaries has any liability in respect of Taxes arising by reason of contract, assumption, transferee liability, operation of Law, Treasury Regulation Section  1.1502-6 (or any similar provision of Law) or otherwise.

Section 5.14Commitments. As of April 23, 2009, Parent has at least $72 million of cash and cash equivalents. From April 23, 2009 to the date hereof, Parent has made no expenditures of any portion of such $72 million other than expenditures that would not be prohibited by Section 6.2 hereof. Except as set forth in Section 5.14 of the Parent Disclosure Schedule, as of the date hereof, or as permitted to be committed or expended by Parent pursuant to Sections 6.2(b), (c) and (d) of this Agreement, none of Parent or any of its Subsidiaries has any plan or commitment to expend such $72 million of cash or cash equivalents.

Section 5.15Brokers. No broker, finder or investment banker (other than the Parent Financial Advisor) is entitled to any brokerage, finder’s or other fee or commission in connection with the transactions contemplated hereby based upon arrangements made by or on behalf of Parent for which ATN or any of its Subsidiaries or unitholders will be liable.

Section 5.16Representations Regarding Merger Sub.

(a) Merger Sub shall be formed solely for the purpose of engaging in the transactions contemplated by this Agreement and, from its formation to the Effective Time, shall have engaged in no business other than in connection with entering into this Agreement and engaging in the transactions contemplated hereby;

(b) Upon Merger Sub becoming a party to this Agreement, Merger Sub will be deemed to have made the same representations set forth in Sections 5.1, 5.4 and 5.6, modified only to reflect that Merger Sub will be a limited liability company organized under the laws of the State of Delaware; and

(c) Following the formation of Merger Sub until the Effective Time, Parent shall own 100 percent of the outstanding equity interests of Merger Sub.

Section 5.17Representations of Atlas Energy Management. Atlas Energy Management hereby makes the same representations set forth in Sections 5.1, 5.4 and 5.6, modified only to reflect that Atlas Energy Management is a corporation organized under the laws of the State of Delaware.

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ARTICLE VI

ACTIONS PENDING MERGER

Section 6.1Conduct of ATN Business. ATN covenants and agrees that, between the date of this Agreement and the earlier of the Effective Time and the termination of this Agreement in accordance with its terms, except (i) with the prior written consent of the Parent, which consent may not be unreasonably withheld, delayed or conditioned, (ii) as contemplated by this Agreement or by the Disclosure Schedules, (iii) for transactions between or among ATN and its wholly-owned Subsidiaries or (iv) as may be required under applicable Law:

(a) the respective businesses of ATN and its Subsidiaries shall be conducted in the ordinary course and in a manner consistent with past practice, in each case in all material respects;

(b) except in the ordinary course of business and consistent with past practice and not in excess of $50,000,000 in the aggregate per quarter, ATN shall not, and shall not permit its Subsidiaries to, (i) acquire, by merging or consolidating with, or by purchasing an equity interest in or the assets of or by any other manner, any business or corporation, partnership or other business organization or division thereof, or otherwise acquire any assets of any other entity (other than the purchase of assets from suppliers, clients or vendors in the ordinary course of business and consistent with past practice); or (ii) make any capital contribution or incur any indebtedness for borrowed money or issue any debt securities or assume, guarantee or endorse, or otherwise as an accommodation become voluntarily responsible for, the obligations of any Person, or make any loans or advances;

(c) ATN shall not amend or otherwise change its certificate of formation or the Operating Agreement;

(d) ATN shall not, and shall not permit any of its Subsidiaries to, issue, sell, pledge, dispose of, grant, encumber, or authorize the issuance, sale, pledge, disposition, grant or encumbrance of, any equity interests of any class of ATN or any of its Subsidiaries, or any options, warrants, convertible securities or other rights of any kind to acquire any such equity interests, of ATN or any of its Subsidiaries (except in accordance with the terms of securities or equity compensation awards outstanding on the date hereof);

(e) ATN shall not, and shall not permit any of its Subsidiaries to, (A) declare, set aside, make or pay any dividend or other distribution, payable in cash, units, property or otherwise, with respect to any of its equity interests or (B) reclassify, combine, split or subdivide, or redeem, purchase or otherwise acquire, directly or indirectly, any of its equity interests;

(f) ATN shall not, and shall not permit any of its Subsidiaries to, adopt a plan of complete or partial liquidation, dissolution, merger, consolidation, restructuring, recapitalization or other reorganization of such entity;

(g) ATN shall not, and shall not permit any of its Subsidiaries to, change its methods of accounting (other than Tax accounting, which shall be governed by clause (h) below), except in accordance with changes in GAAP as concurred to by ATN’s independent auditors;

(h) ATN shall not, and shall not permit any of its Subsidiaries to, enter into any closing agreement with respect to material Taxes, settle or compromise any material liability for Taxes, revoke, change or make any new material Tax election, agree to any adjustment of any material Tax attribute, file or surrender any claim for a material refund of Taxes, execute or consent to any waivers extending the statutory period of limitations with respect to the collection or assessment of material Taxes, file any material amended Tax Return or obtain any material Tax ruling;

(i) except in the ordinary course of business and consistent with past practice, ATN shall not (A) grant to any current or former director or officer of ATN any increase in compensation, bonus or fringe or other benefits or grant any type of compensation or benefit to any such Person not previously receiving or entitled to receive such compensation, except to the extent required under any ATN employee benefit plan as in effect as of the date hereof, (B) grant to any Person any severance, retention, change in control or termination compensation or benefits or any increase therein, except to the extent required under any ATN

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employee benefit plan as in effect as of the date hereof, or (C) enter into or adopt any material employee benefit plan or amend in any material respect any employee benefit plan, except for any amendments in the ordinary course of business consistent with past practice or in order to comply with applicable Laws (including Section 409A of the Code); and

(j) ATN shall not and shall not permit any of its Subsidiaries (as applicable) to agree or formally commit to do any of the foregoing;

provided, however, that for purposes of this Section 6.1, ATN’s obligations with respect to any Subsidiaries that are not wholly owned shall be subject to, and limited by, the contractual and fiduciary duties and obligations of ATN or any of its Subsidiaries with respect to such non-wholly owned Subsidiaries.

Section 6.2Conduct of Parent Business. Parent covenants and agrees that, between the date of this Agreement and the earlier of the Effective Time and the termination of this Agreement in accordance with its terms, except (i) with the prior written consent of the ATN Special Committee, which consent may not be unreasonably withheld, delayed or conditioned, (ii) as contemplated by this Agreement or by the Disclosure Schedules, (iii) for transactions between or among Parent and its wholly-owned Section 6.2 Subsidiaries, (iv) as set forth in Section 6.2 of the Parent Disclosure Schedule or (v) as may be required under applicable Law:

(a) the respective businesses of Parent and its Section 6.2 Subsidiaries shall be conducted in the ordinary course and in a manner consistent with past practice, in each case in all material respects;

(b) except (i) as set forth on Section 6.2 of the Parent Disclosure Schedule, (ii) for normal operating expenses incurred in the ordinary course of business consistent with past practice of not more than $1 million per month or $9 million in the aggregate, (iii) for costs and expenses associated with this Agreement and the consummation of the transactions contemplated hereby or (iv) as permitted by any other provision of this Section 6.2, Parent shall not make any expenditures;

(c) except as set forth on Section 6.2 of the Parent Disclosure Schedule, Parent shall not, and shall not permit any of its Section 6.2 Subsidiaries to, acquire, by merging or consolidating with, or by purchasing an equity interest in or the assets of or by any other manner, any business or corporation, partnership or other business organization or division thereof, or otherwise acquire any assets of any other entity (other than the purchase of assets from suppliers, clients or vendors in the ordinary course of business and consistent with past practice);

(d) except as set forth on Section 6.2 of the Parent Disclosure Schedule, Parent shall not make any capital contribution, acquire any securities of any of its Subsidiaries for cash or incur any indebtedness for borrowed money or issue any debt securities or assume, guarantee or endorse, or otherwise as an accommodation become voluntarily responsible for, the obligations of any Person, or make any loans or advances, other than intercompany payables owed to Parent relating to services rendered or benefits provided by Parent for a Subsidiary in the ordinary course consistent with past practice;

(e) Parent shall not, and shall not permit its Section 6.2 Subsidiaries to, adopt or propose to adopt any amendments to its charter documents;

(f) Parent shall not issue (except in accordance with the terms of securities outstanding on the date hereof or any existing employee ownership or benefit plan or other contractual obligation), split, combine or reclassify any shares of its capital stock, declare, set aside or pay any dividend or other distribution (whether in cash, stock or property or any combination thereof) in respect of its capital stock or otherwise make any payments to stockholders in their capacity as such;

(g) Parent shall not, and shall not permit any of its Section 6.2 Subsidiaries to, adopt a plan of complete or partial liquidation, dissolution, merger, consolidation, restructuring, recapitalization or other reorganization of such entity;

(h) Parent shall not, and shall not permit any of its Section 6.2 Subsidiaries to, change its methods of accounting (other than Tax accounting, which shall be governed by clause (i) below), except in accordance with changes in GAAP as concurred to by Parent’s independent auditors;

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(i) Parent shall not, and shall not permit any of its Section 6.2 Subsidiaries to, enter into any closing agreement with respect to material Taxes, settle or compromise any material liability for Taxes, revoke, change or make any new material Tax election, agree to any adjustment of any material Tax attribute, file or surrender any claim for a material refund of Taxes, execute or consent to any waivers extending the statutory period of limitations with respect to the collection or assessment of material Taxes, file any material amended Tax Return or obtain any material Tax ruling; and

(j) Parent shall not, and shall not permit its Section 6.2 Subsidiaries (as applicable) to, agree or formally commit to do any of the foregoing;

provided, however, that for purposes of this Section 6.2, Parent’s obligations with respect to any Subsidiaries that are not wholly owned shall be subject to, and limited by, the contractual and fiduciary duties and obligations of Parent or any of its Subsidiaries with respect to such non-wholly owned Subsidiaries. “Section 6.2 Subsidiaries” means the Subsidiaries of Parent other than Atlas Pipeline Holdings GP, LLC, Atlas Pipeline Holdings, L.P., Atlas Pipeline Partners GP, LLC, Atlas Pipeline Partners, L.P. or any of their respective Subsidiaries.

ARTICLE VII

COVENANTS

ATN hereby covenants to and agrees with Parent, and Parent hereby covenants to and agrees with ATN, that:

Section 7.1Reasonable Best Efforts. Subject to the terms and conditions of this Agreement, each of ATN and Parent shall use its reasonable best efforts in good faith to take, or cause to be taken, all actions, and to do, or cause to be done, all things necessary, proper, desirable or advisable under applicable Laws, so as to permit consummation of the Merger as soon as reasonably practicable and otherwise to enable consummation of the transactions contemplated hereby, including (a) obtaining Consent in respect of the ATN Credit Agreement, (b) taking such actions as set forth in Section 7.7, (c) using reasonable best efforts to lift or rescind any injunction or restraining order or other order adversely affecting the ability of the parties to consummate the transactions contemplated hereby, and (d) using reasonable best efforts to defend any litigation seeking to enjoin, prevent or delay the consummation of the transactions contemplated hereby or seeking material damages. Each of ATN and Parent shall cooperate fully with the other parties hereto to that end, and shall furnish to the other party copies of all correspondence, filings and communications between it and its Affiliates and any Governmental Authority with respect to the transactions contemplated hereby. In complying with the foregoing, none of ATN, Parent or any of their respective Subsidiaries shall be required to take measures that would have an ATN Material Adverse Effect or Parent Material Adverse Effect, as applicable.

Section 7.2Equityholder Approvals.

(a) Subject to the terms and conditions of this Agreement, ATN shall take, in accordance with applicable Law and the Operating Agreement, all action necessary to call, convene and hold, as soon as reasonably practicable, an appropriate meeting of members of ATN to consider and vote upon the adoption of this Agreement, the approval of the Merger and any other matters required to be approved by the holders of Class A Units and the holders of ATN Common Units for consummation of the Merger (including any adjournment or postponement, the “ATN Meeting”) promptly after the date that the Registration Statement is declared effective by the SEC. Subject to the last sentence of this Section 7.2(a), the ATN Board and the ATN Special Committee shall recommend adoption of this Agreement and approval of the transactions contemplated hereunder, including the Merger, to its holders of Class A Units and holders of ATN Common Units (the “ATN Recommendation”), and each of Parent and ATN shall take all reasonable lawful action to solicit such approval by ATN Unitholders. Notwithstanding the foregoing, at any time prior to obtaining

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ATN Unitholder Approval, the ATN Board or the ATN Special Committee may withdraw, modify or qualify in any manner adverse to Parent the ATN Recommendation (any such action being referred to as an “ATN Change in Recommendation”) if they have concluded in good faith, after consultation with, and taking into account the advice of their outside legal advisors, that the failure to make an ATN Change in Recommendation would be inconsistent with its applicable fiduciary duties.

(b) Subject to the terms and conditions of this Agreement, Parent shall take, in accordance with applicable Law and its certificate of incorporation and bylaws, all action necessary to call, convene and hold, as soon as reasonably practicable, an appropriate meeting of the holders of the Parent Common Stock to consider and vote upon the approval of the Stock Issuance and the adoption of the Charter Amendment and any other matters required to be approved or adopted by them for consummation of the Merger (including any adjournment or postponement, the “Parent Meeting”; and each of the ATN Meeting and Parent Meeting, a “Meeting”), promptly after the date that the Registration Statement is declared effective by the SEC. Subject to the last sentence of this Section 7.2(b), the Parent Board shall recommend approval of the Stock Issuance and the Charter Amendment to the holders of Parent Common Stock (the “Parent Recommendation”). Notwithstanding the foregoing, at any time prior to obtaining Parent Stockholder Approval, the Parent Board may withdraw, modify or qualify in any manner adverse to ATN the Parent Recommendation (any such action being referred to as a “Parent Change in Recommendation”) if the Parent Board has concluded in good faith, after consultation with, and taking into account the advice of their outside legal advisors and financial consultants, that the failure to make a Parent Change in Recommendation would be inconsistent with its fiduciary duties under applicable Law.

(c) Nothing contained in this Agreement shall prevent ATN or the ATN Board or Parent or the Parent Board from taking and disclosing to its equityholders a position contemplated by Rule 14d-9 and Rule 14e-2(a) promulgated under the Exchange Act (or any similar communication to equityholders) or from making any legally required disclosure to its equityholders, it being understood that any “stop-look-and-listen” communication by ATN, the ATN Board, Parent or the Parent Board to its equityholders pursuant to Rule 14d-9(f) promulgated under the Exchange Act (or any similar communication to the unitholders of ATN) shall not be considered an ATN Change in Recommendation or Parent Change in Recommendation, as the case may be.

(d) The obligation of ATN to call, hold and convene the ATN Meeting shall not be affected by an ATN Change in Recommendation, and the obligation of Parent to call, hold and convene the Parent Meeting shall not be affected by a Parent Change in Recommendation.

(e) So long as the ATN Recommendation remains unchanged at the time of the Parent Meeting, Parent and Atlas Energy Management shall vote all of their ATN Common Units and Class A Units to approve the Merger, adopt this Agreement and approve any other matters required to be approved by holders of Class A Units and the holders of ATN Common Units for consummation of the Merger; provided, however, that Parent and Atlas Energy Management may, but shall not be required, to vote their ATN Common Units and Class A Units in such manner if there is an ATN Change in Recommendation.

Section 7.3Registration Statement.

(a) As promptly as is reasonably practicable following the date of this Agreement, Parent and ATN shall cooperate in preparing, and prepare, (i) a joint proxy statement (together with any amendments thereof or supplements thereto, the “Joint Proxy Statement”) in order to seek the Parent Stockholder Approval and the ATN Unitholder Approval and (ii) a registration statement on Form S-4, which Parent shall file with the SEC (together with all amendments thereto, the “Registration Statement”), and in which the Joint Proxy Statement will be included as a prospectus. The Registration Statement and the Joint Proxy Statement shall comply as to form in all material respects with the applicable provisions of the Securities Act and the Exchange Act and the rules and regulations thereunder and other applicable Law. Each of Parent and ATN also agrees to use reasonable best efforts to obtain all necessary state securities Law or “Blue Sky” permits and approvals required to carry out the transactions contemplated hereby. Each of Parent and ATN will use

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its reasonable best efforts to have the Registration Statement become effective and the Joint Proxy Statement cleared by the SEC as promptly as is practicable after such filing and keep the Registration Statement effective for so long as necessary to consummate the Merger, and each of Parent and ATN shall use its respective reasonable best efforts to cause the Joint Proxy Statement to be mailed to the holders of Parent Common Stock and the holders of ATN Common Stock as promptly as practicable after the Registration Statement shall have become effective and the Joint Proxy Statement shall have been cleared by the SEC. No filing of the Registration Statement will be made by Parent, and no filing of or amendment or supplement to the Joint Proxy Statement will made by Parent or ATN, in each case without providing the other party a reasonable opportunity to review and comment thereon.

(b) Each of ATN and Parent agrees that if it shall become aware prior to the Closing Date of any information that would cause any of the statements in the Registration Statement to be false or misleading with respect to any material fact, or omit to state any material fact necessary to make the statements therein, in light of the circumstances under which they were made, not false or misleading, it will promptly inform the other party thereof and take in conjunction with the other party the necessary actions to correct such information in an amendment or supplement to the Registration Statement. No amendment or supplement to, the Registration Statement will be made by Parent, and no filing of or amendment or supplement to the Joint Proxy Statement will made by Parent or ATN, in each case without providing the other party a reasonable opportunity to review and comment thereon.

(c) Parent will advise ATN, promptly after Parent receives notice thereof, of the time when the Registration Statement has become effective or any supplement or amendment has been filed, of the issuance of any stop order or the suspension of the qualification of the shares of Parent Common Stock for offering or sale in any jurisdiction, of the initiation or threat of any proceeding for any such purpose, or of any request by the SEC for the amendment or supplement of the Registration Statement or for additional information.

(d) Each of Parent and ATN will use its commercially reasonable efforts to cause the Joint Proxy Statement to be mailed to its stockholders and members, respectively, as soon as practicable after the effective date of the Registration Statement.

Section 7.4Press Releases. Each of ATN and Parent will not, without the prior approval of the ATN Special Committee in the case of ATN and the Parent Board in the case of Parent, issue any press release or written statement for general circulation relating to the transactions contemplated hereby, except as otherwise required by applicable Law or the rules of the NASDAQ or the NYSE, in which case it will consult with the other party before issuing any such press release or written statement.

Section 7.5Access; Information.

(a) Upon reasonable notice and subject to applicable Laws relating to the exchange of information, each party shall, and shall cause its Subsidiaries to, afford the other parties and their officers, employees, counsel, accountants and other authorized representatives, access, during normal business hours throughout the period prior to the Effective Time, to all of its properties, books, contracts, commitments and records, and to its officers, employees, accountants, counsel or other representatives, and, during such period, it shall, and shall cause its Subsidiaries to, furnish promptly to such other parties and its representatives (i) a copy of each material report, schedule and other document filed by it pursuant to the requirements of federal or state securities Law (other than reports or documents that ATN or Parent or their respective Subsidiaries, as the case may be, are not permitted to disclose under applicable Law) and (ii) all other information concerning the business, properties and personnel of it as the other may reasonably request. Neither ATN nor Parent nor any of their respective Subsidiaries shall be required to provide access to or to disclose information where such access or disclosure would violate or prejudice the rights of its customers, jeopardize the attorney-client privilege of the institution in possession or control of such information or contravene any Law or binding agreement entered into prior to the date of this Agreement. The parties hereto will make appropriate substitute disclosure arrangements under the circumstances in which the restrictions of the preceding sentence apply.

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(b) Parent will not use any information obtained pursuant to this Section 7.5 for any purpose unrelated to the consummation of the transactions contemplated by this Agreement and will hold all information and documents obtained pursuant to this paragraph in confidence. No investigation by either party of the business and affairs of the other shall affect or be deemed to modify or waive any representation, warranty, covenant or agreement in this Agreement, or the conditions to either party’s obligation to consummate the transactions contemplated by this Agreement.

Section 7.6Common Stock Listed. Parent shall use its reasonable best efforts to cause the shares of Parent Common Stock to be issued in the Merger to be listed, as of the Closing, on NASDAQ, subject to official notice of issuance.

Section 7.7Third Party Approvals.

(a) Parent and ATN and their respective Subsidiaries, shall cooperate and use their respective reasonable best efforts to prepare all documentation, to effect all filings, to obtain all permits, consents, approvals and authorizations of all third parties and the expiration or termination of any waiting period under the HSR Act necessary to consummate the transactions contemplated by this Agreement and to comply with the terms and conditions of such permits, consents, approvals and authorizations and to cause the Merger to be consummated as expeditiously as practicable. Without limiting the foregoing, each of Parent and ATN and their respective Subsidiaries agrees to file an appropriate notification under the HSR Act with respect to the Merger within ten (10) Business Days of the date of this Agreement.

(b) With regards to the ATN Credit Agreement, “Consent” shall mean approval in a manner consistent with the terms and conditions set forth in Schedule 7.7(b).

(c) Each party hereto agrees that it will consult with the other parties hereto with respect to the obtaining of all material permits, consents, approvals, clearances and authorizations of all third parties and Governmental Authorities necessary or advisable to consummate the transactions contemplated by this Agreement, and each party will keep the other parties apprised of the status of material matters relating to completion of the transactions contemplated hereby. To the extent practicable and in each case subject to applicable Laws relating to the exchange of information, Parent and ATN agree to (i) cooperate and consult with each other, (ii) furnish to the other such necessary information and assistance as the other may reasonably request in connection with its preparation of any notifications or filings, (iii) keep each other apprised of the status of matters relating to the completion of the transactions contemplated thereby, including promptly furnishing the other with copies of notices or other communications received by such party from, or given by such party to, any third party and/or any Governmental Authority with respect to such transactions, (iv) permit the other party to review and incorporate the other party’s reasonable comments in any communication to be given by it to any Governmental Authority with respect to obtaining the necessary approvals for the Merger, and (v) not to participate in any meeting or discussion related to the transactions contemplated hereby, either in person or by telephone, with any Governmental Authority in connection with the proposed transactions unless, to the extent not prohibited by such Governmental Authority, it gives the other party the opportunity to attend and observe. In exercising the foregoing rights, each of the parties hereto agrees to act reasonably and promptly.

(d) Each party agrees, upon request, to furnish the other party with all information concerning itself, its Subsidiaries, directors, officers and equityholders and such other matters as may be reasonably necessary or advisable in connection with the Registration Statement, the Joint Proxy Statement or any filing, notice or application made by or on behalf of such other party or any of such Subsidiaries to any Governmental Authority in connection with the transactions contemplated hereby.

Section 7.8Indemnification; Directors’ and Officers’ Insurance.

(a) Without limiting any additional rights that any director, officer, trustee, employee, agent, or fiduciary may have under any employment or indemnification agreement or under the Operating Agreement or this Agreement or, if applicable, similar organizational documents or agreements of any of ATN’s

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Subsidiaries, from and after the Effective Time, Parent and ATN, jointly and severally, shall: (i) indemnify and hold harmless each person who is at the date hereof or during the period from the date hereof through the date of the Effective Time serving as a director or officer of ATN or any of its Subsidiaries or as a fiduciary under or with respect to any employee benefit plan (within the meaning of Section 3(3) of ERISA) (collectively, the “Indemnified Parties”) to the fullest extent authorized or permitted by applicable Law, as now or hereafter in effect, in connection with any Claim and any losses, claims, damages, liabilities, costs, Indemnification Expenses, judgments, fines, penalties and amounts paid in settlement (including all interest, assessments and other charges paid or payable in connection with or in respect of any thereof) resulting therefrom; and (ii) promptly pay on behalf of or, within ten (10) days after any request for advancement, advance to each of the Indemnified Parties, any Indemnification Expenses incurred in defending, serving as a witness with respect to or otherwise participating with respect to any Claim in advance of the final disposition of such Claim, including payment on behalf of or advancement to the Indemnified Party of any Indemnification Expenses incurred by such Indemnified Party in connection with enforcing any rights with respect to such indemnification and/or advancement, in each case without the requirement of any bond or other security). The indemnification and advancement obligations of Parent and ATN pursuant to this Section 7.8(a) shall extend to acts or omissions occurring at or before the Effective Time and any Claim relating thereto (including with respect to any acts or omissions occurring in connection with the approval of this Agreement and the consummation of the Merger and the transactions contemplated by this Agreement, including the consideration and approval thereof and the process undertaken in connection therewith and any Claim relating thereto), and all rights to indemnification and advancement conferred hereunder shall continue as to a person who has ceased to be a director or officer of ATN or any of its Subsidiaries after the date hereof and shall inure to the benefit of such person’s heirs, executors and personal and legal representatives. As used in this Section 7.8(a): (x) the term “Claim” shall mean any threatened, asserted, pending or completed action, whether instituted by any party hereto, any Governmental Authority or any other person, that any Indemnified Party in good faith believes might lead to the institution of any Action, whether civil, criminal, administrative, investigative or other, including any arbitration or other alternative dispute resolution mechanism, arising out of or pertaining to matters that relate to such Indemnified Party’s duties or service as a director or officer of ATN, any of its Subsidiaries, or any employee benefit plan (within the meaning of Section 3(3) of ERISA) maintained by any of the foregoing at or prior to the Effective Time; and (y) the term “Indemnification Expenses” shall mean reasonable attorneys’ fees and all other reasonable costs, expenses and obligations (including experts’ fees, travel expenses, court costs, retainers, transcript fees, duplicating, printing and binding costs, as well as telecommunications, postage and courier charges) paid or incurred in connection with investigating, defending, being a witness in or participating in (including on appeal), or preparing to investigate, defend, be a witness in or participate in, any Claim for which indemnification is authorized pursuant to this Section 7.8(a), including any Claim relating to a claim for indemnification or advancement brought by an Indemnified Party. Neither Parent nor ATN shall settle, compromise or consent to the entry of any judgment in any actual or threatened Claim in respect of which indemnification has been or could be sought by such Indemnified Party hereunder unless such settlement, compromise or judgment includes an unconditional release of such Indemnified Party from all liability arising out of such Claim without admission or finding of wrongdoing, or such Indemnified Party otherwise consents thereto.

(b) Without limiting the foregoing, ATN, Parent and Merger Sub agree that all rights to indemnification, advancement of expenses and exculpation from liabilities for acts or omissions occurring at or prior to the Effective Time now existing in favor of the current or former directors or officers of ATN or any of its Subsidiaries as provided in the Operating Agreement (or, as applicable, the charter, bylaws, partnership agreement, limited liability company agreement, or other organizational documents of any of ATN’s Subsidiaries) and indemnification agreements of ATN or any of its Subsidiaries shall be assumed by the Surviving Entity in the Merger, without further action, at the Effective Time and shall survive the Merger and shall continue in full force and effect in accordance with their terms.

(c) For a period of six (6) years from the Effective Time, the limited liability company operating agreement or similar governing document of the Surviving Entity shall contain provisions no less favorable

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with respect to indemnification, advancement of expenses and limitations on liability of directors and officers than are set forth in the Operating Agreement, which provisions shall not be amended, repealed or otherwise modified for a period of six (6) years from the Effective Time in any manner that would affect adversely the rights thereunder of individuals who, at or prior to the Effective Time, were Indemnified Parties, unless such modification shall be required by Law and then only to the minimum extent required by Law.

(d) Parent shall, or shall cause the Surviving Entity to, maintain for a period of at least six (6) years following the Effective Time, the current policies of directors’ and officers’ liability insurance maintained by ATN and its Subsidiaries (provided, that the Surviving Entity may substitute therefor policies of at least the same coverage and amounts containing terms and conditions which are not less advantageous to such directors and officers of ATN than the terms and conditions of such existing policy from carriers with the same or better rating as the carrier under the existing policy provided that such substitution shall not result in gaps or lapses of coverage with respect to matters occurring before the Effective Time) with respect to claims arising from facts or events that occurred on or before the Effective Time, including in respect of the Merger and the transactions contemplated by this Agreement; provided, however, that Parent shall not be required to pay annual premiums in excess of 250% of the last annual premium paid by ATN prior to the date hereof but in such case shall purchase as much coverage as reasonably practicable for such amount.

(e) The provisions of Section 7.8(d) shall be deemed to have been satisfied if prepaid “tail” policies have been obtained by the Surviving Entity for purposes of this Section 7.8 from carriers with the same or better rating as the carrier of such insurances as of the date of this Agreement, which policies provide such directors and officers with the coverage described in Section 7.8(d) for an aggregate period of not less than six (6) years with respect to Claims arising from facts or events that occurred on or before the Effective Time, including, in respect of the Merger and the transactions contemplated by this Agreement.

(f) If the Surviving Entity or any of its respective successors or assigns (i) consolidates with or merges with or into any other Person and shall not be the continuing or surviving corporation, partnership or other entity of such consolidation or merger or (ii) transfers or conveys all or substantially all of its properties and assets to any Person, then, and in each such case, proper provision shall be made so that the successors and assigns of the Surviving Entity assume the obligations set forth in this Section 7.8.

(g) Parent shall cause the Surviving Entity to perform all of the obligations of the Surviving Entity under this Section 7.8.

(h) This Section 7.8 shall survive the consummation of the Merger and is intended to be for the benefit of, and shall be enforceable by, the Indemnified Parties and their respective heirs and personal representatives, and shall be binding on the Surviving Entity and its successors and assigns.

Section 7.9Comfort Letters.

(a) ATN shall use all commercially reasonable efforts to cause to be delivered to Parent a “comfort” letter of Grant Thornton LLP, ATN’s independent public accountants, dated and delivered the date on which the Registration Statement shall become effective, in form and substance reasonably satisfactory to the Parent Board and customary in scope and substance for letters delivered by independent public accountants in connection with registration statements similar to the Registration Statement.

(b) Parent shall use all commercially reasonable efforts to cause to be delivered to ATN a “comfort” letter of Grant Thornton LLP, Parent’s independent public accountants, dated and delivered the date on which the Registration Statement shall become effective, in form and substance reasonably satisfactory to the ATN Special Committee and customary in scope and substance for letters delivered by independent public accountants in connection with registration statements similar to the Registration Statement.

Section 7.10Rule 16b-3. Prior to the Effective Time, ATN shall take all such actions as may be reasonably requested by any party hereto to cause dispositions of ATN equity securities (including derivative securities)

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pursuant to the transactions contemplated by this Agreement by each individual who is a director or officer of ATN to be exempt under Rule 16b-3 promulgated under the Exchange Act, including actions in accordance with that certain No-Action Letter dated January 12, 1999 issued by the SEC regarding such matters.

Section 7.11Board Membership. Prior to the mailing of the Joint Proxy Statement, ATN shall designate in its sole discretion four (4) members from among the current members of the ATN Board, all of whom must be independent within the meaning ascribed thereto by NASDAQ (the “ATN Director Designees”) to serve as members of the Parent Board following the Effective Time. Subject to the foregoing, the parties shall take such action as is necessary to cause the ATN Director Designees to be appointed to the Parent Board effective as of the Effective Time, to serve until the earlier of such individual’s resignation or removal or until his successor is duly elected and qualified.

Section 7.12Name Change. At the Effective Time, Parent shall cause its name to be changed to “Atlas Energy, Inc.” or such other name as mutually agreed by Parent and ATN.

ARTICLE VIII

CONDITIONS TO CONSUMMATION OF THE MERGER

The obligations of each of the parties to consummate the Merger are conditioned upon the satisfaction (or, in the case of Sections 8.3, 8.4 or 8.5, waiver by both Parent and ATN; or, in the case of Sections 8.6 or 8.9, waiver by ATN; or, in the case of Sections 8.7 or 8.10, waiver by Parent) at or prior to the Closing of each of the following:

Section 8.1Parent Stockholder Approval. (a) The Stock Issuance shall have been approved by the affirmative vote of the holders of a majority of the shares of Parent Common Stock voted at the Parent Meeting and (b) the Charter Amendment shall have been approved and adopted by the affirmative vote of the holders of a majority of the shares of Parent Common Stock outstanding and entitled to vote thereon at the Parent Meeting (clauses (a) and (b), collectively, the “Parent Stockholder Approval”), and

Section 8.2ATN Equityholder Approval. The Merger and this Agreement and the other transactions contemplated hereby shall have been approved and adopted by the affirmative vote of (a) a Class A Unit Majority (as defined in the Operating Agreement) and (b) an ATN Common Unit Majority (as defined in the Operating Agreement) (clauses (a) and (b), collectively, the “ATN Unitholder Approval”).

Section 8.3Amendment of the ATN Credit Agreement. The parties shall have obtained Consent under the ATN Credit Agreement.

Section 8.4Governmental Approvals. Any waiting period (including any extended waiting period arising as a result of a request for additional information and documentary material by the Federal Trade Commission or the U.S. Department of Justice) under the HSR Act shall have expired or been terminated. All other filings required to be made prior to the Effective Time with, and all other consents, approvals, permits and authorizations required to be obtained prior to the Effective Time from, any Governmental Authority in connection with the execution and delivery of this Agreement and the consummation of the transactions contemplated hereby by the parties hereto or their Affiliates shall have been made or obtained, except where the failure to obtain such consents, approvals, permits and authorizations would not be reasonably likely to result in an ATN Material Adverse Effect or Parent Material Adverse Effect.

Section 8.5No Injunction. (a) No order, decree or injunction of any court or agency of competent jurisdiction shall be in effect, and no Law shall have been enacted or adopted, that enjoins, prohibits or makes illegal consummation of any of the transactions contemplated hereby, and (b) no action, proceeding or investigation by any Governmental Authority with respect to the Merger or the other transactions contemplated

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hereby shall be pending that seeks to restrain, enjoin, prohibit or delay consummation of the Merger or such other transaction or to impose any material restrictions or requirements thereon or on Parent or ATN with respect thereto; provided, however, that prior to invoking this condition, each party shall have complied fully with its obligations under Section 7.1.

Section 8.6Representations, Warranties and Covenants of Parent and Merger Sub. In the case of ATN’s obligation to consummate the Merger, unless waived, in whole or in part, by ATN:

(a)(i) the representations and warranties contained in Section 5.14 of this Agreement shall be true and correct as of the date specified therein in all material respects, (ii) the representations and warranties contained in Section 5.3(a) of this Agreement shall be true and correct in all material respects; and (iii) each of the other representations and warranties contained herein of Parent and Merger Sub shall be true and correct, in each case in the cases of clauses (ii) and (iii), as of the date of this Agreement and as of the Closing Date with the same effect as though all such representations and warranties had been made on the Closing Date, except for any such representations and warranties made as of a specified date, which shall be true and correct as of such date, except, in the case of clause (iii), where the failure of any such representations and warranties to be so true and correct (without giving effect to any qualification as to materiality or a Parent Material Adverse Effect) would not, individually or in the aggregate, have a Parent Material Adverse Effect;

(b) each and all of the agreements and covenants of Parent and Merger Sub to be performed and complied with pursuant to this Agreement on or prior to the Closing Date shall have been duly performed and complied with in all material respects; and

(c) ATN shall have received a certificate signed by an executive officer of Parent, dated the Closing Date, to the effect set forth in Section 8.5(a) and Section 8.5(b).

Section 8.7Representations, Warranties and Covenants of ATN. In the case of Parent’s and Merger Sub’s obligations to consummate the Merger:

(a)(i) the representations and warranties contained in Section 4.3(a) of this Agreement shall be true and correct in all material respects; and (ii) each of the other representations and warranties contained herein of ATN shall be true and correct, in each case in the cases of clauses (i) and (ii), as of the date of this Agreement and as of the Closing Date with the same effect as though all such representations and warranties had been made on the Closing Date, except for any such representations and warranties made as of a specified date, which shall be true and correct as of such date, except, in the case of clause (ii), where the failure of any such representations and warranties to be so true and correct (without giving effect to any qualification as to materiality or a ATN Material Adverse Effect) would not, individually or in the aggregate, have a ATN Material Adverse Effect;

(b) each and all of the agreements and covenants of ATN to be performed and complied with pursuant to this Agreement on or prior to the Closing Date shall have been duly performed and complied with in all material respects; and

(c) Parent shall have received a certificate signed by an executive officer of ATN, dated the Closing Date, to the effect set forth in Section 8.6(a) and Section 8.6(b).

Section 8.8Effective Registration Statement. The Registration Statement shall have become effective under the Securities Act and no stop order suspending the effectiveness of the Registration Statement shall have been issued and no proceedings for that purpose shall have been initiated or threatened by the SEC or any other Governmental Authority.

Section 8.9Amendment of Parent Certificate of Incorporation; NASDAQ Listing. In the case of ATN’s obligation to consummate the Merger, (a) Parent shall have amended its certificate of incorporation to authorize

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the issuance of additional shares of Parent Common Stock as necessary for the Stock Issuance and (b) the shares of Parent Common Stock issuable pursuant to this Agreement shall have been approved for listing on NASDAQ, subject to official notice of issuance.

Section 8.10Resignation of the ATN Board. In the case of Parent’s obligation to consummate the Merger, ATN shall have received resignations for all of the directors on the ATN Board.

ARTICLE IX

TERMINATION

Section 9.1Termination. Notwithstanding anything herein to the contrary, this Agreement may be terminated and the Merger may be abandoned at any time prior to the Effective Time whether before or after the ATN Unitholder Approval or Parent Stockholder approval:

(a) By the mutual consent of Parent and ATN in a written instrument;

(b) By either ATN or Parent upon written notice to the other, if:

(i) the Merger has not been consummated on or before February 28, 2010 (the “Termination Date”); provided, however, that the right to terminate this Agreement pursuant to this Section 9.1(b)(i) shall not be available to a party whose failure to fulfill any obligation under this Agreement or other breach of this Agreement has been a cause of, or resulted in, the failure of the Merger to have been consummated on or before such date;

(ii) any Governmental Authority has issued a statute, rule, order, decree or regulation or taken any other action permanently restraining, enjoining or otherwise prohibiting the consummation of the Merger or making the Merger illegal and such statute, rule, order, decree, regulation or other action shall have become final and nonappealable (provided that the terminating party has complied with its obligations hereunder);

(iii) ATN fails to obtain the ATN Unitholder Approval at the ATN Meeting;

(iv) there has been a material breach of or any inaccuracy in any of the representations or warranties set forth in this Agreement on the part of any of the other parties (treating Parent and Merger Sub as one party for the purposes of this Section 9.1), which breach is not cured within 30 days following receipt by the breaching party of written notice of such breach from the terminating party, or which breach, by its nature, cannot be cured prior to the Termination Date (provided in any such case that the terminating party is not then in material breach of any representation, warranty, covenant or other agreement contained herein); provided, however, that no party shall have the right to terminate this Agreement pursuant to this Section 9.1(b)(iv) unless (x) the breach of representation or warranty, together with all other such breaches, would entitle the party receiving such representation not to consummate the transactions contemplated by this Agreement under Section 8.5 (in the case of a breach of representation or warranty by Parent or Merger Sub) or Section 8.6 (in the case of a breach of representation or warranty by ATN), and (y) such terminating party is not in material breach of this Agreement;

(v) if there has been a material breach of any of the covenants or agreements set forth in this Agreement on the part of any of the other parties, which breach has not been cured within 30 days following receipt by the breaching party of written notice of such breach from the terminating party, or which breach, by its nature, cannot be cured prior to the Termination Date (provided in any such case that the terminating party is not then in material breach of any representation, warranty, covenant or other agreement contained herein); provided, however, that no party shall have the right to terminate this Agreement pursuant to this Section 9.1(b)(v) unless (x) the breach of covenants or agreements, together with all other such breaches, would entitle the party receiving the benefit of such covenants or

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agreements not to consummate the transactions contemplated by this Agreement under Section 8.5 (in the case of a breach of covenants or agreements by Parent or Merger Sub) or Section 8.6. (in the case of a breach of covenants or agreements by ATN), and (y) such terminating party is not in material breach of this Agreement; or

(vi) Parent fails to obtain the Parent Stockholder Approval at the Parent Meeting;

(c) By ATN (with the prior approval of the ATN Special Committee), upon written notice to Parent, in the event that a Parent Change in Recommendation has occurred; or

(d) By Parent, upon written notice to ATN, in the event that an ATN Change in Recommendation has occurred.

Section 9.2Effect of Termination. In the event of the termination of this Agreement as provided in Section 9.1, written notice thereof shall forthwith be given by the terminating party to the other parties specifying the provision of this Agreement pursuant to which such termination is made, and except as provided in this Section 9.2, this Agreement (other than Article X) shall forthwith become null and void after the expiration of any applicable period following such notice. In the event of such termination, there shall be no liability on the part of Parent, Merger Sub or ATN; provided, however, that nothing herein shall relieve any party from any liability or obligation with respect to any fraud or intentional breach of this Agreement.

ARTICLE X

MISCELLANEOUS

Section 10.1Fees and Expenses.

(a) Whether or not the Merger is consummated, except as set forth in Section 10.1(b), all costs and expenses incurred in connection with this Agreement and the transactions contemplated hereby shall be paid by the party incurring such costs or expenses.

(b)(i) If the Merger is consummated, the Surviving Entity shall pay, or cause to be paid, any and all property or transfer Taxes imposed on Parent, Merger Sub or the Surviving Entity in connection with the Merger, (ii) expenses incurred in connection with filing, printing and mailing the Joint Proxy Statement and the Registration Statement shall be shared equally by Parent and ATN and (iii) filing fees payable pursuant to the HSR Act, regulatory Laws and other filing fees incurred in connection with this Agreement shall be shared equally by Parent and ATN.

(c) This Section 10.1 shall survive any termination of this Agreement.

Section 10.2Waiver; Amendment. Subject to compliance with applicable Law, prior to the Closing, any provision of this Agreement may be (a) waived in writing by the party benefited by the provision and approved by the ATN Special Committee in the case of ATN and by the Parent and executed in the same manner as this Agreement, or (b) amended or modified at any time, whether before or after the ATN Unitholder Approval, by an agreement in writing between the parties hereto approved by the ATN Special Committee in the case of ATN and by the Parent and executed in the same manner as this Agreement;provided, however, that after the ATN Unitholder Approval, no amendment shall be made that requires further ATN Unitholder Approval without such further approval.

Section 10.3Counterparts. This Agreement may be executed in one or more counterparts, each of which shall be deemed to constitute an original.

Section 10.4Governing Law. This Agreement shall be governed by, and interpreted in accordance with, the Laws of the State of Delaware, without regard to the conflict of Law principles thereof (except to the extent that mandatory provisions of federal or Delaware Law govern).

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Section 10.5 Notices. All notices, requests and other communications hereunder to a party shall be in writing and shall be deemed given if personally delivered, telecopied (with confirmation) or mailed by registered or certified mail (return receipt requested) to such party at its address set forth below or such other address as such party may specify by notice to the parties hereto.

If to Parent, to:

Atlas America, Inc.

Attn: General Counsel

Westpointe Corporate Center One

1550 Coraopolis Heights Road

Moon Township, PA

Fax: (215) 761-0457

With copies to:

Wachtell, Lipton, Rosen & Katz

Attn: Mark Gordon

         David K. Lam

51 West 52nd Street

New York, New York 10019

Fax: (212) 403-2000

If to ATN, to:

Atlas Energy Resources, LLC

Attn: General Counsel

Westpointe Corporate Center One

1550 Coraopolis Heights Road

Moon Township, PA

Fax: (215) 761-0457

With copies to:

Chairman of the ATN Special Committee

Ellen F. Warren

OutSource Communications

1003 Wellington Road

Jenkintown, PA 19046

Fax: (215) 886-6926

K&L Gates LLP

Attn: Michael C. McLean

H. W. Oliver Building

535 Smithfield Street

Pittsburgh, PA 15222

Fax: (412) 355-6501

Jones Day

Attn: Jeff Schlegel

717 Texas

Suite 3300

Houston, Texas 77002

Fax: (832) 239-3600

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Section 10.6Entire Understanding; No Third Party Beneficiaries. This Agreement represents the entire understanding of the parties hereto with reference to the transactions contemplated hereby and supersedes any and all other oral or written agreements heretofore made. Except as contemplated by Section 7.8, nothing in this Agreement, expressed or implied, is intended to confer upon any person, other than the parties hereto or their respective successors, any rights, remedies, obligations or liabilities under or by reason of this Agreement.

Section 10.7Severability. Any provision of this Agreement which is invalid, illegal or unenforceable in any jurisdiction shall, as to that jurisdiction, be ineffective to the extent of such invalidity, illegality or unenforceability, without affecting in any way the remaining provisions hereof in such jurisdiction or rendering that or any other provision of this Agreement invalid, illegal or unenforceable in any other jurisdiction.

Section 10.8 Headings. The headings contained in this Agreement are for reference purposes only and are not part of this Agreement.

Section 10.9 Jurisdiction. The parties hereto agree that any suit, action or proceeding seeking to enforce any provision of, or based on any matter arising out of or in connection with, this Agreement or the transactions contemplated hereby shall be brought in any federal court located in the State of Delaware or the Delaware Court of Chancery, and each of the parties hereby irrevocably consents to the jurisdiction of such courts (and of the appropriate appellate courts therefrom) in any such suit, action or proceeding and irrevocably waives, to the fullest extent permitted by Law, any objection that it may now or hereafter have to the laying of the venue of any such suit, action or proceeding in any such court or that any such suit, action or proceeding brought in any such court has been brought in an inconvenient forum. Process in any such suit, action or proceeding may be served on any party anywhere in the world, whether within or without the jurisdiction of any such court. Without limiting the foregoing, each party agrees that service of process on such party as provided in Section 10.6 shall be deemed effective service of process on such party.

Section 10.10 Waiver of Jury Trial. EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY WAIVES ANY AND ALL RIGHT TO TRIAL BY JURY IN ANY LEGAL PROCEEDING ARISING OUT OF OR RELATED TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY.

Section 10.11 Specific Performance. The parties agree that irreparable damage would occur if any provision of this Agreement were not performed in accordance with the terms hereof and, accordingly, that the parties shall be entitled to an injunction or injunctions to prevent breaches of this Agreement or to enforce specifically the performance of the terms and provisions hereof in any federal court located in the State of Delaware or in the Delaware Court of Chancery, in addition to any other remedy to which they are entitled at Law or in equity.

Section 10.12Scope of Representations and Warranties.

(a) Except as and to the extent expressly set forth in this Agreement, ATN makes no, and disclaims any, representations or warranties whatsoever, whether express or implied. ATN disclaims all liability or responsibility for any other statement or information made or communicated (orally or in writing) to Merger Sub, Parent, their Affiliates or any stockholder, officer, director, employee, representative, consultant, attorney, agent, lender or other advisor of Merger Sub, Parent or their Affiliates (including, but not limited to, any opinion, information or advice which may have been provided to any such person by any Representative of ATN or any other person or contained in the files or records of ATN), wherever and however made.

(b) Except as and to the extent expressly set forth in this Agreement Parent does not make and disclaims, any representations or warranties whatsoever, whether express or implied. Each of Merger Sub and Parent disclaims all liability and responsibility for any other statement or information made or communicated (orally or in writing) to ATN, its Affiliates or any member, officer, director, employee, representative, consultant, attorney, agent, lender or other advisor of ATN or its Affiliates (including, but not limited to, any opinion, information or advice which may have been provided to any such person by any Representative Parent or any other person), wherever and however made.

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(c) Any representation “to the knowledge” or “to the best knowledge” of a party or phrases of similar wording shall be limited to matters within the actual conscious awareness of the executive officers of such party and any manager or managers of such party who have primary responsibility for the substantive area or operations in question and who report directly to such executive officers after reasonable inquiry.

Section 10.13 Survival. All representations, warranties, agreements and covenants contained in this Agreement shall not survive the Closing or the termination of this Agreement if this Agreement is terminated prior to the Closing; provided, however, that if the Closing occurs, the agreements of the parties in Sections 3.2, 3.6, 7.8 and Article X shall survive the Closing, and if this Agreement is terminated prior to the Closing, the agreements of the parties in Section 7.5(b), 9.2, and Article X shall survive such termination.

Section 10.14Confidentiality. Except for disclosures (i) approved by (A) with respect to any disclosure by Parent or any of its Subsidiaries, ATN, or (B) with respect to any disclosure by ATN or any of its Subsidiaries, Parent, or (B) as otherwise contemplated by this Agreement (including Section 7.2(c)) or required by applicable Law, none of the parties to this Agreement shall, and shall cause their Affiliates and representatives not to, publicly disclose any confidential information or materials of the other party whether relating to the transactions contemplated by this Agreement or otherwise. Notwithstanding the foregoing, this Section 10.14 shall not prohibit a Person from making any disclosure which, in the reasonable opinion of such Person’s outside legal counsel, is required to avoid a violation of applicable Law by such Person, in which event the Person required to make such disclosure shall do so only to the limited extent necessary to comply with such Law and shall give advance notice thereof to the other Parties and an opportunity to comment on any such disclosure and oppose the need therefor.

Section 10.15Interpretation.

(a) When a reference is made in this Agreement to Articles, Sections, Exhibits, Annexes or Schedules, such reference shall be to an Article or Section of or Exhibit, Annex or Schedule to this Agreement unless otherwise indicated. The table of contents and headings contained in this Agreement are for reference purposes only and shall not affect in any way the meaning or interpretation of this Agreement. Whenever the words “include,” “includes” or “including” are used in this Agreement, they shall be deemed to be followed by the words “without limitation.” The words “hereby,” “herein,” “hereof” or “hereunder,” and similar terms are to be deemed to refer to this Agreement as a whole and not to any specific section. The inclusion of any information in either the ATN Disclosure Schedule or the Parent Disclosure Schedule to this Agreement (as the case may be) shall not be deemed an admission or acknowledgment, solely by virtue of the inclusion of such information therein, that such information is required to be included therein or material to ATN or any of its Subsidiaries, or Parent or any of its Subsidiaries, as the case may be. The disclosure of information in the ATN Disclosure Schedule or the Parent Disclosure Schedule as an exception to, or for purposes of, a representation, warranty or covenant in this Agreement shall be deemed adequately disclosed as an exception to, or for purposes of, all other representations, warranties and covenants herein. The specification of any dollar amount in the representations and warranties or otherwise in this Agreement or in the ATN Disclosure Schedule or Parent Disclosure Schedule is not intended and shall not be deemed to be an admission or acknowledgment of the materiality of such amounts or items, nor shall the same be used in any dispute or controversy between the parties to determine whether any obligation, item or matter (whether or not described herein or included in any schedule) is or is not material for purposes of this Agreement.

(b) The parties have participated jointly in negotiating and drafting this Agreement. In the event that an ambiguity or a question of intent or interpretation arises, this Agreement shall be construed as if drafted jointly by the parties, and no presumption or burden of proof shall arise favoring or disfavoring any party by virtue of the authorship of any provision of this Agreement.

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IN WITNESS WHEREOF, the parties hereto have caused this instrument to be executed in counterparts by their duly authorized officers, all as of the day and year first above written.

ATLAS ENERGY RESOURCES, LLC
By:	/S/    RICHARD D. WEBER
Name:	Richard D. Weber
Title:	President and Chief Operating Officer
ATLAS AMERICA, INC.
By:	/S/    EDWARD E. COHEN
Name:	Edward E. Cohen
Title:	Chief Executive Officer and President
ATLAS ENERGY MANAGEMENT, INC.
By:	/S/    EDWARD E. COHEN
Name:	Edward E. Cohen
Title:	Chief Executive Officer and President

Annex B

J.P.Morgan

April 26, 2009

The Board of Directors

Atlas America, Inc.

Westpointe Corporate Center One

1550 Coraopolis Heights Road

Moon Township, PA

Members of the Board of Directors:

You have requested our opinion as to the fairness, from a financial point of view, to Atlas America, Inc. (the “Company”) of the Exchange Ratio (as defined below) in the proposed merger (the “Transaction”) of a wholly-owned subsidiary of the Company with Atlas Energy Resources, LLC, (the “Merger Partner”). Pursuant to the Agreement and Plan of Merger, dated as of April 27, 2009 (the “Agreement”), among the Company, the Merger Partner and from and after its accession to the Agreement in accordance with the terms thereof, the Delaware limited liability company to be formed as a wholly-owned subsidiary of Parent, the Merger Partner will become a wholly-owned subsidiary of the Company, and each common unit of the Merger Partner (the “Merger Partner Common Units”) (other than Merger Partner Common Units held in treasury or owned by the Company and its Subsidiaries), including the ATN Restricted Units (as defined in the Agreement), will be converted into the right to receive 1.16 shares (the “Exchange Ratio”) of the Company’s common stock, par value $0.01 per share (the “Company Common Stock”).

In arriving at our opinion, we have (i) reviewed a draft dated April 26, 2009 of the Agreement; (ii) reviewed certain publicly available business and financial information concerning the Merger Partner and the Company and the industries in which they operate; (iii) compared the financial and operating performance of the Merger Partner and the Company with publicly available information concerning certain other companies we deemed relevant and reviewed the current and historical market prices of the Merger Partner Common Units and the Company Common Stock and certain publicly traded securities of such other companies; (iv) reviewed certain internal financial analyses and forecasts prepared by or at the direction of the managements of the Merger Partner and the Company relating to their respective businesses; and (v) performed such other financial studies and analyses and considered such other information as we deemed appropriate for the purposes of this opinion.

In addition, we have held discussions with certain members of the management of the Merger Partner and the Company with respect to certain aspects of the Transaction, and the past and current business operations of the Merger Partner and the Company, the financial condition and future prospects and operations of the Merger Partner and the Company, the effects of the Transaction on the financial condition and future prospects of the Company, and certain other matters we believed necessary or appropriate to our inquiry.

In giving our opinion, we have relied upon and assumed the accuracy and completeness of all information that was publicly available or was furnished to or discussed with us by the Merger Partner and the Company or otherwise reviewed by or for us, and we have not independently verified (nor have we assumed responsibility or liability for independently verifying) any such information or its accuracy or completeness. We have not conducted or been provided with any valuation or appraisal of any assets or liabilities, nor have we evaluated the solvency of the Merger Partner or the Company under any state or federal laws relating to bankruptcy, insolvency or similar matters. In relying on financial analyses and forecasts provided to us or derived therefrom, we have assumed that they have been reasonably prepared based on assumptions reflecting the best currently available estimates and judgments by management as to the expected future results of operations and financial

383 Madison Avenue, New York, New York 10179

J.P. Morgan Securities Inc.

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condition of the Merger Partner and the Company to which such analyses or forecasts relate. We express no view as to such analyses or forecasts or the assumptions on which they were based. We have also assumed that the Transaction and the other transactions contemplated by the Agreement will have the tax consequences described in discussions with, and materials furnished to us by, representatives of the Company, and will be consummated as described in the Agreement, and that the definitive Agreement will not differ in any material respects from the draft thereof furnished to us. We have also assumed that the representations and warranties made by the Company and the Merger Partner in the Agreement and the related agreements are and will be true and correct in all ways material to our analysis. We are not legal, regulatory or tax experts and have relied on the assessments made by advisors to the Company with respect to such issues. We have further assumed that all material governmental, regulatory or other consents and approvals (including the amendments to any credit facilities) necessary for the consummation of the Transaction will be obtained without any adverse effect on the Merger Partner or the Company or on the contemplated benefits of the Transaction.

Our opinion is necessarily based on economic, market and other conditions as in effect on, and the information made available to us as of, the date hereof. It should be understood that subsequent developments may affect this opinion and that we do not have any obligation to update, revise, or reaffirm this opinion. Our opinion is limited to the fairness, from a financial point of view, to the Company of the Exchange Ratio in the proposed Transaction and we express no opinion as to the fairness of the Transaction to the holders of any class of securities, creditors or other constituencies of the Company or as to the underlying decision by the Company to engage in the Transaction. Furthermore, we express no opinion with respect to the amount or nature of any compensation to any officers, directors, or employees of any party to the Transaction, or any class of such persons relative to the Exchange Ratio in the Transaction or with respect to the fairness of any such compensation. We are expressing no opinion herein as to the price at which the Merger Partner Common Units or the Company Common Stock will trade at any future time.

We have acted as financial advisor to the Company with respect to the proposed Transaction and will receive a fee from the Company for our services, a substantial portion of which will become payable only if the proposed Transaction is consummated. In addition, the Company has agreed to indemnify us for certain liabilities arising out of our engagement. During the two years preceding the date of this letter, we and our affiliates have had commercial or investment banking relationships with the Company, the Merger Partner and certain of their respective affiliates for which we and such of our affiliates have received customary compensation. Such services during such period have included acting as joint bookrunner for Atlas Pipeline Holdings LP in a $250 million bond offering in June 2008, co-manager and bookrunner for Atlas Pipeline Holdings LP in a $187.6 million follow-on equity offering in June 2008, lead bookrunner for Atlas Energy Resources LLC on bond offerings of $250 million and $150 million in January and May 2008, respectively, and agent bank and lender on the Company’s $850 million credit facility in June 2007. In addition, our banking affiliate is an agent bank and a lender under the Merger Partner’s $650 million senior secured revolving credit facility (the “Merger Partner Credit Facility”), for which it receives customary compensation or other financial benefits. It is anticipated that the Merger Partner Credit Facility will be amended in connection with the Transaction and that such amendment will result in the payment of customary compensation to our affiliate and in certain of the terms under the Merger Partner Credit Facility being amended to be more favorable to the lenders thereunder. In the ordinary course of our businesses, we and our affiliates may actively trade the debt and equity securities of the Company or the Merger Partner for our own account or for the accounts of customers and, accordingly, we may at any time hold long or short positions in such securities.

On the basis of and subject to the foregoing, it is our opinion as of the date hereof that the Exchange Ratio in the proposed Transaction is fair, from a financial point of view, to the Company.

The issuance of this opinion has been approved by a fairness opinion committee of J.P. Morgan Securities Inc. This letter is provided to the Board of Directors of the Company in connection with and for the purposes of its evaluation of the Transaction. This opinion does not constitute a recommendation to any shareholder of the Company as to how such shareholder should vote with respect to the Transaction or any other matter. This

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opinion may not be disclosed, referred to, or communicated (in whole or in part) to any third party for any purpose whatsoever except with our prior written approval. This opinion may be reproduced in full in any proxy or information statement mailed to shareholders of the Company but may not otherwise be disclosed publicly in any manner without our prior written approval.

Very truly yours,

/s/ J.P. Morgan Securities Inc.

J.P. MORGAN SECURITIES INC.

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Annex C

[LETTERHEAD OF UBS SECURITIES LLC]

April 27, 2009

The Special Committee of the Board of Directors

Atlas Energy Resources, LLC

1845 Walnut Street, Suite 1000

Philadelphia, Pennsylvania 19103

Dear Members of the Special Committee:

We understand that Atlas Energy Resources, LLC, a Delaware limited liability company (“Atlas Energy”), is considering a transaction whereby a Delaware limited liability company (“Merger Sub”) to be formed as a wholly owned subsidiary of Atlas America, Inc. (“Atlas America”), a Delaware corporation, will merge with and into Atlas Energy (the “Transaction”). Pursuant to the terms of an Agreement and Plan of Merger, draft dated April 27, 2009 (the “Merger Agreement”), among Atlas Energy, Atlas America, Atlas Energy Management, Inc. and, after its formation, Merger Sub, each outstanding common unit of Atlas Energy (collectively, “Atlas Energy Class B Units”), other than Atlas Energy Class B Units held by Atlas America or its subsidiaries, will be converted into the right to receive 1.16(the “Exchange Ratio”) shares of the common stock, par value $0.01 per share, of Atlas America (“Atlas America Common Stock”). The terms and conditions of the Transaction are more fully set forth in the Merger Agreement.

You have requested our opinion as to the fairness, from a financial point of view, to the holders of Atlas Energy Class B Units (other than Atlas America, officers and directors of Atlas Energy and Atlas America and their respective affiliates (collectively, “Excluded Holders”)) of the Exchange Ratio provided for in the Transaction.

UBS Securities LLC (“UBS”) has acted as financial advisor to the Special Committee of the Board of Directors of Atlas Energy in connection with the Transaction and will receive a fee for its services, a portion of which is payable in connection with this opinion and a significant portion of which is contingent upon consummation of the Transaction. UBS and its affiliates in the past have provided services to Atlas Energy and affiliates of Atlas Energy and Atlas America, and currently are providing services to an affiliate of Atlas Energy and Atlas America, unrelated to the proposed Transaction, for which UBS and its affiliates received and expect to receive compensation, including acting as financial advisor to an affiliate of Atlas Energy and Atlas America in connection with a pending disposition transaction and having acted as (i) financial advisor to Atlas Energy in connection with an acquisition transaction in 2007, (ii) placement agent for block trades and private placements of equity securities of Atlas Energy and affiliates of Atlas Energy and Atlas America in 2007 and 2008 and (iii) joint bookrunner for a public offering of equity securities of an affiliate of Atlas Energy and Atlas America in 2008. In addition, an affiliate of UBS in the past has been and currently is a participant in credit facilities of Atlas Energy, for which such affiliate of UBS received and continues to receive fees and interest payments.In the ordinary course of business, UBS and its affiliates may hold or trade, for their own accounts and the accounts of their customers, securities of Atlas Energy, Atlas America and certain affiliates of Atlas Energy and Atlas America and, accordingly, may at any time hold a long or short position in such securities. The issuance of this opinion was approved by an authorized committee of UBS.

Our opinion does not address the relative merits of the Transaction as compared to other business strategies or transactions that might be available with respect to Atlas Energy or Atlas Energy’s underlying business decision to effect the Transaction. Our opinion does not constitute a recommendation to any security holderof Atlas Energy as to how such security holder should vote or act with respect to the Transaction. At your direction, we have not been asked to, nor do we, offer any opinion as to the terms, other than the Exchange Ratio to the extent expressly specified herein, of the Merger Agreement or the form of the Transaction. In addition, we express no opinion as to the fairness of the amount or nature of any compensation to be received by any officers,

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The Special Committee of the Board of Directors

Atlas Energy Resources, LLC

April 27, 2009

Page 2

directors or employees of any parties to the Transaction, or any class of such persons, relative to the Exchange Ratio. We express no opinion as to what the value of Atlas America Common Stock will be when issued pursuant to the Transaction or the prices at which Atlas America Common Stock or Atlas Energy Class B Units will trade at any time. In rendering this opinion, we have assumed, with your consent, that (i) the final executed form of the Merger Agreement will not differ in any material respect from the draft that we have reviewed, (ii) the parties to the Merger Agreement will comply with all material terms of the Merger Agreement and (iii) the Transaction will be consummated in accordance with the terms of the Merger Agreement without any adverse waiver or amendment of any material term or condition thereof. We have also assumed that all governmental, regulatory or other consents and approvals necessary for the consummation of the Transaction will be obtained without any material adverse effect on Atlas Energy, Atlas America or the Transaction. We have not been authorized to solicit and have not solicited indications of interest in a transaction with Atlas Energy from any party.

In arriving at our opinion, we have, among other things: (i) reviewed certain publicly available business and financial information relating to Atlas Energy and Atlas America, including publicly available gas reserve estimates of Atlas Energy; (ii) reviewed certain internal financial information and other data relating to the business and financial prospects of Atlas Energy that were not publicly available, including financial forecasts and estimates prepared by the management of Atlas Energy that you have directedus to utilize for purposes of our analysis; (iii) reviewed certain internal financial information and other data relating to the business and financial prospects of Atlas America that were not publicly available, including financial forecasts and estimates prepared by the management of Atlas America that you have directedus to utilize for purposes of our analysis; (iv) reviewed certain estimates of synergies prepared by the management of Atlas America that were not publicly available and that you have directed us to utilize for purposes of our analysis; (v) conducted discussions with members of the senior managements of Atlas Energy and Atlas America concerning the businesses and financial prospects of Atlas Energy and Atlas America; (vi) reviewed publicly available financial and stock market data with respect to certain other companies we believe to be generally relevant; (vii) reviewed current and historical market prices of Atlas Energy Class B Units, Atlas America Common Stock and publicly traded securities of certain affiliated entities in which Atlas America holds equity interests and/or for which it has guaranteed certain indebtedness; (viii) reviewed the Merger Agreement; and (ix) conducted such other financial studies, analyses and investigations, and considered such other information, as we deemed necessary or appropriate.

In connection with our review, with your consent, we have assumed and relied upon, without independent verification, the accuracy and completeness in all material respects of the information provided to or reviewed by us for the purpose of this opinion. In addition, with your consent, we have not made any independent evaluation or appraisal of any of the assets or liabilities (contingent or otherwise) of Atlas Energy, Atlas America or any affiliated entity, nor have we been furnished with any such evaluation or appraisal. With respect to the financial forecasts and estimates, gas reserve estimates and synergies referred to above, we have assumed, at your direction, that they have been reasonably prepared on a basis reflecting the best currently available estimates and judgments of the managements of Atlas Energy and Atlas America as to the future financial performance of Atlas Energy and Atlas America, the gas reserves of Atlas Energy and such synergies. In addition, we have assumed with your approval that the financial forecasts and estimates, including synergies, referred to above will be achieved at the times and in the amounts projected. We are not experts in the evaluation of gas reserves and we express no view as to the reserve quantities, or the development or production (including, without limitation, as to the feasibility or timing thereof), of any gas properties of Atlas Energy. We have relied, without independent verification, upon the assessments of the managements of Atlas Energy and Atlas America as to market trends and prospects relating to the natural gas industry and the potential impact of such trends and prospects on Atlas Energy and Atlas America, including the assumptions of such managements as to future

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The Special Committee of the Board of Directors

Atlas Energy Resources, LLC

April 27, 2009

Page 3

commodity prices reflected in the financial forecasts and estimates utilized in our analyses, which prices are subject to significant volatility and which, if different than as assumed, could have a material impact on our opinion. Our opinion is necessarily based on economic, monetary, market and other conditions as in effect on, and the information available to us as of, the date hereof.

Based upon and subject to the foregoing, it is our opinion that, as of the date hereof, the Exchange Ratio provided for in the Transaction is fair, from a financial point of view, to the holders of Atlas Energy Class B Units (other than Excluded Holders).

This opinion is provided for the benefit of the Special Committee of the Board of Directors in connection with, and for the purpose of, its evaluation of the Exchange Ratio in the Transaction.

Very truly yours,

/s/ UBS Securities LLC

UBS SECURITIES LLC

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Annex D

ATLAS AMERICA, INC.

2009 STOCK INCENTIVE PLAN

SECTION 1. Purpose; Definition

The purpose of this Plan is to give the Company a competitive advantage in attracting, retaining and motivating officers, employees, directors and/or consultants and to provide the Company and its Subsidiaries and Affiliates with a stock and incentive plan providing incentives directly linked to stockholder value. Certain terms used herein have definitions given to them in the first place in which they are used. In addition, for purposes of this Plan, the following terms are defined as set forth below:

(a) “Affiliate” means a corporation or other entity controlled by, controlling or under common control with, the Company.

(b) “Applicable Exchange” means NASDAQ or such other securities exchange as may at the applicable time be the principal market for the Common Stock.

(c) “Award” means an Option, Stock Appreciation Right, Share of Restricted Stock, Restricted Stock Unit, Deferred Unit or other stock-based award granted pursuant to the terms of this Plan.

(d) “Award Agreement” means a written or electronic document or agreement setting forth the terms and conditions of a specific Award.

(e) “Beneficial Ownership” shall have the meaning given in Rule 13d-3 promulgated under the Exchange Act.

(f) “Board” means the Board of Directors of the Company.

(g) “Change in Control” shall mean the occurrence of any of the following events:

(i) an acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act) (a “Person”) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20% or more of either (A) the then outstanding shares of common stock of the Company (the “Outstanding Company Common Stock”) or (B) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the “Outstanding Company Voting Securities”);provided,however, that, for purposes of this Section 1(g), the following acquisitions shall not constitute a Change of Control: (A) any acquisition directly from the Company, other than an acquisition by virtue of the exercise of a conversion privilege unless the security being so converted was itself acquired directly from the Company, (B) any acquisition by the Company, (C) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or an Affiliate, or (D) any acquisition pursuant to a transaction which complies with clauses (A), (B) and (C) of Section 1(g)(iii);

(ii) a change in the composition of the Board such that the individuals who, as of the effective date of the Plan, constitute the Board (such Board shall be hereafter referred to as the “Incumbent Board”) cease for any reason to constitute at least a majority of the Board;provided,however, for purposes of this Section 1(g), that any individual who becomes a member of the Board subsequent to the effective date of the Plan, whose election, or nomination for election by the Company’s stockholders, was approved by a vote of at least a majority of those individuals who are members of the Board and who were also members of the Incumbent Board (or deemed to be such pursuant to this proviso) shall be considered as though such individual were a member of the Incumbent Board;provided,further, that any such individual whose initial

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assumption of office occurs as a result of either an actual or threatened election contest (as such terms are used in Rule 14a-11 of Regulation 14A promulgated under the Exchange Act) or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board shall not be so considered as a member of the Incumbent Board;

(iii) consummation of a reorganization, merger, statutory share exchange or consolidation or similar transaction involving the Company or any of its subsidiaries, a sale or other disposition of all or substantially all of the assets of the Company, or the acquisition of assets or securities of another entity by the Company or any of its subsidiaries (each, a “Business Combination”), in each case unless, following such Business Combination, (A) all or substantially all of the individuals and entities who are the beneficial owners of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such Business Combination will beneficially own, directly or indirectly, more than 50% of, respectively, the outstanding shares of common stock (or, for a non-corporate entity, equivalent securities) and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors (or, for a non-corporate entity, equivalent governing body), as the case may be, of the entity resulting from such Business Combination (including, without limitation, an entity that, as a result of such transaction, owns the Company or all or substantially all of the Company’s assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination, of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (B) no Person (other than the Company, any employee benefit plan (or related trust) of the Company or such entity resulting from such Business Combination) will beneficially own, directly or indirectly, 20% or more of, respectively, the outstanding shares of common stock (or, for a non-corporate entity, equivalent securities) of the entity resulting from such Business Combination or the combined voting power of the outstanding voting securities of such entity, except to the extent that such ownership existed prior to the Business Combination, and (C) individuals who were members of the Incumbent Board (or, for a non-corporate entity, equivalent governing body) will constitute at least a majority of the members of the board of directors of the entity resulting from such Business Combination; or

(iv) approval by the stockholders of the Company of a complete liquidation or dissolution of the Company.

(h) “Code” means the Internal Revenue Code of 1986, as amended from time to time, and any successor thereto. Reference to any specific section of the Code shall be deemed to include such regulations and relevant interpretive guidance issued by the Internal Revenue Service or the Treasury Department, as well as any comparable provision of any future regulation and guidance amending, supplementing or superseding such regulations and guidance.

(i) “Committee” has the meaning set forth in Section 2(a).

(j) “Common Stock” means common stock of the Company.

(k) “Company” means Atlas America, Inc., a Delaware corporation, or any successor thereto.

(l)“Covered Employee” means a Participant designated in connection with the grant of any Qualified Performance-Based Award as a Participant who is or may be a “covered employee” within the meaning of Section 162(m)(3) of the Code in the year in which such Qualified Performance-Based Award is expected to be taxable to the Participant.

(m) “Deferred Unit” means a contractual obligation of the Company to deliver a Share pursuant to Section 8, subject to availability pursuant to Section 3.

(n) “Director” means any individual who is a member of the Board.

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(o) “Disability” means, unless otherwise provided in an Award Agreement, (i) “Disability” as defined in any Individual Agreement to which the Participant is a party, (ii) if there is no such Individual Agreement or it does not define “Disability,” (A) permanent and total disability as determined under the Company’s long-term disability plan applicable to the Participant, or (B) if there is no such plan applicable to the Participant, “permanent and total disability” as defined in Section 22(e)(3) of the Code. Notwithstanding the above, with respect to an Incentive Stock Option, Disability shall mean “permanent and total disability” as defined in Section 22(e)(3) of the Code and, with respect to any Award, to the extent necessary to avoid accelerated taxation or tax penalties under Section 409A of the Code, Disability shall mean “disability” within the meaning of Section 409A of the Code.

(p) “Disaffiliation” means a Subsidiary’s or Affiliate’s ceasing to be a Subsidiary or Affiliate for any reason (including, without limitation, as a result of a public offering, or a spinoff or sale by the Company of the stock of the Subsidiary or Affiliate) or a sale of a division of the Company and its Affiliates.

(q) “Eligible Individuals” means directors, officers, employees and consultants of the Company or any of its Subsidiaries or Affiliates, and prospective employees and consultants who have accepted offers of employment or consultancy from the Company or its Subsidiaries or Affiliates.

(r) “Exchange Act” means the Securities Exchange Act of 1934, as amended from time to time, and any successor thereto.

(s) “Fair Market Value” means, as of any given date, (i) (A) the closing price for the Common Stock on the Applicable Exchange, or if the shares were not traded on the Applicable Exchange on such date, then on the last preceding date on which such shares of Common Stock were traded, all as reported by such source as the Committee may select, or, at the discretion of the Committee, the price prevailing on the Applicable Exchange at the relevant time (as determined under procedures established by the Committee), (B) if the Common Stock is not listed on a securities exchange, the mean between the closing bid and asked price on that date, or, if there are no quotations available for such date, on the last preceding date on which such quotations shall be available, as reported by the Pink OTC Markets Inc. or (C) if shares of Common Stock are not publicly traded, the most recent value determined by an independent appraiser appointed by the Company for such purpose in accordance with the requirements of Section 409A of the Code, or (ii) if applicable and subject to the requirements of Section 409A of the Code, the price per share as determined in accordance with the terms, conditions, and limitations set forth in an Award Agreement, or (iii) if applicable and subject to the requirements of Section 409A of the Code, the price per share as determined in accordance with the procedures of a third party administrator retained by the Company to administer the Plan and as approved by the Committee.

(t) “Free-Standing SAR” has the meaning set forth in Section 5(b).

(u) “Grant Date” means, with respect to an Award, (i) the date on which the Committee by resolution selects an Eligible Individual to receive a grant of an Award and determines the number of Shares to be subject to such Award or the formula for earning a number of shares or cash amount, or (ii) such later date as the Committee shall provide in such resolution.

(v) “Incentive Stock Option” means any Option that is designated in the applicable Award Agreement as an “incentive stock option” within the meaning of Section 422 of the Code, and that in fact so qualifies.

(w) “Individual Agreement” means an employment, consulting or similar agreement between a Participant and the Company or one of its Subsidiaries or Affiliates.

(x) “NASDAQ” means The NASDAQ Stock Market.

(y) “Nonqualified Option” means any Option that is not an Incentive Stock Option.

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(z) “Non-Employee Director” means a member of the Board who is an employee of neither the Company nor of any Affiliate.

(aa) “Option” means an Award granted under Section 5.

(bb) “Participant” means an Eligible Individual to whom an Award is or has been granted.

(cc) “Performance Goals” means the performance goals in connection with the grant of an Award made pursuant to the Plan that is subject to the attainment of one or more standards established by the Committee to determine in whole or in part whether the Award shall be earned. In the case of Qualified-Performance Based Awards, (i) such goals shall be based on the attainment of one or any combination of the following either in absolute terms or in comparison to publicly available industry standards or indices: stock price, return on equity, assets under management, EBITDA (earnings before interest, taxes, depreciation and amortization), earnings per share, price-earnings multiples, net income, operating income, pre-tax income, sales, net profit after tax, gross profit, operating profit, cash generation, unit volume, return on equity, change in working capital, return on capital revenues, working capital, accounts receivable, productivity, margin, net capital employed, return on assets, stockholder return, return on capital employed, increase in assets, unit volume, sales, internal sales growth, cash flow, market share, relative performance to a comparison group designated by the Committee, or strategic business criteria consisting of one or more objectives based on meeting specified revenue goals, market penetration goals, customer growth, geographic business expansion goals, cost targets, goals relating to acquisitions or divestitures or stockholder return with respect to the Company or any Subsidiary, Affiliate, division or department of the Company and (ii) such Performance Goals shall be set by the Committee within the time period prescribed by Section 162(m) of the Code and the regulations promulgated thereunder. Such Performance Goals also may be based upon the attaining of specified levels of Company, Subsidiary, Affiliate or divisional performance under one or more of the measures described above relative to the performance of other entities, divisions or subsidiaries.

(dd) “Plan” means this Atlas America, Inc. 2009 Stock Incentive Plan, as set forth herein and as hereafter amended from time to time.

(ee) “Qualified Performance-Based Award” means an Award subject to Performance Goals and intended to qualify for the Section 162(m) Exemption, as provided in Section 11.

(ff) “Restricted Stock” means an Award granted under Section 6.

(gg) “Restricted Stock Units” means an Award granted under Section 7.

(hh) “Restriction Period” means, with respect to an Award of Restricted Stock or Restricted Stock Units, the period, if any, set by the Committee, commencing with the date of such Award for which vesting restrictions apply and until the expiration of such vesting restrictions.

(ii) “Section 162(m) Exemption” means the exemption from the limitation on deductibility imposed by Section 162(m) of the Code that is set forth in Section 162(m)(4)(C) of the Code.

(jj) “Share” means a share of Common Stock.

(kk) “Stock Appreciation Right” means an award described in Section 5(b).

(ll) “Subsidiary” means any corporation, partnership, joint venture, limited liability company or other entity during any period in which at least a 50% voting or profits interest is owned, directly or indirectly, by the Company or any successor to the Company.

(mm) “Tandem SAR” has the meaning set forth in Section 5(b).

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(nn) “Term” means the maximum period during which an Option or Stock Appreciation Right may remain outstanding, subject to earlier termination upon Termination of Employment or otherwise, as specified in the applicable Award Agreement.

(oo) “Termination of Employment” means the termination of the applicable Participant’s employment with, or performance of services for, the Company and any of its Subsidiaries or Affiliates. Unless otherwise determined by the Committee, if a Participant’s employment with, or membership on a board of directors of the Company and its Affiliates terminates but such Participant continues to provide services to the Company and its Affiliates in a non-employee director capacity or as an employee, as applicable, such change in status shall not be deemed a Termination of Employment. A Participant employed by, or performing services for, a Subsidiary or an Affiliate or a division of the Company and its Affiliates shall be deemed to incur a Termination of Employment if, as a result of a Disaffiliation, such Subsidiary, Affiliate, or division ceases to be a Subsidiary, Affiliate or division, as the case may be, and the Participant does not immediately thereafter become an employee of (or service provider for), or member of the board of directors of, the Company or another Subsidiary or Affiliate. Temporary absences from employment because of illness, vacation or leave of absence and transfers among the Company and its Subsidiaries and Affiliates shall not be considered Terminations of Employment. Notwithstanding the foregoing, with respect to any Award that constitutes “nonqualified deferred compensation” within the meaning of Section 409A of the Code, “Termination of Employment” shall mean a “separation from service” as defined under Section 409A of the Code.

SECTION 2. Administration

(a)Committee. The Plan shall be administered by the Compensation Committee of the Board or such other committee of the Board as the Board may from time to time designate to administer the Plan (the “Committee”), which shall be composed of not less than two directors, and shall be appointed by and serve at the pleasure of the Board. The Committee shall, subject to Section 11, have plenary authority to grant Awards pursuant to the terms of the Plan to Eligible Individuals. Among other things, the Committee shall have the authority, subject to the terms and conditions of the Plan:

(i) to select the Eligible Individuals to whom Awards may from time to time be granted;

(ii) to determine whether and to what extent Incentive Stock Options, Nonqualified Options, Stock Appreciation Rights, Shares of Restricted Stock, Restricted Stock Units, other stock-based awards, or any combination thereof, are to be granted hereunder;

(iii) to determine the number of Shares to be covered by each Award granted hereunder;

(iv) to determine the terms and conditions of each Award granted hereunder, based on such factors as the Committee shall determine;

(v) subject to Section 12, to modify, amend or adjust the terms and conditions of any Award;provided, however, that the Committee may not adjust upwards the amount payable with respect to a Qualified Performance-Based Award or waive or alter the Performance Goals associated therewith other than as described in Section 3(d)(iii);

(vi) to adopt, alter and repeal such administrative rules, guidelines and practices governing the Plan as it shall from time to time deem advisable;

(vii) subject to Section 11, to accelerate the vesting or lapse of restrictions of any outstanding Award, based in each case on such considerations as the Committee in its sole discretion determines;

(viii) to interpret the terms and provisions of the Plan and any Award issued under the Plan (and any agreement relating thereto);

(ix) to establish any “blackout” period that the Committee in its sole discretion deems necessary or advisable;

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(x) to determine whether, to what extent, and under what circumstances cash, Shares, and other property and other amounts payable with respect to an Award under this Plan shall be deferred either automatically or at the election of the Participant;

(xi) to decide all other matters that must be determined in connection with an Award; and

(xii) to otherwise administer the Plan.

(b)Procedures.

(i) The Committee may act only by a majority of its members then in office, except that the Committee may, subject to Section 11 and except to the extent prohibited by applicable law or the listing standards of the Applicable Exchange, allocate all or any portion of its responsibilities and powers to any one or more of its members and may delegate all or any part of its responsibilities and powers to any person or persons selected by it, provided that any such delegation shall be consistent with the requirements of the Delaware General Corporation Law (including, without limitation, that any such delegation to grant Awards shall be consistent with Section 157(c) of the Delaware General Corporation Law).

(ii) Subject to Section 11, any authority granted to the Committee may also be exercised by the full Board, and to the extent that any permitted action taken by the Board conflicts with action taken by the Committee, the Board action shall control.

(c)Discretion of Committee. Any determination made by the Committee or by an appropriately delegated officer pursuant to delegated authority under the provisions of the Plan with respect to any Award shall be made in the sole discretion of the Committee or such delegate at the time of the grant of the Award or, unless in contravention of any express term of the Plan, at any time thereafter. All decisions made by the Committee or any appropriately delegated officer pursuant to the provisions of the Plan shall be final, conclusive and binding on all persons, including the Company, Participants, and Eligible Individuals.

(d)Award Agreements. The terms and conditions of each Award, as determined by the Committee, shall be set forth in an Award Agreement, which shall be delivered to the Participant receiving such Award upon, or as promptly as is reasonably practicable following, the grant of such Award. The effectiveness of an Award shall not be subject to the Award Agreement’s being signed by the Company and/or the Participant receiving the Award Agreement unless specifically so provided in the Award Agreement. Award Agreements may be amended only in accordance with Section 12 hereof.

SECTION 3. Common Stock Subject to Plan

(a)Plan Maximums. Subject to Section 3(d), the maximum number of Shares that may be delivered pursuant to Awards under the Plan shall be 4,800,000. The maximum number of Shares that may be granted pursuant to Options intended to be Incentive Stock Options shall be 4,800,000 Shares. Shares subject to an Award under the Plan may be authorized and unissued Shares or may be treasury Shares.

(b)Individual Limits. No Participant may be granted Options and Free-Standing SARs covering in excess of 500,000 Shares during any calendar year. No Participant may be granted Qualified Performance-Based Awards (other than Options and Free-Standing SARs) covering in excess of 500,000 Shares during any calendar year.

(c)Rules for Calculating Shares Delivered.

(i) To the extent that any Award is cancelled, forfeited, or any Option and the related Tandem SAR (if any) or Free-Standing SAR terminates, expires or lapses without being exercised, or any Award is settled for cash, the Shares subject to such Awards not delivered as a result thereof shall again be available for Awards under the Plan.

(ii) If the exercise price of any Option and/or the tax withholding obligations relating to any Award are satisfied by delivering Shares to the Company (by either actual delivery or by attestation), only the number of Shares issued net of the Shares delivered or attested to shall be deemed delivered for purposes of the

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limits set forth in Section 3(a). To the extent any Shares subject to an Award are withheld to satisfy the exercise price (in the case of an Option) and/or the tax withholding obligations relating to such Award, such Shares shall not be deemed to have been delivered for purposes of the limits set forth in Section 3(a).

(d)Adjustment Provision.

(i) In the event of a merger, consolidation, acquisition of property or shares, stock rights offering, liquidation, Disaffiliation, or similar event affecting the Company or any of its Subsidiaries (each, a “Corporate Transaction”), the Committee or the Board shall in its discretion make such substitutions or adjustments as it deems appropriate and equitable to (A) the aggregate number and kind of Shares or other securities reserved for issuance and delivery under the Plan, (B) the various maximum limitations set forth in Sections 3(a) and 3(b) upon certain types of Awards and upon the grants to individuals of certain types of Awards, (C) the number and kind of Shares or other securities subject to outstanding Awards; and (D) the exercise price of outstanding Options and Stock Appreciation Rights. In the case of Corporate Transactions, such adjustments may include, without limitation, (1) the cancellation of outstanding Awards in exchange for payments of cash, property or a combination thereof having an aggregate value equal to the value of such Awards, as determined by the Committee or the Board in its sole discretion (it being understood that in the case of a Corporate Transaction with respect to which stockholders of Common Stock receive consideration other than publicly traded equity securities of the ultimate surviving entity, any such determination by the Committee that the value of an Option or Stock Appreciation Right shall for this purpose be deemed to equal the excess, if any, of the value of the consideration being paid for each Share pursuant to such Corporate Transaction over the exercise price of such Option or Stock Appreciation Right shall conclusively be deemed valid); (2) the substitution of other property (including, without limitation, cash or other securities of the Company and securities of entities other than the Company) for the Shares subject to outstanding Awards; and (3) in connection with any Disaffiliation, arranging for the assumption of Awards, or replacement of Awards with new awards based on other property or other securities (including, without limitation, other securities of the Company and securities of entities other than the Company), by the affected Subsidiary, Affiliate or division or by the entity that controls such Subsidiary, Affiliate or division following such Disaffiliation (as well as any corresponding adjustments to Awards that remain based upon Company securities).

(ii) In the event of a stock dividend, stock split, reverse stock split, separation, spinoff, reorganization, extraordinary dividend of cash or other property, share combination, or recapitalization or similar event affecting the capital structure of the Company (each, a “Share Change”), the Committee or the Board shall make such substitutions or adjustments as it deems appropriate and equitable to (A) the aggregate number and kind of Shares or other securities reserved for issuance and delivery under the Plan, (B) the various maximum limitations set forth in Sections 3(a) and 3(b) upon certain types of Awards and upon the grants to individuals of certain types of Awards, (C) the number and kind of Shares or other securities subject to outstanding Awards; and (D) the exercise price of outstanding Options and Stock Appreciation Rights.

(iii) The Committee may adjust in its sole discretion the Performance Goals applicable to any Awards to reflect any Share Change and any Corporate Transaction and any unusual or non-recurring events and other extraordinary items, impact of charges for restructurings, discontinued operations and the cumulative effects of accounting or tax changes, each as defined by generally accepted accounting principles or as identified in the Company’s financial statements, notes to the financial statements, management’s discussion and analysis or the Company’s other SEC filings,provided that no such modification shall be made if the effect would be to cause an Award that is intended to be a Qualified Performance-Based Award to no longer constitute a Qualified Performance-Based Award. If the Committee determines that a change in the business, operations, corporate structure or capital structure of the Company or the applicable subsidiary, division or other operational unit of, or the manner in which any of the foregoing conducts its business, or other events or circumstances render the Performance Goals to be unsuitable, the Committee may modify such Performance Goals or the related minimum acceptable level of achievement, in whole or in part, as the Committee deems appropriate and equitable;provided, however, that no such modification shall be made if

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the effect would be to cause an Award that is intended to be a Qualified Performance-Based Award to no longer constitute a Qualified Performance-Based Award.

(iv) Any adjustment under this Section 3(d) need not be the same for all Participants.

(e)Section 409A. Notwithstanding the foregoing: (i) any adjustments made pursuant to Section 3(d) to Awards that are considered “deferred compensation plans” within the meaning of Section 409A of the Code shall be made in compliance with the requirements of Section 409A of the Code; (ii) any adjustments made pursuant to Section 3(d) to Awards that are not considered “deferred compensation plans” subject to Section 409A of the Code shall be made in such a manner as to ensure that after such adjustment, the Awards either (A) continue not to be subject to Section 409A of the Code or (B) comply with the requirements of Section 409A of the Code; and (iii) in any event, neither the Committee nor the Board shall have the authority to make any adjustments pursuant to Section 3(d) to the extent the existence of such authority would cause an Award that is not intended to be subject to Section 409A of the Code at the Grant Date to be subject thereto as of the Grant Date.

SECTION 4. Eligibility

Awards may be granted under the Plan to Eligible Individuals.

SECTION 5. Options and Stock Appreciation Rights

(a)Types of Options. Options may be of two types: Incentive Stock Options and Nonqualified Options. The Award Agreement for an Option shall indicate whether the Option is intended to be an Incentive Stock Option or a Nonqualified Option;provided,however, that Incentive Stock Options may be granted only to employees of the Company and any subsidiary corporation (within the meaning of Section 424(f) of the Code) or parent corporation (within the meaning of Section 424(e) of the Code), and the aggregate Fair Market Value (determined on the applicable Grant Date) of the Shares with respect to which Incentive Stock Options are exercisable for the first time by any Participant during any calendar year (under all plans of the Company and its Affiliates) shall not exceed $100,000.

(b)Types and Nature of Stock Appreciation Rights. Stock Appreciation Rights may be “Tandem SARs,” which are granted in conjunction with an Option, or “Free-Standing SARs,” which are not granted in conjunction with an Option. Upon the exercise of a Stock Appreciation Right, the Participant shall be entitled to receive an amount in cash, Shares or both, in value equal to the product of (i) the excess of the Fair Market Value of one Share over the exercise price of the applicable Stock Appreciation Right, multiplied by (ii) the number of Shares in respect of which the Stock Appreciation Right has been exercised. The applicable Award Agreement shall specify whether such payment is to be made in cash or Common Stock or both, or shall reserve to the Committee or the Participant the right to make that determination prior to or upon the exercise of the Stock Appreciation Right.

(c)Tandem SARs. A Tandem SAR may be granted at the Grant Date of the related Option. A Tandem SAR shall be exercisable only at such time or times and to the extent that the related Option is exercisable in accordance with the provisions of this Section 5, and shall have the same exercise price as the related Option. A Tandem SAR shall terminate or be forfeited upon the exercise or forfeiture of the related Option, and the related Option shall terminate or be forfeited upon the exercise or forfeiture of the Tandem SAR.

(d)Exercise Price. The exercise price per Share subject to an Option or Free-Standing SAR shall be determined by the Committee and set forth in the applicable Award Agreement, and shall not be less than the Fair Market Value of a share of the Common Stock on the applicable Grant Date;provided, however, that the exercise price per Share subject to such Incentive Stock Option granted to an Eligible Individual (together with persons whose stock ownership is attributed to such Eligible Individual pursuant to Section 424(d) of the Code) who owns stock possessing more than ten percent (10%) of the total combined voting power of all classes of

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stock of the Company or any of its Subsidiaries shall not be less than one hundred and ten percent (110%) of the Fair Market Value of a Share on the applicable Grant Date. In no event may any Option or Free-Standing SAR granted under this Plan be amended, other than pursuant to Section 3(d), to decrease the exercise price thereof, be cancelled in conjunction with the grant of any new Option or Free-Standing SAR with a lower exercise price or otherwise be subject to any action that would be treated, for accounting purposes, as a “repricing” of such Option or Free-Standing SAR, unless such amendment, cancellation or action is approved by the Company’s stockholders.

(e)Term. The Term of each Option and each Free-Standing SAR shall be fixed by the Committee, but shall not exceed ten years from the Grant Date.

(f)Vesting and Exercisability. Except as otherwise provided herein, Options and Free-Standing SARs shall be exercisable at such time or times and subject to such terms and conditions as shall be determined by the Committee;provided,however, that if an Incentive Stock Option is exercised after the expiration of the exercise periods that apply for purposes of Section 422 of the Code, such Option will thereafter be treated as a Nonqualified Option. If the Committee provides that any Option or Free-Standing SAR will become exercisable only in installments, the Committee may at any time waive such installment exercise provisions, in whole or in part, based on such factors as the Committee may determine. In addition, the Committee may at any time accelerate the exercisability of any Option or Free-Standing SAR.

(g)Method of Exercise. Subject to the provisions of this Section 5, Options and Free-Standing SARs may be exercised, in whole or in part, at any time during the applicable Term by giving written notice of exercise to the Company or through the procedures established with the Company or the Company’s appointed third-party Option administrator specifying the number of Shares as to which the Option or Free-Standing SAR is being exercised;provided,however, that, unless otherwise permitted by the Committee, any such exercise must be with respect to a portion of the applicable Option or Free-Standing SAR relating to no less than the lesser of the number of Shares then subject to such Option or Free-Standing SAR or 100 Shares. In the case of the exercise of an Option, such notice shall be accompanied by payment in full of the purchase price (which shall equal the product of such number of Shares multiplied by the applicable exercise price) by certified or bank check or such other instrument as the Company may accept. If approved by the Committee, payment, in full or in part, may also be made:

(i) in the form of unrestricted Shares (by delivery of such Shares or by attestation) of the same class as the Common Stock subject to the Option already owned by the Participant (based on the Fair Market Value of the Common Stock on the date the Option is exercised);provided,however, that, in the case of an Incentive Stock Option, the right to make a payment in the form of already owned Shares of the same class as the Common Stock subject to the Option may be authorized only at the time the Option is granted;

(ii) to the extent permitted by applicable law, by delivering a properly executed exercise notice to the Company, together with a copy of irrevocable instructions to a broker to deliver promptly to the Company the amount of sale or loan proceeds necessary to pay the purchase price, and, if requested, the amount of any federal, state, local or foreign withholding taxes, and in order to facilitate the foregoing, the Company may, to the extent permitted by applicable law, enter into agreements for coordinated procedures with one or more brokerage firms or provide for Company loans to be made for purposes of the exercise of Options;

(iii) by instructing the Company to withhold a number of Shares having a Fair Market Value (based on the Fair Market Value of the Common Stock on the date the applicable Option is exercised) equal to the product of (A) the exercise price multiplied by (B) the number of Shares in respect of which the Option shall have been exercised; or

(iv) A combination of the foregoing methods.

(h)Delivery; Rights of Stockholders. No Shares shall be delivered pursuant to the exercise of an Option until the exercise price therefor has been fully paid and applicable taxes have been withheld. The applicable

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Participant shall have all of the rights of a stockholder of the Company holding the class or series of Common Stock that is subject to the Option or Stock Appreciation Right (including, if applicable, the right to vote the applicable Shares and the right to receive dividends), when the Participant (i) has given written notice of exercise, (ii) if requested, has given the representation described in Section 14(a), and (iii) in the case of an Option, has paid in full for such Shares.

(i)Terminations of Employment. Subject to such other rules concerning the consequences of a Termination of Employment as the Committee may, in its discretion, set forth in the applicable Award Agreement, a Participant’s Options and Stock Appreciation Rights shall be forfeited upon such Participant’s Termination of Employment for any reason;provided,however, that no Incentive Stock Option may be exercised more than (i) three (3) months after the Participant’s Termination of Employment for any reason other than Disability or death, unless (A) the Participant dies during such three-month period and (B) the Award Agreement or the Committee permits later exercise, and (ii) one (1) year after the Participant’s Termination of Service on account of Disability, unless (A) the Participant dies during such one-year period and (B) the Award Agreement or the Committee permit later exercise.

(j)Nontransferability of Options and Stock Appreciation Rights. Except as the Committee may, in its discretion, set forth in the applicable Award Agreement, no Option or Free-Standing SAR shall be transferable by a Participant other than (i) by will or by the laws of descent and distribution, or (ii) in the case of a Nonqualified Option or Free-Standing SAR, pursuant to a qualified domestic relations order or as otherwise expressly permitted by the Committee including, if so permitted, pursuant to a transfer to the Participant’s family members or to a charitable organization, whether directly or indirectly or by means of a trust or partnership or otherwise. For purposes of this Plan, unless otherwise determined by the Committee, “family member” shall have the meaning given to such term in General Instructions A.1(a)(5) to Form S-8 under the Securities Act of 1933, as amended, and any successor thereto. A Tandem SAR shall be transferable only with the related Option as permitted by the preceding sentence. Any Option or Stock Appreciation Right shall be exercisable, subject to the terms of this Plan, only by the applicable Participant, the guardian or legal representative of such Participant or any person to whom such Option or Stock Appreciation Right is permissibly transferred pursuant to this Section 5(j), it being understood that the term “Participant” includes such guardian, legal representative and other transferee;provided,however, that the term “Termination of Employment” shall continue to refer to the Termination of Employment of the original Participant.

SECTION 6. Restricted Stock

(a)Nature of Awards and Certificates. Shares of Restricted Stock are actual Shares issued to a Participant, and shall be evidenced in such manner as the Committee may deem appropriate, including book-entry registration or issuance of one or more stock certificates. Any certificate issued in respect of Shares of Restricted Stock shall be registered in the name of the applicable Participant and shall bear an appropriate legend referring to the terms, conditions, and restrictions applicable to such Award. The Committee may require that the certificates evidencing such shares be held in custody by the Company until the restrictions thereon shall have lapsed and that, as a condition of any Award of Restricted Stock, the applicable Participant shall have delivered a stock power, endorsed in blank, relating to the Common Stock covered by such Award.

(b)Terms and Conditions. Shares of Restricted Stock shall be subject to the following terms and conditions:

(i) The Committee shall, prior to or at the time of grant, condition the vesting or transferability of an Award of Restricted Stock upon the continued service of the applicable Participant, upon the attainment of performance conditions (whether or not such conditions are Performance Goals) or upon both the attainment of performance conditions (whether or not such conditions are Performance Goals) and the continued service of the applicable Participant. In the event that the grant or vesting of an Award of Restricted Stock is conditioned upon the attainment of Performance Goals, or upon both the attainment of Performance Goals and the continued service of the applicable Participant, the Committee may, prior to or at the time of grant,

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designate such an Award as a Qualified Performance-Based Award. The conditions for grant, vesting or transferability and the other provisions of Restricted Stock Awards (including without limitation any Performance Goals) need not be the same with respect to each Participant. The Committee may at any time, in its sole discretion, accelerate or waive, in whole or in part, any of the foregoing restrictions;provided, however, that in the case of Restricted Stock that is a Qualified Performance-Based Award, unless done in connection with the Participant’s death or Disability, the applicable Performance Goals have been satisfied.

(ii) Subject to the provisions of the Plan and the applicable Award Agreement, during the Restriction Period, the Participant shall not be permitted to sell, assign, transfer, pledge or otherwise encumber Shares of Restricted Stock.

(iii) Except as provided in this Section 6 and in an applicable Award Agreement, the applicable Participant shall have, with respect to the Shares of Restricted Stock, all of the rights of a stockholder of the Company holding the class or series of Common Stock that is the subject of the Restricted Stock, including the right to vote the Shares. If so determined by the Committee in the applicable Award Agreement and subject to Section 14(e), (A) cash dividends on the class or series of Common Stock that is the subject of the Restricted Stock Award shall be automatically deferred and/or reinvested in additional Restricted Stock and held subject to the vesting of the underlying Restricted Stock, and (B) subject to any adjustment pursuant to Section 3(d), dividends payable in Common Stock shall be paid in the form of Restricted Stock of the same class as the Common Stock with which such dividend was paid, held subject to the vesting of the underlying Restricted Stock.

(iv) Except as otherwise set forth in the applicable Award Agreement, upon a Participant’s Termination of Employment for any reason during the Restriction Period, all Shares of Restricted Stock still subject to restriction shall be forfeited by such Participant;provided,however, that subject to Section 11(b), the Committee shall have the discretion to waive, in whole or in part, any or all remaining restrictions with respect to any or all of such Participant’s Shares of Restricted Stock,provided, further,that in the case of Restricted Stock that is a Qualified Performance-Based Award, unless the Participant’s employment is terminated by reason of death or Disability, the applicable Performance Goals shall have been satisfied.

(v) If and when any applicable Performance Goals are satisfied and the Restriction Period expires without a prior forfeiture of the Shares of Restricted Stock for which legended certificates have been issued, unlegended certificates for such Shares shall be delivered to the Participant upon surrender of the legended certificates.

SECTION 7. Restricted Stock Units

(a)Nature of Awards. Restricted Stock Units are Awards denominated in Shares that will be settled, subject to the terms and conditions of the Restricted Stock Units, in an amount in cash, Shares or both, based upon the Fair Market Value of a specified number of Shares.

(b)Terms and Conditions. Restricted Stock Units shall be subject to the following terms and conditions:

(i) The Committee shall, prior to or at the time of grant, condition the grant, vesting or transferability of Restricted Stock Units upon the continued service of the applicable Participant, upon the attainment of performance conditions (whether or not such conditions are Performance Goals) or upon both the attainment of performance conditions (whether or not such conditions are Performance Goals) and the continued service of the applicable Participant. In the event that the Committee conditions the grant or vesting of Restricted Stock Units upon the attainment of Performance Goals or upon both the attainment of Performance Goals and the continued service of the applicable Participant, the Committee may, prior to or at the time of grant, designate such Awards as Qualified Performance-Based Awards. The conditions for grant, vesting or transferability and the other provisions of Restricted Stock Units (including without limitation any Performance Goals) need not be the same with respect to each Participant. An Award of Restricted Stock Units shall be settled as and when the Restricted Stock Units vest or at a later time

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specified by the Committee in an applicable Award Agreement or if the Committee so permits, in accordance with an election of the Participant pursuant to a deferred compensation arrangement in compliance with, or intended to an exception or exemption from, the requirements of Section 409A of the Code.

(ii) Subject to the provisions of the Plan and the applicable Award Agreement, during the Restriction Period, the Participant shall not be permitted to sell, assign, transfer, pledge or otherwise encumber Restricted Stock Units. Restricted Stock Units may not be sold, assigned, transferred, pledged or otherwise encumbered until they are settled, except to the extent provided in the applicable Award Agreement in the event of the Participant’s death.

(iii) The Award Agreement for Restricted Stock Units shall specify whether, to what extent and on what terms and conditions the applicable Participant shall be entitled to receive current or deferred payments of cash, Common Stock or other property corresponding to the dividends payable on the Common Stock (subject to Section 14(e) below).

(iv) Except as otherwise set forth in the applicable Award Agreement, upon a Participant’s Termination of Employment for any reason during the Restriction Period, all Restricted Stock Units still subject to restriction shall be forfeited by such Participant;provided,however, that subject to Section 11(b), the Committee shall have the discretion to waive, in whole or in part, any or all remaining restrictions with respect to any or all of such Participant’s Restricted Stock Units;provided,further, that in the case of a Restricted Stock Unit that is a Qualified Performance-Based Award, unless the Participant’s employment is terminated by reason of death or Disability, the applicable Performance Goals shall have been satisfied.

SECTION 8. Non-Employee Director Awards.

The provisions of this Section 8 are applicable only to Awards granted to Non-Employee Directors.

(a)Grants of Deferred Units.Upon his or her first election or appointment to the Board, each Non-Employee Director shall be awarded, on the date of first election or appointment, Deferred Units for Shares having a Fair Market Value of $15,000.00 on the Grant Date. Thereafter, on each anniversary of the date on which a Non-Employee Director is first elected or appointed to the Board, the Non-Employee Director shall be awarded Deferred Units for Shares having a Fair Market Value of $15,000.00. This Plan shall not impose any obligations on the Company to retain any Non-Employee Director as a Director nor shall it impose any obligation on the part of any Non-Employee Director to remain as a Director of the Company.

(b)Terms and Conditions.

(i) Each Award granted pursuant to this Section 8 shall be evidenced by a written Award Agreement between the Participant and the Company.

(ii) Each Award granted pursuant to this Section 8 shall vest in three equal installments on each of the second, third and fourth anniversary of the Grant Date, in each case, subject to the Non-Employee Director’s continuous service to the Company through the applicable vesting date. Notwithstanding the foregoing, and except as provided herein, if the Non-Employee Director’s service to the Company terminates by reason of the Non-Employee Director’s death or Disability prior to the completion of the period of service required to be performed to fully vest in any Award, all Deferred Units that are the subject of such Award shall be delivered to such Non-Employee Director (or the Non-Employee Director’s beneficiary or estate). Upon the occurrence of a Change in Control, unless the Committee determines otherwise in the Award Agreement, each Non-Employee Director’s right and interest in Deferred Units which have not previously vested shall become vested and nonforfeitable, regardless of the period of the Non-Employee Director’s service since the date such Deferred Units were awarded.

(iii) All provisions of the Plan not inconsistent with this Section 8 shall apply to Awards granted to Non-Employee Directors.

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SECTION 9. Other Stock-Based Awards

Other Awards of Common Stock and other Awards that are valued in whole or in part by reference to, or are otherwise based upon or settled in, Common Stock, including (without limitation) unrestricted stock, performance units, dividend equivalents and convertible debentures, may be granted under the Plan.

SECTION 10. Change in Control.

Except as otherwise specifically provided in Section 8, the Award Agreement evidencing each Award under this Plan may specify the impact, if any, of the occurrence of a Change in Control on such Award.

SECTION 11. Qualified Performance-Based Awards; Section 16(b)

(a) The provisions of this Plan are intended to ensure that all Options and Stock Appreciation Rights granted hereunder to any Covered Employee in the tax year in which such Option or Stock Appreciation Right is expected to be deductible to the Company qualify for the Section 162(m) Exemption, and all such Awards shall therefore be considered Qualified Performance-Based Awards and this Plan shall be interpreted and operated consistent with that intention (including, without limitation, to require that all such Awards be granted by a committee composed solely of members who satisfy the requirements for being “outside directors” for purposes of the Section 162(m) Exemption (“Outside Directors”)). When granting any Award other than an Option or Stock Appreciation Right, the Committee may designate such Award as a Qualified Performance-Based Award, based upon a determination that (i) the recipient is or may be a Covered Employee with respect to such Award, and (ii) the Committee wishes such Award to qualify for the Section 162(m) Exemption, and the terms of any such Award (and of the grant thereof) shall be consistent with such designation (including, without limitation, that all such Awards be granted by a committee composed solely of Outside Directors).

(b) Each Qualified Performance-Based Award (other than an Option or Stock Appreciation Right) shall be earned, vested and payable (as applicable) only upon the achievement of one or more Performance Goals, together with the satisfaction of any other conditions, such as continued employment, as the Committee may determine to be appropriate, and no Qualified Performance-Based Award may be amended, nor may the Committee exercise any discretionary authority it may otherwise have under this Plan with respect to a Qualified Performance-Based Award under this Plan, in any manner that would cause the Qualified Performance-Based Award to cease to qualify for the Section 162(m) Exemption;provided,however, that the Committee may provide, either in connection with the grant of the applicable Award or by amendment thereafter, that achievement of such Performance Goals will be waived upon the death or Disability of the Participant or under any other circumstance with respect to which the existence of such possible waiver will not cause the Award to fail to qualify for the Section 162(m) Exemption as of the Grant Date.

(c) The full Board shall not be permitted to exercise authority granted to the Committee to the extent that the grant or exercise of such authority would cause an Award designated as a Qualified Performance-Based Award not to qualify for, or to cease to qualify for, the Section 162(m) Exemption.

(d) The provisions of this Plan are intended to ensure that no transaction under the Plan is subject to (and not exempt from) the short-swing recovery rules of Section 16(b) of the Exchange Act (“Section 16(b)”). Accordingly, the composition of the Committee shall be subject to such limitations as the Board deems appropriate to permit transactions pursuant to this Plan to be exempt (pursuant to Rule 16b-3 promulgated under the Exchange Act) from Section 16(b), and no delegation of authority by the Committee shall be permitted if such delegation would cause any such transaction to be subject to (and not exempt from) Section 16(b).

SECTION 12. Term, Amendment and Termination

(a)Effectiveness. The Plan shall be effective as of the date it is adopted by the Board (the “Effective Date”), subject to the approval by the holders of at least a majority of the voting power represented by outstanding capital stock of the Company that is entitled generally to vote in the election of directors.

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(b)Termination. The Plan will terminate on the tenth anniversary of the Effective Date. Awards outstanding as of such date shall not be affected or impaired by the termination of the Plan.

(c)Amendment of Plan. The Board, in its sole discretion, may amend, suspend, or terminate the Plan, but no such amendment, suspension or termination shall cause a Qualified Performance-Based Award to cease to qualify for the Section 162(m) Exemption and no such amendment, alteration or discontinuation shall be made which would materially impair the rights of a Participant with respect to a previously granted Award without such Participant’s consent, except such an amendment made (i) to comply with applicable law (including, without limitation, stock exchange rules or accounting rules) or (ii) to avoid accelerated taxation or tax penalties pursuant to Section 409A of the Code. In addition, no such amendment shall be made without the approval of the Company’s stockholders to the extent such approval is required by applicable law or the listing standards of the Applicable Exchange.

(d)Amendment of Awards. Subject to Section 5(d), the Committee may unilaterally amend the terms of any Award theretofore granted, but no such amendment shall cause a Qualified Performance-Based Award to cease to qualify for the Section 162(m) Exemption or shall materially impair the rights of any Participant with respect to an Award without the Participant’s consent, except such an amendment made (i) to comply with applicable law (including, without limitation, stock exchange rules or accounting rules) or (ii) to avoid accelerated taxation or tax penalties pursuant to Section 409A of the Code.

SECTION 13. Unfunded Status of Plan

It is presently intended that the Plan constitute an “unfunded” plan. The Committee may authorize the creation of trusts or other arrangements to meet the obligations created under the Plan to deliver Common Stock or make payments;provided, however, that unless the Committee otherwise determines, the existence of such trusts or other arrangements is consistent with the “unfunded” status of the Plan. The Company shall not be required to segregate any assets for purposes of this Plan or Awards hereunder, nor shall the Company, the Board or the Committee be deemed to be a trustee of any benefit to be granted under this Plan. Any liability or obligation of the Company to any Participant with respect to an Award under this Plan shall be based solely upon any contractual obligations that may be created by this Plan and any Award Agreement or the terms of the Award, and no such liability or obligation of the Company shall be deemed to be secured by any pledge or other encumbrance on any property of the Company. Neither the Company nor the Board nor the Committee shall be required to give any security or bond for the performance of any obligation that may be created by this Plan.

SECTION 14. General Provisions

(a)Conditions for Issuance. The Committee may require each person purchasing or receiving Shares pursuant to an Award to represent to and agree with the Company in writing that such person is acquiring the Shares without a view to the distribution thereof. The certificates for such Shares may include any legend which the Committee deems appropriate to reflect any restrictions on transfer. Notwithstanding any other provision of the Plan or agreements made pursuant thereto, the Company shall not be required to issue or deliver any certificate or certificates for Shares under the Plan prior to fulfillment of all of the following conditions: (i) listing or approval for listing upon notice of issuance, of such Shares on the Applicable Exchange; (ii) any registration or other qualification of such Shares of the Company under any state or federal law or regulation, or the maintaining in effect of any such registration or other qualification which the Committee shall, in its absolute discretion upon the advice of counsel, deem necessary or advisable; and (iii) obtaining any other consent, approval, or permit from any state or federal governmental agency which the Committee shall, in its absolute discretion after receiving the advice of counsel, determine to be necessary or advisable.

(b)Additional Compensation Arrangements. Nothing contained in the Plan shall prevent the Company or any Subsidiary or Affiliate from adopting other or additional compensation arrangements for its employees.

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(c)No Contract of Employment. The Plan and each Award Agreement thereunder shall not constitute a contract of employment, and adoption of the Plan or an Award Agreement shall not confer upon any Participant any right to continued employment or other service relationship with the Company or its Subsidiaries, nor shall it interfere with or limit in any way the right of the Company or any Subsidiary or Affiliate to terminate the employment or other service relationship of any Participant at any time.

(d)Required Taxes. No later than the date as of which an amount first becomes includible in the gross income of a Participant for federal, state, local or foreign income or employment or other tax purposes with respect to any Award under the Plan, such Participant shall pay to the Company, or make arrangements satisfactory to the Company regarding the payment of, any federal, state, local or foreign taxes of any kind required by law to be withheld with respect to such amount. If determined by the Company, withholding obligations may be settled with Common Stock, including Common Stock that is part of the Award that gives rise to the withholding requirement;provided, however,that if shares of Common Stock are used to satisfy tax withholding, such shares shall be valued based on the Fair Market Value when the tax withholding is required to be made;provided, further, however, that not more than the legally required minimum withholding may be settled with Common Stock. The obligations of the Company under the Plan shall be conditional on such payment or arrangements, and the Company and its Affiliates shall, to the extent permitted by law, have the right to deduct any such taxes from any payment otherwise due to such Participant. The Committee may establish such procedures as it deems appropriate, including making irrevocable elections, for the settlement of withholding obligations with Common Stock.

(e)Limitation on Dividend Reinvestment and Dividend Equivalents. Reinvestment of dividends in additional Restricted Stock at the time of any dividend payment and the payment of Shares with respect to dividends to Participants holding Awards of Restricted Stock Units shall only be permissible if sufficient Shares are available under Section 3(a) for such reinvestment or payment (taking into account then outstanding Awards). In the event that sufficient Shares are not available for such reinvestment or payment, such reinvestment or payment shall be made in the form of a grant of Restricted Stock Units in respect of an equal number of Shares that would have been obtained by such payment or reinvestment had sufficient Shares been available, the terms of which Restricted Stock Units shall provide for settlement in cash and for dividend equivalent reinvestment in further Restricted Stock Units on the terms contemplated by this Section 14(e).

(f)Designation of Beneficiary. The Committee shall establish such procedures as it deems appropriate for a Participant to designate a beneficiary to whom any amounts payable in the event of such Participant’s death are to be paid or by whom any rights of such eligible Individual, after such Participant’s death, may be exercised.

(g)Successors.All obligations of the Company under the Plan with respect to Awards granted hereunder shall be binding on any successor to the Company, whether the existence of such successor is the result of a direct or indirect purchase, merger, consolidation, or otherwise, of all or substantially all of the business and/or assets of the Company.

(h)Subsidiary Employees. In the case of a grant of an Award to any employee of a Subsidiary of the Company, the Company may, if the Committee so directs, issue or transfer the Shares, if any, covered by the Award to the Subsidiary, for such lawful consideration as the Committee may specify, upon the condition or understanding that the Subsidiary will transfer the Shares to the employee in accordance with the terms of the Award specified by the Committee pursuant to the provisions of the Plan. All Shares underlying Awards that are forfeited or canceled should revert to the Company.

(i)Governing Law and Interpretation. The Plan and all Awards made and all determinations made and actions taken thereunder shall be governed by and construed in accordance with the laws of the State of Delaware, without reference to principles of conflict of laws. The captions of this Plan are not part of the provisions hereof and shall have no force or effect.

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(j)Non-Transferability. Except as otherwise provided in Section 5(j) or by the Committee, Awards under the Plan are not transferable except by will or by laws of descent and distribution or pursuant to a qualified domestic relations order as defined by the Code or Title I of the Employee Retirement Income Securities Act, or the rules thereunder. In the event that a designation of death beneficiary in accordance with Section 14(f) conflicts with an assignment by will or the laws of descent and distribution, the beneficiary designation will prevail. The Committee may prescribe and include in applicable Award Agreements other restrictions on transfer as it may deem advisable, including, but not limited to, restrictions related to applicable federal securities laws, the requirements of any national securities exchange or system upon which Shares are then listed or traded, or any blue sky or state securities laws. Any attempted assignment of an Award or any other benefit under this Plan in violation of this Section 14(j) shall be null and void.

(k)Foreign Employees and Foreign Law Considerations. The Committee may grant Awards to Eligible Individuals who are foreign nationals, who are located outside the United States or who are not compensated from a payroll maintained in the United States, or who are otherwise subject to (or could cause the Company to be subject to) legal or regulatory provisions of countries or jurisdictions outside the United States, on such terms and conditions different from those specified in the Plan as may, in the judgment of the Committee, be necessary or advisable to comply with the laws of the applicable foreign jurisdictions and to foster and promote achievement of the purposes of the Plan, and, in furtherance of such purposes, the Committee may make such modifications, amendments, procedures, or subplans as may be necessary or advisable to comply with such legal or regulatory provisions. Notwithstanding the above, the Committee may not take any actions hereunder, and no Awards shall be granted, that would violate the Exchange Act, the Code, any securities law, any governing statute, or any other applicable law.

(l)Section 409A of the Code. It is the intention of the Company that an Award granted under the Plan shall either (i) not be a “nonqualified deferred compensation plan” subject to Section 409A of the Code, or (ii) meet the requirements of Section 409A of the Code, such that no Participant shall be subject to accelerated taxation or tax penalties pursuant to Section 409A of the Code in respect thereof, and the Plan and the terms and conditions of all Awards shall be interpreted and administered accordingly. Notwithstanding any other provision of the Plan to the contrary, any payments (whether in cash, shares of Common Stock or other property) with respect to any Award that constitutes a “nonqualified deferred compensation plan” subject to Section 409A of the Code, to be made upon a Participant’s termination of employment shall be made no earlier than (A) the first day of the seventh month following the Participant’s “separation from service” (within the meaning of Section 409A of the Code) and (B) the Participant’s death if at the time of such termination of employment the Participant is a “specified employee,” within the meaning of Section 409A of the Code (as determined by the Company in accordance with its uniform policy with respect to all arrangements subject to Section 409A of the Code).

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